h:\projects\2010proj\10389556 ge shady hills revision\ghg psd review\final ghg applicaiton 9 20 12\shady hills transmittal ltr .docx

Golder Associates Inc.

5100 W. Lemon Street, Suite 208

Tampa, FL 33609 USA 

Tel: (813) 287-1717 Fax: (813) 287-1716 www.golder.com

Golder Associates: Operations in Africa, Asia, Australasia, Europe, North America and South America

Golder, Golder Associates and the GA globe design are trademarks of Golder Associates Corporation

September 21, 2012 103-89556

Mr. Gregg M. Worley

Chief, Air Permits Section

United States Environmental Protection Agency, Region IV

Atlanta Federal Center

61 Forsyth Street

Atlanta, GA 30303-8960

RE: NEW SOURCE REVIEW FOR GREENHOUSE GASES

SHADY HILLS POWER COMPANY, LLC; FACILITY ID NO: 1010373

AIR PERMIT NO. 1010373-007-AC / PSD-FL-402

Dear Mr. Worley:

Shady Hills Power Company, LLC, a subsidiary of GE Energy Financial Services, owns and operates the 

Shady Hills Generating Station located at 14240 Merchant Energy Way, Shady Hills, Pasco County, 

Florida. This facility consists of three, dual-fuel, nominal 170 megawatt (MW) General Electric model 

PG7241FA (GE 7FA) simple cycle combustion turbine-electric generators, three 75-foot exhaust stacks, 

and one 2.8 million gallon fuel oil storage tank. 

Air construction permit number PSD-FL-402, project number 1010373-007-AC, authorized the 

construction of two additional, nominal 170 MW simple cycle combustion turbine (CT) electric generators 

at the Shady Hills Power Company, LLC (Shady Hills) through December 30, 2010. In addition to the two 

new CTs, PSD-FL-402 authorized the construction of a 2.5 MW emergency generator, a natural gas fuel 

heater, and a 2.8-million gallon distillate fuel oil storage tank. Construction of these units has not been 

initiated. Since the issuance of the air construction permit in 2009, a new generation of General Electric 

(GE) CTs have been produced, GE 7FA.05. A new air construction permit application was submitted on 

July 12, 2010 to update the application submitted to the Florida Department of Environmental Protection 

(FDEP) in May 2008. The Project was issued a PSD permit from the FDEP (Permit No. 1010373-012-AC, 

PSD-FL-402A) on April 6, 2012.

The project will result in an increase and a net increase greater than 75,000 TPY CO2e and an increase 

and a net increase in GHG emissions on a mass basis greater than zero TPY. In addition to the CTs, 

CO2e emissions result from the emergency generator, gas heater, circuit breaker, and natural gas 

pipeline proposed as part of the Project. The project represents new emission units for the facility, and 

thus the maximum potential emissions are utilized for comparison with PSD review thresholds. In light of 

the new Tailoring Rule requirements, the GHGs emitted from the proposed project are subject to PSD 

review, including a BACT analysis for the GHGs.

EPA Region IV is the permitting authority for the GHG-portion of the proposed Shady Hills expansion 

project under a Federal Implementation Plan (FIP) that became effective on December 30, 2010. On this 

date, EPA established a FIP authorizing EPA to issue PSD permits in Florida for GHG-emitting sources. 

The FIP constitutes the EPA regulations found in 40 CFR 52.21, including the PSD applicability 

provisions, but applies only to GHGs.
Mr. Gregg M. Worley September 21, 2012

USEPA, Region IV Air Permits Section 2 113-89554

Shady Hills Transmittal Ltr .docx

GE Energy Financial Services looks forward to working with you on this permitting effort. If you would like 

to discuss any issues regarding this application, please contact Mr. Roy Belden at (203) 357-6820 or 

Scott Osbourn at (813) 287-1717 in Tampa.

Sincerely, 

GOLDER ASSOCIATES INC. 

Scott Osbourn, PE Dave Larocca

Associate and Tampa Operations Manager Senior Project Engineer

cc: Roy Belden, Shady Hills Power Company, LLC

 

Enclosure: New Source Review for Greenhouse Gases Report
A world of

capabilities

delivered locally

NEW SOURCE REVIEW FOR 

GREENHOUSE GASES

Shady Hills Generating Station / EFS Shady Hills LLC

Pasco County, Florida

Submitted To: Mr. Gregg M. Worley

Chief, Air Permits Section

United States Environmental Protection Agency, Region IV

Atlanta Federal Center

61 Forsyth Street

Atlanta, Georgia 30303-8960

Submitted By: Golder Associates Inc.

5100 W. Lemon Street, Suite 208

Tampa, FL 33609 USA 

Distribution: Electronic distribution to:

Kathleen Forney, EPA Region IV (forney.kathleen@epa.gov)

Heather Ceron, EPA Region IV (ceron.heather@epa.gov)

Natasha Hazziez, EPA Region IV (hazziez.natasha@epa.gov)

Hard copy distribution to:

2 Copy to US EPA, Region IV

3 Copy to GE Energy Financial Services

1 Copy to Golder Associates Inc.

1 Copy to Florida Department of Environmental Protection 

September 2012 103-89556

REPORT
September 2012 i 103-89556

Table of Contents 

1.0 INTRODUCTION.............................................................................................................................. 1

1.1 Project Background...................................................................................................................... 1

1.2 Florida Department of Environmental Protection (FDEP) Permit Status ..................................... 2

1.3 Endangered Species Act.............................................................................................................. 2

1.4 Cultural Resources....................................................................................................................... 3

1.5 Prevention of Significant Deterioration (PSD) Applicability Introduction...................................... 4

2.0 BEST AVAILABLE CONTROL TECHNOLOGY (BACT) ANALYSIS ............................................. 6

2.1 Simple Cycle CTs......................................................................................................................... 7

2.1.1 Step 1 – Identify All Available Control Technologies ............................................................... 7

2.1.1.1 Clean Fuel............................................................................................................................ 8

2.1.1.2 Energy Efficiency ................................................................................................................. 8

2.1.1.3 Carbon Capture and Storage (CCS).................................................................................... 9

2.1.2 Step 2 – Identification of Technically Feasible Control Alternatives ......................................10

2.1.2.1 Clean Fuels ........................................................................................................................ 11

2.1.2.2 Energy Efficiency ............................................................................................................... 11

2.1.2.3 Carbon Capture and Storage (CCS).................................................................................. 13

2.1.3 Step 3 – Rank Remaining Control Technologies................................................................... 17

2.1.4 Step 4 - Economic, Energy, and Environmental Impacts ......................................................19

2.1.4.1 CCS.................................................................................................................................... 19

2.1.4.1 Clean Fuels ........................................................................................................................ 20

2.1.4.2 Energy Efficiency ............................................................................................................... 20

2.1.5 Step 5 - Selection the BACT.................................................................................................. 22

2.1.5.1 BACT Emission Limits........................................................................................................ 22

2.2 Emergency Generator................................................................................................................ 27

2.2.1 BACT Emission Rate ............................................................................................................. 28

2.3 Fuel Gas Heater......................................................................................................................... 29

2.4 Fuel Oil Storage Tank ................................................................................................................ 30

2.5 Electrical Breaker – SF6 ............................................................................................................. 31

2.5.1 Step 1 – Identify All Available Control Technologies .............................................................31

2.5.2 Steps 2 & 3 – Identification and Ranking of Technically Feasible Control Alternatives ........32

2.5.3 Step 4 – Economic, Energy, and Environmental Impacts .....................................................32

2.5.4 Step 5 – Select the BACT...................................................................................................... 32

2.6 On-Site Pipeline and Natural Gas Supply.................................................................................. 32
September 2012 ii 103-89556

List of Tables

Table 1 GHG Emissions for the Proposed Shady Hills Expansion Project Compared to PSD 

Review Threshold

Table 2 Cost Effectiveness Analysis for Alternative Simple Cycle Generation Technologies

Table 2a Cost Effectiveness Analysis for Alternative Simple Cycle Generation Technologies – One 

CT

Table 3 Proposed GHG Emission Limits – per Turbine

Table 4 Proposed GHG Emissions for the Proposed Emergency Generator and Fuel Gas Heater

List of Appendices

Appendix A FDEP Permit No. 1010373-012-AC, PSD-FL-402A

Appendix B FDEP Air Construction Permit Application Forms for GHG Emissions

Appendix C Endangered Species Act Consultation

Appendix D Correspondence with USFW and NMFS

Appendix E Cultural Resource Analysis
September 2012 1 103-89556

1.0 INTRODUCTION

1.1 Project Background

EFS Shady Hills LLC (“EFS”) is proposing to construct 2 new General Electric (GE) 7FA.05 simple cycle 

combustion turbine-electric units with nominal ratings of 218 megawatts (MWs) each, along with 

associated ancillary equipment (the “Project”) at the site of the existing Shady Hills Generating Station 

which is owned and operated by its subsidiary Shady Hills Power Company, L.L.C. Shady Hills 

Generating Station is located at 14240 Merchant Energy Way, Shady Hills, Pasco County, Florida. The 

existing facility consists of three dual-fuel, nominal 170 MW GE model PG7241FA (GE 7FA.03) simple 

cycle combustion turbine-electric generators, three 75-foot exhaust stacks, and one 2.8 million gallon fuel 

oil storage tank, and has been in operation since 2002. 

The purpose of the Project, detailed herein, is to provide peaking duty service for commercial power offtake agreements while maximizing site output and minimizing costs within the existing Shady Hills 

Generating Station site boundary and constraints, including water availability for operational or emission 

control requirements. Peaking duty service refers to meeting the needs of power generation when there 

is a high demand. As a result of their short startup period, simple-cycle gas turbine technologies are 

deployed to meet the range of capacity factors typical for peaking duty service. Typically, peak demand 

often occurs in the afternoon, especially during the summer months when the power consumption load is 

high. In EPA’s recently proposed “Standards of Performance for Greenhouse Gas Emissions for New 

Stationary Sources: Electric Utility Generating Units,” (77 Fed. Reg. 22392 (April 13, 2012)), the agency 

notes that peaking units “generally operate differently” than combined cycle combustion turbines. EPA 

points out that “simple cycle turbines are generally used much less often (and thus have lower GHG 

emissions) and are generally used to meet peak demand rather than base or intermediate load 

requirements.” 77 Fed. Reg. 22392, 22398. 

EFS has evaluated the market needs in Florida and the conditions that support new generation capacity 

at the Shady Hills Generating Station. The potential contractual arrangements that EFS has been 

pursuing are long term contracts with utility customers (load-serving) in order to satisfy their peak power 

needs. These contracts provide a great deal of flexibility to the utility off-takers to manage their system 

load. Similar to the existing long term agreements for the Shady Hills Generating Station, EFS expects to 

provide full dispatch control to its utility off-taker under the power purchase agreement.

Simple cycle combustion turbines serve a fundamentally different purpose from combined cycle 

combustion turbines that are installed for intermediate and baseload generation needs. This is 

acknowledged by EPA in the recently proposed GHG NSPS discussed above. Therefore the evaluation 
September 2012 2 103-89556

of combined cycle combustion turbines represents re-definition of the source and as such is not included 

in this application. 

1.2 Florida Department of Environmental Protection (FDEP) Permit Status

Air construction permit number PSD-FL-402, project number 1010373-007-AC, authorized the 

construction of two additional, GE Frame 7FA.03 nominal 170 MW simple cycle combustion turbine (CT) 

electric generators at the Shady Hills Generating Station through December 30, 2010. In addition to the 

two new CTs, PSD-FL-402 authorized the construction of a 2.5 MW emergency generator, a natural gas 

fuel heater, and a 2.8-million gallon distillate fuel oil storage tank. Construction of these units has not 

been initiated. Since the issuance of the air construction permit in 2009, a new generation of larger and 

more fuel efficient General Electric (GE) CTs has become available, the GE 7FA.05 with a nominal rating 

of 218 MWs. A new air construction permit application was submitted on July 12, 2010, to update the 

application submitted to the Florida Department of Environmental Protection (FDEP) in May 2008 with the 

following variation: 

The proposed CTs will reflect the newest generation of turbines, GE’s 7FA.05, as compared to the 

authorized turbine units GE 7FA.03. The GE 7FA.05 provides increased output, 218 gross MW per CT for 

natural gas firing, 59 deg. F (223 MW fuel oil firing, 59 deg. F) with a heat input of 1,923 MMBtu/hr LHV, 

as compared to 181.6 MW per CT with a heat input of 1,704.4 MMBtu/hr in the original application. The 

new CTs result in increased MW output of 20% while only increasing the heat input by 12.8% resulting in 

increased efficiency over its predecessor GE 7FA while maintaining the same reliability and operational 

flexibility during cyclic and peaking operations. Other manufacturers of CTs offer units of similar output as 

the proposed GE 7FA.05 and all of these other units operated within a range of 1% thermal efficiency 

compared to the GE 7FA.05, which itself is the most efficient. As such, the GE 7FA.05 is representative 

of the most efficient CTs within the F-Class of units for this analysis.

The 2010 application was further updated with a new scenario for fuel oil usage should only one unit be 

constructed. This supplemental information was provided to the Florida Department of Environmental 

Protection (FDEP) on May 24, 2011. The Project was issued a PSD permit from the FDEP (Permit No. 

1010373-012-AC, PSD-FL-402A) on April 6, 2012. A copy of the final FDEP PSD permit is attached in 

Appendix A. The FDEP air construction permit application form addressing GHG emissions is provided in 

Appendix B herein. 

1.3 Endangered Species Act

EFS has conducted an ecological assessment of the proposed site to determine the likely occurrence and 

likely abundance of species considered by the U.S. Fish and Wildlife Service (FWS) to be endangered or 

threatened, and/or their critical habitat, under 50 Code of Federal Regulations 17. Based on field reviews 
September 2012 3 103-89556

and examination of available agency data, neither federally listed species, nor their critical habitats, were 

identified or observed within the Proposed Project site. However, standard protection measures for the 

eastern indigo snake will be enforced during construction of the Proposed Project to ensure eastern 

indigo snakes are not harmed. These protection measures include, but are not limited to, training 

contractors in the proper identification of eastern indigo snakes; and posting signs on the construction site 

to aid in the proper identification of indigo snakes and procedures to follow if an indigo snake is 

encountered. If an eastern indigo snake is encountered, work in the area will be stopped and will not 

recommence until the indigo snake has safely evacuated the area on its own.

On March 29, 2012, EFS’ consultant, Golder Associates (Golder) discussed the following findings of the 

analyses with Dr. Heath Rauschenberger of FWS:

 The proposed project is located within an existing industrial site in Pasco County, Florida.

 Due to the presence of gopher tortoise burrows within the proposed project site (18 

burrows total, of which 14 are potentially occupied), there is a potential for the eastern 

indigo snake to be present. Standard protection measures for the eastern indigo snake 

will be enforced during construction of the proposed project to ensure eastern indigo 

snakes are not harmed.

 The proposed project does not include discharge of heated water.

 No wetlands were identified within the proposed project site. In addition, no dredge or fill 

activities are proposed within wetlands or other surface waters. 

On August 29, 2012, EFS submitted the ecological assessment, Appendix C, to the U.S. Fish and Wildlife 

Service (USFWS). As identified in the email response (Appendix C) from Heath Rauschenberger, PhD, 

dated August 29, 2012, the USFWS has determined that the project is not likely to adversely affect 

federally listed species.

In addition, EFS’ consultant, Golder Associates, contacted Kyle Baker at the National Marine Fisheries 

Service (NMFS) on October 7, 2011, and March 29, 2012. Golder Associates presented to Mr. Baker a 

description of the Project, its location, and the site characteristics, and based on this information, he 

determined that no species regulated by the NMFS will be directly or indirectly affected by the proposed 

project. Therefore, the Project does not meet the threshold for consultation, so no consultation with NMFS 

is required. Correspondence with FWS and NMFS is provided in Appendix D.

1.4 Cultural Resources

Based on Florida Department of State Division of Historical Resources (FDHR) data, there are no 

previously recorded archaeological sites or historic structures within the Project Site. There are two 

resources identified within 0.3 mile north and southeast of the Project Site: Site PA00324 (MATHIS) and 
September 2012 4 103-89556

Site PA00321 (Bell Pond West). Both sites are single artifact or isolated finds that are prehistoric but lack 

pottery. Sites PA00324 and PA00321 are ineligible for listing on the National Register of Historic Places. 

Based on the characteristics of the proposed Project and previous disturbance by the existing power 

plant, Golder anticipates the Project will have no impacts on cultural resources. EFS has submitted to the 

FDHR a cultural resources desktop analysis, Appendix E, requesting FDHR’s concurrence that no 

additional cultural resources investigation is required to demonstrate compliance with Section 106 of the 

National Historic Preservation Act (NHPA).

1.5 Prevention of Significant Deterioration (PSD) Applicability Introduction

On June 3, 2010, the United States Environmental Protection Agency (EPA) published a final rule that 

“tailors” the applicability provisions of the Prevention of Significant Deterioration (PSD) and Title V 

programs to enable EPA and states to phase in permitting requirements for greenhouse gases (GHGs) in 

a common sense manner (“Tailoring Rule”). 75 Fed. Reg. 31514.

For PSD purposes, GHGs are a single air pollutant defined as the aggregate group of the following six 

gases:

 Carbon dioxide (CO2)

 Nitrous oxide (N2O)

 Methane (CH4)

 Hydrofluorocarbons (HFCs)

 Perfluorocarbons (PFCs)

 Sulfur hexafluoride (SF6)

Since January 2, 2011, under federal law these GHGs are a regulated NSR pollutant under the PSD 

major source permitting program when they are emitted by new sources or modifications in amounts that 

meet the Tailoring Rule’s set of applicability thresholds.

The proposed Shady Hills expansion Project is a major modification and subject to PSD review for 

nitrogen oxides (NOx), particulate matter (PM, PM10), carbon monoxide (CO), and GHGs. The Project 

was issued a PSD permit from the FDEP (Permit No. 1010373-012-AC, PSD-FL-402A) on April 6, 2012 

covering NOx, PM, PM10, and CO. As shown in Table 1, the expansion Project will result in an increase 

and a net increase greater than 75,000 TPY CO2e and an increase and a net increase in GHG emissions 

on a mass basis greater than zero TPY. In addition to the CTs, CO2e emissions result from the 

emergency generator, gas heater, circuit breaker, and natural gas pipeline proposed as part of the 

Project. The Project represents new emission units for the facility, and thus the maximum potential 

emissions are utilized for comparison with PSD review thresholds. No offsetting emissions are available 
September 2012 5 103-89556

from other projects within a contemporaneous period with the Project. Therefore no netting analysis is 

provided and the Project triggers PSD review based on the potential emissions from the Project. In light 

of the new Tailoring Rule requirements, the GHGs emitted from the proposed Project are subject to PSD 

review, including a BACT analysis for the GHGs.

EPA Region IV is the permitting authority for the GHG-portion of the proposed Shady Hills expansion 

Project under a Federal Implementation Plan (FIP) that became effective on December 30, 2010. On this 

date, EPA established a FIP authorizing EPA to issue PSD permits in Florida for GHG-emitting sources. 

75 Fed. Reg. 82246 (December 30, 2010). The FIP incorporates the EPA regulations found in 40 CFR 

52.21, including the PSD applicability provisions, but applies only to GHGs. 75 Fed. Reg. 82246, 82250. 

The FIP will remain in effect until Florida submits a corrective State Implementation Plan (SIP) to apply its 

PSD program to sources of GHGs and the SIP is approved by EPA. To date, Florida has not submitted to 

EPA a corrective SIP. Accordingly, this application has been prepared and submitted to EPA Region IV 

pursuant to the FIP, and in accordance with EPA’s guidance document titled “PSD and Title V Permitting 

Guidance for Greenhouse Gases,” March 2011.1

 1 PSD and Title V Permitting Guidance for Greenhouse Gases,” U.S. Environmental Protection Agency, Office of Air Quality 

Planning and Standards, EPA-457/B-11-001, March 2011.
September 2012 6 103-89556

2.0 BEST AVAILABLE CONTROL TECHNOLOGY (BACT) ANALYSIS

This section presents the proposed BACT for the GHGs. The approach to the BACT analysis is based on 

the regulatory definitions of BACT, as well as consideration of EPA’s current policy guidelines requiring a 

“top-down” approach. The CAA and corresponding implementing regulations require that a BACT 

analysis be conducted on a case-by-case basis taking into consideration the amount of emissions 

reductions that each available emissions-reducing technology or technique would achieve, as well as the 

energy, environmental, economic and other costs associated with each technology or technique.

EPA recommends that permitting authorities continue to use the Agency’s five-step “top down” BACT 

process to determine BACT for GHGs. In brief, the top-down process calls for all available control 

technologies for a given pollutant to be identified and ranked in descending order of control effectiveness. 

The permit applicant should first examine the highest-ranked (“top”) option. The top-ranked options 

should be established as BACT unless the permit applicant demonstrates to the satisfaction of the 

permitting authority that technical considerations, or energy, environmental, or economic impacts justify a 

conclusion that the top ranked technology is not “achievable” in that case. If the most effective control 

strategy is eliminated in this fashion, then the next most effective alternative should be evaluated, and so 

on, until an option is selected as BACT. EPA has broken down this analytical process into the following 

five steps:

 Step 1: Identify all available control technologies.

 Step 2: Eliminate technically infeasible options.

 Step 3: Rank remaining control technologies.

 Step 4: Evaluate most effective controls and document results.

 Step 5: Select BACT

The Clean Air Act specifies that BACT cannot be less stringent than any applicable standard of 

performance under the New Source Performance Standards (NSPS). As of August, 2012, EPA has not 

promulgated any NSPS that contain emissions limits for GHGs applicable to simple cycle combustion 

turbines. 

EPA believes that in BACT reviews it is important to consider options that improve the overall energy 

efficiency of the source or modification – through technologies, processes and practices at the emitting 

unit. In general, a more energy efficient technology burns less fuel than a less energy efficient technology 

on a per-unit-of-output basis. Thus, considering the most energy efficient technologies in the BACT 

analysis helps reduce the products of combustion, which include not only GHGs but other regulated NSR 

pollutants (e.g., NOX, SO2, PM/PM10/PM2.5, CO, etc.). Thus, EPA emphasizes that energy efficiency 

should be considered in BACT determinations for all regulated NSR pollutants (not just GHGs). 
September 2012 7 103-89556

The following sections provide the required BACT analysis for each source of GHG emissions. In the 

BACT analysis, GHGs are considered as a single air pollutant, which is the aggregate group of the 

following six gases: CO2, N2O, CH4, HFCs, PFCs, and SF6. Natural gas and distillate fuel oil combustion 

result in GHG emissions of CO2, N2O, and CH4 only. CO2, N2O, and CH4 are the principal GHGs that 

will be emitted at the Shady Hills Generating Station. CO2 emissions will result from the oxidation of 

carbon in the fuel. CH4 emissions will result from incomplete combustion and N2O emissions will result 

primarily from low temperature combustion. The Project’s proposed new circuit breaker and natural gas 

pipeline system might result in additional minor, fugitive releases of GHGs (SF6 and CH4). The facility 

will not use any products containing HFCs or PFCs. 

As described in Section 1.1, combined-cycle combustion turbine configurations do not meet the needs of 

peaking duty service due to their longer duration startup period, resulting in an inability to respond in a 

timeframe sufficient to meet market needs. Although, “fast-start” combined-cycle combustion turbines are 

being marketed, no units have been constructed and operated. In addition the fast start units are typically 

designed with an auxiliary boiler to keep the heat recovery steam generator (HRSG) and steam turbine 

seals and critical equipment at sufficient temperature to facilitate faster startup of the combustion turbine. 

In the “fast-start” unit, the auxiliary boiler would operate when the combustion turbine is down, during 

periods when no electricity is being produced. As such, for peaking duty operation, GHG emissions would 

be potentially generated from the auxiliary boiler a significant portion of the year with no electricity 

generated from the CTs generating units during this period. Furthermore, combined-cycle combustion 

turbine projects also have a high fixed cost profile that is incompatible with the expected low utilization of 

a peaking facility (as defined by the limit on annual operating hours). For the above reasons and those 

described in Section 1.1, consideration of combined-cycle combustion turbine configurations is 

considered “redefining the source,” and therefore not considered in this New Source Review evaluation.

2.1 Simple Cycle CTs

This section contains the BACT analysis for the GHG emissions from the proposed simple cycle CTs. 

2.1.1 Step 1 – Identify All Available Control Technologies

The first step in the top-down BACT process is to identify all “available” control options. Available control 

options are those air pollution control technologies or techniques (including lower-emitting processes and 

practices) that have the potential for practical application to the emissions unit and the regulated pollutant

under evaluation.

EPA has placed potentially applicable control alternatives identified and evaluated in the BACT analysis 

into the following three categories:
September 2012 8 103-89556

 Inherently Lower-Emitting Processes/Practices/Designs,

 Add-on Controls, and

 Combinations of Inherently Lower Emitting Processes/Practices/Designs and Add-on 

Controls.

EPA recommends that the BACT analysis should consider potentially applicable control techniques from 

all of the above three categories, and permit applicants and permitting authorities identify all “available” 

GHG control options that have the potential for practical application to the source under consideration. 

Control technologies considered (and discussed below) include clean fuel, energy efficiency, and carbon 

capture and storage (CCS). 

2.1.1.1 Clean Fuel 

The definition of BACT in 40 CFR 52.21(b)(12) includes use of clean fuels as a pollution control 

technique. The PSD and the Title V Permitting Guidance for GHGs states that clean fuels which would 

reduce GHG emissions should be considered while recognizing at the same time that the BACT analysis 

does not need to include a clean fuel option that would fundamentally redefine the source.2

 The 

proposed CTs at the Shady Hills Generating Station will be fired primarily with natural gas. Ultra low 

sulfur diesel fuel oil (ULSDO) will be limited to a maximum of 750 hrs/yr per CT if one CT is constructed 

and an aggregate of 1,000 hours if both CTs are constructed. The combustion of natural gas emits about 

30 percent less CO2 than oil, and just under 45 percent less CO2 than coal (40 CFR 75 Appendix G, and 

40 CFR 98 Tables C-1 and C-2). Therefore, the proposed CTs will be fired with “clean fuels” as included 

in the definition for BACT in the CAA Section 169(3).

2.1.1.2 Energy Efficiency

In the PSD and Title V Permitting Guidance for GHGs, EPA emphasizes two mitigation approaches for 

CO2 – energy efficiency and carbon capture and storage (CCS).3

 The first of these, energy efficiency, 

falls under the general category of lower-polluting processes/practices. Applying technologies, measures 

and options that are energy efficient translates not only to the reduction of emissions of the particular 

regulated NSR air pollutant undergoing BACT review, but it also may achieve collateral reductions of 

emissions of other pollutants. There are two different categories of energy efficient improvements:

 Technologies or processes that maximize the efficiency of the individual emissions unit.

 Options that could reduce emissions from a new green field facility by improving the 

utilization of thermal energy and electricity that is generated and used on site. 

 2 PSD and Title V Permitting Guidance for Greenhouse Gases,” U.S. Environmental Protection Agency, Office of Air Quality 

Planning and Standards, EPA-457/B-11-001, March 2011.

3 Id.
September 2012 9 103-89556

When the efficiency of the power generation process is increased, less fuel is burned to produce the 

same amount of electricity. This provides the benefits of lower fuel costs and reduced air pollutant 

emissions (including CO2 on a lb/MWhr basis). Efficient power generation as a method of minimizing 

GHG emissions is considered to be an available technology for the proposed CTs at the Shady Hills 

Generating Station. 

2.1.1.3 Carbon Capture and Storage (CCS)

CCS falls under the category of add-on controls, which are air pollution control technologies that remove 

pollutants from a facility’s emissions stream. As identified in EPA’s, “PSD and Title V Permitting 

Guidance for Greenhouse Gases,” March 2011, EPA classifies CCS as an add-on pollution control 

technology that is “available” for large CO2-emitting facilities including fossil fuel-fired power plants and 

industrial facilities with high-purity CO2 streams. As a result, EPA requires that CCS be considered in 

Step 1 of the BACT analysis. 

CCS is composed of three main components: CO2 capture and/or compression, transport, and long-term, 

perpetual storage. 

Carbon Capture - Before CO2 gas can feasibly be stored, it must be captured as a relatively pure gas. 

Most power plants and other large point sources use air-fired combustors, a process that exhausts CO2

diluted with nitrogen. According to the US Department of Energy, flue gas from the combustion of fossil 

fuels contains approximately 5 – 15 percent CO2.4 For effective carbon sequestration, the CO2 in these 

exhaust gases must be separated and concentrated.

According to the Department of Energy’s National Energy Technology Laboratory (NETL), technologies 

for capturing CO2 from relatively dilute streams such as those produced by power generation facilities are 

less common. These technologies currently include amine and chilled ammonia solvent systems, which 

have been used with coal-based power plant applications.5

The Carbon Sequestration Leadership Forum (CSLF), a ministerial-level international climate change 

initiative comprised of 24 member nations representing over 60% of the world’s population, states:

“Evolutionary improvements in existing CO2 capture systems and revolutionary new capture and 

sequestration concepts will be needed to bring carbon capture costs down. The most likely options 

currently identifiable for CO2 separation and capture include the following:

• Absorption (chemical and physical) 

• Adsorption (physical and chemical) 

• Low-temperature distillation 
September 2012 10 103-89556

• Gas separation membranes 

• Mineralization and bio-mineralization. “ 5

Carbon Transport – After the CO2 is captured, it must be transported to a carbon sequestration site. 

Pipelines are the most common method for transporting large quantities of CO2 over long distances. 

Shipping CO2 via pipeline involves compressing gaseous CO2 to a pressure above 1,160 pounds per 

square inch (psi), to increase CO2 density and make it easier and less expensive to ship. A CO2 pipeline 

would be similar to a high pressure natural gas pipeline and is available. CO2 also can be transported as 

a liquid in seagoing vessels or via tankers on roads or railways. In these instances, the CO2 is held in 

insulated tanks at low temperatures and relatively low pressures.

Carbon Storage – In a CCS system, CO2 is captured, it is transported, if necessary, and then stored. 

Geologic formations such as depleted oil and gas reservoirs, unmineable coal seams, and underground 

saline formations are potential options for long-term storage. Pressurized CO2 is injected into the deep 

geologic formations through drilled wells. Under high pressure, CO2 turns to liquid and can move through 

a formation as a fluid. Once injected, the liquid CO2 tends to be buoyant and will flow upward until it 

encounters a barrier of non-porous rock, which can trap the CO2 and prevent further upward migration. 

When CO2 is injected into a coal seam, it is adsorbed onto the coal surfaces, and methane gas is 

potentially released and produced in adjacent wells. This technology is available. There are other 

mechanisms for CO2 trapping as well: CO2 molecules can dissolve in brine, react with minerals to form 

solid carbonates, or adsorb in the pores of porous rock.

Deep saline formations, which are layers of porous rock saturated with brine present an enormous 

potential for geologic storage of CO2. There is ongoing research focused on storage in organic rich 

shale, which is a thin horizontal layer of sedimentary rock with low vertical permeability and in basalt 

formations, which are geologic formations of solidified lava. Other possible options include liquid storage 

in the ocean.

2.1.2 Step 2 – Identification of Technically Feasible Control Alternatives

Under the second step of the top-down BACT analysis, all available control techniques listed in Step 1 

may be eliminated from further consideration if they are not technically feasible for the specific source and 

unit under review. EPA considers a technology to be technically feasible if it has been demonstrated and 

operated successfully on the same type of source under review, or it is available and applicable to the 

source type under review. Step 2 takes into consideration technical difficulties that would preclude 

successful use of the control option on the emissions unit under review taking into account sourcespecific and unit-specific factors (considering physical, chemical, and engineering principles). 
September 2012 11 103-89556

2.1.2.1 Clean Fuels 

The proposed CTs at the Shady Hills Generating Station will be fired primarily with natural gas. ULSDO 

will be limited to a maximum of 750 hrs/yr if one CT is constructed and an aggregate of 1,000 hours if 

both CTs are constructed. Therefore, the proposed CTs will be fired with “clean fuels” as included in the 

definition for BACT in the CAA Section 169(3).

The need for fuel oil as a backup fuel is driven by fuel supply reliability considerations. The Project will 

negotiate a tolling agreement(s) with utility offtaker(s) whereby the offtaker(s) will provide all the fuel for 

the units. The offtaker(s) will also control when and for how long the units are dispatched and what fuel 

will be used to generate power in order to meet the electricity demands of its customers. It is the Project

owner’s understanding that for a peaking plant, the offtaker(s) will not dedicate firm natural gas 

transportation to the Project, and instead, will operate the units on natural gas when interruptible natural 

gas transportation service is available. In the event that interruptible natural gas transportation is not 

available and customer load demand is high, the offtaker(s) would likely dispatch the units on fuel 

oil. Therefore, the Project needs the flexibility to use ULSDO as directed by the offtakers.

2.1.2.2 Energy Efficiency

Efficient power generation is considered to be technically feasible for the proposed CTs at the Shady Hills 

Generating Station. The proposed GE 7FA.05 CT is the latest version of 7FA CT and the output per unit 

of fuel combusted is higher than the 7FA.03 or the 7FA.04. Therefore, the proposed CTs provide the 

highest level of energy efficiency available for GE Frame 7 simple cycle CT operation. The GE Frame 7 

turbine was analyzed as a surrogate for the performance of similar F class turbines as discussed in 

Section 1.1. Attachment H, Table 5-3, of Puget Sound Energy’s PSD Permit Application for Fredonia 

Generating Station Expansion Project, Mount Vernon, Washington, February 2011, provides a 

comparison of other vendor “F-class” CTs and demonstrates that efficiencies are essentially the same as 

the Proposed GE 7FA.05 units (within one percent).4

 

The Project is proposed to operate in response to peaking duty requirements of the Florida market. 

Multiple simple cycle technologies are available to meet this basic purpose, including both heavy duty 

industrial and aeroderivative designs. For the Project, GE evaluated the 7FA.05, LM6000, and LMS100 

simple cycle gas turbine technologies. Smaller F-class simple-cycle turbines than the 7FA.05, such as 

the GE Frame 6FA rated at 77 MWs, are available, but are not as economic as the 7FA.05 based on 

installed capital costs and lower efficiency, and would not yield as much output on the site as the 7FA.05. 

 4 Attachment H of the PSD permit application for the Puget Sound Energy Fredonia Generating Station Expansion Project near 

Mount Vernon, Washington, can be found at the State of Washington’s Department of Ecology website: 

http://www.ecy.wa.gov/programs/air/psd/psd_permits_recd.htm (last visited Sept. 13, 2012).
September 2012 12 103-89556

Smaller sized aeroderivative class turbines are available, but do not meet the objective to maximize site 

output at lowest overall cost. 

The LMS100 is representative of the class of the 100 MW aeroderivative CTs for the Project’s evaluation. 

The purpose of the Project is to provide peaking duty service with dual fuel capability, and a water source 

will be required for NOx emission control on the LMS100 even during primary fuel operation on natural 

gas. Additionally, the LMS100 requires inter-cooling which can be achieved through water or air cooling. 

Water for cooling and emissions control results in additional environmental impacts associated with water 

withdrawal and discharge. Currently, there are no arrangements in place for additional water supplies to 

meet operational or emission control requirements for the LMS100 CT units at the Shady Hills Generating 

Station. The two new proposed GE Frame 7FA.05 simple cycle units will require the use of up to 

approximately 35,000 gallons per day (GPD) of water when operating on natural gas primary fuel, and 

approximately 165,000 GPD of water on an annual average daily basis (both natural gas primary fuel 

operation and back-up fuel operations). In comparison, four GE LMS100’s (400 MW) would require 

approx. 325,000 GPD of water when operating on natural gas primary fuel, and approximately 330,000 

GPD on water on an annual average daily basis (including both natural gas primary fuel operation and 

back-up fuel operations). Reclaimed water and surface water are not expected to be available to supply 

this water need. Therefore, this need would very likely have to be met by using new quantities of 

groundwater. A portion of these water requirements may be able to be supplied through the existing 

water use permit for the Shady Hills site on an as-available basis (i.e., existing project would maintain 

priority rights). A new water use permit for any incremental increase in water usage may be required. If a 

new water use permit is required, EFS will need to demonstrate that the increased water withdrawal does 

not create new groundwater impacts.

The Shady Hills site is located in Pasco, County Florida. Pasco County lies within the territory of the 

Southwest Florida Water Management District (SWFWMD) which regulates the use of water. See 

sections 373.069 and Part II, Chapter 373, F.S. The SWFWMD requires that a water use permit be 

obtained for a new groundwater withdrawal if the proposed groundwater withdrawal will be greater than 

100,000 GPD on an average daily basis. Rule 40D-2.041(1)(b), F.A.C. The SWFWMD has adopted 

permitting criteria that must be met to obtain a WUP. Rule 40D-2.301, F.A.C. These criteria include a 

showing that it is not technically, environmentally, or economically feasible to use an alternative water 

supply which includes the reuse of reclaimed water. (See section 3.0, Basis of Review for Water Use 

Permits). In addition, the user must demonstrate that the proposed groundwater use will not cause 

environmental harm to wetlands and other surface water bodies. (See generally section 4.0, Basis of 

Review for Water Use Permits).

 
September 2012 13 103-89556

Pasco County also lies within the Northern Tampa Bay Water Use Caution Area designated by 

SWFWMD. Rule 40D-2.801(3)(a)1., F.A.C. Within the Northern Tampa Bay Water Use Caution Area, the 

SWFWMD has adopted additional rules establishing minimum water levels or minimum flows for certain 

surface water bodies. Chapter 40D-8, F.A.C. If a waterbody is at or above its established minimum flow 

or level, then the rules provide that the proposed groundwater use cannot cause the waterbody to drop 

below that establish minimum flow or level. Section 4.3.A., Basis of Review for Water Use Permit 

Applications adopted by reference in Rule 40D-2.091, F.A.C.. The rules require the proposed 

groundwater user to propose prevention measures, such as an environmental management plan or 

hydration, to ensure that the long-term aquifer level does not drop further. Section 4.3.1.A1., Basis of 

Review for Water Use Permit Applications, adopted by reference in Rule 40D-2.091, F.A.C. If a 

waterbody is below a minimum flow or level and a new groundwater withdrawal will impact that 

waterbody, the rules provide that the SWFWMD will generally not approve the new groundwater 

withdrawal. Section 4.3.1.A.(1) b., Basis of Review for Water Use Permit Applications, adopted by 

reference in Rule 40D-2.091, F.A.C. 

While specific hydrologic or engineering analysis would be needed to evaluate any new groundwater use 

proposal for its impacts on water bodies, in general a large new groundwater use in Pasco County is likely 

to impact a water body that is below the established minimum flow and level making it much more likely 

that SWFWMD would issue a water use permit for the 7FA.05 given its relatively small incremental water 

requirement as compared to the needs of the LMS100.

As stated previously, the heavy duty industrial 7FA.05 CT units maximize output for peaking duty service 

within the existing Shady Hills Generating Station site boundary and constraints. To achieve the 

equivalent generation capacity with aeroderivative CTs like LMS100 units would require additional water 

resources. Nonetheless, we have included the LMS100 aeroderivative gas turbines as available 

technology in the cost-effectiveness evaluation even though the units are not considered technically 

feasible. 

2.1.2.3 Carbon Capture and Storage (CCS)

In the preamble to EPA’s recently proposed “Standards of Performance for Greenhouse Gas Emissions 

for New Stationary Sources: Electric Utility Generating Units,” (77 Fed. Reg. 22,392, 22,414 (April 13, 

2012)), EPA states that “CCS is a feasible technology option for new coal-fired power plants because 

CCS is technically feasible and sufficiently available in light of the limited amount of new coal-fired 

construction expected in the foreseeable future.” This Federal Register notice did not state that CCS was 

a feasible technology for simple cycle combustion turbines, however. Also, EPA stated in the PSD and 

Title V permitting guidance for GHGs that it does not believe CCS will be a technically feasible BACT 
September 2012 14 103-89556

option in certain cases at this time.5 To establish that an option is technically feasible, the permitting 

record should show either that an available control option has been demonstrated in practice or is 

available and applicable, with the term “applicable” generally meaning a technology can reasonably be 

installed and operated on the source type under consideration. EPA recognizes the significant logistical 

hurdles that the installation and operation of a CCS system presents and that sets it apart from other addon controls that are typically used to reduce emissions of other regulated pollutants and already have an 

existing reasonably accessible infrastructure in place to address waste disposal and other offsite needs. 

It should also be noted that while CCS may be available as identified in EPA’s PSD and Title V Permitting 

Guidance for Greenhouse Gases, March, 20116

, there are no CCS systems commercially demonstrated 

and available for full-scale power plants in the United States, for either coal-fired boilers or gas-fired 

combustion turbines. 

On February 3, 2010, President Obama established an Interagency Task Force on Carbon Capture and 

Storage, composed of 14 Executive Departments and Federal Agencies. The Task Force, co-chaired by 

the Department of Energy (DOE) and the EPA, was charged with proposing a comprehensive and 

coordinated strategy to overcome the barriers to the widespread, cost-effective deployment of CCS within 

ten years, with a goal of bringing five to ten commercial demonstration projects online by 2016. These 

projects, to be deployed with the help of federal funding, are intended to demonstrate a range of current 

generation CCS technologies applied to coal-fired power plants and industrial facilities. Some of these 

projects are underway, as noted in EPA’s recent April 13, 2012, Federal Register notice for the proposed 

GHG emission standards for utility units, but none of these projects is in full-scale commercial operation. 

The Florida Energy Systems Consortium (FESC) was created by the Florida state government to promote 

collaboration among the energy experts at its 11 supported universities to share energy-related expertise. 

The consortium assists the state in the development and implementation of an environmentally 

compatible, sustainable, and efficient energy strategic plan. FESC has performed a preliminary evaluation 

of carbon sequestration reservoirs in the state of Florida. Florida has deep saline formations near the 

facility location which represent a potential for CO2 geologic storage. FESC research on Florida carbon 

sequestration reservoirs is discussed in “Potential for carbon dioxide sequestration in the Lower 

Cretaceous Sunniland Formation within the Sunniland Trend of the South Florida Basin, U.S.” by Tina 

Roberts-Ashby and Mark Stewart, Department of Geology, University of South Florida, published in 

International Journal of Greenhouse Gas Control 6 (2012) 113 125. As discussed by Tina Roberts-Ashby 

and Mark Stewart:

 5 “PSD and Title V Permitting Guidance for Greenhouse Gases,” U.S. Environmental Protection Agency, Office of Air Quality 

Planning and Standards, EPA-457/B-11-001, March 2011.

6 Id. 
September 2012 15 103-89556

“The Sunniland Trend (Trend) in south Florida is an arcuate trend about 235 kilometers long by 30 

kilometers wide that has supported oil production from the Sunniland Formation for over 60 years. The 

individual oil fields within the Trend have average porosities that range 15–18%, and have the potential to 

serve as carbon dioxide (CO2) sequestration reservoirs due to their high porosity and proven ability to 

trap hydrocarbons for millennia. In addition, the non-oil-bearing porous intervals of the Sunniland 

Formation along the Trend have relatively high porosities as well, with an average porosity range of 10–

20%. All of the porous intervals in the Sunniland Formation within the extent of the Trend, including the 

oil-bearing intervals, have the potential to store 1.2 billion tons of CO2, which could potentially support 

CO2 sequestration for multiple large-scale power plants in the southeastern United States for their entire 

40-year lifespan. The Sunniland Formation is an example of the large CO2 storage capacities that are 

potentially available in depleted oil and gas basins if all porous units, including those which are non-oil 

bearing, are considered for storage.”

The following figure is taken from FESC’s 2011 Annual Report and shows the potential carbon 

sequestration potential in south Florida. The study area does not include the Shady Hills project site in 

Pasco County. However, Pasco County is the county adjacent to the northeast corner of the study area, 

and as such demonstrates carbon sequestration potential nearby the Project site. 
September 2012 16 103-89556
September 2012 17 103-89556

In addition to the evaluation of carbon sequestration reservoirs, FESC has been in collaboration with 

Tampa Electric Company, DOE and RTI International to develop a pilot project to demonstrate technology 

for the removal of sulfur and the capture of CO2 from the Tampa Electric Polk Power Station’s 250-

megawatt integrated gasification combined cycle (IGCC) unit. The latest publically available information 

indicates that the project is designed to capture CO2 from a 30 percent side stream of the coal-fired 

plant’s syngas. The syngas, a synthetic gas generated by the gasification of coal and petroleum coke, is 

used as a fuel in the plant’s combustion turbine to create electricity. 

Although Tampa Electric has been involved with the development of a pilot scale project, which to date 

has not been implemented, this does not establish the technology as commercially available for the 

Shady Hills project. The application of CCS to simple-cycle combustion turbine power plants has not been 

commercially demonstrated. Although research has been completed indicating the potential for carbon 

sequestration in Florida nearby the project site, the suitability of these saline formations for CO2 storage 

has not been demonstrated and is uncertain, and therefore the estimated storage costs are unpredictable. 

In addition, logistical hurdles for CCS for a particular project may also include obtaining contracts for 

offsite land acquisition (including the availability of land), the need for funding (including, for example, 

government subsidies), liability protections, timing of available transportation infrastructure, and 

developing a site for secure, long-term storage. The resources needed to overcome the offsite logistical 

barriers necessary to apply CCS technology to its operations would make this Project economically 

unviable and it would not be constructed.

EPA considers a technology to be technically feasible if it has been demonstrated in practice or is 

available and applicable. While CCS technology is available, there are no known applications to simple 

cycle CTs and there is uncertainty of the location of available and acceptable geologic formations for the 

long-term CO2 storage. Even if the type of equipment needed to accomplish the compression, capture, 

and storage of CO2 are determined to be generally available from commercial vendors, the CCS 

technology has not been demonstrated on simple-cycle CT projects and is not technically feasible for this 

project. Nevertheless, CCS will be included in the analysis and proven not to be cost-effective. 

2.1.3 Step 3 – Rank Remaining Control Technologies

After the list of all available controls is narrowed down to a list of the technically feasible control 

technologies in Step 2, Step 3 of the top-down BACT process calls for the remaining control technologies 

to be listed in order of overall control effectiveness for the regulated NSR pollutant under review. The 

most effective control alternative (i.e., the option that achieves the lowest emissions level) should be listed 

at the top and the remaining technologies ranked in descending order of control effectiveness. Of the 

three potential control technologies, CCS, clean fuels, and energy efficiency are technically feasible 

technologies. Of these technically feasible technologies, CCS followed by the selection of natural gas as 
September 2012 18 103-89556

the primary fuel offers the highest pollutant control effectiveness, followed by energy efficiency. Selection 

of the GE 7FA.05 results in a 0.5% increase in thermal efficiency compared to the GE 7FA.04, and a 

2.3% increase in thermal efficiency compared to the GE 7FA.03 as shown in the following graph from 

GE. 7

 7 GE, “The 7FA Gas Turbine A Classic Reimagined,” GE Gas Turbine Technology Symposium, Greenville, SC. October, 2009.
September 2012 19 103-89556

2.1.4 Step 4 - Economic, Energy, and Environmental Impacts

Under Step 4 of the top-down BACT analysis, economic, energy, and environmental impacts must be 

evaluated for each option remaining under consideration.

The “top” control option should be established as BACT unless the applicant demonstrates, and the 

permitting authority agrees, that the energy, environmental, or economic impacts justify a conclusion that 

the most stringent technology is not “achievable” in that case. If the most stringent technology is 

eliminated in this fashion, then the next most stringent alternative is considered, and so on.

Where GHG control strategies affect emissions of other regulated pollutants, EPA recommends that 

applicants should consider the potential trade-offs between emissions of GHGs and emissions of other 

regulated NSR pollutants. 

2.1.4.1 CCS

Although CCS is not considered demonstrated on simple cycle CT projects nor technically feasible for the 

Shady Hills expansion Project, the following discussion of technology costs is provided. 

Currently there are no commercial-scale power plants that employ CCS in the US; however, several 

demonstration projects are underway or planned. The costs associated with CCS include: separation, 

transportation, and injection and long-term storage. Site specific parameters impact the cost of CCS 

including: 

 The choice of technology and design for separation, compression and injection; and

 The distance, terrain, and permitting factors involved with CO2 transport;

The Harvard Kennedy School has prepared a study of the potential costs of CCS, “Realistic Costs of 

Carbon Capture,” July 2009.8

 As provided in Annex C of the Harvard Kennedy School study, for natural 

gas combined cycle combustion turbines the range of avoided cost in $ per metric ton of CO2 separated 

is from $63 to $83 equivalent to $70 to $93 short tons of CO2 separated, based on 2 advanced F class 

turbines. Based on a cost of $70 per short ton of CO2, and an estimated annual CO2 rate of 833,796

short tons from the CTs, the annual cost for separation alone would be approximately $58,450,000. 

Additionally per footnote of Annex C, this cost does not include costs associated with transportation and 

injection and storage. The total capital cost of the Project is projected to be ~$250,000,000. The annual 

cost associated with capture of CO2 is estimated to be greater than 23% of the total capital cost of the 

Project. Given the costs to remove the CO2, the overall costs of CCS (which would include transportation, 

 8 Al-Juaied, Mohammed and Adam Whitmore, “Realistic Costs of Carbon Capture.” Discussion Paper 2009-08, Energy Technology 

Innovation Research Group, Belfer Center for Science and International Affairs, Harvard Kennedy School, July 2009.
September 2012 20 103-89556

injection, and permanent storage), and the costs of CCS relative to the Project costs, CCS is prohibitively 

expensive and not considered cost effective for the Project.

2.1.4.1 Clean Fuels

The proposed CTs at the Shady Hills Generating Station will be fired primarily with natural gas. ULSDO 

will be used as a secondary fuel and will be limited to a maximum of 750 hrs/yr if one CT is constructed 

and an aggregate of 1,000 hrs/yr if two CTs are constructed. The definition of BACT in 40 CFR 

52.21(b)(12) includes use of clean fuels as a pollution control technique. The PSD and the Title V 

Permitting Guidance for GHGs9 states that clean fuels which would reduce GHG emissions should be 

considered while recognizing at the same time that the BACT analysis does not need to include a clean 

fuel option that would fundamentally redefine the source. Therefore, the proposed simple cycle CTs will 

be fired with “clean fuels” as included in the definition for BACT in the CAA Section 169(3).

2.1.4.2 Energy Efficiency

The simple cycle CTs will reflect the newest generation of turbines, GE 7FA.05. The GE 7FA.05 provides 

increased output, 218 MW per CT with a heat input rate of 1,923 mmBtu/hour (LHV, natural gas firing, 

100 percent load, 59F) (and 2,117 mmBtu/hour ULSDO firing, LHV, 100 percent load, 59F). The GE 

7FA.05 represents the state of the art combustion turbine technology.

As discussed in Section 2.1.2.2, GE evaluated the 7FA.05, LM6000, and LMS100 simple cycle gas 

turbine technologies. The LMS100 technology is available but is not technically feasible for the Shady 

Hills Project based on the significant process water requirements and uncertainty of availability of such 

water resources, as more fully described in Section 2.1.2.2. Nevertheless, EFS is submitting Tables 2 and 

2a which present comparison of the cost-effectiveness of GHG emissions reduction for the three types of 

units evaluated and demonstrates that the 7FA.05 is the most cost-effective unit for the Project. Table 2 

provides a comparison to the Project CTs if 2 units are installed for a total of 425 MW from 2 7FA.05 CTs. 

Table 2a provides a comparison if only one unit is installed, 213 MW from one 7FA.05 CT. The 

operational difference of these two scenarios is that ULSDO will be limited to a maximum of 750 hrs/yr if 

one CT is constructed and an aggregate of 1,000 hours if both CTs are constructed. The costeffectiveness analysis assumes maximum annual permitted operating hours, and calculates the 

incremental cost, including both capital and operating costs associated with achieving incremental CO2

emission reduction from the LM6000 and LMS100 technologies in terms of $/ton of CO2 avoided. As 

shown in Tables 2 and 2a, the installation of 10 LM6000 CTs and 4 LMS100 CTs needed to produce the 

same generation as the Project’s proposed 2 7FA.05 CTs would result in a minimum of $286 and $60 per 

 9 “PSD and Title V Permitting Guidance for Greenhouse Gases,” U.S. Environmental Protection Agency, Office of Air Quality 

Planning and Standards, EPA-457/B-11-001, March 2011.
September 2012 21 103-89556

ton CO2e reduced, respectively under the best operating scenario. Therefore, the LM6000 and LMS100 

are not cost-effective for the Project.

Smaller aeroderivative CTs are available in units up to 100 MW per CT. However, the use of these CTs, 

if feasible, would result in increased uncontrolled emissions of NOx and CO compared to the proposed 

Project potentially resulting in selective catalytic reduction (SCR) and oxidation catalyst pollution control 

technology being required. The emission guarantees of NOx and CO for the aeroderivative CTs without 

add-on controls are higher than for the 7FA.05 CTs, as shown in the following comparison of emission 

concentrations per CT:

Combustion Turbine NOx (ppmvd @15% O2) CO (ppmvd @ 15% O2)

Proposed 7FA.05 CT 9 9

Aeroderivative CTs (35 – 100 MW) 15 – 25 25

Smaller aeroderivative CTs in the range of 35 – 65 MW are available. However, these CTs have NOx 

emissions guarantees of 15 ppmvd @15% O2 and CO emissions guaranteed at levels equal to 25 ppmvd 

@15% O2 with the use of dry low NOx technology. To achieve the same emission levels for NOx and CO 

as the proposed 7FA.05 CTs, additional pollution controls to reduce NOx and CO would be needed, e.g., 

SCR and oxidation catalyst. For this Project, compared to the proposed Frame 7FA.05 CTs, smaller CTs 

in this range would result in higher operating costs associated with operation and maintenance, ammonia, 

catalyst replacement, and lost energy through parasitic load from the SCR (backpressure and operational 

electrical demand of process equipment). SCR would result in additional environmental impact as a 

result of emissions of NH4 in the form of catalyst slip. Assuming typical vendor guarantees of 9 ppm NH4

slip, and based on exhaust mass flow rates of 1,142,125 and 1,690,750 lb/hr for the LM6000 and 

LMS100, respectively, the estimated NH4 emissions are 6.24 and 9.24 lb/hr, respectively per CT (ten 

LM6000’s and four LMS100’s). This would result in additional environmental impacts of 63 to 84 tons per 

year of NH4 emissions and impacts that would not otherwise occur with use of the proposed GE 7FA.05 

CTs. 

The use of a CO oxidation catalyst would also result in higher operating costs associated with operation 

and maintenance, catalyst replacement, and lost energy through parasitic load, and would convert the CO 

emissions to CO2, resulting in a negligible environmental benefit. Although aeroderivative CTs of this 

size would result in higher operating costs and add additional environmental impacts of other pollutants 

while resulting in no significant benefit in CO2e reduction, the LM6000 was evaluated as a representative 

smaller aeroderivative CT. In fact, Attachment H, Table 5-3, of Puget Sound Energy’s PSD Permit 
September 2012 22 103-89556

Application for Fredonia Generating Station Expansion Project, Mount Vernon, Washington, February 

2011, demonstrates that the LM6000 is the most efficient areoderivative CT that is technically feasible for 

the Project.10 However, as noted above, there are significant additional environmental impacts 

associated with smaller CTs compared to the GE 7FA.05 CTs.

An important measure of the efficiency, for an electrical generating facility, is the unit’s heat rate. Heat 

rate is a measurement of how efficiently a generator uses heat energy. It is expressed as the number of 

Btu’s of heat required to produce a kilowatt-hour of energy. A heat rate of 3,412 Btu/kW-hr reflects a 

conversion efficiency of 100 percent from thermal energy to electrical energy. The proposed simple cycle 

CTs’ heat rate and energy efficiency were compared to data obtained from the U.S. Energy Information 

Administration (US EIA). Based on data provided in the Annual Energy Review 2010, the average heat 

rate for fossil-fueled power plants in the U.S. in 2010 was 9,760 Btu/kW-hr [LHV] (35.0 percent 

efficiency).11 The proposed CTs are estimated to be greater than 38 percent efficient. The heat rate for 

the proposed CTs for gas firing only is 8,826 Btu/kW-hr (LHV, 100 percent load at 59F) (38.7 percent 

efficiency) and 9,509 Btu/kW-hr (LHV, 100 percent load at 59F) (35.9 percent efficiency) for fuel oil firing 

which is limited to 750 hours per year per CT if one unit is constructed and a total of 1,000 hours per year 

if both CTs are constructed. The overall heat rate based on a total of 3,390 hours per year of operation 

with 500 of the total hours on fuel oil is equal to 8,926 Btu/kW-hr (LHV, 100 percent load at 59F) (38.2 

percent efficiency, two unit average). The proposed heat rate is well below (i.e., more efficient than) the 

average fossil-fuel power plants based on US EIA’s Annual Energy Review 2010 for the electric power 

industry described above.

2.1.5 Step 5 - Selection the BACT

In Step 5 of the BACT determination process, the most effective control option not eliminated in Step 4 

should be selected as BACT for the pollutant and emissions unit under review and included in the permit.

The Project will utilize clean fuels and the newest generation of turbines, GE 7FA.05, with an estimated 

thermal energy efficiency of greater than 38%, which represents the highest level of efficiency currently 

available for GE Frame 7F turbines. 

2.1.5.1 BACT Emission Limits

The fuel utilized determines the amount of GHG emissions per unit of energy. For example, based on 40 

CFR Part 75, Appendix G emission factors, the emission factors for CO2 are about 119 lb CO2/MMBtu for 

 10 Attachment H of the PSD permit application for the Puget Sound Energy Fredonia Generating Station Expansion Project near 

Mount Vernon, Washington, can be found at the State of Washington’s Department of Ecology website: 

http://www.ecy.wa.gov/programs/air/psd/psd_permits_recd.htm (last visited June 25, 2012). 11 “Annual Energy Review 2010,” U.S. Energy Information Administration, DOE/EIA-0384 (2010), October 19, 2011, Table A6, 

http://www.eia.doe.gov/emeu/aer/txt/ptb1306.html. 
September 2012 23 103-89556

natural gas and 163 lb CO2/MMBtu for distillate oil. Table 3 provides CO2e emission calculations for 

100% and 50% load at ISO Conditions (59 deg. F, 60% relative humidity) for both natural gas and fuel oil 

firing. In addition, Table 3 presents GHG emissions in units of mass/MWh, which is a measure of GHG 

emissions per unit energy output. The total carbon dioxide equivalent (CO2e) emissions take into 

account the global warming potential for each pollutant as prescribed under 40 CFR Part 98 and the 

Tailoring Rule, 40 CFR 52.21. 

Due to the nature of the proposed CTs’ peaking duty service described previously and associated 

operational variability, EFS is proposing separate CO2e emissions BACT Limits for “normal operation” 

and for “startup/shutdown events” for each fuel. The proposed CO2e emissions BACT Limits for the CTs, 

in units of lb/MWh, are estimated based on projected operation on natural gas and fuel oil at 100% and 

50% load (ISO Conditions). As explained in more detail in Table 3, the proposed BACT CO2e emission 

limits for natural gas and fuel oil “normal” operation on the CTs are as follows:

Normal Operation Limits:

• Natural Gas: average of 1,377 lb CO2e per MWh (HHV, Gross Output, ISO Conditions) on a 

12-month rolling average basis, during normal operation while firing natural gas. Gross

output is proposed so that the evaluation of BACT for the CT is performed on a unit specific 

basis without consideration of ancillary facility equipment and parasitic load. 

• Fuel Oil: average of 1,928 lb CO2e per MWh (HHV, Gross Output, ISO Conditions) on a 12-

month rolling average basis, during normal operation while firing fuel oil. 

Criteria for valid hours during normal operation:

For each fuel, a new 12-month rolling average value is calculated each calendar month after the 

1st year of operation based on the total fuel fired, during normal operation, during the prior 12 

calendar months. Valid data shall be any fuel firing during periods of normal operation. Normal 

operation is achieved when the CT reaches 50% load or greater. 

The proposed limits consider (a) operation across the range from 50 percent to 100 percent load, which is 

important for flexible, quick-starting resources under a utilities dispatch control; (b) design standards 

typical of construction contracts and equipment manufacturer’s supply contracts, which contain 

commercial terms for minimum performance test acceptance criteria; (c) typical performance degradation 

of combustion turbines between major overhauls even with implementation of best maintenance 

practices; and (d) typical performance degradation over the life of the equipment. Specifically, to account 

for the above considerations, the proposed limits incorporate a 5.0 percent design margin and a 3.0 
September 2012 24 103-89556

percent turbine performance degradation margin between major overhauls and over the life of the 

equipment as reflected in Table 3. 

Startup and shutdown BACT emission limitations are proposed as follows: 

Startup and Shutdown Limits:

• Natural Gas: 21 short tons CO2e per Startup and Shutdown event while firing natural gas, 

based on an average of all startup and shutdown events occurring during natural gas firing 

over the past 12 consecutive calendar months.

• Fuel Oil: 28 short tons CO2e per Startup and Shutdown event while firing fuel oil, based on 

an average of all startup and shutdown events occurring during fuel oil firing over the past 12 

consecutive calendar months.

Criteria for valid minutes during startup and shutdown: 

For each fuel, a new startup and shutdown CO2e 12-month average is calculated each calendar 

month based on the summation of fuel consumption during all startup and shutdown events 

during the prior 12 consecutive calendar months divided by the number of startup events in the 

12-month period. Fuel flow meter data shall be used to determine emissions during startup and 

shutdown events. Startup is defined to begin on the minute when fuel is first ignited in the CT 

and terminates on the minute when the CT reaches 50 percent load. Shutdown occurs on the 

minute when the CT load is less than 50 percent load until the minute that fuel flow to the CT 

stops. “Valid data during startup or shutdown operations” requires the CT to be less than 50 

percent load while any fuel flow meter samples are recorded at that load. 

Compliance with the CO2e BACT emission limits for both normal operation and startup/shutdown events 

will be achieved through continuous monitoring of fuel consumption and gross power output to determine 

the CO2e emissions based on 40 CFR Part 75 methodologies (CO2 emissions) and 40 CFR Part 98 

,methodologies (CH4 and N2O emissions) as follows:

1. Normal Operation, Startup and Shutdown – Natural Gas Firing

a. Heat input (MMBtu, HHV) will be continuously monitored, via fuel flow meters as 

required by 40 CFR Part 75 Appendix D. CO2e 12-month rolling average emissions 

will be calculated based on measured heat input and 40 CFR Part 75 and Part 98 

emission factors. From 40 CFR 75, Appendix G, Eq. G-4, an equation for CO2

lb/MMBtu is derived as follows:
September 2012 25 103-89556

• Natural gas-firing CO2 lb/MMBtu = 1,040 scf/MMBtu x (1/385) scf CO2/lb-mole x 44 

lb/lb-mole = 118.9 lb/MMBtu 

o CO2 lb/12-Month Rolling Period = Heat Input MMBtu/12-Month Rolling 

Period x 118.9 lb CO2/MMBtu

 Where the Heat Input, MMBtu, is HHV and corrected to ISO

conditions.

• From 40 CFR Part 98, Subpart C, Table 8a an equation for CH4 and N2O lb/12-

Month Rolling Period is derived as follows:

o Natural gas-firing CH4 lb/12-Month Rolling Period = Heat Input MMBtu/12-

Month Rolling Period x 2.2E-3 lb/MMBtu Natural gas-firing N2O lb/12-

Month Rolling Period = Heat Input MMBtu/12-Month Rolling Period x 2.2E4 lb/MMBtu (Table C-2, Subpart C, 40 CFR Part 98)

 Where emission factor in kg/MMBtu is converted to lb/MMBtu by 

multiplying by 2.204. 

 Where the Heat Input, MMBtu, is HHV and corrected to ISO 

conditions.

• CO2e lb/12-Month Rolling Period = CO2 lb/12Month Rolling Period + (21 x CH4

lb/12-Month Rolling) + (310 x N2O lb/12-Month Rolling)

• CO2e lb/MWh = (CO2e lb/12-Month Rolling) / (MW/12-Month Rolling) (gross)

 Where MWh is gross output and recorded in corresponding 12-

month rolling periods.

2. Normal Operation and Startup and Shutdown – Fuel Oil Firing

From 40 CFR 75, Appendix G, Eq. G-5, an equation for CO2 lb/MMBtu is derived as follows:

• Oil-firing CO2 lb/MMBtu = 1,420 scf/MMBtu x (1/385) scf CO2/lb-mole x 44 lb/lbmole = 162.3 lb/MMBtu 

o CO2 lb/12-Month Rolling Period = Heat Input MMBtu/12-Month Rolling 

Period x 162.3 lb CO2/MMBtu
September 2012 26 103-89556

o Where the Heat Input, MMBtu, is HHV and corrected to ISO conditions.

From 40 CFR Part 98, Subpart C, Table 8a an equation for CH4 and N2O lb/12-Month 

Rolling Period is derived as follows:

• CH4 lb/12-Month Rolling Period = Heat Input MMBtu/12-Month Rolling Period x 

(3.0E-3) x 2.204 = Heat Input MMBtu/hr x 6.6E-3 lb/Mmbtu 

• N2O lb/12-Month Rolling Period = Heat Input MMBtu/12-Month Rolling x (6.0E-4) x 

2.204 = Heat Input MMBtu/hr x 1.32E-3 lb/Mmbtu 

o Where emission factor in kg/MMBtu is converted to lb/MMBtu by 

multiplying by 2.204.

o Where the Heat Input, MMBtu, is HHV and corrected to ISO conditions.

CO2e lb/12-Month Rolling Period = CO2 lb/12-Month Rolling Period + (21 x CH4 lb/12-

Month Rolling Period) + (310 x N2O lb/12-Month Rolling Period) (40 CFR 98 and 52.21)

o CO2e lb/MWh = (CO2e lb/12-Month Rolling Period) / (MW/12-

Month Rolling Period) (gross) Where MWh is gross output and 

recorded in corresponding hourly averages.

During normal operation, for each fuel, a new total is calculated each month based on the total fuel 

fired, during normal operation, the prior 12 consecutive calendar months. Valid data shall be any 

fuel firing during periods of normal operation. Normal operation is achieved when the CT reaches 

50% load or greater. 

For each fuel, a new startup and shutdown CO2e 12-month average is calculated each calendar 

month based on the summation of fuel consumption during all startup and shutdown events during 

the prior 12 consecutive calendar months divided by the number of startup events in the 12-month

period. Fuel flow meter data shall be used to determine emissions during startup and shutdown 

events. Startup is defined to begin on the minute when fuel is first ignited in the CT and terminates 

on the minute when the CT reaches 50 percent load. Shutdown occurs on the minute when the CT 

load is less than 50 percent load until the minute that fuel flow to the CT stops. “Valid data during 

startup or shutdown operations” requires the CT to be less than 50 percent load while any fuel flow 

meter samples are recorded at that load. 
September 2012 27 103-89556

2.2 Emergency Generator

The proposed emergency generator is diesel fired with a rating of 1,000 kW (1,342 hp) and limited to 500 

hours per year of operation. Diesel emergency generators are typically exercised on a weekly or monthly 

basis to verify operability and to ensure availability during emergencies. Otherwise, the emergency 

generator is only operated for limited periods of time during plant power outages and black start 

conditions. Black start conditions are defined by the ability to start without an outside electrical supply.

Energy efficiency, fueling with biodiesel, fueling with natural gas, and limitations on operating hours are 

considered as potentially available control options for the diesel generators. Standby diesel engines used 

in emergency generator service and fire pump service are designed for quick startup (approximately ten 

seconds to provide power), whereas natural gas fueled engines provide power within 30 seconds to two 

minutes. Thus two engine manufacturers’ representatives contacted (Cummins/Cummins Northeast and 

Caterpillar/Milton Cat, April 2012) stated that the respective companies do not manufacture standby 

engines fueled with natural gas in the size range planned for the Project. And, although natural gas is a 

lower carbon fuel, natural gas fueled engines of comparable size are not appreciably more efficient than 

diesel fueled engines.

The use of biodiesel has technical issues that represent unacceptable risk of non-operation of essential 

equipment during emergency events. The use of biodiesel involves maintenance of engine components 

and fuel management issues that impact the feasibility of using biodiesel, especially B100 (i.e., 100% 

biodiesel), as an alternative fuel for emergency generators.12,13. Because biodiesel exhibits properties of 

a strong solvent, frequent inspection of components such as rubber hoses and seals is required to 

monitor potential deterioration. In addition, fuel filters in engines converted from petroleum diesel to 

biodiesel require regular inspection and replacement to prevent clogging as a result of deposition of 

leftover sediments dissolved by biodiesel from the fuel tank and fuel lines. 

Shelf life is also a major concern for biodiesel fuel due to separation, congealing and degradation of the 

fuel. Biodiesel can degrade very quickly in the presence of oxygen, moisture and heat, increasing 

viscosity, acidity, and forming gums and sediments which can clog and/or damage the engine. Moisture 

buildup in biodiesel can also encourage microbial growth, which can clog fuel filters and injectors. The 

degradation of biodiesel also has a negative impact on the fuel quality, requiring greater quantities of fuel 

to produce the same heat output as the fuel ages. Although these issues may be controlled to some 

extent with the addition of fuel additives and frequent monitoring of fuel quality, storage of biodiesel is 

recommended for no longer than 6 months. 

 12 Assessing Biodiesel in Standby Generators for the Olympic Peninsula. July 2004. Barrett Consulting Inc.

13 Plebuch, E. It’s in the Tank: Strategies for Maintaining Standby Generators Powered by Biodiesel. Peterson Power Systems. 
September 2012 28 103-89556

In addition to the operational issues discussed above, based on discussions with representatives of 

standby diesel engine suppliers, there are limited, if any, emissions data available for biodiesel-fired 

standby generators.14 This is a result of limited experience and use of biodiesel for standby power 

generation, the corresponding low demand for biodiesel emissions data and the potential wide variation in 

fuel composition. These variations in fuel composition stand in contrast to No. 2 diesel oil which has fairly 

standard compositions and therefore, standard combustion properties and consistent levels of emissions. 

Biodiesel may be produced from a variety of different feedstock materials (e.g., rapeseed oil, soybean oil, 

used vegetable oil, animal fats) and the composition of the fuel will depend on the availability and costs of 

the source materials (which may fluctuate over time) and possibly the capabilities and preferences of the 

producer. Firing of these different types of biodiesel in standby generators may produce different power 

outputs and varying levels of emissions. Although levels of emissions for most pollutants from 

combustion of biodiesel are generally much lower than diesel, data are only available for tailpipe 

emissions for heavy and medium duty engines. Declines in biodiesel fuel quality as a result of storage can 

add additional uncertainty to emissions levels. 

Based on the technical limitations and lack of availability of generator systems of sufficient size to meet 

the demands of the Project, the use of natural gas fuel as BACT was eliminated. Based on the limited 

use of biodiesel for standby power generation and uncertainties associated with emissions data for 

standby power generation, biodiesel fuel was also eliminated as BACT. Thus, limitation of operating 

hours and the associated TPY of CO2 is the only technically feasible and cost effective BACT measure 

for the diesel engines. 

2.2.1 BACT Emission Rate

The generator will meet the requirements of 40 CFR Part 60, Subpart IIII – Standards of Performance for 

Stationary Compression Ignition Internal Combustion Engines. Greater fuel efficiency is inherently a result 

of the more stringent limitations imposed by Subpart IIII for PM, NOx and hydrocarbon emissions. The 

CO2e emissions resulting from the combustion of diesel fuel in the generator will be limited based on 

energy efficiency requirements inherent in compliance with Subpart IIII and be representative of BACT. 

Based on 40 CFR 52.21 and Part 98 methodologies (Table C-2, Subpart C, kg/MMBtu factors converted 

to lb/mmBtu by multiplying by 2.204), CO2e emissions from diesel firing of the emergency generator are 

estimated to be 398 short TPY based on 500 hours of operation, see Table 4. BACT is proposed based 

on a calendar year annual average. Compliance demonstration is proposed based on the following 40 

CFR Part 98 methodologies:

 14 Telephone conversations between Gavin Hoch of Golder Associates, Inc. and Chad Taurman and Ron Romanelli of Ring Power 

Corporation on July 9, 2012.
September 2012 29 103-89556

• CO2 Short TPY = 73.96 kg CO2/MMBtu x Annual Heat Input (MMBtu) x 2.204 / 

2204 x 2000 (40 CFR Part 98 Table C-1)

• CH4 Short TPY = (3.0E-3) x 2.204 x Heat Input MMBtu/hr / 2204 x 2000

• N2O Short TPY = (6.0E-4) x 2.204 x Heat Input MMBtu/hr / 2204 x 2000

• CO2e Short TPY = CO2 TPY + (21 x CH4 TPY) + (310 x N2O TPY) 

All fuel consumption during the calendar year is included in the averaging period. A new average is 

calculated at the end of each calendar year based on total fuel consumption including startup and 

shutdown events.

2.3 Fuel Gas Heater

The proposed natural gas-fired fuel heater will be used to preheat natural gas to keep the gas above the 

dew point temperature. The proposed gas-fired fuel heater is standard equipment used in power plants to 

preheat natural gas and such equipment is used successfully in hundreds of utility, processing, and 

upstream oil and gas industry applications.

The heater will be an indirect-fired type where the fire tube is surrounded by a chamber full of natural gas 

and heat transfer will occur between the fire tube and the thermal reservoir that transfers heat to the 

natural gas. Although the specific unit has not been selected for the Project, indirect-fired fuel heaters 

have thermal efficiencies of up to 70% (amount of heat transferred to the natural gas per amount of heat 

input into heater). Please note that fuel heaters are similar to a boiler used for hot water or space heating 

and cannot be compared to commercial boilers. The fuel heater is expected to use indirect heat transfer 

where a heat transfer fluid (e.g., water and ethylene glycol mixture) maintains the required temperature of 

the natural gas. 

BACT for the natural gas fired fuel gas heater is achieved through exclusive natural gas combustion and 

operation of a high thermal efficiency. Although the specific gas heater unit has not been specified, new 

units are capable of greater than 75% thermal efficiency as demonstrated by Weatherford’s GRITTM

Natural-Gas-Line-Heater.

15 Based on 40 CFR Part 98 methodologies, CO2e emissions from the fuel gas 

heater are estimated to be 5,123 short TPY based on 8,760 hours per year, see Table 4. BACT is 

proposed based on a calendar year annual average. Compliance demonstration is proposed based on 

the following 40 CFR Part 98 methodologies:

 15 (http://www.weatherford.com/weatherford/groups/web/documents/weatherfordcorp/WFT075697.pdf)
September 2012 30 103-89556

• CO2 Short TPY = 53.02 kg CO2/MMBtu x Annual Heat Input (MMBtu) x 2.204 / 

2204 x 2000 (40 CFR Part 98 Table C-1)

• CH4 Short TPY = (1.0E-3) x 2.204 x Heat Input MMBtu/hr / 2204 x 2000

• N2O Short TPY = (1.0E-4) x 2.204 x Heat Input MMBtu/hr / 2204 x 2000

• CO2e Short TPY = CO2 TPY + (21 x CH4 TPY) + (310 x N2O TPY)

All fuel consumption during the calendar year is included in the averaging period. A new average is 

calculated at the end of each calendar year based on total fuel consumption including startup and 

shutdown events.

2.4 Fuel Oil Storage Tank

The proposed fuel oil storage tank is estimated to emit 2.02 tons per year of VOC. GHG emissions for the 

fuel oil storage tank were evaluated by reviewing EPA guidance regarding greenhouse gas emissions 

reporting for the petroleum and natural gas industry, including the final rule for Mandatory Reporting for 

Greenhouse Gases: Petroleum and Natural Gas Systems (dated November 30, 2010, accessed 

at http://www.gpo.gov/fdsys/pkg/FR-2010-11-30/pdf/2010-28655.pdf). This rule was based on technical 

considerations discussed and evaluated in the background Technical Support Document (EPA-HQ-OAR2009-0923, accessed at http://www.epa.gov/climatechange/emissions/downloads10/SubpartW_TSD.pdf). The technical support document compiled and summarized information from a number of 

supporting references, including an American Petroleum Institute (API) study which specifically addresses 

potential GHG emissions resulting from standing and working losses from liquid petroleum storage tanks.

This study, titled Compendium of GHG Emissions Estimation Methodologies for the Oil and Gas Industry

(dated August 2009, accessed at http://www.api.org/ehs/climate/new/upload/2009_ghg_compendium.pdf, 

pages 5-55 to 5-56) indicates that “Unless site-specific data indicate otherwise, “weathered” crude and 

other refined petroleum products are assumed to contain no CH4 or CO2. Therefore, it is also assumed 

that there are no CH4 or CO2 emissions from the working and breathing losses of tanks containing 

“weathered” crude or other petroleum products.” Similarly, EPA’s study entitled Available and Emerging 

Technologies for Reducing Greenhouse Gas Emissions from the Petroleum Refining Industry (dated 

October 2010, accessed at http://www.epa.gov/nsr/ghgdocs/refineries.pdf, page 10) also concluded that 

petroleum liquid storage tanks will generally have negligible GHG emissions. Thus, GHG emissions for 

the fuel oil storage tank were considered negligible.
September 2012 31 103-89556

2.5 Electrical Breaker – SF6

The Project includes one new electrical breaker that is expected to contain SF6. Industrial circuit 

breakers typically contain sulfur hexafluoride (SF6) for the purpose of electrical insulation and interruption 

of electrical current. SF6 has been, and continues to be, broadly used in the U.S. due to its dielectric 

strength and arc-quenching characteristics. Flammable insulating oils have been largely replaced with 

SF6. SF6 is a GHG. 

BACT will be good operational practices to help ensure the breaker does not break or leak. The BACT 

analysis for the GHG emissions from the circuit breakers follows the EPA’s suggested 5 step “top down” 

process: 

2.5.1 Step 1 – Identify All Available Control Technologies

The available control options include alternative (non-SF6) dielectric fluids and minimization of fugitive 

emissions of SF6. Historically, dielectric fluids such as dielectric oils have been used in high voltage 

service for electrical insulation purposes. Other dielectric fluids have been replaced with SF6 for use in 

circuit breakers because SF6 is not flammable and has exceptional dielectric strength and arc-quenching 

characteristics.

The SF6 Emission Reduction Partnership is one of EPA’s voluntary industry programs aimed at reducing 

greenhouse gas emissions. The Partnership’s primary objective is to reduce SF6 emissions via costeffective technologies and practices. Through improvements in the leak rate of new equipment, 

refurbishing of older equipment, and the use of more efficient operation and maintenance techniques, 

utilities often find economical solutions to reduce SF6 emissions.

Modern SF6 circuit breakers are designed as totally enclosed pressure systems with minimal potential for 

fugitive SF6 emissions. The Proposed SF6 circuit breakers will have a pressure gage with internal set 

points for operation limitations. The breaker gage will be continuously monitored with alarm sounding for 

operators when a leak is detected. Corrective action will be taken to repair the leak should one occur or 

replace the leaking circuit breaker. In addition, O&M procedures include routine safety inspections of the 

circuit breaker equipment to ensure proper operation.
September 2012 32 103-89556

2.5.2 Steps 2 & 3 – Identification and Ranking of Technically Feasible Control 

Alternatives

EPA’s SF6 Partnership has recognized that there is no clear alternative to using SF6 in combination with 

fugitive SF6 emissions detection, repair, and replacement strategies.16 Thus, the only technically feasible 

option is use of sealed SF6 circuit breakers with leak detection (i.e., alarm), repair, and replacement 

strategies. Since only one technically feasible option is available, no ranking of options is required and 

the remaining option is the “top” control option.

2.5.3 Step 4 – Economic, Energy, and Environmental Impacts

The “top” control option is use of SF6 circuit breakers in conjunction with use of modern totally enclosed 

equipment, equipped with leak detection equipment (density alarms), and implementation of maintenance 

programs and period safety inspections. SF6 is chemically inert, non-toxic, non-flammable, and thermally 

stable. This system of equipment and procedures offers low economic, energy, and environmental 

impacts.

2.5.4 Step 5 – Select the BACT

Based on the top down analysis, the “top” technically feasible control option has been selected for the 

Project as the following:

• Three new totally enclosed circuit breakers 

• Pressure gage with internal set points for operation limitations Repair of leaks or replacement 

of equipment

• Continuous monitoring of circuit breaker pressure gage and inspection and maintenance 

2.6 On-Site Pipeline and Natural Gas Supply

The scope of this BACT analysis is limited to the Project site and new natural gas pipelines to be installed 

as part of the expansion Project. Within the existing Shady Hills Generating Station site, new natural gas 

supply lines to the new CTs and heater will be installed. Natural gas leaks from the new on-site natural 

gas supply lines represent a potential source of fugitive GHG emissions in the form of methane contained 

in the natural gas. Leakage of natural gas will be actively monitored and repaired if found at the site since 

natural gas leaks are flammable and pose a safety risk. Thus methane emissions from the on-site 

pipeline and natural gas supply lines will be minimized at the site. Such minimization using monitoring 

 16 “SF6 Emission Reduction Partnership for Electric Power Systems,” 2010 Annual Report, U.S. Environmental Protection Agency, 

December 2011 (http://www.epa.gov/electricpower-sf6/resources/index.html).
September 2012 33 103-89556

and repair is considered BACT. EFS will continuously monitor pipeline system pressure against alarm set 

points, to be determined upon system design and implementation, to identify leaks as they occur. In 

addition the natural gas is treated with mercaptan so that the odor from leaks can be detected by 

personnel. 
TABLES
N2O Emissions (a) CH4 Emissions 

Emission Emission Emission

Heat Input Operation Annual Heat Input Factor Annual Emissions Factor Annual Emissions Factor Annual 

Unit (MMBtu/hr) (Hr/yr) (MMBtu/yr) (lb/MMBtu) (Short tons/yr) (lb/MMBtu) (Short tons/yr) (lb/MMBtu) (Short 

Emergency Generator 9.73 500 4,864 163.0 396 1.32E-03 3.22E-03 6.6E-03 1.6Fuel Gas Heater 10 8760 87,600 116.9 5118 2.20E-04 9.65E-03 2.2E-03 9.65(a) Table C-2, Subpart C, 40 CFR Part 98. Emission factors in kg/MMBtu were converted to lb/MMBtu by multiplying by 2.204.(b ) CO2e = CO2 + (21 x CH4) + (310 x N2O)Source: Golder, 2012

TABLE 4. Shady Hills Expansion: GHG Emissions for the Proposed Emergency Generator and Fuel Gas Heater

CO2 Emissions (a)
TABLE 3. Shady Hills Expansion: Proposed CO2e emission limits - per Turbine

Gas-fired operationsUnit load

Output, MW 

(gross)

Heat Rate, 

Btu/kWh (LHV, 

gross)

Heat Rate, 

Btu/kWh (HHV, 

gross) operating hours %

 Annual operating 

hours 

Generation, 

MWh/yr

lb/mmBtu (HHV 

basis) lb/hr 

100% 218 8,826 9,797 50% 1,445 314,835 119 254,040 50% 109 11,265 12,504 50% 1,445 157,417 119 162,120 Totals 472,252 Design margin Performance degradation margin Proposed GHG limit on NG 

Normal Operations 12-Month Rolling Average lb/MWh at ISO Start-up and Shut-down 12-Month Rolling Average Short tons per SU-SD 

Oil-fired operationsUnit load

Output, MW 

(gross)

Heat Rate, 

Btu/kWh (LHV, 

gross)

Heat Rate, 

Btu/kWh (HHV, 

gross) operating hours %

 Annual operating 

hours 

Generation, 

MWh/yr

lb/mmBtu (HHV 

basis) lb/hr 

100% 223 9,509 10,175 50% 250 55,658 163 368,883 50% 111 11,670 12,487 50% 250 27,829 163 226,358 Totals 83,487 Design margin Performance degradation margin Proposed GHG limit on ULSD n)

Normal Operations 12-Month Rolling Average lb/MWh at ISO Start-up and Shut-down 12-Month Rolling Average Short tons per SU-SD 

Notes:

12 CO2e - includes CO2, N2O, and CH4 and is based on 40 CFR Part 75 and Part 98 factors.3 ISO = 59 deg. F., 60% relative humidity4 Assumes 5% margin for design basis and 3% margin for degradation between major overhauls and the life of unit. 5 CO2e lb/MMBtu Emission Factors based on Table 1. CO2e = CO2 + (21 x CH4) + (310 x N2O)6 Startup Shutdown Emission based on CO2e Emission Factor and Estimated Fuel Consumption fer event: 338 MMBtu/event, and 339 

MMBtu/event, for Natural Gas and ULSD, respectively, and 119 lb CO2e/MMBtu and 163 lb CO2e/MMBtu, respectively for natural gas ans ULSD, respectively. 

Source: EFS, 2012

CO2e Emi

CO2e Emi

The above GHG limits take into consideration a number of operating, design and maintenance factors typical of combustion turbine generatoperation across the range from minimum load to full load output, which is important for flexible, quick-starting resources under a utility's dtypical of construction contracts and equipment manufacturer’s supply contracts, which contain commercial terms for minimum performantypical performance degradation of combustion turbines between major overhauls and the life of the equipment even with implementation 
1 x 7FA.05 5 x LM6000 2 x LMS100

Plant 

Plant Total Output (MW) 213 213 213

Number of Turbines (Unit) 1 5 2

Capacity Factor (%) 27.3% 27.3% 27.3%

Fuel Operating Hours (Hours) 2,390 2,390 2,390

Number of Starts (Starts/Unit) 176 176 176

Percentage of operation by fuel -- NG (%) 69% 69% 69%

-- FO (%) 31% 31% 31%

Annual operating hours -- NG (Hours/year) 1,640 1,640 1,640

-- FO (Hours/year) 750 750 750

Net Plant Heat Rate (LHV) -- NG (Btu/kWh) 8,928 8,312 7,971

-- FO (Btu/kWh) 9,708 8,489 8,061

HHV/LHV Conversion -- NG 1.11 1.11 1.11

-- FO 1.07 1.07 1.07

Net Plant Heat Rate (HHV) -- NG (Btu/kWh) 9,910 9,226 8,848

-- FO (Btu/kWh) 10,388 9,083 8,625

Total Plant Heat Input per Start/Shutdown (HHV) (MMBtu) 257 44 90

Fuel Price -- NG ($/MMBtu) 5 5 5

-- FO ($/MMBtu) 20 20 20

CO2e (fuel HHV basis, incl CO2, N2O and CH4) -- NG (lb/MMBtu) 119 119 119

-- FO (lb/MMBtu) 163 163 163

Costs

Capital Cost ($/kW) 617 1129 979

Fixed Charge Rate (%) 11.0% 11.0% 11.0%

Fixed Operation & Maintenance costs (Fixed O&M) ($/kW-yr) 18.2 28.8 25.8

Variable Operation & Maintenance costs (Variable O&M) ($/MWh) 7.44 7.11 5.78

Operations

Energy Produced Total (MWh/yr) 507,875 507,875 507,875

-- NG 348,500 348,500 348,500

-- FO 159,375 159,375 159,375

Fuel Consumption Total (MMBtu/yr) 5,109,223 4,662,864 4,458,137

-- NG 3,453,635 3,215,261 3,083,528

-- FO 1,655,588 1,447,603 1,374,609

CO2e Emission Total (Short Tons/yr) 340,322 309,202 295,420

-- NG 205,517 191,332 183,493

-- FO 134,805 117,870 111,927

Emission Difference to 7FA.05 (Short Tons/yr) 0 -31,120 -44,903

Cost of Electricity

Capital Recovery $/kW-yr $ 67.7 $ 123.9 $ 107.5

Fixed O&M $/kW-yr $ 18.2 $ 28.8 $ 25.8

Total fixed revenue req't $/kW-yr $ 85.9 $ 152.7 $ 133.2

Fuel - NG $/MWh $ 49.6 $ 46.1 $ 44.2

Fuel - FO $/MWh $ 198.2 $ 184.5 $ 177.0

Fuel - Weighted $/MWh $ 96.2 $ 89.6 $ 85.9

Fuel - Startup $/MWh $ 0.4 $ 0.4 $ 0.3

Variable O&M $/MWh $ 7.4 $ 7.1 $ 5.8

Total variable revenue req't $/MWh $ 104.1 $ 97.0 $ 92.0

Capital Recovery $MM/yr $ 14.4 $ 26.3 $ 22.8

Fixed O&M $MM/yr $ 3.9 $ 6.1 $ 5.5

Fuel $MM/yr $ 49.1 $ 45.7 $ 43.8

Variable O&M $MM.yr $ 3.8 $ 3.6 $ 2.9

Total $MM/yr $ 71.1 $ 81.7 $ 75.0

All-in cost of electricity $/MWh $ 140.0 $ 160.9 $ 147.7

Differences v. 7FA.05 Option $MM/yr $ 10.6 $ 3.9

$/Short Ton CO2e $ 341.5 $ 87.2

* NG = natural gas; FO = ultra low sulfur fuel oil; LHV = lower heating value; HHV = higher heating value

* CO2e - includes CO2, N2O, and CH4 and is based on 40 CFR Part 75 and Part 98 factors.

* Sigma Energy estimate is based on 2011 overnight dollars. Escalated to 2015 dollars using 2% Annual Inflation Rate

* 10% Contingency built into the capital cost estimate provided by Sigma for Simple Cycle units

* FOM and VOM costs are escalate at 2% annual rate. Inputs in this table is a levelized rate over 20 years horizon.

* Output and heat rate values above are net of plant auxiliary loads and incorporate a degradation allowance over the 20 year horizon.

* Fixed charge rate used above for evaluation consistent with long-term investment considerations

Source: EFS 2012, Sigma 2012.

Table 2a. Shady Hills Expansion: Cost Effectiveness Analysis for Alternative Simple Cycle Generation Technologies

Alternate scenario - Only 1 unit installed
2 x 7FA.05 10 x LM6000 4 x LMS100

Plant 

Plant Total Output (MW) 425 425 425

Number of Turbines (Unit) 2 10 4

Capacity Factor (%) 38.7% 38.7% 38.7%

Fuel Operating Hours (Hours) 3,390 3,390 3,390

Number of Starts (Starts/Unit) 250 250 250

Percentage of operation by fuel -- NG (%) 85% 85% 85%

-- FO (%) 15% 15% 15%

Annual operating hours -- NG (Hours/year) 2,890 2,890 2,890

-- FO (Hours/year) 500 500 500

Net Plant Heat Rate (LHV) -- NG (Btu/kWh) 8,928 8,312 7,971

-- FO (Btu/kWh) 9,708 8,489 8,061

HHV/LHV Conversion -- NG 1.11 1.11 1.11

-- FO 1.07 1.07 1.07

Net Plant Heat Rate (HHV) -- NG (Btu/kWh) 9,910 9,226 8,848

-- FO (Btu/kWh) 10,388 9,083 8,625

Total Plant Heat Input per Start/Shutdown (HHV) (MMBtu) 255 44 90

Fuel Price -- NG ($/MMBtu) 5 5 5

-- FO ($/MMBtu) 20 20 20

CO2e (fuel HHV basis, incl CO2, N2O and CH4) -- NG (lb/MMBtu) 119 119 119

-- FO (lb/MMBtu) 163 163 163

Costs

Capital Cost ($/kW) 617 1129 979

Fixed Charge Rate (%) 11.0% 11.0% 11.0%

Fixed Operation & Maintenance costs (Fixed O&M) ($/kW-yr) 18.2 28.8 25.8

Variable Operation & Maintenance costs (Variable O&M) ($/MWh) 7.44 7.11 5.78

Operations

Energy Produced Total (MWh/yr) 1,440,801 1,440,801 1,440,801

-- NG 1,228,301 1,228,301 1,228,301

-- FO 212,500 212,500 212,500

Fuel Consumption Total (MMBtu/yr) 14,379,913 13,262,443 12,700,820

-- NG 12,172,463 11,332,305 10,868,007

-- FO 2,207,450 1,930,138 1,832,813

CO2e Emission Total (Short Tons/yr) 904,094 831,519 795,965

-- NG 724,353 674,357 646,728

-- FO 179,742 157,161 149,237

Emission Difference to 7FA.05 (Short Tons/yr) 0 -72,576 -108,130

Cost of Electricity

Capital Recovery $/kW-yr $ 67.7 $ 123.9 $ 107.5

Fixed O&M $/kW-yr $ 18.2 $ 28.8 $ 25.8

Total fixed revenue req't $/kW-yr $ 85.9 $ 152.7 $ 133.2

Fuel - NG $/MWh $ 49.6 $ 46.1 $ 44.2

Fuel - FO $/MWh $ 198.2 $ 184.5 $ 177.0

Fuel - Weighted $/MWh $ 71.5 $ 66.5 $ 63.8

Fuel - Startup $/MWh $ 0.4 $ 0.4 $ 0.3

Variable O&M $/MWh $ 7.4 $ 7.1 $ 5.8

Total variable revenue req't $/MWh $ 79.4 $ 74.0 $ 69.9

Capital Recovery $MM/yr $ 28.8 $ 52.7 $ 45.7

Fixed O&M $MM/yr $ 7.7 $ 12.2 $ 11.0

Fuel $MM/yr $ 103.6 $ 96.4 $ 92.4

Variable O&M $MM.yr $ 10.7 $ 10.2 $ 8.3

Total $MM/yr $ 150.8 $ 171.6 $ 157.3

All-in cost of electricity $/MWh $ 104.7 $ 119.1 $ 109.2

Differences v. 7FA.05 Option $MM/yr $ 20.7 $ 6.5

$/Short Ton CO2e $ 285.6 $ 60.2

* NG = natural gas; FO = ultra low sulfur fuel oil; LHV = lower heating value; HHV = higher heating value

* CO2e - includes CO2, N2O, and CH4 and is based on 40 CFR Part 75 and Part 98 factors.

* Sigma Energy estimate is based on 2011 overnight dollars. Escalated to 2015 dollars using 2% Annual Inflation Rate

* 10% Contingency built into the capital cost estimate provided by Sigma for Simple Cycle units

* FOM and VOM costs are escalate at 2% annual rate. Inputs in this table is a levelized rate over 20 years horizon.

* Output and heat rate values above are net of plant auxiliary loads and incorporate a degradation allowance over the 20 year horizon.

* Fixed charge rate used above for evaluation consistent with long-term investment considerations

Source: EFS 2012, Sigma 2012.

Table 2. Shady Hills Expansion: Cost Effectiveness Analysis for Alternative Simple Cycle Generation Technologies

Base scenario - Both units installed
Gross 

Heat Input Heat Input Power Output 

Unit (MMBtu/hr) (MMBtu/hr) (MW) (lb/hr) (tons/hr) (lb/hr) (tons/hr) (lb/hr) (tons/hr) (lb/hr) (tons/hr) 

(7FA.05) LHV HHV

100% Load, 59 F, 60% Relative Humidity (ISO), Natural Gas-Firing, CT Only

CT1 1,923 2,135 218 118.9 228,645 114.3 2.20E-04 0.4 0.0002 2.2E-03 4.2 0.0021 254,040 127

CT2 1,923 2,135 218 118.9 228,645 114.3 2.20E-04 0.4 0.0002 2.2E-03 4.2 0.0021 254,040 127

3,846 4,269 435.8 457,289 228.6 1 0.0004 8 0.004 508,081 254 

Design Margin 5%

Performance 

Degradation Margin 3%

100 % Load, ISO, Oil-Firing, CT Only

CT1 2,117 2,265 223 162.3 343,589 171.8 1.32E-03 2.8 0.0014 6.6E-03 14.0 0.0070 368,883 184CT2 2,117 2,265 223 162.3 343,589 171.8 1.32E-03 2.8 0.0014 6.6E-03 14.0 0.0070 368,883 184

4,234 4,530 445.3 687,178 343.6 6 0.0028 28 0.014 737,767 369 

Design Margin 5%

Performance 

Degradation Margin 3%

Annual Operating Scenario No. 1Annual Average Case Baseload, 59 F, 3390 Hours per Year of Natural Gas Firing and Zero Hours per Year of Oil Firing.

(Short 

CT1 430,CT2 430,

Total (2 CTs) 861,

Annual Operating Scenario No. 2Annual Average Case Baseload, 59 F, 2890 Hours per Year of Natural Gas Firing and 500 Hours per Year of Oil Firing.

(Short 

CT1 459,CT2 459,

Total (2 CTs) 918,

Annual Operating Scenario No. 3Annual Average Case Baseload, 59 F, 1640 Hours per Year of Natural Gas Firing and 750 Hours per Year of Oil Firing.

(Short 

CT1 Total (1 CT) 346,

CT Maximum Annual Emissions (Scenario No. 2) 918,Emergency Generator 39Fuel Gas Heater 5,1Total Annual CO2e Emissions (Incudes Startup and Shutdown Emissions)(e) 924,PSD Review Threshold 75,0

(a) Appendix G - Determination of CO2 Emissions, 40 CFR Part 75. Natural gas-firing CO2 lb/MMBtu = 1040 scf/MMBtu(HHV) x (1/385) scf CO2/lb-mole x 44 lb/lb-mole = 118.9 lb/MMBtu.

 Appendix G - Determination of CO2 Emissions, 40 CFR Part 75. Oil-firing CO2 lb/MMBtu = 1420 scf/MMBtu(HHV) x (1/385) scf CO2/lb-mole x 44 lb/lb-mole = 162.3 lb/MMBtu.

(b) Table C-2, Subpart C, 40 CFR Part 98. Emission factors in kg/MMBtu were converted to lb/MMBtu by multiplying by 2.204.

(c ) CO2e = CO2 + (21 x CH4) + (310 x N2O)(d) Assumes 5% margin for design basis and 3% margin for degradation between major overhauls and the life of unit. (e) TPY CO2e conservatively based on 100 % utilization at maximum load at an annual average operating case based on ISO conditions, 100% load @ 59 deg. F, 60 % relative humidity. Source: Golder, 2012.

Adjusted lb/MWh for Margin

CO2e Emissions (c)

Emission Emission Emission

Factor Emission Rate Factor Emission Rate Factor Emission Rate Emission Rate

(lb/MMBtu) (lb/MMBtu) (lb/MMBtu)

Adjusted lb/MWh for Margin

TABLE 1. GHG Emissions for the Proposed Shady Hills Expansion Project Compared to PSD Review Threshod

CO2 Emissions (a) N2O Emissions (b) CH4 Emissions (b)
APPENDIX A

AIR PERMIT NO. 1010373-012-AC (PSD-FL-402A)
Florida Department of

Environmental Protection

Bob Martinez Center

2600 Blair Stone Road

Tallahassee, Florida 32399-2400

Rick Scott

Governor

Jennifer Carroll

Lt. Governor

Herschel T. Vinyard Jr.

Secretary

www.dep.state.fl.us

PERMITTEE

EFS Shady Hills, LLC.

14240 Merchant Energy Way

Spring Hill, Florida 06927

Authorized Representative:

Roy S. Belden, Vice President

Air Permit No. 1010373-012-AC (PSD-FL-402A)

Shady Hills Generating Station

Site Expansion Project

Modified and Reissued Permit

Expires: July 31, 2015

FACILITY AND LOCATION

This is the final air construction permit, which authorizes the construction of two nominal 223 megawatt 

(MW) simple cycle combustion turbine electric generators, and associated support equipment. This permit 

modifies and replaces Air Permit No. 1010373-007-AC (PSD-FL-402) issued on January 12, 2009. The

proposed work will be conducted at the Shady Hills Generating Station, which is an electric utilities plant

categorized under Standard Industrial Classification No. 4911. The existing facility is located in Pasco

County at 14240 Merchant Energy Way in Spring Hill, Florida. The UTM coordinates are Zone 17, 347.0

kilometers (km) East, and 3139.0 km North. 

This final permit is organized into the following sections: Section 1 (General Information); Section 2

(Administrative Requirements); Section 3 (Emissions Unit Specific Conditions); Section 4 (Appendices). 

Because of the technical nature of the project, the permit contains numerous acronyms and abbreviations, 

which are defined in Appendix A of Section 4 of this permit. As noted in the Final Determination provided 

with this final permit, only minor changes and clarifications were made to the draft permit.

STATEMENT OF BASIS

This air pollution construction permit is issued under the provisions of Chapter 403 of the Florida Statutes 

(F.S.), and Chapters 62-4, 62-204, 62-210, 62-212, 62-296 and 62-297 of the Florida Administrative Code 

(F.A.C.) and Title 40, Parts 60 and 63 of the Code of Federal Regulations (CFR). The permittee is 

authorized to conduct the proposed work in accordance with the conditions of this permit. This project is 

subject to the general preconstruction review requirements in Rule 62-212.300, F.A.C. and the 

preconstruction review requirements for major stationary sources in Rule 62-212.400, F.A.C. for the 

Prevention of Significant Deterioration (PSD) of Air Quality.

Upon issuance of this final permit, any party to this order has the right to seek judicial review of it under 

Section 120.68 of the Florida Statutes by filing a notice of appeal under Rule 9.110 of the Florida Rules of 

Appellate Procedure with the clerk of the Department of Environmental Protection in the Office of General 

Counsel (Mail Station #35, 3900 Commonwealth Boulevard, Tallahassee, Florida, 32399-3000) and by filing 

a copy of the notice of appeal accompanied by the applicable filing fees with the appropriate District Court 

of Appeal. The notice must be filed within 30 days after this order is filed with the clerk of the Department.

Executed in Tallahassee, Florida

Division of Air Resource Management

Office of Permitting and Compliance

(Electronic Signature)
FINAL PERMIT

Shady Hills Generating Station, Site Expansion Air Permit No. 1010373-012-AC

Permit Modification and Reissuance PSD-FL-402A

Page 2 of 17

CERTIFICATE OF SERVICE

The undersigned duly designated deputy agency clerk hereby certifies that this Final Air Permit package 

(including the Final Determination and Final Permit with Appendices) was sent by electronic mail, or a link to 

these documents made available electronically on a publicly accessible server, with received receipt requested 

before the close of business on the date indicated below to the following persons.

Roy S. Belden, Shady Hills Power Company, LLC: roy.belden@ge.com

Scott Osbourn, P.E., Golder Associates, Inc.: sosbourn@golder.com

Robert Wong, DEP SWD: robert.wong@dep.state.fl.us

Heather Ceron, EPA Region 4: ceron.heather@epa.gov

Catherine Collins, U.S. Fish and Wildlife Service: catherine_collins@fws.gov

Ms. Barbara Friday, DEP OPC: barbara.friday@dep.state.fl.us

Ms. Lynn Scearce, DEP OPC: lynn.scearce@dep.state.fl.us

Clerk Stamp

FILING AND ACKNOWLEDGMENT FILED, on this 

date, pursuant to Section 120.52(7), Florida Statutes, with 

the designated agency clerk, receipt of which is hereby 

acknowledged.

(Electronic Signature)
SECTION 1. GENERAL INFORMATION

Shady Hills Generating Station, Site Expansion Air Permit No. 1010373-012-AC

Permit Modification and Reissuance PSD-FL-402A

Page 3 of 17

FACILITY DESCRIPTION

This facility consists of: three, dual-fuel, nominal 170 MW General Electric (GE) Model PG7241FA simple 

cycle combustion turbine-electrical generators, three exhaust stacks that are 18 feet in diameter and 75 feet tall, 

and one nominal 2.8-million gallon distillate fuel oil storage tank. The combustion turbine units can operate in 

simple-cycle mode and intermittent duty mode. The units are equipped with dry low-nitrogen oxides (NOX) 

combustors and water injection capability. The three combustion turbines are regulated under Phase II of the 

Federal Acid Rain Program. This facility operates during peak hours of electrical use.

PROPOSED PROJECT

The proposed site expansion project is to install two, dual-fuel nominal 223 MW GE 7FA.05 simple cycle 

combustion turbine-electrical generators, two 75-feet exhaust stacks, an emergency generator, a natural gas

heater and a nominal 2.8-million gallon distillate fuel oil storage tank. 

The new emission units will be assigned the following emissions unit identification number (E.U. ID No.) 

within the Department’s Air Resource Management System (ARMS):

Facility ID No. 1010373

ID No. Description

005 223 MW General Electric Model 7FA.05 simple cycle combustion turbine-electrical generator

006 223 MW General Electric Model 7FA.05 simple cycle combustion turbine-electrical generator

007 2,500 kW Emergency Generator

008 10 million British thermal units per hour (MMBtu/hr) Natural Gas Heater

009 2.8 million gallon distillate fuel oil storage tank 

REGULATORY CLASSIFICATION

The facility is not a major source of hazardous air pollutants (HAP).

The facility operates units subject to the acid rain provisions of the Clean Air Act (CAA).

The facility is a Title V major source of air pollution in accordance with Chapter 62-213, F.A.C.

The facility is a major stationary source in accordance with Rule 62-212.400(PSD), F.A.C.

The facility operates units subject to the New Source Performance Standards (NSPS) of 40 CFR 60

The facility operates units subject to the National Emissions Standards for Hazardous Air Pollutants (NESHAP) 

of 40 CFR 63.

RELEVANT DOCUMENTS:

The permit request and additional information received to make it complete are not a part of this permit; 

however, the information is listed in the technical evaluation which is issued concurrently with this permit. 
SECTION 2. ADMINISTRATIVE REQUIREMENTS

Shady Hills Generating Station, Site Expansion Air Permit No. 1010373-012-AC

Permit Modification and Reissuance PSD-FL-402A

Page 4 of 17

1. Permitting Authority: The Permitting Authority for this project is the Office of Permitting and Compliance 

(OPC) in the Division of Air Resource Management of the Department. The mailing address for the OPC is 

2600 Blair Stone Road, MS #5505, Tallahassee, Florida 32399-2400. All documents related to applications 

for permits to operate an emissions unit shall be submitted to the OPC Section.

2. Compliance Authority: All documents related to compliance activities such as reports, tests and 

notifications shall be submitted to the Southwest District Office. The mailing address and phone number of 

the Southwest District Office is: 13051 N. Telecom Parkway, Temple Terrace, FL 33637-0926, 

813/632-7600. 

3. Appendices: The following Appendices are attached as part of this permit:

a. Appendix A. Citation Formats and Glossary of Common Terms;

b. Appendix B. General Conditions;

c. Appendix C. Common Conditions;

d. Appendix D. Common Testing Requirements;

e. Appendix E. Summary of Best Available Control Technology Determinations;

f. Appendix F. NSPS, Subpart A, General Provisions and NESHAP, Subpart A, General Provisions;

g. Appendix G. NSPS, Subpart KKKK, Requirements for Stationary Combustion Turbines;

h. Appendix H. NSPS, Subpart IIII and NESHAP, Subpart ZZZZ; and 

i. Appendix I. NSPS, Subpart Dc, Standards of Performance for Small Industrial-CommercialInstitutional Steam Generating Units.

4. Applicable Regulations, Forms and Application Procedures: Unless otherwise specified in this permit, the 

construction and operation of the subject emissions units shall be in accordance with the capacities and 

specifications stated in the application. The facility is subject to all applicable provisions of: Chapter 403, 

F.S.; and Chapters 62-4, 62-204, 62-210, 62-212, 62-213, 62-296 and 62-297, F.A.C. Issuance of this 

permit does not relieve the permittee from compliance with any applicable federal, state, or local permitting 

or regulations.

5. New or Additional Conditions: For good cause shown and after notice and an administrative hearing, if 

requested, the Department may require the permittee to conform to new or additional conditions. The 

Department shall allow the permittee a reasonable time to conform to the new or additional conditions, and 

on application of the permittee, the Department may grant additional time. [Rule 62-4.080, F.A.C.]

6. Modifications: No emissions unit shall be constructed or modified without obtaining an air construction 

permit from the Department. Such permit shall be obtained prior to beginning construction or modification. 

[Rules 62-210.300(1) and 62-212.300(1)(a), F.A.C.]

7. Source Obligation:

a. Authorization to construct shall expire if construction is not commenced within 18 months after receipt 

of the permit, if construction is discontinued for a period of 18 months or more, or if construction is not 

completed within a reasonable time. This provision does not apply to the time period between 

construction of the approved phases of a phased construction project except that each phase must 

commence construction within 18 months of the commencement date established by the Department in 

the permit.

b. At such time that a particular source or modification becomes a major stationary source or major 

modification (as these terms were defined at the time the source obtained the enforceable limitation) 

solely by virtue of a relaxation in any enforceable limitation which was established after August 7, 

1980, on the capacity of the source or modification otherwise to emit a pollutant, such as a restriction on 

hours of operation, then the requirements of subsections 62-212.400(4) through (12), F.A.C., shall apply 

to the source or modification as though construction had not yet commenced on the source or 

modification.
SECTION 2. ADMINISTRATIVE REQUIREMENTS

Shady Hills Generating Station, Site Expansion Air Permit No. 1010373-012-AC

Permit Modification and Reissuance PSD-FL-402A

Page 5 of 17

c. At such time that a particular source or modification becomes a major stationary source or major 

modification (as these terms were defined at the time the source obtained the enforceable limitation) 

solely by exceeding its projected actual emissions, then the requirements of subsections 62-212.400(4) 

through (12), F.A.C., shall apply to the source or modification as though construction had not yet 

commenced on the source or modification.

[Rule 62-212.400(12), F.A.C.]

8. Application for Title IV Permit: At least 24 months before the date on which the new unit begins serving an 

electrical generator greater than 25 MW, the permittee shall submit an application for a Title IV Acid Rain 

Permit to the Department's Office of Permitting and Compliance Section in Tallahassee and a copy to the 

Region 4 office of the U.S. Environmental Protection Agency (EPA) in Atlanta, Georgia. [40 CFR 72]

9. Title V Permit: This permit authorizes specific modifications and/or new construction on the affected 

emissions units as well as initial operation to determine compliance with conditions of this permit. A Title 

V operation permit is required for regular operation of the permitted emissions unit. The permittee shall 

apply for a Title V operation permit at least 90 days prior to expiration of this permit, but no later than 180 

days after completing the required work and commencing operation. To apply for a Title V operation 

permit, the applicant shall submit the appropriate application form, compliance test results, and such 

additional information as the Department may by law require. The application shall be submitted to the 

appropriate Permitting Authority with copies to each Compliance Authority. 

[Rules 62-4.030, 62-4.050, 62-4.220, and Chapter 62-213, F.A.C.]
SECTION 3. EMISSIONS UNIT SPECIFIC CONDITIONS

A. Simple Cycle Combustion Turbines (EU-005 and 006)

Shady Hills Generating Station, Site Expansion Air Permit No. 1010373-012-AC

Permit Modification and Reissuance PSD-FL-402A

Page 6 of 17

This section of the permit addresses the following emissions units.

ID No. Emission Unit Description

005 General Electric Model 7FA.05 combustion turbine-electric generator (nominal 223 MW)

006 General Electric Model 7FA.05 combustion turbine-electric generator (nominal 223 MW)

Design Heat Input Rating: The design heat input rating of each combustion turbine is 1,923 MMBtu/hr 

when firing natural gas and 2,117 MMBtu/hr when firing fuel oil (based on a compressor inlet air 

temperature of 59° Fahrenheit (F), 60 percent (%) relative humidity, 14.7 pounds per square inch (psi) 

pressure, the lower heating value (LHV) of each fuel and 100% load). Actual heat input rate will vary 

depending upon gas turbine characteristics, ambient conditions and evaporative cooling. 

APPLICABLE STANDARDS AND REGULATIONS

1. BACT Determinations: Determinations of the Best Available Control Technology (BACT) were conducted 

for nitrogen oxides (NOX), initial carbon monoxide (CO) and particulate matter (PM/PM10/PM2.5). 

[Rule 62-210.200 (BACT), F.A.C.]

2. NSPS Requirements: These units shall comply with the applicable NSPS in 40 CFR 60, including: 

Subpart A (General Provisions) and Subpart KKKK (Standards of Performance for Stationary Gas 

Turbines). See Appendices F and G of this permit. The BACT emissions standards for NOX and the fuel 

sulfur specifications are as stringent as, or more stringent than the NOX and sulfur dioxide (SO2) limits 

imposed by the applicable NSPS provisions. Some separate reporting and monitoring may be required by 

the individual subparts. [Rule 62-204.800(7)(b), F.A.C.; 40 CFR 60, Subparts A and KKKK]

EQUIPMENT DESCRIPTION

3. Combustion Turbines: The permittee is authorized to install, tune, operate, and maintain two GE

Model 7FA.05 combustion turbine-electrical generator sets and an inlet air filtration system with 

evaporative coolers. The combustion turbines will be designed for operation in simple cycle mode and will 

have dual-fuel capability. [Application 1010373-012-AC; Design]

CONTROL TECHNOLOGY

4. Combustion Technology: The permittee shall install, operate and maintain the GE dry-low NOX (DLN 2.6)

combustion system with the GE Start-up NOX technology feature to control NOX emissions from the 

combustion turbines when firing natural gas. Prior to the initial emissions performance tests required for the 

gas turbines, the DLN combustors and automated gas turbine control system shall be tuned to achieve the 

permitted levels for NOX. Thereafter, the system shall be maintained and tuned in accordance with the 

manufacturer's recommendations or determined best practices. 

[Design; Rule 62-212.400(10)(BACT), F.A.C.]

5. Wet Injection: The permittee shall install, operate, and maintain a water injection system to reduce NOX

emissions from the combustion turbines when firing distillate fuel oil. Prior to the initial emissions 

performance tests, the water injection system shall be tuned to achieve sufficiently low NOX values to meet 

the NOX limits of this permit. Thereafter, the system shall be maintained and tuned in accordance with the 

manufacturer's recommendations or determined best practices.

[Applicant request; Rule 62-212.400(10)(BACT), F.A.C.]

PERFORMANCE REQUIREMENTS

6. Authorized Fuels: The combustion turbines shall fire natural gas as the primary fuel, which shall contain no 

more than 1.5 grains of sulfur per 100 standard cubic feet (gr. sulfur/100 SCF) of natural gas. As a 

restricted alternate fuel, the combustion turbines may fire ultra low sulfur distillate (ULSD) fuel oil 

containing no more than 0.0015% sulfur by weight. 

[Rules 62-210.200 (Potential to emit) and 62-212.400, F.A.C.; BACT for PM/PM10/PM2.5]
SECTION 3. EMISSIONS UNIT SPECIFIC CONDITIONS

A. Simple Cycle Combustion Turbines (EU-005 and 006)

Shady Hills Generating Station, Site Expansion Air Permit No. 1010373-012-AC

Permit Modification and Reissuance PSD-FL-402A

Page 7 of 17

7. Hours of Operation: 

a. Natural Gas Operation:

1. The two combustion turbines may operate an average of no more than 3,390 hours per year per 

turbine with no single unit operating more than 5,000 hours per year.

2. If only one combustion turbine is installed, then it may operate no more than 3,390 hours per year.

b. ULSD Fuel Oil Operation:

1. The two combustion turbines combined may operate up to 1,000 hours on ULSD fuel oil per 

calendar year.

2. If only one combustion turbine is installed, then it may operate up to 500 hours on ULSD fuel oil 

per calendar year. The single combustion turbine may fire an additional 250 hours of ULSD fuel 

oil, provided that for every hour of ULSD fuel fired beyond 500 hours, the combustion turbine must 

reduce its capability to fire natural gas by five hours (i.e. 5:1 natural gas to ULSD fuel oil ratio).

{E.g., if the single combustion turbine operates on ULSD fuel oil for 750 hours in a calendar year, 

then it may only operate for only 1,640 hours on natural gas during the same calendar year 

[(3,390 – 500) – 5(750-500)]}

[Rules 62-210.200(PTE, and BACT) and 62-212.400 (PSD), F.A.C.]

8. Manufacturer’s Performance Curves: The permittee shall provide manufacturer's performance curves (or 

equations) that correct combustion turbine design heat input rating and operation for site conditions to the 

Permitting and Compliance Authorities within 45 days of completing the initial compliance testing. 

Operating data may be adjusted for the appropriate site conditions in accordance with the performance 

curves and/or equations on file with the Department. [Rule 62-210.200(PTE), F.A.C.]

9. Simple Cycle, Intermittent Operation: The turbines shall operate only in simple cycle mode not to exceed 

the permitted hours of operation allowed by this permit. This restriction is based on the permittee's request, 

which formed the basis of the PSD applicability and BACT determination and resulted in the emission 

standards specified in this permit. For any request to convert this unit to combined cycle operation by 

installing/connecting to heat recovery steam generators, including changes to the fuel quality or quantity 

related to combined cycle conversion which may cause an increase in short or long-term emissions, the 

permittee may be required to submit a full PSD permit application complete with a new proposal of the 

BACT as if the unit had never been built. [Rules 62-212.400(12) and 62-212.400(BACT), F.A.C.]

EMISSIONS AND TESTING REQUIREMENTS

10. Emission Standards: Emissions from the combustion turbines shall not exceed the following standards.

Pollutant Emission Standard a,b Basis Compliance Method c Averaging Time

NOX

Gas

15.0 ppmvd @15% O2 NSPS KKKK

CEMS

4-hr rolling avg.

9.0 ppmvd @15% O2

BACT

24-hr block avg.

69.5 lb/hour d One 24-hr blockd

Oil

42.0 ppmvd @15% O2 NSPS KKKK, BACT 4-hr rolling avg.

370.9 lb/hour d BACT One 24-hr blockd

CO

Gas 9.0 ppmvd e

Initial BACT e Initial and Annual 

Stack Tests three 1-hr runs 33.5 lb/hour e

Oil

20.0 ppmvd e

73.2 lb/hour e

PM/PM10/PM2.5

f

1.5 gr. sulfur/100 SCF gas

0.0015% sulfur fuel oil f

BACT

Fuel Record Keeping N/A

10 percent opacity

Visible Emissions

Annual Test g 6-minute block
SECTION 3. EMISSIONS UNIT SPECIFIC CONDITIONS

A. Simple Cycle Combustion Turbines (EU-005 and 006)

Shady Hills Generating Station, Site Expansion Air Permit No. 1010373-012-AC

Permit Modification and Reissuance PSD-FL-402A

Page 8 of 17

a. Nitrogen oxides (NOX) concentration emission standards are expressed in parts per million by volume, dry, corrected to 

15 percent oxygen, abbreviated as ppmvd @15% O2. Carbon monoxide (CO) concentration emissions standards in ppmvd 

are not corrected to 15% O2.

b. The mass emission rate standards in pounds per hour (lb/hour) are based on a turbine inlet condition of 59°F and using the 

higher heating value (HHV) of the fuel. Mass emission rate shall be adjusted to actual test conditions in accordance with the 

performance curves and/or equations provided to the Department pursuant to Condition 8 above.

c. CEMS means continuous emissions monitoring system.

d. One time initial compliance demonstration by CEMS. Subject to the notification requirements in 62-297.310(7)(a)9., F.A.C. 

The demonstration period shall include all valid hours within the designated 24-hour block and not less than three valid hours 

during the block. Pound/hour NOX values reported as NO2 equivalent of nitrous oxide (NO) plus nitrogen dioxide (NO2).

e. The stated CO emission standards represent initial BACT limits. Final BACT limits will be determined and incorporated into 

a future permit modification as described in Condition 35 below. 

f. The fuel sulfur specifications combined with the efficient combustion design and operation of the combustion turbines 

represent BACT for PM/PM10/PM2.5 emissions and effectively limit the potential SO2 project emissions to values less than 40 

tons/year. Compliance with the fuel specifications, carbon monoxide (CO) standards, and visible emissions (opacity) limit 

shall serve as indicators of good combustion. 

g. Compliance with the 10% opacity standard shall be demonstrated by conducting 30-minute tests in accordance with EPA 

Method 9 - Visual Determination of Opacity.

[Rules 62-4.070(3), 62-210.200, 62-212.400, 62-297and 40 CFR 60, Subpart KKKK]

11. Unconfined Particulate Emissions: During the construction period, unconfined PM emissions shall be 

minimized by dust suppressing techniques such as covering, confining, or applying water or chemicals to 

the affected areas, as necessary. [Rule 62-296.320(4)(c), F.A.C.]

12. Test Methods: Required initial and annual compliance stack tests shall be performed in accordance with the 

following reference methods.

Method Description of Method and Comments

7E Determination of NOX Emissions - Instrumental

9 Visual Determination of Opacity

10 Determination of Carbon Monoxide Emissions from Stationary Sources 

20 Determination of NOX, Sulfur Dioxide, and Diluent Emissions from Stationary Gas Turbines

The methods are described in 40 CFR 60, Appendix A, and adopted by reference in Rule 62-204.800, F.A.C. No other 

methods may be used for compliance testing unless prior written approval is received from the administrator of the 

Department’s Emissions Monitoring Section in accordance with an alternate sampling procedure pursuant to 

62-297.620, F.A.C. [Rules 62-204.800, F.A.C.; 40 CFR 60, Appendix A]

13. Testing Requirements: Initial and annual tests shall be conducted at 90% or greater of the design heat input 

ratings provided in emissions unit description above and corrected as described therein. If it is 

impracticable to test within the described range, the combustion turbine may be tested at less the described 

range. In such case, the reported mass emission rates (corrected as described in Condition 10 above) shall 

be further corrected by dividing the result by the percent of the design heat rating at which the test was 

conducted and multiplying by 100%. [Rule 62-297.310, F.A.C.; and 40 CFR 60.8]

14. Initial Compliance Demonstration: Initial compliance stack tests while firing natural gas shall be conducted 

within 60 days after achieving the maximum production rate, but not later than 180 days after the initial 

startup. Initial testing on fuel oil shall be conducted within 60 days of any fuel oil firing in the CT. In 

accordance with the test methods specified in this permit, the combustion turbines shall be tested to 

demonstrate initial compliance with the mass emission rate standards for NOX, CO and with the visible 

emissions standard. [Rules 62-4.070, 62-297.310(7)(a), F.A.C. and 40 CFR 60.8]

15. Subsequent Compliance Testing: Annual compliance tests for CO and visible emissions shall be conducted 

during each federal fiscal year (October 1st to September 30th) while firing natural gas. CO and visible 

emissions tests shall also be performed while firing fuel oil, on each combustion turbine that is fired with

fuel oil, for more than 400 hours during the federal fiscal year. 

[Rules 62-4.070, 62-210.200(BACT), and 62-297.310(7)(a)4, F.A.C.]
SECTION 3. EMISSIONS UNIT SPECIFIC CONDITIONS

A. Simple Cycle Combustion Turbines (EU-005 and 006)

Shady Hills Generating Station, Site Expansion Air Permit No. 1010373-012-AC

Permit Modification and Reissuance PSD-FL-402A

Page 9 of 17

16. Continuous Compliance: Continuous compliance with the permit standard for emissions of NOX shall be 

demonstrated with data collected from the required CEMS. 

[Rules 62-4.070, and 62-210.200(BACT), F.A.C.]

17. Special Compliance Tests: When the Department, after investigation, has good reason (such as complaints, 

increased visible emissions or questionable maintenance of control equipment) to believe that any applicable 

emission standard contained in a Department rule or in a permit issued pursuant to those rules is being 

violated, it shall require the owner or operator of the emissions unit to conduct compliance tests which 

identify the nature and quantity of pollutant emissions from the emissions unit and to provide a report on the 

results of said tests to the Department. [Rule 62-297.310(7)(b), F.A.C.]

EXCESS EMISSIONS

{Permitting Note: The following conditions apply only to the State Implementation Plan (SIP)-based emissions 

standards specified in Condition No. 10 of this subsection. Rule 62-210.700, F.A.C. (Excess Emissions) cannot 

vary or supersede any federal provision of the NSPS, NESHAP, or Acid Rain programs.}

18. Definitions:

a. Startup is defined as the commencement of operation of any emissions unit which has shut down or 

ceased operation for a period of time sufficient to cause temperature, pressure, chemical or pollution 

control device imbalances, which result in excess emissions.

b. Shutdown is the cessation of the operation of an emissions unit for any purpose.

c. Malfunction is defined as any unavoidable mechanical and/or electrical failure of air pollution control 

equipment or process equipment or of a process resulting in operation in an abnormal or unusual 

manner.

[Rule 62-210.200(165, 242, and 258), F.A.C.]

19. Excess Emissions Prohibited: Excess emissions caused entirely or in part by poor maintenance, poor 

operation or any other equipment or process failure that may reasonably be prevented during startup, 

shutdown or malfunction shall be prohibited. All such preventable emissions shall be included in any 

compliance determinations based on CEMS data. [Rule 62-210.700(4), F.A.C.]

20. Data Exclusion Procedures for SIP Compliance: As per the procedures in this condition, limited amounts of 

CEMS emissions data, as specified in Condition 21, may be excluded from the corresponding SIP-based 

compliance demonstration, provided that best operational practices to minimize emissions are adhered to, 

the duration of data excluded is minimized, and the procedures for data exclusion listed below are followed. 

As provided by the Department’s authority in Rule 62-210.700(5), F.A.C., the following provisions and 

those given in Condition 21 are adjustments to maximum and minimum factors in Rule 62-210.700(1), F.A.C. 

a. Limiting Data Exclusion. If the compliance calculation using all valid CEMS emission data indicates 

that the emission unit is in compliance, then no CEMS data shall be excluded from the compliance 

demonstration.

b. Event Driven Exclusion. There must be an underlying event (startup, shutdown, malfunction, or fuel 

switching) in order to exclude data. If there is no underlying event, then no data may be excluded.

c. Continuous Exclusion. Data shall be excluded on a continuous basis. Data from discontinuous periods 

shall not be excluded for the same underlying event.

[Rule 62-210.700, F.A.C.]

21. Allowable Data Exclusions: The following data may be excluded from the corresponding SIP-based 

compliance demonstration for each of the events listed below in accordance with the Data Exclusion 

Procedures of Condition 200:

a. Startup and Shutdown: Up to 60 minutes of CEMS data may be excluded for each combustion turbine 

startup and shutdown cycle. For startups and shutdowns of less than 60 minutes in duration, only those 

minutes attributable to startup and shutdown may be excluded.
SECTION 3. EMISSIONS UNIT SPECIFIC CONDITIONS

A. Simple Cycle Combustion Turbines (EU-005 and 006)

Shady Hills Generating Station, Site Expansion Air Permit No. 1010373-012-AC

Permit Modification and Reissuance PSD-FL-402A

Page 10 of 17

b. Malfunction: Up to 120 minutes (in any operating day) of CEMS data may be excluded due to a 

documented malfunction. A "documented malfunction" means a malfunction that is documented within 

one working day of detection by contacting the Compliance Authority by telephone, facsimile 

transmittal, or electronic email.

c. DLN Tuning: CEMS data collected during initial or other DLN tuning sessions may be excluded from 

the compliance demonstrations provided the tuning session is performed in accordance with the 

manufacturer's specifications or determined best practices. Prior to performing any tuning session, the 

permittee shall provide the Compliance Authority with an advance notice that details the activity and 

proposed tuning schedule. The notice may be by telephone, facsimile transmittal, or electronic mail. 

[Design; Rule 62-4.070(3), F.A.C.]

d. Fuel Switching: Up to 60 minutes of CEMS data may be excluded for each fuel switch. For fuel 

switches of less than 60 minutes in duration, only those minutes attributable to fuel switching may be 

excluded.

All valid emissions data (including data collected during startup, shutdown, malfunction, DLN tuning, and 

fuel switching) shall be used to report emissions for the Annual Operating Report.

[Rules 62-210.200(BACT), 62-210.370, and 62-210.700, F.A.C.]

22. Notification Requirements: The owner or operator shall notify the Compliance Authority within one 

working day of discovering any emissions that demonstrate non-compliance for a given averaging period. 

[Rule 62-4.070, F.A.C.]

CONTINUOUS MONITORING REQUIREMENTS

23. CEMS: Subject to the following, the permittee shall install, calibrate, operate, and maintain a CEMS to 

measure and record the emissions of NOX from the combustion turbines in terms of the applicable standards. 

The monitoring system shall be installed, and functioning within the required performance specifications by 

the time of the initial compliance demonstration.

a. NOX Monitor: Each NOX monitor shall be certified pursuant to the specifications of 40 CFR 75. 

Quality assurance procedures shall conform to the requirements of 40 CFR 75. The annual and required 

RATA tests required for the NOX monitor shall be performed using EPA Method 20 or 7E in Appendix 

A of 40 CFR 60.

b. Diluent Monitor: The oxygen (O2) or carbon dioxide (CO2) content of the flue gas shall be monitored at 

the location where NOX is monitored to correct the measured emissions rates to 15% O2. If a CO2

monitor is installed, the O2 content of the flue gas shall be calculated using F-factors that are appropriate 

for the fuel fired. Each monitor shall comply with the performance and quality assurance requirements 

of 40 CFR 75.

[Rules 62-4.070(3), 62-210.200(BACT), F.A.C., and 40 CFR 60, Subpart 75]

24. Moisture Correction: If necessary, the owner or operator shall determine the moisture content of the exhaust 

gas and develop an algorithm to enable correction of the monitoring results to a dry basis (0% moisture). 

[Rules 62-4.070(3), 62-210.200(BACT), F.A.C]

25. CEMS Data Requirements for BACT Standards:

{Permitting Note: The following conditions apply only to the SIP-based NOX emissions standards specified 

in Condition No. 10 of this section. These requirements cannot vary or supersede any federal provision of 

the NSPS, or Acid Rain programs. Additional reporting and monitoring may be required by the individual 

subparts.}

a. Data Collection: Except for continuous monitoring system breakdowns, repairs, calibration checks, and 

zero and span adjustments, emissions shall be monitored and recorded during all operation including 

startup, shutdown, and malfunction.
SECTION 3. EMISSIONS UNIT SPECIFIC CONDITIONS

A. Simple Cycle Combustion Turbines (EU-005 and 006)

Shady Hills Generating Station, Site Expansion Air Permit No. 1010373-012-AC

Permit Modification and Reissuance PSD-FL-402A

Page 11 of 17

b. Operating Hours and Operating Days: An hour is the 60-minute period beginning at the top of each 

hour. Any hour during which an emissions unit is in operation for more than 15 minutes is an operating 

hour for that emission unit. A day is the 24-hour period from midnight to midnight. Any day with at 

least one operating hour for an emissions unit is an operating day for that emission unit.

c. Valid Hour: Each CEMS shall be designed and operated to sample, analyze, and record data evenly 

spaced over the hour at a minimum of one measurement per minute. All valid measurements collected 

during an hour shall be used to calculate a 1-hour block average that begins at the top of each hour. 

(1) Hours that are not operating hours are not valid hours.

(2) For each operating hour, the 1-hour block average shall be computed from at least two data points 

separated by a minimum of 15 minutes. If less than two such data points are available, there is 

insufficient data and the 1-hour block average is not valid.

(3) During fuel switching an hour in which fuel oil is fired is attributed towards compliance with the 

permit standards for oil firing.

d. 24-hour Block Averages: A 24-hour block shall begin at midnight of each operating day and shall be 

calculated from 24 consecutive valid hourly average concentration values. If a unit operates less than 

24 hours during the block, or there are less than 24 valid hourly averages available, the 24-hour block 

average shall be the average of all available valid hourly average concentration values for the 24-hour 

block. {Permitting Note: For purposes of determining compliance with the 24-hour CEMS standards, 

the missing data substitution methodology of 40 CFR Part 75, Subpart D, shall not be utilized. Instead, 

the 24-hour block average shall be determined using the remaining hourly data in the 24-hour block 

and periods of missing CEMS data are to be reported as monitor downtime in the excess emissions and 

monitoring performance reports. For example, the "24-hr block average" may consist of only 6 valid 

operating hours for the day.}

e. 4-hour Rolling Averages: A 4-hour rolling average is the arithmetic average of the average emission 

concentration measured by the CEMS for a given hour and the three unit operating hour average 

concentrations immediately preceding that unit operating hour.

f. Data Exclusion: Each CEMS shall monitor and record emissions during all operations including 

episodes of startup, shutdown, malfunction, DLN tuning, and fuel switches. Some of the CEMS 

emissions data recorded during these episodes may be excluded from the corresponding CEMS 

compliance demonstration subject to the provisions of Conditions 20 and 211 of this subsection.

g. Availability: The quarterly excess emissions report shall identify monitor availability for each quarter in 

which the unit operated. 

[Rules 62-4.070(3) and 62-210.200(BACT), F.A.C.]

CEMS REQUIREMENTS FOR ANNUAL EMISSIONS

26. CEMS Annual Emissions Requirement: The owner or operator shall use data from the NOX CEMS when 

calculating annual emissions for purposes of computing actual emissions, baseline actual emissions, and net 

emissions increase, as defined at Rule 62-210.200, F.A.C., and for purposes of computing emissions 

pursuant to the reporting requirements of Rule 62-210.370(3), F.A.C. In computing the emissions of a 

pollutant, the owner or operator shall account for the emissions during periods of startup and shutdown of 

the emissions unit. [Rules 62-210.200, and 62-210.370(3), F.A.C.]

REPORTING AND RECORD KEEPING REQUIREMENTS

27. Monitoring of Operations: The permittee shall monitor and record the operating rate of the combustion 

turbines on a daily average basis, considering the number of hours of operation during each day (including 

the times of startup, shutdown, malfunction, DLN tuning, and fuel switching). Such monitoring shall be 

made by monitoring daily rates of consumption and heat content of each allowable fuel in accordance with 

the provisions of 40 CFR 75 Appendix D. [Rules 62-4.070(3) and 62-210.200(BACT), F.A.C.]
SECTION 3. EMISSIONS UNIT SPECIFIC CONDITIONS

A. Simple Cycle Combustion Turbines (EU-005 and 006)

Shady Hills Generating Station, Site Expansion Air Permit No. 1010373-012-AC

Permit Modification and Reissuance PSD-FL-402A

Page 12 of 17

28. Monthly Operations Summary: By the 15th calendar day of each month, the permittee shall record the 

following for each fuel in a written or electronic log for the combustion turbines for the previous month of 

operation: fuel consumption, hours of operation on each fuel, and the updated calendar year totals for each. 

Information recorded and stored as an electronic file shall be available for inspection and printing within at 

least three days of a request by the Department. The fuel consumption shall be monitored in accordance 

with the provisions of 40 CFR 75 Appendix D. [Rules 62-4.070(3) and 62-210.200(BACT), F.A.C.]

29. Fuel Sulfur Records: The permittee shall demonstrate compliance with the fuel sulfur limits specified in 

this permit by maintaining the following records of the sulfur contents.

a. Natural Gas Sulfur Limit: Compliance with the fuel sulfur limit for natural gas shall be demonstrated 

by keeping reports obtained from the vendor indicating the average sulfur content of the natural gas 

being supplied from the pipeline for each month of operation. Methods for determining the sulfur 

content of the natural gas shall be ASTM methods D4084-82, D4468-85, D5504-01, D6228-98 and 

D6667-01, D3246-81 or more recent versions.

b. Distillate Fuel Oil Sulfur Limit: Compliance with the distillate fuel oil sulfur limit shall be 

demonstrated by taking a sample, analyzing the sample for fuel sulfur, and reporting the results to each 

Compliance Authority before initial startup. Sampling the fuel oil sulfur content shall be conducted in 

accordance with ASTM D4057-88, Standard Practice for Manual Sampling of Petroleum and Petroleum 

Products, and one of the following test methods for sulfur in petroleum products: ASTM methods 

D5453-00, D129-91, D1552-90, D2622-94, or D4294-90. More recent versions of these methods may 

be used. For each subsequent fuel delivery, the permittee shall maintain a permanent file of the certified 

fuel sulfur analysis from the fuel vendor. At the request of the Compliance Authority, the permittee 

shall perform additional sampling and analysis for the fuel sulfur content.

The above methods shall be used to determine the fuel sulfur content in conjunction with the provisions of 

40 CFR 75 Appendix D. [Rules 62-4.070(3) and 62-4.160(15), F.A.C.] 

30. Emissions Performance Test Reports: A report indicating the results of any required emissions performance 

test shall be submitted to the Compliance Authority no later than 45 days after completion of the last test 

run. The test report shall provide sufficient detail on the tested emission unit and the procedures used to 

allow the Department to determine if the test was properly conducted and if the test results were properly 

computed. At a minimum, the test report shall provide the applicable information listed in Rule

62-297.310(8)(c), F.A.C. and in Appendix D of this permit. [Rule 62-297.310(8), F.A.C.].

31. Excess Emissions Reporting:

a. Malfunction Notification: If emissions in excess of a standard (subject to the specified averaging 

period) occur due to malfunction, the permittee shall notify the Compliance Authority within (1) 

working day of: the nature, extent, and duration of the excess emissions; the cause of the excess 

emissions; and the actions taken to correct the problem. In addition, the Department may request a 

written summary report of the incident.

b. SIP Quarterly Report: Within 30 days following the end of each calendar-quarter, the permittee shall 

submit a report to the Compliance Authority summarizing periods of NOX emissions in excess of the 

BACT permit standard following the NSPS format in 40 CFR 60.7(c), Subpart A. A summary of data 

excluded from SIP compliance calculations should also be provided. In addition, the report shall 

summarize the NOX CEMS system monitor availability for the previous quarter.

[Rules 62-4.130, 62-204.800, 62-210.700(6) and 62-212.400(BACT), F.A.C., and 40 CFR 60.7 

and 60.4375]

32. Annual Operating Report: The permittee shall submit an annual report that summarizes the actual operating 

hours and emissions from this facility in accordance with Rule 62-210.370. Annual operating reports shall 

be submitted to the Compliance Authority by April 1st of each year. [Rule 62-210.370(2), F.A.C.]
SECTION 3. EMISSIONS UNIT SPECIFIC CONDITIONS

A. Simple Cycle Combustion Turbines (EU-005 and 006)

Shady Hills Generating Station, Site Expansion Air Permit No. 1010373-012-AC

Permit Modification and Reissuance PSD-FL-402A

Page 13 of 17

33. Single Combustion Turbine Option – Fuel Oil Use Notification: If only one combustion turbine is 

constructed, the permittee shall submit a notification to the Compliance Authority no later than 15 days after 

the combustion turbine has operated for more than 500 hours ULSD fuel oil in a calendar year. Thereafter,

the permittee shall, upon request, promptly provide the Department with year-to-date records of hours of 

operation on ULSD fuel oil and natural gas for that calendar year. [Rule 62-4.070, F.A.C.]

FINAL BACT DETERMINATION FOR CARBON MONOXIDE

34. Temporary CO Continuous Emission Monitoring System (CO-CEMS): Within 270 days after the initial 

startup of the first combustion turbine authorized by this permit, the permittee shall install and certify a 

temporary CO-CEMS using the methodology described in 40 CFR 60, Appendix B, Performance Specification 4 

or 4A. If two combustion turbines are constructed, the permittee may select to install a temporary CO-CEMs on only 

one unit and the emission data shall be used to establish a limit for both combustion turbine units. The permittee shall 

for a period of 365 consecutive calendar days collect and preserve the collected data and shall code the data for 

inclusion and identification of data obtained during startups, shutdowns, malfunctions, low load conditions and normal 

operations. [Rules 62-070(3), 62-210.200 (BACT Definition), and 62-212.400, F.A.C.] 

{Permitting note: The Department requires ultimate submittal of all data because they may be considered in 

determining a final CO BACT determination that may define low load, startup, shutdown and malfunction excess 

emissions. The temporary CO-CEMS data do not have to be submitted until the due date of the technical report 

described in Condition 35. The demonstration CO-CEMS data will not be subject to the excess emission reporting 

requirements given in Condition 31 above.}

35. Final CO Emission Standard: Within 820 days of initial startup of the first combustion turbine, the 

permittee shall submit an application with a final CO emission standard proposal and compliance method 

consistent with the procedures for determining BACT or with procedures that demonstrate that the project is 

and will continue to be a minor stationary source of CO. The application shall include a technical report 

summarizing the data collected using the temporary CO-CEMS installed pursuant to Condition 34 above. 

[Rules 62-070(3), 62-210.200 (BACT Definition), and 62-212.400, F.A.C.]
SECTION 3. EMISSIONS UNIT SPECIFIC CONDITIONS

B. 2500 kW Emergency Generator (EU-007)

Shady Hills Generating Station, Site Expansion Air Permit No. 1010373-012-AC

Permit Modification and Reissuance PSD-FL-402A

Page 14 of 17

This section of the permit addresses the following emissions unit.

ID No. Emission Unit Description

007 One 2,500 kilowatts Emergency Generator (model year 2011 or later)

APPLICABLE STANDARDS AND REGULATIONS

1. NSPS, Subpart IIII Applicability: This emergency generator is a Stationary Compression Ignition Internal 

Combustion Engine (Stationary ICE) and is subject to 40 CFR 60, Subpart IIII. The applicant shall comply 

with 40 CFR 60, Subpart IIII only to the extent that the regulations apply to the emission unit and its 

operations (e.g. non-road, emergency, displacement, capacity and model year selected).

[40 CFR 60, Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal 

Combustion Engines and Rule 62-204.800(8)(b)79., F.A.C.]

2. NESHAP, Subpart ZZZZ Applicability: This emergency generator is a Stationary Reciprocating Internal 

Combustion engine located at an area source of hazardous air pollutants emissions and is subject to 40 CFR 

63, Subpart ZZZZ. Because this emergency generator is subject to regulation under 40 CFR 60, Subpart 

IIII, the Subpart ZZZZ only requires that the emergency generator meet the requirements of 40 CFR 60, 

Subpart IIII. No further requirements of Subpart ZZZZ apply to this emergency generator. 

[40 CFR 63, subpart ZZZZ - National Emissions Standards for Hazardous Air Pollutants for Stationary 

Reciprocating Internal Combustion Engines, section 63.6590(c) and Rule 62-204.800(11)(b)82., F.A.C.]

EQUIPMENT SPECIFICATIONS

3. Equipment: The permittee is authorized to install, operate, and maintain one fuel oil-fired emergency 

generator. [Applicant Request; Rule 62-210.200(PTE), F.A.C.]

EMISSIONS AND PERFORMANCE REQUIREMENTS

4. Hours of Operation and Fuel Specifications: The hours of operation shall not exceed 500 hours per year. 

The generator shall burn distillate fuel oil with a sulfur content of 15 parts per million (ppm) or less. 

[Applicant Request; Rule 62-210.200(PTE), F.A.C.]

5. Fuel: Total fuel consumption of the emergency generator and four ancillary generators shall be no more 

than 77,750 gallons of distillate fuel oil per year. [Application]

6. Emergency Generator Emission Limits: 

Emergency Generator

(> 560 kilowatts)

CO

(g/kW-hr)1

PM

(g/kW-hr)

NMHC2+NOX

(g/kW-hr)

Diesel Fuel3

(sulfur)

2011 and later 3.5 0.20 6.4 15 ppm

1. g/kW-hr means grams per kilowatt-hour.

2. NMHC means Non-Methane Hydrocarbons. 

3. Nonroad diesel specification of 15 ppm is from 40 CFR part 80, subpart I – Motor Vehicle Diesel Fuel; Nonroad, 

Locomotive, and Marine Diesel Fuel; and ECA Marine Fuel. 

[Applicant Request; 62-212.400(BACT), F.A.C.; NSPS Subpart IIII]

7. Emergency Generator Testing Requirements: This unit shall be stack tested to demonstrate initial 

compliance with the emission standards for CO and NOX. The tests shall be conducted within 60 days after 

achieving the maximum production rate at which the unit will be operated, but not later than 180 days after 

the initial startup of this unit. As an alternative, an EPA certification of emissions characteristics of the 

purchased model that are at least as stringent as the BACT (NSPS Subpart IIII) values and the use of

ultralow sulfur distillate fuel oil or nonroad diesel fuel with a sulfur content of 15 ppm or less can be used to 

fulfill this requirement. [Rule 62-297.310(7)(a)1, F.A.C.; 40 CFR 60.8 and 40 CFR 60.4211]
SECTION 3. EMISSIONS UNIT SPECIFIC CONDITIONS

B. 2500 kW Emergency Generator (EU-007)

Shady Hills Generating Station, Site Expansion Air Permit No. 1010373-012-AC

Permit Modification and Reissuance PSD-FL-402A

Page 15 of 17

8. Test Methods: Any required tests shall be performed in accordance with the following reference methods.

Method Description of Method and Comments

7E Determination of Nitrogen Oxides Emissions from Stationary Sources

10 Determination of Carbon Monoxide Emissions from Stationary Sources

NOTIFICATION, REPORTING AND RECORDS

9. Notifications: Initial notifications are required pursuant to 40 CFR 60.7, 40 CFR 63.9, and 40 CFR 63.6590 

(b) (i) for the 2500 kW emergency generator.

10. Reporting: The permittee shall maintain records of the amount of liquid fuel used. These records shall be 

submitted to the Compliance Authority on an annual basis or upon request. [Rule 62-4.070(3), F.A.C.]
SECTION 3. EMISSIONS UNIT SPECIFIC CONDITIONS

C. Natural Gas Heater (EU-008)

Shady Hills Generating Station, Site Expansion Air Permit No. 1010373-012-AC

Permit Modification and Reissuance PSD-FL-402A

Page 16 of 17

This section of the permit addresses the following emissions unit.

ID No. Emission Unit Description

008 10 MMBtu/hour Natural Gas Heater 

EQUIPMENT

1. Natural Gas Heater: The permittee is authorized to install, operate, and maintain one natural gas heater for 

the purpose of heating the natural gas supply to the combustion turbines. 

[Application]

PERFORMANCE RESTRICTIONS

2. Authorized Fuel: The natural gas heater shall fire only natural gas with a maximum fuel sulfur content of 

1.5 grains/100 scf. [Application; Rules 62-210.200(PTE) and 62-296.406(BACT) F.A.C.]

3. Hours of Operation: The natural gas heater is allowed to operate 3,390 hours/year/installed CTG. 

[Applicant Request and Rule 62-210.200(PTE), F.A.C.] 

REGULATORY APPLICABILITY

4. Small Boiler BACT: The natural gas heater is subject to the requirements of Rule 62-296.406, F.A.C., 

which includes a determination of the Best Available Control Technology (BACT) for PM and SO2

emissions. For this project, BACT for PM and SO2 emissions is determine to be the firing of natural gas

with a maximum fuel sulfur content of 1.5 grains/100 scf as the only authorized fuel. 

[Rule 62-296.406, F.A.C.]

5. NSPS Subpart Dc and Subpart A Applicability: The natural gas heater is subject to all applicable 

requirements of 40 CFR 60, Subpart Dc which applies to Small Industrial, Commercial or Institutional 

Boilers and Subpart A, General Provisions. Specifically, this emission unit shall comply with 40 CFR 

60.48c Reporting and Recordkeeping Requirements. The applicable conditions are given in Appendices A 

and Dc of this permit. 

[Rule 62-204.800(7)(b) and 40 CFR 60, NSPS-Subpart Dc - Standards of Performance for Small IndustrialCommercial-Institutional Steam Generating Units, attached as Appendix J].

EMISSIONS STANDARDS

6. BACT Determination: The determination of BACT for this emissions unit is the requirement that the heater

only fire of natural gas with a maximum fuel sulfur content of 1.5 grains/100 scf. 

[Rules 62-296.406; 62-4.070(3) and 62-210.200(BACT), F.A.C.]

NOTIFICATIONS, RECORDS AND REPORTS

7. Notification: Initial notification is required for the natural gas heater. [40 CFR 60.7]

8. Reporting: The permittee shall maintain records of the amount of natural gas used in the heater. These 

records shall be submitted to the Compliance Authority on an annual basis or upon request. 

[Rule 62-4.070(3] F.A.C.]
SECTION 3. EMISSIONS UNIT SPECIFIC CONDITIONS

D. 2.8 Million Gallon Distillate Fuel Oil Tank (EU-009)

Shady Hills Generating Station, Site Expansion Air Permit No. 1010373-012-AC

Permit Modification and Reissuance PSD-FL-402A

Page 17 of 17

ID No. Emission Unit Description

009 2.8 Million Gallon Ultralow Sulfur Distillate Fuel Oil Storage Tank

NSPS APPLICABILITY

1. NSPS, Subpart Kb Applicability: Based on the true vapor pressure of ultralow sulfur distillate fuel (< 3.5 

kilopascals), the storage tank is not subject to 40 CFR 60, Subpart Kb - Standards of Performance for 

Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for Which 

Construction, Reconstruction, or Modification Commenced After July 23, 1984. 

[Application; 40 CFR 60.110b(b)] 

EQUIPMENT SPECIFICATIONS

2. Equipment: The permittee is authorized to operate, and maintain one nominal 2.8 million gallon distillate 

fuel oil storage tank to provide fuel oil to Units 005 and 006 or to other units on the site. [Application]

EMISSIONS AND PERFORMANCE REQUIREMENTS

3. Hours of Operation: The hours of operation are not restricted (8,760 hours per year). [Application]

NOTIFICATION, REPORTING AND RECORDS

4. Ultralow Sulfur Distillate Fuel Oil Records: The permittee shall keep readily accessible records showing 

the maximum true vapor pressure of the stored liquid. Compliance with this condition may be demonstrated 

by using the information from the respective manufacturers safety data sheets (MSDS) for the fuel oil stored 

in the tanks. [Rule 62-4.070(3) F.A.C.; avoidance of 40 CFR 60, Subpart Kb]
APPENDIX B

FDEP AIR APPLICATION FORMS 
Department of 

Environmental Protection

Division of Air Resource Management 

APPLICATION FOR AIR PERMIT - LONG FORM 

DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 1 

I. APPLICATION INFORMATION 

Air Construction Permit – Use this form to apply for an air construction permit: 

• For any required purpose at a facility operating under a federally enforceable state air operation 

permit (FESOP) or Title V air operation permit; 

• For a proposed project subject to prevention of significant deterioration (PSD) review, nonattainment 

new source review, or maximum achievable control technology (MACT); 

• To assume a restriction on the potential emissions of one or more pollutants to escape a requirement 

such as PSD review, nonattainment new source review, MACT, or Title V; or 

• To establish, revise, or renew a plantwide applicability limit (PAL). 

Air Operation Permit – Use this form to apply for: 

• An initial federally enforceable state air operation permit (FESOP); or 

• An initial, revised, or renewal Title V air operation permit. 

To ensure accuracy, please see form instructions. 

Identification of Facility 

1. Facility Owner/Company Name: Shady Hills Power Company, LLC

2. Site Name: Shady Hills Generating Station

3. Facility Identification Number: 1010373

4. Facility Location... 

 Street Address or Other Locator: 14240 Merchant Energy Way

 City: Spring Hill County: Pasco Zip Code: 34610

5. Relocatable Facility? 

 Yes No 

6. Existing Title V Permitted Facility? 

 Yes No 

Application Contact 

1. Application Contact Name: Roy S. Belden

2. Application Contact Mailing Address... 

 Organization/Firm: Shady Hills Power Company, LLC

 Street Address: 800 Long Ridge Rd.

 City: Stamford State: CT Zip Code: 06927

3. Application Contact Telephone Numbers... 

 Telephone: (203) 357-6820 ext. Fax: Fax: (203) 967-5116

4. Application Contact E-mail Address: Roy.Belden@GE.com

Application Processing Information (DEP Use) 

1. Date of Receipt of Application: 3. PSD Number (if applicable): 

2. Project Number(s): 4. Siting Number (if applicable): 
APPLICATION INFORMATION 

DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 2 

Purpose of Application 

This application for air permit is being submitted to obtain: (Check one)

Air Construction Permit 

 Air construction permit. 

 Air construction permit to establish, revise, or renew a plantwide applicability limit (PAL). 

 Air construction permit to establish, revise, or renew a plantwide applicability limit (PAL), 

and separate air construction permit to authorize construction or modification of one or 

more emissions units covered by the PAL. 

Air Operation Permit 

 Initial Title V air operation permit. 

 Title V air operation permit revision. 

 Title V air operation permit renewal. 

 Initial federally enforceable state air operation permit (FESOP) where professional 

engineer (PE) certification is required. 

 Initial federally enforceable state air operation permit (FESOP) where professional 

engineer (PE) certification is not required. 

Air Construction Permit and Revised/Renewal Title V Air Operation Permit 

(Concurrent Processing) 

 Air construction permit and Title V permit revision, incorporating the proposed project. 

 Air construction permit and Title V permit renewal, incorporating the proposed project. 

Note: By checking one of the above two boxes, you, the applicant, are 

requesting concurrent processing pursuant to Rule 62-213.405, F.A.C. In 

such case, you must also check the following box: 

 I hereby request that the department waive the processing time 

requirements of the air construction permit to accommodate the 

processing time frames of the Title V air operation permit. 

Application Comment 

This application is a supplemental air construction permit application to the July, 2010, Air 

Permit Application and Prevention of Significant Deterioration Analysis, and Final FDEP Permit 

No. 1010373-012-AC, PSD-FL-402A, for the Shady Hills Generation Station. This application 

provides PSD review analyses of GHG emissions from the project. The project will consist of two 

General Electric Frame 7FA.05 CTs (GE 7FA.05) and associated facilities. The GE 7FA.05 units 

will each be equipped with evaporative cooling. The annual maximum capacity factor of the 

plant will be 39 percent per CT, which is equivalent to operating 6,554,565 MMBtu/CT/year 

(3,390 hours/year) at full load per CT). Natural gas will be used as the primary fuel, and fuel oil 

will be used as a backup fuel. The project will require an additional gas heater, emergency 

generator and fuel oil storage tank for the two new CTs. 
APPLICATION INFORMATION 

DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 3 

Scope of Application

Emissions 

Unit ID

Number 

Description of Emissions Unit

Air 

Permit 

Type 

Air Permit 

Processing 

Fee

005 223 Megawatt Simple-Cycle Combustion 

Turbine 

AC1A 

006 223 Megawatt Simple-Cycle Combustion 

Turbine 

AC1A 

007 Emergency Generator AC1E 

008 Natural Gas Heater AC1F 

009 Distillate Fuel Oil Storage Tank AC1F 

 

 

 

 

 

 

 

 

 

 

Application Processing Fee 

Check one: Attached - Amount: Not Applicable

APPLICATION INFORMATION 

DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 5 

Application Responsible Official Certification 

Complete if applying for an initial, revised, or renewal Title V air operation permit or 

concurrent processing of an air construction permit and revised or renewal Title V air 

operation permit. If there are multiple responsible officials, the “application responsible 

official” need not be the “primary responsible official.” 

1. Application Responsible Official Name: 

 

2. Application Responsible Official Qualification (Check one or more of the following 

options, as applicable): 

 For a corporation, the president, secretary, treasurer, or vice-president of the corporation in 

charge of a principal business function, or any other person who performs similar policy or 

decision-making functions for the corporation, or a duly authorized representative of such 

person if the representative is responsible for the overall operation of one or more 

manufacturing, production, or operating facilities applying for or subject to a permit under 

Chapter 62-213, F.A.C.

 For a partnership or sole proprietorship, a general partner or the proprietor, respectively. 

 For a municipality, county, state, federal, or other public agency, either a principal executive 

officer or ranking elected official. 

 The designated representative at an Acid Rain source or CAIR source.

3. Application Responsible Official Mailing Address... 

 Organization/Firm: 

Street Address: 

City: State: Zip Code: 

4. Application Responsible Official Telephone Numbers... 

 Telephone: ( ) - ext. Fax: ( ) - 

5. Application Responsible Official E-mail Address: 

6. Application Responsible Official Certification: 

I, the undersigned, am a responsible official of the Title V source addressed in this air permit application. 

I hereby certify, based on information and belief formed after reasonable inquiry, that the statements

made in this application are true, accurate and complete and that, to the best of my knowledge, any 

estimates of emissions reported in this application are based upon reasonable techniques for calculating 

emissions. The air pollutant emissions units and air pollution control equipment described in this 

application will be operated and maintained so as to comply with all applicable standards for control of 

air pollutant emissions found in the statutes of the State of Florida and rules of the Department of 

Environmental Protection and revisions thereof and all other applicable requirements identified in this 

application to which the Title V source is subject. I understand that a permit, if granted by the 

department, cannot be transferred without authorization from the department, and I will promptly notify 

the department upon sale or legal transfer of the facility or any permitted emissions unit. Finally, I 

certify that the facility and each emissions unit are in compliance with all applicable requirements to 

which they are subject, except as identified in compliance plan(s) submitted with this application. 

 

 Signature Date 

DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 7 

II. FACILITY INFORMATION 

A. GENERAL FACILITY INFORMATION 

Facility Location and Type 

1. Facility UTM Coordinates... 

 Zone 17 East (km) 347.0 

North (km) 3,139.0 

2. Facility Latitude/Longitude... 

 Latitude (DD/MM/SS) 28/22/00 

 Longitude (DD/MM/SS) 82/33/30

3. Governmental 

 Facility Code: 

 0

4. Facility Status 

 Code: 

 A

5. Facility Major 

 Group SIC Code: 

 49

6. Facility SIC(s): 

 

 4911

7. Facility Comment : 

 

Facility Contact 

1. Facility Contact Name: 

 Roy S. Belden, Vice President

2. Facility Contact Mailing Address... 

 Organization/Firm: Shady Hills Power Company, LLC

Street Address: 800 Long Ridge Rd.

City: Stamford State: CT Zip Code: 06927

3. Facility Contact Telephone Numbers: 

 Telephone: (203) 357-6820 ext. Fax: (203) 967-5116

4. Facility Contact E-mail Address: Roy.Belden@GE.com

Facility Primary Responsible Official 

Complete if an “application responsible official” is identified in Section I that is not the 

facility “primary responsible official.”

1. Facility Primary Responsible Official Name: 

 

2. Facility Primary Responsible Official Mailing Address... 

 Organization/Firm: 

Street Address: 

City: State: Zip Code: 

3. Facility Primary Responsible Official Telephone Numbers... 

 Telephone: ( ) - ext. Fax: ( ) - 

4. Facility Primary Responsible Official E-mail Address: 
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 8 

Facility Regulatory Classifications 

Check all that would apply following completion of all projects and implementation of all 

other changes proposed in this application for air permit. Refer to instructions to 

distinguish between a “major source” and a “synthetic minor source.” 

1. Small Business Stationary Source Unknown 

2. Synthetic Non-Title V Source 

3. Title V Source 

4. Major Source of Air Pollutants, Other than Hazardous Air Pollutants (HAPs) 

5. Synthetic Minor Source of Air Pollutants, Other than HAPs 

6. Major Source of Hazardous Air Pollutants (HAPs) 

7. Synthetic Minor Source of HAPs 

8. One or More Emissions Units Subject to NSPS (40 CFR Part 60) 

9. One or More Emissions Units Subject to Emission Guidelines (40 CFR Part 60) 

10. One or More Emissions Units Subject to NESHAP (40 CFR Part 61 or Part 63) 

11. Title V Source Solely by EPA Designation (40 CFR 70.3(a)(5)) 

12. Facility Regulatory Classifications Comment: 

Emissions units 005, and 006 are subject to NSPS Subpart KKKK - Standards of Performance for 

Stationary Gas Turbines. 

Emergency Generator, emission unit 007: 

• NSPS Subpart IIII – Standards of Performance for Stationary Compression Ignition Internal 

Combustion Engines. 

• NESHAP Subpart ZZZZ. 

Emission unit 009, the proposed 2.8 million gallon fuel oil storage tank, is subject to NSPS Subpart Kb 

– Standards of Performance for Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid 

Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced After July 23, 

1984. 
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 9 

List of Pollutants Emitted by Facility 

1. Pollutant Emitted 2. Pollutant Classification 3. Emissions Cap 

 [Y or N]? 

PM/PM10/ PM2.5 A N

CO A N

VOC A N

SO2

A N

NOx

A N

CO2e A N

 

 

 

 

 

 

 
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 10 

B. EMISSIONS CAPS 

Facility-Wide or Multi-Unit Emissions Caps 

1. Pollutant 

 Subject to 

 Emissions

 Cap 

2. Facility- 

 Wide Cap 

 [Y or N]? 

 (all units) 

3. Emissions 

 Unit ID’s 

 Under Cap 

 (if not all units) 

4. Hourly 

 Cap 

 (lb/hr) 

5. Annual 

 Cap 

 (ton/yr) 

6. Basis for 

 Emissions 

 Cap 

 

7. Facility-Wide or Multi-Unit Emissions Cap Comment: 

 
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 11 

C. FACILITY ADDITIONAL INFORMATION 

Additional Requirements for All Applications, Except as Otherwise Stated 

1. Facility Plot Plan: (Required for all permit applications, except Title V air operation permit 

revision applications if this information was submitted to the department within the previous 

five years and would not be altered as a result of the revision being sought) 

 Attached, Document ID: See Note Previously Submitted, Date: 

2. Process Flow Diagram(s): (Required for all permit applications, except Title V air operation 

permit revision applications if this information was submitted to the department within the 

previous five years and would not be altered as a result of the revision being sought) 

 Attached, Document ID: See Note Previously Submitted, Date: 

3. Precautions to Prevent Emissions of Unconfined Particulate Matter: (Required for all 

permit applications, except Title V air operation permit revision applications if this information 

was submitted to the department within the previous five years and would not be altered as a 

result of the revision being sought) 

 Attached, Document ID: NA Previously Submitted, Date: 

Additional Requirements for Air Construction Permit Applications 

1. Area Map Showing Facility Location: 

 Attached, Document ID: See Note Not Applicable (existing permitted facility)

2. Description of Proposed Construction, Modification, or Plantwide Applicability Limit 

(PAL): 

 Attached, Document ID: NA 

3. Rule Applicability Analysis: 

 Attached, Document ID: See Report for GHG Rule Applicability Analysis

4. List of Exempt Emissions Units: 

 Attached, Document ID: Not Applicable (no exempt units at facility)

5. Fugitive Emissions Identification: 

 Attached, Document ID: Not Applicable 

6. Air Quality Analysis (Rule 62-212.400(7), F.A.C.): 

 Attached, Document ID: See Note Not Applicable 

7. Source Impact Analysis (Rule 62-212.400(5), F.A.C.): 

 Attached, Document ID: See Note Not Applicable 

8. Air Quality Impact since 1977 (Rule 62-212.400(4)(e), F.A.C.): 

 Attached, Document ID: See Note Not Applicable 

9. Additional Impact Analyses (Rules 62-212.400(8) and 62-212.500(4)(e), F.A.C.): 

 Attached, Document ID: See Note Not Applicable 

10. Alternative Analysis Requirement (Rule 62-212.500(4)(g), F.A.C.): 

 Attached, Document ID: Not Applicable

Note: See Air Permit Application and Prevention of Significant Deterioration Analysis for 

the Shady Hills Generation Station, July, 2010.
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 12 

C. FACILITY ADDITIONAL INFORMATION (CONTINUED) 

Additional Requirements for FESOP Applications 

1. List of Exempt Emissions Units: 

 Attached, Document ID: Not Applicable (no exempt units at facility)

Additional Requirements for Title V Air Operation Permit Applications NA 

1. List of Insignificant Activities: (Required for initial/renewal applications only)

 Attached, Document ID: Not Applicable (revision application) 

2. Identification of Applicable Requirements: (Required for initial/renewal applications, and 

for revision applications if this information would be changed as a result of the revision being 

sought) 

 Attached, Document ID: 

 Not Applicable (revision application with no change in applicable requirements) 

3. Compliance Report and Plan: (Required for all initial/revision/renewal applications) 

 Attached, Document ID: 

Note: A compliance plan must be submitted for each emissions unit that is not in compliance with 

all applicable requirements at the time of application and/or at any time during application 

processing. The department must be notified of any changes in compliance status during 

application processing. 

4. List of Equipment/Activities Regulated under Title VI: (If applicable, required for 

initial/renewal applications only) 

 Attached, Document ID: 

 Equipment/Activities Onsite but Not Required to be Individually Listed 

 Not Applicable 

5. Verification of Risk Management Plan Submission to EPA: (If applicable, required for 

initial/renewal applications only) 

 Attached, Document ID: Not Applicable 

6. Requested Changes to Current Title V Air Operation Permit: 

 Attached, Document ID: Not Applicable 
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 13 

C. FACILITY ADDITIONAL INFORMATION (CONTINUED) 

Additional Requirements for Facilities Subject to Acid Rain, CAIR, or Hg Budget Program 

1. Acid Rain Program Forms: 

Acid Rain Part Application (DEP Form No. 62-210.900(1)(a)): 

 Attached, Document ID: See Note Previously Submitted, Date: 

 Not Applicable (not an Acid Rain source) 

Phase II NOX Averaging Plan (DEP Form No. 62-210.900(1)(a)1.): 

 Attached, Document ID: Previously Submitted, Date: 

 Not Applicable 

New Unit Exemption (DEP Form No. 62-210.900(1)(a)2.): 

 Attached, Document ID: Previously Submitted, Date: 

 Not Applicable 

2. CAIR Part (DEP Form No. 62-210.900(1)(b)): 

 Attached, Document ID: See Note Previously Submitted, Date: 

 Not Applicable (not a CAIR source) 

Note: See Air Permit Application and Prevention of Significant Deterioration Analysis for 

the Shady Hills Generation Station, July, 2010. 

Additional Requirements Comment 
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 14

EMISSIONS UNIT INFORMATION

Section [1] of [4]

Simple-Cycle Combustion Turbines

III. EMISSIONS UNIT INFORMATION

Title V Air Operation Permit Application - For Title V air operation permitting only, emissions units 

are classified as regulated, unregulated, or insignificant. If this is an application for an initial, revised or 

renewal Title V air operation permit, a separate Emissions Unit Information Section (including 

subsections A through I as required) must be completed for each regulated and unregulated emissions 

unit addressed in this application. Some of the subsections comprising the Emissions Unit Information 

Section of the form are optional for unregulated emissions units. Each such subsection is appropriately 

marked. Insignificant emissions units are required to be listed at Section II, Subsection C.

Air Construction Permit or FESOP Application - For air construction permitting or federally 

enforceable state air operation permitting, emissions units are classified as either subject to air permitting 

or exempt from air permitting. The concept of an “unregulated emissions unit” does not apply. If this is 

an application for an air construction permit or FESOP, a separate Emissions Unit Information Section 

(including subsections A through I as required) must be completed for each emissions unit subject to air 

permitting addressed in this application for air permit. Emissions units exempt from air permitting are 

required to be listed at Section II, Subsection C.

Air Construction Permit and Revised/Renewal Title V Air Operation Permit Application – Where 

this application is used to apply for both an air construction permit and a revised or renewal Title V air 

operation permit, each emissions unit is classified as either subject to air permitting or exempt from air 

permitting for air construction permitting purposes, and as regulated, unregulated, or insignificant for 

Title V air operation permitting purposes. A separate Emissions Unit Information Section (including 

subsections A through I as required) must be completed for each emissions unit addressed in this 

application that is subject to air construction permitting and for each such emissions unit that is a 

regulated or unregulated unit for purposes of Title V permitting. (An emissions unit may be exempt from 

air construction permitting but still be classified as an unregulated unit for Title V purposes.) Emissions 

units classified as insignificant for Title V purposes are required to be listed at Section II, Subsection C.

If submitting the application form in hard copy, the number of this Emissions Unit Information Section 

and the total number of Emissions Unit Information Sections submitted as part of this application must be

indicated in the space provided at the top of each page.
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 15

EMISSIONS UNIT INFORMATION

Section [1] of [4]

Simple-Cycle Combustion Turbines

A. GENERAL EMISSIONS UNIT INFORMATION

Title V Air Operation Permit Emissions Unit Classification 

1. Regulated or Unregulated Emissions Unit? (Check one, if applying for an initial, revised 

or renewal Title V air operation permit. Skip this item if applying for an air construction 

permit or FESOP only.)

The emissions unit addressed in this Emissions Unit Information Section is a regulated 

emissions unit.

The emissions unit addressed in this Emissions Unit Information Section is an 

unregulated emissions unit.

Emissions Unit Description and Status

1. Type of Emissions Unit Addressed in this Section: (Check one)

This Emissions Unit Information Section addresses, as a single emissions unit, a single 

process or production unit, or activity, which produces one or more air pollutants and 

which has at least one definable emission point (stack or vent).

This Emissions Unit Information Section addresses, as a single emissions unit, a group 

of process or production units and activities which has at least one definable emission 

point (stack or vent) but may also produce fugitive emissions.

This Emissions Unit Information Section addresses, as a single emissions unit, one or 

more process or production units and activities which produce fugitive emissions only. 

2. Description of Emissions Unit Addressed in this Section:

Two simple-cycle combustion turbines.a

3. Emissions Unit Identification Number: 005 and 006

4. Emissions Unit

Status Code:

 C

5. Commence

Construction 

Date:

6. Initial Startup 

Date:

7. Emissions Unit 

Major Group

SIC Code:

49

8. Federal Program Applicability: (Check all that apply)

Acid Rain Unit

CAIR Unit

9. Package Unit:

Manufacturer: GE Model Number: 7FA.05

10. Generator Nameplate Rating: 223 MW/CTb

11. Emissions Unit Comment: 

a

. Two simple cycle General Electric Model 7FA.05 (GE 7FA.05) combustion turbines.

b Parameter of distillate oil at 59◦

F and 100% base load.
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 16

EMISSIONS UNIT INFORMATION

Section [1] of [4]

Simple-Cycle Combustion Turbines

Emissions Unit Control Equipment/Method: Control 1 of 1

1. Control Equipment/Method Description:

Water injection for NOx control (distillate oil firing).

 Dry Low NOx burner for NOx control (natural gas burning).

2. Control Device or Method Code: 028, 025

Emissions Unit Control Equipment/Method: Control of 

1. Control Equipment/Method Description:

2. Control Device or Method Code:

Emissions Unit Control Equipment/Method: Control of 

1. Control Equipment/Method Description:

2. Control Device or Method Code:

Emissions Unit Control Equipment/Method: Control of 

1. Control Equipment/Method Description:

2. Control Device or Method Code:
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 17

EMISSIONS UNIT INFORMATION

Section [1] of [4]

Simple-Cycle Combustion Turbines

B. EMISSIONS UNIT CAPACITY INFORMATION

(Optional for unregulated emissions units.)

Emissions Unit Operating Capacity and Schedule

1. Maximum Process or Throughput Rate:

2. Maximum Production Rate:

3. Maximum Heat Input Rate: 2,106.9 million Btu/hra

4. Maximum Incineration Rate: pounds/hr

tons/day

5. Requested Maximum Operating Schedule:

24 hours/day 7 days/week

52 weeks/year (See Below)hours/year

6. Operating Capacity/Schedule Comment:

a Parameter of distillate oil at 59◦

F and 100% base load.

Maximum heat input rates: Natural gas firing - 1,923 MMBtu/hr

 Distillate fuel oil firing - 2,117 MMBtu/hr

Maximum heat input rates are based on lower heating value of each fuel at ambient conditions of 59 degree 

F, 60 percent RH, 100 percent load, and 14.7 psi pressure.

Three proposed operating scenarios:

1. 2 CTs operating 3,390 hours per CT including 1,000 hours of total oil firing;

2. 2 CTs operating 3,390 hours per CT, 100% natural gas firing;

3. 1 CT, operating 1,640 hours of natural gas firing and 750 hours of oil firing.
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 18

EMISSIONS UNIT INFORMATION

Section [1] of [4]

Simple-Cycle Combustion Turbines

C. EMISSION POINT (STACK/VENT) INFORMATION

(Optional for unregulated emissions units.)

Emission Point Description and Type

1. Identification of Point on Plot Plan or 

Flow Diagram: 005 and 006

2. Emission Point Type Code:

3. Descriptions of Emission Points Comprising this Emissions Unit for VE Tracking:

4. ID Numbers or Descriptions of Emission Units with this Emission Point in Common:

5. Discharge Type Code:

V

6. Stack Height:

75 feet

7. Exit Diameter:

18 feet

8. Exit Temperature:

1,099F

a

9. Actual Volumetric Flow Rate:

2,780,256 acfma

10. Water Vapor:

12.11 %

a

11. Maximum Dry Standard Flow Rate:

dscfm

12. Nonstack Emission Point Height:

feet

13. Emission Point UTM Coordinates...

Zone: 17 East (km): 347.0 

North (km): 3,139.0 

14. Emission Point Latitude/Longitude...

Latitude (DD/MM/SS) 28/22/00

Longitude (DD/MM/SS) 82/33/30

15. Emission Point Comment:

a Parameter of distillate oil at 59◦

F and 100% base load. 
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 19

EMISSIONS UNIT INFORMATION

Section [1] of [4]

Simple-Cycle Combustion Turbines

D. SEGMENT (PROCESS/FUEL) INFORMATION

Segment Description and Rate: Segment 1 of 2

1. Segment Description (Process/Fuel Type):

Internal Combustion Engines; Electric Generation; Natural-Gas Firing

2. Source Classification Code (SCC):

2-01-002-01

3. SCC Units:

Million cubic feet natural gas burned

4. Maximum Hourly Rate:

2.06

5. Maximum Annual Rate:

6,983 Per CT

6. Estimated Annual Activity 

Factor:

7. Maximum % Sulfur: 8. Maximum % Ash: 9. Million Btu per SCC Unit:

933

10. Segment Comment:

Based on natural gas lower heating value (LHV) of 933 Btu/ft3.

Maximum hourly rate = 1923 MMBtu/hr /933 MMBtu/MM ft3 = 2.06 MM ft3/hr

Maximum annual rate = 2.06 MM ft3/hr x 3,390 hr/yr = 6,983 MM ft3/yr. (Scenario 2.)

Segment Description and Rate: Segment 2 of 2

1. Segment Description (Process/Fuel Type):

Internal Combustion Engines; Electric Generation; Distillate Oil Firing

2. Source Classification Code (SCC):

2-01-001-01

3. SCC Units:

1000 Gallons burned

4. Maximum Hourly Rate:

16.04 Per CT

5. Maximum Annual Rate:

16,040 Total 2 CTs

6. Estimated Annual Activity 

Factor: 

7. Maximum % Sulfur:

0.0015

8. Maximum % Ash: 9. Million Btu per SCC Unit:

132

10. Segment Comment:

Based on distillate oil LHV of 132 MMBtu/1,000 gal

Maximum hourly rate = 2,117 MMBtu/hr /132 MMBtu/1,000 gallon = 16.04 1,000 gallons/hr. 

Maximum annual rate = 16,040 gallons/hr x 1,000 hr/yr = 16,040 1,000 gallons/yr. (Scenario 1)
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 20

EMISSIONS UNIT INFORMATION

Section [1] of [4]

Simple-Cycle Combustion Turbines

E. EMISSIONS UNIT POLLUTANTS

List of Pollutants Emitted by Emissions Unit

1. Pollutant Emitted 2. Primary Control 

Device Code

3. Secondary Control 

Device Code

4. Pollutant 

Regulatory Code

CO2e EL
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 21

EMISSIONS UNIT INFORMATION POLLUTANT DETAIL INFORMATION

Section [1] of [4] Page [1] of [1]

Simple-Cycle Combustion Turbines CO2e

F1. EMISSIONS UNIT POLLUTANT DETAIL INFORMATION –

POTENTIAL, FUGITIVE, AND ACTUAL EMISSIONS

(Optional for unregulated emissions units.)

Complete a Subsection F1 for each pollutant identified in Subsection E if applying for an 

air construction permit or concurrent processing of an air construction permit and a 

revised or renewal Title V operation permit. Complete for each emissions-limited pollutant 

identified in Subsection E if applying for an air operation permit.

Potential, Estimated Fugitive, and Baseline & Projected Actual Emissions

1. Pollutant Emitted:

CO2e

2. Total Percent Efficiency of Control:

3. Potential Emissions:

(See Table 1) lb/hour (See Table 1) tons/year

4. Synthetically Limited?

Yes No

5. Range of Estimated Fugitive Emissions (as applicable):

 to tons/year

6. Emission Factor: Multi-Component, See Table 1

Reference: Appendix G, 40 CFR Part 75 and 40 CFR Part 98

7. Emissions

Method Code:

5

8.a. Baseline Actual Emissions (if required):

tons/year

8.b. Baseline 24-month Period:

From: To:

9.a. Projected Actual Emissions (if required):

tons/year

9.b. Projected Monitoring Period:

 5 years 10 years

10. Calculation of Emissions:

Table 1 provides lb/hr emission rates for 100 % load and 59F, for both natural gas firing 

and fuel oil firing.

Annual emission provided in Table 1 for three operating scenarios:

1. 2 CTs operating 3,390 hours per CT including 1,000 hours of total oil firing;

2. 2 CTs operating 3,390 hours per CT, 100% natural gas firing;

3. 1 CT, operating 1,640 hours of natural gas firing and 750 hours of oil firing.

11. Potential, Fugitive, and Actual Emissions Comment:
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 22

EMISSIONS UNIT INFORMATION POLLUTANT DETAIL INFORMATION

Section [1] of [4] Page [1] of [1]

Simple-Cycle Combustion Turbines CO2e

F2. EMISSIONS UNIT POLLUTANT DETAIL INFORMATION -

ALLOWABLE EMISSIONS

Complete Subsection F2 if the pollutant identified in Subsection F1 is or would be subject 

to a numerical emissions limitation.

Allowable Emissions Allowable Emissions 1 of 1

1. Basis for Allowable Emissions Code:

BACT

2. Future Effective Date of Allowable

Emissions:

3. Allowable Emissions and Units:

See Table 3

4. Equivalent Allowable Emissions:

lb/hour 833,796 tons/year

5. Method of Compliance:

40 CFR Part 75, Appendix G and 40 CFR Part 98 Emission Factors.

6. Allowable Emissions Comment (Description of Operating Method):

See Table 3.

Allowable Emissions Allowable Emissions of 

1. Basis for Allowable Emissions Code: 2. Future Effective Date of Allowable

Emissions: 

3. Allowable Emissions and Units: 4. Equivalent Allowable Emissions:

lb/hour tons/year

5. Method of Compliance:

6. Allowable Emissions Comment (Description of Operating Method):

Allowable Emissions Allowable Emissions of 

1. Basis for Allowable Emissions Code: 2. Future Effective Date of Allowable

Emissions:

3. Allowable Emissions and Units: 4. Equivalent Allowable Emissions:

lb/hour tons/year

5. Method of Compliance:

6. Allowable Emissions Comment (Description of Operating Method):
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 23

EMISSIONS UNIT INFORMATION

Section [1] of [4]

Simple-Cycle Combustion Turbines

I. EMISSIONS UNIT ADDITIONAL INFORMATION

Additional Requirements for All Applications, Except as Otherwise Stated

1. Process Flow Diagram: (Required for all permit applications, except Title V air operation 

permit revision applications if this information was submitted to the department within the 

previous five years and would not be altered as a result of the revision being sought)

Attached, Document ID: See Note Previously Submitted, Date

2. Fuel Analysis or Specification: (Required for all permit applications, except Title V air 

operation permit revision applications if this information was submitted to the department within 

the previous five years and would not be altered as a result of the revision being sought)

Attached, Document ID: See Note Previously Submitted, Date 

3. Detailed Description of Control Equipment: (Required for all permit applications, except Title 

V air operation permit revision applications if this information was submitted to the department 

within the previous five years and would not be altered as a result of the revision being sought)

Attached, Document ID: See Note Previously Submitted, Date 

4. Procedures for Startup and Shutdown: (Required for all operation permit applications, except 

Title V air operation permit revision applications if this information was submitted to the 

department within the previous five years and would not be altered as a result of the revision being 

sought)

Attached, Document ID: See Note Previously Submitted, Date 

Not Applicable (construction application)

5. Operation and Maintenance Plan: (Required for all permit applications, except Title V air 

operation permit revision applications if this information was submitted to the department within 

the previous five years and would not be altered as a result of the revision being sought)

Attached, Document ID: See Note Previously Submitted, Date 

Not Applicable 

6. Compliance Demonstration Reports/Records:

Attached, Document ID: 

Test Date(s)/Pollutant(s) Tested:

Previously Submitted, Date:

Test Date(s)/Pollutant(s) Tested: 

To be Submitted, Date (if known):

Test Date(s)/Pollutant(s) Tested: 

 Not Applicable

Note: For FESOP applications, all required compliance demonstration records/reports must be submitted at the time of application. For 

Title V air operation permit applications, all required compliance demonstration reports/records must be submitted at the time of 

application, or a compliance plan must be submitted at the time of application.

7. Other Information Required by Rule or Statute:

Attached, Document ID: Not Applicable

Note: See Air Permit Application and Prevention of Significant Deterioration Analysis for the Shady Hills 

Generation Station, July, 2010.
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 24

EMISSIONS UNIT INFORMATION

Section [1] of [4]

Simple-Cycle Combustion Turbines

I. EMISSIONS UNIT ADDITIONAL INFORMATION (CONTINUED)

Additional Requirements for Air Construction Permit Applications

1. Control Technology Review and Analysis (Rules 62-212.400(10) and 62-212.500(7), 

F.A.C.; 40 CFR 63.43(d) and (e)):

Attached, Document ID: Not Applicable

2. Good Engineering Practice Stack Height Analysis (Rules 62-212.400(4)(d) and 62-

212.500(4)(f), F.A.C.):

Attached, Document ID: Not Applicable

3. Description of Stack Sampling Facilities: (Required for proposed new stack sampling facilities 

only)

Attached, Document ID: Not Applicable

Additional Requirements for Title V Air Operation Permit Applications - NA

1. Identification of Applicable Requirements:

Attached, Document ID:

2. Compliance Assurance Monitoring:

Attached, Document ID: Not Applicable

3. Alternative Methods of Operation:

Attached, Document ID: Not Applicable

4. Alternative Modes of Operation (Emissions Trading):

Attached, Document ID: Not Applicable

Additional Requirements Comment
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 26

EMISSIONS UNIT INFORMATION

Section [2] of [4]

Emergency Generator

III. EMISSIONS UNIT INFORMATION

Title V Air Operation Permit Application - For Title V air operation permitting only, emissions units 

are classified as regulated, unregulated, or insignificant. If this is an application for an initial, revised or 

renewal Title V air operation permit, a separate Emissions Unit Information Section (including 

subsections A through I as required) must be completed for each regulated and unregulated emissions 

unit addressed in this application. Some of the subsections comprising the Emissions Unit Information 

Section of the form are optional for unregulated emissions units. Each such subsection is appropriately 

marked. Insignificant emissions units are required to be listed at Section II, Subsection C.

Air Construction Permit or FESOP Application - For air construction permitting or federally 

enforceable state air operation permitting, emissions units are classified as either subject to air permitting 

or exempt from air permitting. The concept of an “unregulated emissions unit” does not apply. If this is 

an application for an air construction permit or FESOP, a separate Emissions Unit Information Section 

(including subsections A through I as required) must be completed for each emissions unit subject to air 

permitting addressed in this application for air permit. Emissions units exempt from air permitting are 

required to be listed at Section II, Subsection C.

Air Construction Permit and Revised/Renewal Title V Air Operation Permit Application – Where 

this application is used to apply for both an air construction permit and a revised or renewal Title V air 

operation permit, each emissions unit is classified as either subject to air permitting or exempt from air

permitting for air construction permitting purposes, and as regulated, unregulated, or insignificant for 

Title V air operation permitting purposes. A separate Emissions Unit Information Section (including 

subsections A through I as required) must be completed for each emissions unit addressed in this 

application that is subject to air construction permitting and for each such emissions unit that is a 

regulated or unregulated unit for purposes of Title V permitting. (An emissions unit may be exempt from 

air construction permitting but still be classified as an unregulated unit for Title V purposes.) Emissions 

units classified as insignificant for Title V purposes are required to be listed at Section II, Subsection C.

If submitting the application form in hard copy, the number of this Emissions Unit Information Section 

and the total number of Emissions Unit Information Sections submitted as part of this application must be

indicated in the space provided at the top of each page.
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 27

EMISSIONS UNIT INFORMATION

Section [2] of [4]

Emergency Generator

A. GENERAL EMISSIONS UNIT INFORMATION

Title V Air Operation Permit Emissions Unit Classification 

1. Regulated or Unregulated Emissions Unit? (Check one, if applying for an initial, revised 

or renewal Title V air operation permit. Skip this item if applying for an air construction 

permit or FESOP only.)

The emissions unit addressed in this Emissions Unit Information Section is a regulated 

emissions unit.

The emissions unit addressed in this Emissions Unit Information Section is an 

unregulated emissions unit.

Emissions Unit Description and Status

1. Type of Emissions Unit Addressed in this Section: (Check one)

This Emissions Unit Information Section addresses, as a single emissions unit, a single 

process or production unit, or activity, which produces one or more air pollutants and 

which has at least one definable emission point (stack or vent).

This Emissions Unit Information Section addresses, as a single emissions unit, a group 

of process or production units and activities which has at least one definable emission 

point (stack or vent) but may also produce fugitive emissions.

This Emissions Unit Information Section addresses, as a single emissions unit, one or 

more process or production units and activities which produce fugitive emissions only. 

2. Description of Emissions Unit Addressed in this Section:

Emergency generator.

3. Emissions Unit Identification Number: 007

4. Emissions Unit

Status Code:

 C

5. Commence

Construction 

Date:

6. Initial Startup 

Date:

7. Emissions Unit 

Major Group 

SIC Code:

49

8. Federal Program Applicability: (Check all that apply)

Acid Rain Unit

CAIR Unit

9. Package Unit:

Manufacturer: Model Number: 

10. Generator Nameplate Rating: 1 MW

11. Emissions Unit Comment: 
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 28

EMISSIONS UNIT INFORMATION

Section [2] of [4]

Emergency Generator

Emissions Unit Control Equipment/Method: Control of 

1. Control Equipment/Method Description:

2. Control Device or Method Code:

Emissions Unit Control Equipment/Method: Control of 

1. Control Equipment/Method Description:

2. Control Device or Method Code:

Emissions Unit Control Equipment/Method: Control of 

1. Control Equipment/Method Description:

2. Control Device or Method Code:

Emissions Unit Control Equipment/Method: Control of 

1. Control Equipment/Method Description:

2. Control Device or Method Code:
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 29

EMISSIONS UNIT INFORMATION

Section [2] of [4]

Emergency Generator

B. EMISSIONS UNIT CAPACITY INFORMATION

(Optional for unregulated emissions units.)

Emissions Unit Operating Capacity and Schedule

1. Maximum Process or Throughput Rate:

2. Maximum Production Rate:

3. Maximum Heat Input Rate: 9.73 million Btu/hr (HHV)

4. Maximum Incineration Rate: pounds/hr

tons/day

5. Requested Maximum Operating Schedule:

24 hours/day 7 days/week

52 weeks/year 500 hours/year

6. Operating Capacity/Schedule Comment:
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 30

EMISSIONS UNIT INFORMATION

Section [2] of [4]

Emergency Generator

C. EMISSION POINT (STACK/VENT) INFORMATION

(Optional for unregulated emissions units.)

Emission Point Description and Type

1. Identification of Point on Plot Plan or 

Flow Diagram: 007

2. Emission Point Type Code:

3. Descriptions of Emission Points Comprising this Emissions Unit for VE Tracking:

4. ID Numbers or Descriptions of Emission Units with this Emission Point in Common:

5. Discharge Type Code: 6. Stack Height:

feet

7. Exit Diameter:

feet

8. Exit Temperature:

F

9. Actual Volumetric Flow Rate:

acfm

10. Water Vapor:

%

11. Maximum Dry Standard Flow Rate:

dscfm

12. Nonstack Emission Point Height:

feet

13. Emission Point UTM Coordinates...

Zone: 17 East (km): 347.0 

North (km): 3,139.0 

14. Emission Point Latitude/Longitude...

Latitude (DD/MM/SS) 28/22/00

Longitude (DD/MM/SS) 82/30/00

15. Emission Point Comment:
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 31

EMISSIONS UNIT INFORMATION

Section [2] of [4]

Emergency Generator

D. SEGMENT (PROCESS/FUEL) INFORMATION

Segment Description and Rate: Segment 1 of 1

1. Segment Description (Process/Fuel Type):

 Diesel

2. Source Classification Code (SCC):

2-01-001-02

3. SCC Units:

1000 gallons of Distillate Oil (Diesel) Burned

4. Maximum Hourly Rate:

70.5

5. Maximum Annual Rate:

35,253

6. Estimated Annual Activity 

Factor:

7. Maximum % Sulfur: 8. Maximum % Ash: 9. Million Btu per SCC Unit:

138

10. Segment Comment:

Maximum hourly rate = 9.73 MMBtu/hr / (138 MMBtu / 1000 gal) = 70.5 gal/hr

Maximum annual rate = 70.5 gal/hr x 500 hr/yr = 35,253 gal/hr

Segment Description and Rate: Segment of 

1. Segment Description (Process/Fuel Type):

2. Source Classification Code (SCC): 3. SCC Units:

4. Maximum Hourly Rate: 5. Maximum Annual Rate: 6. Estimated Annual Activity 

Factor: 

7. Maximum % Sulfur: 8. Maximum % Ash: 9. Million Btu per SCC Unit:

10. Segment Comment:
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 32

EMISSIONS UNIT INFORMATION

Section [2] of [4]

Emergency Generator

E. EMISSIONS UNIT POLLUTANTS

List of Pollutants Emitted by Emissions Unit

1. Pollutant Emitted 2. Primary Control 

Device Code

3. Secondary Control 

Device Code

4. Pollutant 

Regulatory Code

CO2e EL
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 33

EMISSIONS UNIT INFORMATION POLLUTANT DETAIL INFORMATION

Section [2] of [4] Page [1] of [1]

Emergency Generator CO2e

F1. EMISSIONS UNIT POLLUTANT DETAIL INFORMATION –

POTENTIAL, FUGITIVE, AND ACTUAL EMISSIONS

(Optional for unregulated emissions units.)

Complete a Subsection F1 for each pollutant identified in Subsection E if applying for an 

air construction permit or concurrent processing of an air construction permit and a 

revised or renewal Title V operation permit. Complete for each emissions-limited pollutant 

identified in Subsection E if applying for an air operation permit.

Potential, Estimated Fugitive, and Baseline & Projected Actual Emissions

1. Pollutant Emitted:

CO2e

2. Total Percent Efficiency of Control:

3. Potential Emissions:

1,592 lb/hour 398 tons/year

4. Synthetically Limited?

Yes No

5. Range of Estimated Fugitive Emissions (as applicable):

 to tons/year

6. Emission Factor: Various, 40 CFR Part 98, See Table 4.

Reference: 40 CFR Part 98

7. Emissions

Method Code:

3

8.a. Baseline Actual Emissions (if required):

tons/year

8.b. Baseline 24-month Period:

From: To:

9.a. Projected Actual Emissions (if required):

tons/year

9.b. Projected Monitoring Period:

 5 years 10 years

10. Calculation of Emissions:

See Table 4.

11. Potential, Fugitive, and Actual Emissions Comment:
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 34

EMISSIONS UNIT INFORMATION POLLUTANT DETAIL INFORMATION

Section [2] of [4] Page [1] of [1]

Emergency Generator CO2e

F2. EMISSIONS UNIT POLLUTANT DETAIL INFORMATION -

ALLOWABLE EMISSIONS

Complete Subsection F2 if the pollutant identified in Subsection F1 is or would be subject 

to a numerical emissions limitation.

Allowable Emissions Allowable Emissions of

1. Basis for Allowable Emissions Code:

BACT

2. Future Effective Date of Allowable

Emissions:

3. Allowable Emissions and Units:

398 TPY

4. Equivalent Allowable Emissions:

1,592 lb/hour 398 tons/year

5. Method of Compliance:

Fuel monitoring and 40 CFR Part 98 Emission Factors.

6. Allowable Emissions Comment (Description of Operating Method):

Allowable Emissions Allowable Emissions of 

1. Basis for Allowable Emissions Code: 2. Future Effective Date of Allowable

Emissions: 

3. Allowable Emissions and Units: 4. Equivalent Allowable Emissions:

lb/hour tons/year

5. Method of Compliance:

6. Allowable Emissions Comment (Description of Operating Method):

Allowable Emissions Allowable Emissions of 

1. Basis for Allowable Emissions Code: 2. Future Effective Date of Allowable

Emissions:

3. Allowable Emissions and Units: 4. Equivalent Allowable Emissions:

lb/hour tons/year

5. Method of Compliance:

6. Allowable Emissions Comment (Description of Operating Method):
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 35

EMISSIONS UNIT INFORMATION

Section [2] of [4]

Emergency Generator

I. EMISSIONS UNIT ADDITIONAL INFORMATION

Additional Requirements for All Applications, Except as Otherwise Stated

1. Process Flow Diagram: (Required for all permit applications, except Title V air operation 

permit revision applications if this information was submitted to the department within the 

previous five years and would not be altered as a result of the revision being sought)

Attached, Document ID: See Note Previously Submitted, Date

2. Fuel Analysis or Specification: (Required for all permit applications, except Title V air 

operation permit revision applications if this information was submitted to the department within 

the previous five years and would not be altered as a result of the revision being sought)

Attached, Document ID: See Note Previously Submitted, Date 

3. Detailed Description of Control Equipment: (Required for all permit applications, except Title 

V air operation permit revision applications if this information was submitted to the department 

within the previous five years and would not be altered as a result of the revision being sought)

Attached, Document ID: See Note Previously Submitted, Date 

4. Procedures for Startup and Shutdown: (Required for all operation permit applications, except 

Title V air operation permit revision applications if this information was submitted to the 

department within the previous five years and would not be altered as a result of the revision being 

sought)

Attached, Document ID: See Note Previously Submitted, Date 

Not Applicable (construction application)

5. Operation and Maintenance Plan: (Required for all permit applications, except Title V air 

operation permit revision applications if this information was submitted to the department within 

the previous five years and would not be altered as a result of the revision being sought)

Attached, Document ID: See Note Previously Submitted, Date 

Not Applicable 

6. Compliance Demonstration Reports/Records:

Attached, Document ID: 

Test Date(s)/Pollutant(s) Tested:

Previously Submitted, Date:

Test Date(s)/Pollutant(s) Tested: 

To be Submitted, Date (if known):

Test Date(s)/Pollutant(s) Tested: 

 Not Applicable

Note: For FESOP applications, all required compliance demonstration records/reports must be submitted at the time of application. For 

Title V air operation permit applications, all required compliance demonstration reports/records must be submitted at the time of 

application, or a compliance plan must be submitted at the time of application.

7. Other Information Required by Rule or Statute:

Attached, Document ID: Not Applicable

Note: See Air Permit Application and Prevention of Significant Deterioration Analysis for the Shady Hills Generating 

Station, July, 2010.
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 36

EMISSIONS UNIT INFORMATION

Section [2] of [4]

Emergency Generator

I. EMISSIONS UNIT ADDITIONAL INFORMATION (CONTINUED)

Additional Requirements for Air Construction Permit Applications

1. Control Technology Review and Analysis (Rules 62-212.400(10) and 62-212.500(7), 

F.A.C.; 40 CFR 63.43(d) and (e)):

Attached, Document ID: See PSD Report Not Applicable

2. Good Engineering Practice Stack Height Analysis (Rules 62-212.400(4)(d) and 62-

212.500(4)(f), F.A.C.):

Attached, Document ID: See Note Not Applicable

3. Description of Stack Sampling Facilities: (Required for proposed new stack sampling facilities 

only)

Attached, Document ID: See Note Not Applicable

Note: See Air Permit Application and Prevention of Significant Deterioration Analysis for the Shady Hills Generating 

Station, July, 2010.

Additional Requirements for Title V Air Operation Permit Applications

1. Identification of Applicable Requirements:

Attached, Document ID:

2. Compliance Assurance Monitoring:

Attached, Document ID: Not Applicable

3. Alternative Methods of Operation:

Attached, Document ID: Not Applicable

4. Alternative Modes of Operation (Emissions Trading):

Attached, Document ID: Not Applicable

Additional Requirements Comment
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 37

EMISSIONS UNIT INFORMATION

Section [3] of [4]

Natural Gas Heater

III. EMISSIONS UNIT INFORMATION

Title V Air Operation Permit Application - For Title V air operation permitting only, emissions units 

are classified as regulated, unregulated, or insignificant. If this is an application for an initial, revised or 

renewal Title V air operation permit, a separate Emissions Unit Information Section (including 

subsections A through I as required) must be completed for each regulated and unregulated emissions 

unit addressed in this application. Some of the subsections comprising the Emissions Unit Information 

Section of the form are optional for unregulated emissions units. Each such subsection is appropriately 

marked. Insignificant emissions units are required to be listed at Section II, Subsection C.

Air Construction Permit or FESOP Application - For air construction permitting or federally 

enforceable state air operation permitting, emissions units are classified as either subject to air permitting 

or exempt from air permitting. The concept of an “unregulated emissions unit” does not apply. If this is 

an application for an air construction permit or FESOP, a separate Emissions Unit Information Section 

(including subsections A through I as required) must be completed for each emissions unit subject to air 

permitting addressed in this application for air permit. Emissions units exempt from air permitting are 

required to be listed at Section II, Subsection C.

Air Construction Permit and Revised/Renewal Title V Air Operation Permit Application – Where 

this application is used to apply for both an air construction permit and a revised or renewal Title V air 

operation permit, each emissions unit is classified as either subject to air permitting or exempt from air 

permitting for air construction permitting purposes, and as regulated, unregulated, or insignificant for 

Title V air operation permitting purposes. A separate Emissions Unit Information Section (including 

subsections A through I as required) must be completed for each emissions unit addressed in this 

application that is subject to air construction permitting and for each such emissions unit that is a 

regulated or unregulated unit for purposes of Title V permitting. (An emissions unit may be exempt from 

air construction permitting but still be classified as an unregulated unit for Title V purposes.) Emissions 

units classified as insignificant for Title V purposes are required to be listed at Section II, Subsection C.

If submitting the application form in hard copy, the number of this Emissions Unit Information Section 

and the total number of Emissions Unit Information Sections submitted as part of this application must be

indicated in the space provided at the top of each page.
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 38

EMISSIONS UNIT INFORMATION

Section [3] of [4]

Natural Gas Heater

A. GENERAL EMISSIONS UNIT INFORMATION

Title V Air Operation Permit Emissions Unit Classification 

1. Regulated or Unregulated Emissions Unit? (Check one, if applying for an initial, revised 

or renewal Title V air operation permit. Skip this item if applying for an air construction 

permit or FESOP only.)

The emissions unit addressed in this Emissions Unit Information Section is a regulated 

emissions unit.

The emissions unit addressed in this Emissions Unit Information Section is an 

unregulated emissions unit.

Emissions Unit Description and Status

1. Type of Emissions Unit Addressed in this Section: (Check one)

This Emissions Unit Information Section addresses, as a single emissions unit, a single 

process or production unit, or activity, which produces one or more air pollutants and 

which has at least one definable emission point (stack or vent).

This Emissions Unit Information Section addresses, as a single emissions unit, a group 

of process or production units and activities which has at least one definable emission 

point (stack or vent) but may also produce fugitive emissions.

This Emissions Unit Information Section addresses, as a single emissions unit, one or 

more process or production units and activities which produce fugitive emissions only. 

2. Description of Emissions Unit Addressed in this Section:

Natural Gas Heater.

3. Emissions Unit Identification Number: 008

4. Emissions Unit

Status Code:

 C

5. Commence

Construction 

Date:

6. Initial Startup 

Date:

7. Emissions Unit 

Major Group 

SIC Code:

49

8. Federal Program Applicability: (Check all that apply)

Acid Rain Unit

CAIR Unit

9. Package Unit:

Manufacturer: Model Number: 

10. Generator Nameplate Rating:

11. Emissions Unit Comment: 
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 39

EMISSIONS UNIT INFORMATION

Section [3] of [4]

Natural Gas Heater

Emissions Unit Control Equipment/Method: Control of 

1. Control Equipment/Method Description:

2. Control Device or Method Code:

Emissions Unit Control Equipment/Method: Control of 

1. Control Equipment/Method Description:

2. Control Device or Method Code:

Emissions Unit Control Equipment/Method: Control of 

1. Control Equipment/Method Description:

2. Control Device or Method Code:

Emissions Unit Control Equipment/Method: Control of 

1. Control Equipment/Method Description:

2. Control Device or Method Code:
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 40

EMISSIONS UNIT INFORMATION

Section [3] of [4]

Natural Gas Heater

B. EMISSIONS UNIT CAPACITY INFORMATION

(Optional for unregulated emissions units.)

Emissions Unit Operating Capacity and Schedule

1. Maximum Process or Throughput Rate:

2. Maximum Production Rate:

3. Maximum Heat Input Rate: 10 million Btu/hr (HHV)

4. Maximum Incineration Rate: pounds/hr

tons/day

5. Requested Maximum Operating Schedule:

24 hours/day 7 days/week

52 weeks/year 3,390 hours/year

6. Operating Capacity/Schedule Comment:
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 41

EMISSIONS UNIT INFORMATION

Section [3] of [4]

Natural Gas Heater

C. EMISSION POINT (STACK/VENT) INFORMATION

(Optional for unregulated emissions units.)

Emission Point Description and Type

1. Identification of Point on Plot Plan or 

Flow Diagram: 008

2. Emission Point Type Code:

3. Descriptions of Emission Points Comprising this Emissions Unit for VE Tracking:

4. ID Numbers or Descriptions of Emission Units with this Emission Point in Common:

5. Discharge Type Code:

V

6. Stack Height:

30 feet

7. Exit Diameter:

feet

8. Exit Temperature:

500F

9. Actual Volumetric Flow Rate:

4,950 acfm

10. Water Vapor:

%

11. Maximum Dry Standard Flow Rate:

dscfm

12. Nonstack Emission Point Height:

feet

13. Emission Point UTM Coordinates...

Zone: 17 East (km): 347.0 

North (km): 3,139.0 

14. Emission Point Latitude/Longitude...

Latitude (DD/MM/SS) 28/22/00

Longitude (DD/MM/SS) 82/33/30

15. Emission Point Comment:
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 42

EMISSIONS UNIT INFORMATION

Section [3] of [4]

Natural Gas Heater

D. SEGMENT (PROCESS/FUEL) INFORMATION

Segment Description and Rate: Segment 1 of 1

1. Segment Description (Process/Fuel Type):

Natural gas

2. Source Classification Code (SCC): 3. SCC Units:

1,000,000 SCF

4. Maximum Hourly Rate:

0.011

5. Maximum Annual Rate:

96.4

6. Estimated Annual Activity 

Factor:

7. Maximum % Sulfur: 8. Maximum % Ash: 9. Million Btu per SCC Unit:

933

10. Segment Comment:

Maximum hourly rate = 10 MMBtu/hr / 933 MMBtu/MMscf = 0.011 MMscf/hr

Maximum annual rate = 0.011 MMscf/hr x 8,760 hr/yr = 96.4 MMscf/yr

Segment Description and Rate: Segment of 

1. Segment Description (Process/Fuel Type):

2. Source Classification Code (SCC): 3. SCC Units:

4. Maximum Hourly Rate: 5. Maximum Annual Rate: 6. Estimated Annual Activity 

Factor: 

7. Maximum % Sulfur: 8. Maximum % Ash: 9. Million Btu per SCC Unit:

10. Segment Comment:
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 43

EMISSIONS UNIT INFORMATION

Section [3] of [4]

Natural Gas Heater

E. EMISSIONS UNIT POLLUTANTS

List of Pollutants Emitted by Emissions Unit

1. Pollutant Emitted 2. Primary Control 

Device Code

3. Secondary Control 

Device Code

4. Pollutant 

Regulatory Code

CO2e EL
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 44

EMISSIONS UNIT INFORMATION POLLUTANT DETAIL INFORMATION

Section [3] of [4] Page [1] of [1]

Natural Gas Heater CO2e

F1. EMISSIONS UNIT POLLUTANT DETAIL INFORMATION –

POTENTIAL, FUGITIVE, AND ACTUAL EMISSIONS

(Optional for unregulated emissions units.)

Complete a Subsection F1 for each pollutant identified in Subsection E if applying for an 

air construction permit or concurrent processing of an air construction permit and a 

revised or renewal Title V operation permit. Complete for each emissions-limited pollutant 

identified in Subsection E if applying for an air operation permit.

Potential, Estimated Fugitive, and Baseline & Projected Actual Emissions

1. Pollutant Emitted:

CO2e

2. Total Percent Efficiency of Control:

3. Potential Emissions:

1,170 lb/hour 5123 tons/year

4. Synthetically Limited?

Yes No

5. Range of Estimated Fugitive Emissions (as applicable):

 to tons/year

6. Emission Factor: Various, 40 CFR Part 98, See Table 4.

Reference: 40 CFR Part 98

7. Emissions

Method Code:

3

8.a. Baseline Actual Emissions (if required):

tons/year

8.b. Baseline 24-month Period:

From: To:

9.a. Projected Actual Emissions (if required):

tons/year

9.b. Projected Monitoring Period:

 5 years 10 years

10. Calculation of Emissions:

See Table 4.

11. Potential, Fugitive, and Actual Emissions Comment:
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 45

EMISSIONS UNIT INFORMATION POLLUTANT DETAIL INFORMATION

Section [3] of [4] Page [1] of [1]

Natural Gas Heater CO2e

F2. EMISSIONS UNIT POLLUTANT DETAIL INFORMATION -

ALLOWABLE EMISSIONS

Complete Subsection F2 if the pollutant identified in Subsection F1 is or would be subject 

to a numerical emissions limitation.

Allowable Emissions Allowable Emissions of

1. Basis for Allowable Emissions Code: 2. Future Effective Date of Allowable

Emissions:

3. Allowable Emissions and Units: 4. Equivalent Allowable Emissions:

lb/hour tons/year

5. Method of Compliance:

6. Allowable Emissions Comment (Description of Operating Method):

Allowable Emissions Allowable Emissions of 

1. Basis for Allowable Emissions Code: 2. Future Effective Date of Allowable

Emissions: 

3. Allowable Emissions and Units: 4. Equivalent Allowable Emissions:

lb/hour tons/year

5. Method of Compliance:

6. Allowable Emissions Comment (Description of Operating Method):

Allowable Emissions Allowable Emissions of 

1. Basis for Allowable Emissions Code: 2. Future Effective Date of Allowable

Emissions:

3. Allowable Emissions and Units: 4. Equivalent Allowable Emissions:

lb/hour tons/year

5. Method of Compliance:

6. Allowable Emissions Comment (Description of Operating Method):
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 46

EMISSIONS UNIT INFORMATION

Section [3] of [4]

Natural Gas Heater

I. EMISSIONS UNIT ADDITIONAL INFORMATION

Additional Requirements for All Applications, Except as Otherwise Stated

1. Process Flow Diagram: (Required for all permit applications, except Title V air operation 

permit revision applications if this information was submitted to the department within the 

previous five years and would not be altered as a result of the revision being sought)

Attached, Document ID: See Note Previously Submitted, Date

2. Fuel Analysis or Specification: (Required for all permit applications, except Title V air 

operation permit revision applications if this information was submitted to the department within 

the previous five years and would not be altered as a result of the revision being sought)

Attached, Document ID: See Note Previously Submitted, Date 

3. Detailed Description of Control Equipment: (Required for all permit applications, except Title 

V air operation permit revision applications if this information was submitted to the department 

within the previous five years and would not be altered as a result of the revision being sought)

Attached, Document ID: See Note Previously Submitted, Date 

4. Procedures for Startup and Shutdown: (Required for all operation permit applications, except 

Title V air operation permit revision applications if this information was submitted to the 

department within the previous five years and would not be altered as a result of the revision being 

sought)

Attached, Document ID: See Note Previously Submitted, Date 

Not Applicable (construction application)

5. Operation and Maintenance Plan: (Required for all permit applications, except Title V air 

operation permit revision applications if this information was submitted to the department within 

the previous five years and would not be altered as a result of the revision being sought)

Attached, Document ID: See Note Previously Submitted, Date 

Not Applicable 

6. Compliance Demonstration Reports/Records:

Attached, Document ID: 

Test Date(s)/Pollutant(s) Tested:

Previously Submitted, Date:

Test Date(s)/Pollutant(s) Tested: 

To be Submitted, Date (if known):

Test Date(s)/Pollutant(s) Tested: 

 Not Applicable

Note: For FESOP applications, all required compliance demonstration records/reports must be submitted at the time of 

application. For Title V air operation permit applications, all required compliance demonstration reports/records must be 

submitted at the time of application, or a compliance plan must be submitted at the time of application.

7. Other Information Required by Rule or Statute:

Attached, Document ID: Not Applicable

Note: See Air Permit Application and Prevention of Significant Deterioration Analysis for the Shady Hills Generating 

Station, July, 2010.
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 47

EMISSIONS UNIT INFORMATION

Section [3] of [4]

Natural Gas Heater

I. EMISSIONS UNIT ADDITIONAL INFORMATION (CONTINUED)

Additional Requirements for Air Construction Permit Applications

1. Control Technology Review and Analysis (Rules 62-212.400(10) and 62-212.500(7), 

F.A.C.; 40 CFR 63.43(d) and (e)):

 Attached, Document ID: See PSD Report Not Applicable

2. Good Engineering Practice Stack Height Analysis (Rules 62-212.400(4)(d) and 62-

212.500(4)(f), F.A.C.):

 Attached, Document ID: See Note Not Applicable

3. Description of Stack Sampling Facilities: (Required for proposed new stack sampling facilities 

only)

 Attached, Document ID: See Note Not Applicable

Note: See Air Permit Application and Prevention of Significant Deterioration Analysis for the Shady Hills Generating 

Station, July, 2010.

Additional Requirements for Title V Air Operation Permit Applications

1. Identification of Applicable Requirements:

Attached, Document ID:

2. Compliance Assurance Monitoring:

Attached, Document ID: Not Applicable

3. Alternative Methods of Operation:

Attached, Document ID: Not Applicable

4. Alternative Modes of Operation (Emissions Trading):

Attached, Document ID: Not Applicable

Additional Requirements Comment
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 48

EMISSIONS UNIT INFORMATION

Section [4] of [4]

Distillate Fuel Oil Storage Tank

III. EMISSIONS UNIT INFORMATION

Title V Air Operation Permit Application - For Title V air operation permitting only, emissions units 

are classified as regulated, unregulated, or insignificant. If this is an application for an initial, revised or 

renewal Title V air operation permit, a separate Emissions Unit Information Section (including 

subsections A through I as required) must be completed for each regulated and unregulated emissions 

unit addressed in this application. Some of the subsections comprising the Emissions Unit Information 

Section of the form are optional for unregulated emissions units. Each such subsection is appropriately 

marked. Insignificant emissions units are required to be listed at Section II, Subsection C.

Air Construction Permit or FESOP Application - For air construction permitting or federally 

enforceable state air operation permitting, emissions units are classified as either subject to air permitting 

or exempt from air permitting. The concept of an “unregulated emissions unit” does not apply. If this is 

an application for an air construction permit or FESOP, a separate Emissions Unit Information Section 

(including subsections A through I as required) must be completed for each emissions unit subject to air 

permitting addressed in this application for air permit. Emissions units exempt from air permitting are 

required to be listed at Section II, Subsection C.

Air Construction Permit and Revised/Renewal Title V Air Operation Permit Application – Where 

this application is used to apply for both an air construction permit and a revised or renewal Title V air 

operation permit, each emissions unit is classified as either subject to air permitting or exempt from air 

permitting for air construction permitting purposes, and as regulated, unregulated, or insignificant for 

Title V air operation permitting purposes. A separate Emissions Unit Information Section (including 

subsections A through I as required) must be completed for each emissions unit addressed in this 

application that is subject to air construction permitting and for each such emissions unit that is a 

regulated or unregulated unit for purposes of Title V permitting. (An emissions unit may be exempt from 

air construction permitting but still be classified as an unregulated unit for Title V purposes.) Emissions 

units classified as insignificant for Title V purposes are required to be listed at Section II, Subsection C.

If submitting the application form in hard copy, the number of this Emissions Unit Information Section 

and the total number of Emissions Unit Information Sections submitted as part of this application must be

indicated in the space provided at the top of each page.
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 49

EMISSIONS UNIT INFORMATION

Section [4] of [4]

Distillate Fuel Oil Storage Tank

A. GENERAL EMISSIONS UNIT INFORMATION

Title V Air Operation Permit Emissions Unit Classification 

1. Regulated or Unregulated Emissions Unit? (Check one, if applying for an initial, revised 

or renewal Title V air operation permit. Skip this item if applying for an air construction 

permit or FESOP only.)

The emissions unit addressed in this Emissions Unit Information Section is a regulated 

emissions unit.

The emissions unit addressed in this Emissions Unit Information Section is an 

unregulated emissions unit.

Emissions Unit Description and Status

1. Type of Emissions Unit Addressed in this Section: (Check one)

This Emissions Unit Information Section addresses, as a single emissions unit, a single 

process or production unit, or activity, which produces one or more air pollutants and 

which has at least one definable emission point (stack or vent).

This Emissions Unit Information Section addresses, as a single emissions unit, a group 

of process or production units and activities which has at least one definable emission 

point (stack or vent) but may also produce fugitive emissions.

This Emissions Unit Information Section addresses, as a single emissions unit, one or 

more process or production units and activities which produce fugitive emissions only. 

2. Description of Emissions Unit Addressed in this Section:

Distillate Fuel Oil Storage Tank.

3. Emissions Unit Identification Number: 007

4. Emissions Unit

Status Code:

 C

5. Commence

Construction 

Date:

6. Initial Startup 

Date:

7. Emissions Unit 

Major Group 

SIC Code:

49

8. Federal Program Applicability: (Check all that apply)

Acid Rain Unit

CAIR Unit

9. Package Unit:

Manufacturer: Model Number: 

10. Generator Nameplate Rating:

11. Emissions Unit Comment: 
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 50

EMISSIONS UNIT INFORMATION

Section [4] of [4]

Distillate Fuel Oil Storage Tank

Emissions Unit Control Equipment/Method: Control of 

1. Control Equipment/Method Description:

2. Control Device or Method Code:

Emissions Unit Control Equipment/Method: Control of 

1. Control Equipment/Method Description:

2. Control Device or Method Code:

Emissions Unit Control Equipment/Method: Control of 

1. Control Equipment/Method Description:

2. Control Device or Method Code:

Emissions Unit Control Equipment/Method: Control of 

1. Control Equipment/Method Description:

2. Control Device or Method Code:
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 51

EMISSIONS UNIT INFORMATION

Section [4] of [4]

Distillate Fuel Oil Storage Tank

B. EMISSIONS UNIT CAPACITY INFORMATION

(Optional for unregulated emissions units.)

Emissions Unit Operating Capacity and Schedule

1. Maximum Process or Throughput Rate: 16,939,770 gal/year

2. Maximum Production Rate:

3. Maximum Heat Input Rate: 

4. Maximum Incineration Rate: pounds/hr

tons/day

5. Requested Maximum Operating Schedule:

24 hours/day 7 days/week

52 weeks/year 8,760 hours/year

6. Operating Capacity/Schedule Comment:
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 52

EMISSIONS UNIT INFORMATION

Section [4] of [4]

Distillate Fuel Oil Storage Tank

C. EMISSION POINT (STACK/VENT) INFORMATION

(Optional for unregulated emissions units.)

Emission Point Description and Type

1. Identification of Point on Plot Plan or 

Flow Diagram: 007

2. Emission Point Type Code:

3. Descriptions of Emission Points Comprising this Emissions Unit for VE Tracking:

4. ID Numbers or Descriptions of Emission Units with this Emission Point in Common:

5. Discharge Type Code: 6. Stack Height:

feet

7. Exit Diameter:

feet

8. Exit Temperature:

F

9. Actual Volumetric Flow Rate: 10. Water Vapor:

%

11. Maximum Dry Standard Flow Rate:

dscfm

12. Nonstack Emission Point Height:

feet

13. Emission Point UTM Coordinates...

Zone: 17 East (km): 347.0 

North (km): 3,139.0 

14. Emission Point Latitude/Longitude...

Latitude (DD/MM/SS) 28/22/00

Longitude (DD/MM/SS) 82/33/30

15. Emission Point Comment:
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 53

EMISSIONS UNIT INFORMATION

Section [4] of [4]

Distillate Fuel Oil Storage Tank

D. SEGMENT (PROCESS/FUEL) INFORMATION

Segment Description and Rate: Segment 1 of 1

1. Segment Description (Process/Fuel Type):

 Diesel

2. Source Classification Code (SCC):

3-90-900-03

3. SCC Units:

1000 gal/yr distillate oil (No.2) Storage capacity 

(breathing losses)

4. Maximum Hourly Rate: 5. Maximum Annual Rate: 6. Estimated Annual Activity 

Factor:

7. Maximum % Sulfur:

0.0015

8. Maximum % Ash: 9. Million Btu per SCC Unit:

10. Segment Comment:

See Air Permit Application and Prevention of Significant Deterioration Analysis for the Shady Hills 

Generating Station, July, 2010.

Segment Description and Rate: Segment of 

1. Segment Description (Process/Fuel Type):

2. Source Classification Code (SCC):

3-90-900-04

3. SCC Units:

1000 gal/yr distillate oil (No.2) throughput

(working losses)

4. Maximum Hourly Rate: 5. Maximum Annual Rate: 6. Estimated Annual Activity 

Factor: 

7. Maximum % Sulfur:

0.0015

8. Maximum % Ash: 9. Million Btu per SCC Unit:

10. Segment Comment:

See Air Permit Application and Prevention of Significant Deterioration Analysis for the Shady Hills 

Generating Station, July, 2010.
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 54

EMISSIONS UNIT INFORMATION

Section [4] of [4]

Distillate Fuel Oil Storage Tank

E. EMISSIONS UNIT POLLUTANTS

List of Pollutants Emitted by Emissions Unit

1. Pollutant Emitted 2. Primary Control 

Device Code

3. Secondary Control 

Device Code

4. Pollutant 

Regulatory Code

CO2e NS
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 55

EMISSIONS UNIT INFORMATION POLLUTANT DETAIL INFORMATION

Section [4] of [4] Page [1] of [1]

Distillate Fuel Oil Storage Tank CO2e

F1. EMISSIONS UNIT POLLUTANT DETAIL INFORMATION –

POTENTIAL/ESTIMATED FUGITIVE EMISSIONS

(Optional for unregulated emissions units.)

Complete a Subsection F1 for each pollutant identified in Subsection E if applying for an 

air construction permit or concurrent processing of an air construction permit and a 

revised or renewal Title V operation permit. Complete for each emissions-limited pollutant 

identified in Subsection E if applying for an air operation permit.

Potential, Estimated Fugitive and Baseline & Projected Actual Emissions

1. Pollutant Emitted:

CO2e

2. Total Percent Efficiency of Control:

3. Potential Emissions:

lb/hour negligible tons/year

4. Synthetically Limited?

Yes No

5. Range of Estimated Fugitive Emissions (as applicable):

to tons/year

6. Emission Factor:

Reference: 

7. Emissions

Method Code:

5

8.a. Baseline Actual Emissions (if required):

 tons/year

8.b. Baseline 24-month Period:

From: To: 

9.a. Projected Actual Emissions (if required):

 tons/year

9.b. Projected Monitoring Period:

 5 years 10 years

10. Calculation of Emissions:

11. Potential, Fugitive, and Actual Emissions Comment:
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 56

EMISSIONS UNIT INFORMATION POLLUTANT DETAIL INFORMATION

Section [4] of [4] Page [1] of [1]

Distillate Fuel Oil Storage Tank CO2e

F2. EMISSIONS UNIT POLLUTANT DETAIL INFORMATION -

ALLOWABLE EMISSIONS

Complete Subsection F2 if the pollutant identified in Subsection F1 is or would be subject 

to a numerical emissions limitation.

Allowable Emissions Allowable Emissions of 

1. Basis for Allowable Emissions Code: 2. Future Effective Date of Allowable

Emissions: 

3. Allowable Emissions and Units: 4. Equivalent Allowable Emissions:

lb/hour tons/year

5. Method of Compliance:

6. Allowable Emissions Comment (Description of Operating Method):

Allowable Emissions Allowable Emissions 

1. Basis for Allowable Emissions Code: 2. Future Effective Date of Allowable

Emissions: 

3. Allowable Emissions and Units: 4. Equivalent Allowable Emissions:

lb/hour tons/year

5. Method of Compliance:

6. Allowable Emissions Comment (Description of Operating Method):

 

Allowable Emissions Allowable Emissions of 

1. Basis for Allowable Emissions Code: 2. Future Effective Date of Allowable

Emissions: 

3. Allowable Emissions and Units: 4. Equivalent Allowable Emissions:

lb/hour tons/year

5. Method of Compliance:

6. Allowable Emissions Comment (Description of Operating Method):
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 57

EMISSIONS UNIT INFORMATION

Section [4] of [4]

Distillate Fuel Oil Storage Tank

I. EMISSIONS UNIT ADDITIONAL INFORMATION

Additional Requirements for All Applications, Except as Otherwise Stated

1. Process Flow Diagram: (Required for all permit applications, except Title V air operation 

permit revision applications if this information was submitted to the department within the 

previous five years and would not be altered as a result of the revision being sought)

Attached, Document ID: See Note Previously Submitted, Date

2. Fuel Analysis or Specification: (Required for all permit applications, except Title V air 

operation permit revision applications if this information was submitted to the department within 

the previous five years and would not be altered as a result of the revision being sought)

Attached, Document ID: See Note Previously Submitted, Date 

3. Detailed Description of Control Equipment: (Required for all permit applications, except Title 

V air operation permit revision applications if this information was submitted to the department 

within the previous five years and would not be altered as a result of the revision being sought)

Attached, Document ID: See Note Previously Submitted, Date 

4. Procedures for Startup and Shutdown: (Required for all operation permit applications, except 

Title V air operation permit revision applications if this information was submitted to the 

department within the previous five years and would not be altered as a result of the revision being 

sought)

Attached, Document ID: Previously Submitted, Date 

Not Applicable (construction application)

5. Operation and Maintenance Plan: (Required for all permit applications, except Title V air 

operation permit revision applications if this information was submitted to the department within 

the previous five years and would not be altered as a result of the revision being sought)

Attached, Document ID: Previously Submitted, Date 

Not Applicable 

6. Compliance Demonstration Reports/Records:

Attached, Document ID: 

Test Date(s)/Pollutant(s) Tested:

Previously Submitted, Date:

Test Date(s)/Pollutant(s) Tested: 

To be Submitted, Date (if known):

Test Date(s)/Pollutant(s) Tested: 

 Not Applicable

Note: For FESOP applications, all required compliance demonstration records/reports must be submitted at the time of 

application. For Title V air operation permit applications, all required compliance demonstration reports/records must be 

submitted at the time of application, or a compliance plan must be submitted at the time of application.

7. Other Information Required by Rule or Statute:

Attached, Document ID: Not Applicable

Note: See Air Permit Application and Prevention of Significant Deterioration Analysis for the Shady Hills 

Generating Station, July, 2010.
DEP Form No. 62-210.900(1) – Form 

Effective: 03/11/2010 58

EMISSIONS UNIT INFORMATION

Section [4] of [4]

Distillate Fuel Oil Storage Tank

I. EMISSIONS UNIT ADDITIONAL INFORMATION (CONTINUED)

Additional Requirements for Air Construction Permit Applications

1. Control Technology Review and Analysis (Rules 62-212.400(10) and 62-212.500(7), 

F.A.C.; 40 CFR 63.43(d) and (e)):

Attached, Document ID: See PSD Report Not Applicable

2. Good Engineering Practice Stack Height Analysis (Rules 62-212.400(4)(d) and 62-

212.500(4)(f), F.A.C.):

Attached, Document ID: Not Applicable

3. Description of Stack Sampling Facilities: (Required for proposed new stack sampling facilities 

only)

Attached, Document ID: Not Applicable

Additional Requirements for Title V Air Operation Permit Applications

1. Identification of Applicable Requirements:

Attached, Document ID:

2. Compliance Assurance Monitoring:

Attached, Document ID: Not Applicable

3. Alternative Methods of Operation:

Attached, Document ID: Not Applicable

4. Alternative Modes of Operation (Emissions Trading):

Attached, Document ID: Not Applicable

Additional Requirements Comment
APPENDIX C

USFWS CONSULTATION
1

Larocca, David

From: Heath_Rauschenberger@fws.gov

Sent: Wednesday, August 29, 2012 4:41 PM

To: Ahrens, Heather

Cc: Larocca, David; jaxregs@fws.gov; Belden, Roy S (GE Capital) (roy.belden@ge.com); 

Osbourn, Scott

Subject: Re: Shady Hills Generating Station ESA Consultation

Hi Heather, 

After reviewing your information, we have determined that the project is not likely to adversely affect federally listed 

species. 

Sincerely, 

Heath 

>>>>>>>>>>>>>>>>>>>>>>>>>>>>> 

Heath Rauschenberger, PhD 

Project Consultation Chief 

U.S. Fish and Wildlife Service 

7915 Baymeadows Way, Suite 200 

Jacksonville, Florida 32256-7517 

(o) 904.731.3203 

(c) 904.228.2217 

(f) 904.731.3045 

E-mail:heath_rauschenberger@fws.gov 

http:/www.fws.gov/northflorida 

"Your life is an occasion. Rise to it." 

- Edward Magorium 

"Ahrens, Heather" <Heather_Ahrens@golder.com>

08/29/2012 04:34 PM 

To "jaxregs@fws.gov" <jaxregs@fws.gov>, "Heath_Rauschenberger@fws.gov" 

<Heath_Rauschenberger@fws.gov>

cc "Belden, Roy S (GE Capital) (roy.belden@ge.com)" <roy.belden@ge.com>, "Larocca, 

David" <DLaRocca@golder.com>, "Osbourn, Scott" <Scott_Osbourn@golder.com>

Subject Shady Hills Generating Station ESA Consultation

Dr. Rauschenberger, 

 

Per our previous telephone and email correspondence, the ecological due diligence report for the referenced project is attached for 

your review. 

 

Please do not hesitate to contact me if you have any questions or comments. 

 

Regards, 

Heather Todd Ahrens | Senior Ecologist | Golder Associates Inc. 

5100 West Lemon Street, Suite 208, Tampa, Florida, USA 33609 

T: +1 (813) 287-1717 | D: +1 (813) 769-5307 | F: +1 (813) 287-1716 | C: +1 (813) 407-8846 | E: 
h:\projects\2010proj\10389556 ge shady hills revision\10389556a\10389556a ecology\final\ecological assessment report_cover letter_usfws.docx 

Golder Associates Inc. 

5100 W. Lemon Street, Suite 208 

Tampa, FL 33609 USA 

Tel: (813) 287-1717 Fax: (813) 287-1716 www.golder.com 

Golder Associates: Operations in Africa, Asia, Australasia, Europe, North America and South America 

Golder, Golder Associates and the GA globe design are trademarks of Golder Associates Corporation 

August 17, 2012 103-89556A 

Dr. Heath Rauschenberger 

Chief, Regulatory Compliance 

US Fish and Wildlife Service 

North Florida Ecological Services Office 

7915 Baymeadows Way, Suite 200 

Jacksonville, FL 32256-7517 

RE: ENDANGERED SPECIES ACT CONSULTATION 

EFS SHADY HILLS LLC GENERATING STATION (PSD-FL-402A), 

PASCO COUNTY, FLORIDA 

Dear Dr. Rauschenberger: 

On August 18, 2011, Golder Associates Inc. conducted an ecological assessment of the abovereferenced proposed site to satisfy a request for information from the US Environmental Protection 

Agency (USEPA) regarding the likely occurrence and likely abundance of species considered by the US 

Fish and Wildlife Service to be endangered or threatened, and/or their critical habitat, under 50 Code of 

Federal Regulations 17. 

No federally listed species were documented on-site; however, two federally listed species, the eastern 

indigo snake (threatened) and the wood stork (endangered) were identified by the Florida Natural Areas 

Inventory and/or the Southwest Florida Water Management District as having a potential to occur within 

the vicinity of the site. Impacts to federally listed species are not anticipated due to the proposed 

construction or operation of this project. 

Golder contacted Kyle Baker at the National Marine Fisheries Service (NMFS) on October 7, 2011 and 

March 29, 2012, and described the project, its location, and the site characteristics. Based on this 

information, he determined that no species regulated by the NMFS will be directly or indirectly affected by 

the proposed project, and therefore, consultation with NMFS is not required. 

In addition, Golder contacted the North Florida Ecological Services Office of the USFWS on October 7, 2011 

and March 29, 2012 to discuss the proposed project with you. During our conversations, you indicated that 

the USFWS would like to review the ecological assessment report before making a final determination on 

whether the proposed project will affect listed species. The ecological report is enclosed for your review. 

Please do not hesitate to contact Heather Ahrens at (813) 287-1717 if you have any questions regarding 

the ecological assessment conducted within the generating station site. 

Sincerely, 

GOLDER ASSOCIATES INC. 

 Heather T. Ahrens David T. Larocca 

Senior Ecologist Senior Engineer 

Enclosure: Shady Hills Generating Station Ecological Assessment Report 

HTA/DTL/lcr 
H:\PROJECTS\2010proj\10389556 GE Shady Hills Revision\10389556a\10389556A Ecology\FINAL\Attachment B Ecological Assessment Report.docx 

Golder Associates Inc. 

5100 W. Lemon Street, Suite 208 

Tampa, FL 33609 USA 

Tel: (813) 287-1717 Fax: (813) 287-1716 www.golder.com 

Golder Associates: Operations in Africa, Asia, Australasia, Europe, North America and South America 

Golder, Golder Associates and the GA globe design are trademarks of Golder Associates Corporation 

August 17, 2012 103-89556A 

Mr. Roy Belden 

Vice President 

EFS Shady Hills LLC 

c/o GE Energy Financial Services 

800 Long Ridge Road 

Stamford, CT 06927 

RE: EFS SHADY HILLS LLC GENERATING STATION, ECOLOGICAL ASSESSMENT, PASCO 

COUNTY, FLORIDA 

Dear Mr. Belden: 

On August 18, 2011, Golder Associates Inc. conducted an ecological assessment of the abovereferenced proposed site to satisfy a request for information from the US Environmental Protection 

Agency (USEPA) regarding the likely occurrence and likely abundance of species considered by the US 

Fish and Wildlife Service (USFWS) to be endangered or threatened, and/or their critical habitat, under 50 

Code of Federal Regulations (CFR) 17. Although the USEPA did not specifically request it, Golder has 

also identified species considered by the Florida Fish and Wildlife Conservation Commission (FFWCC) to 

be endangered, threatened, or of special concern under Chapter 39-27.002-004, Florida Administrative 

Code (FAC), to assist GE Energy Financial Services with identifying any potentially significant ecological 

constraints or project encumbrances. In addition, Golder reviewed the site to identify approximate 

boundaries of wetlands that will likely be claimed by the US Army Corps of Engineers (USACE) under the 

1987 Federal Wetland Delineation Methodology (Interim Regional Supplement 2008), and the Florida 

Department of Environmental Protection (FDEP) using the statewide unified Wetland Delineation 

Methodology found in Chapter 62-340, FAC. 

Please recognize that this assessment is designed to assist in your preliminary site planning and due 

diligence efforts and is not intended to represent final agency action with regard to any listed species 

permitting or wetland delineation. 

PROJECT LOCATION AND DESCRIPTION 

EFS Shady Hills LLC, an affiliate of the Shady Hills Power Company, LLC and subsidiary of GE Energy 

Financial Services, owns and operates the Shady Hills Generating Station located at 14240 Merchant 

Energy Way, in Section 25, Township 24 South, Range 17 East, Pasco County, Florida. This facility 

consists of three, dual-fuel, nominal 170-megawatt (MW) General Electric model PG7241FA (GE 7FA) 

simple cycle combustion turbine-electric generators, three 75-foot exhaust stacks, and one 2.8 million 

gallon fuel oil storage tank. EFS Shady Hills LLC (Shady Hills) proposes to license, construct, and 

operate two additional new simple-cycle units at the Shady Hills Generating Station (the Proposed 

Project) (Figure 1). The Proposed Project consists of the addition of two simple cycle GE 7FA combustion 

turbines (CTs) that will use dry low-nitrogen oxide combustion technology. The primary fuel of the CTs will 

be natural gas with distillate fuel oil used as backup fuel. The Proposed Project will require an additional 

gas heater for the two new CTs. The present heater at the facility is only sized for the existing three GE 

7FA CTs. In addition, since the present generator is marginally rated, the emergency diesel/generator will 

need to be larger to accommodate the additional CTs. 

Land cover and land use within the Proposed Project site were classified using the Florida Land Use, Cover 

and Forms Classification System (FLUCFCS) (Florida Department of Transportation 1999) (Figure 2). The 

Proposed Project site and immediate vicinity include the following land uses: low density residential 

(FLUCFCS 110), industrial (FLUCFCS 150), open land (FLUCFCS 190), cropland and pastureland 
Mr. Roy Belden August 17, 2012 

GE Energy Financial Services 2 103-89556A 

Attachment B Ecological Assessment Report.docx 

(FLUCFCS 210), hardwood-coniferous mixed forest (FLUCFCS 434), coniferous (pine) plantations 

(FLUCFCS 441), reservoirs, less than 10 acres (FLUCFCS 534), freshwater marshes (FLUCFCS 641), 

emergent aquatic vegetation (FLUCFCS 644), disturbed land (FLUCFCS 740), and electric power facilities 

(FLUCFCS 831). The sections below describe land use and cover/habitat classifications within and 

immediately adjacent to the generating station site that may be utilized by listed wildlife species. 

Uplands 

Golder’s analysis of the Southwest Florida Water Management District (SWFWMD) land use maps 

(SWFWMD 2009) and the field review data revealed three upland land cover/habitat types within the 

Proposed Project site that may be utilized by listed wildlife species: coniferous (pine) plantations 

(FLUCFCS 441), disturbed land (FLUCFCS 740), and electric power facilities (FLUCFCS 831). These 

upland land cover types are described in more detail in the table below. 

Table 1: Upland Habitat Classifications within the Proposed Project Site 

FLUCFCS 

Code Description 

Acreage within 

Proposed 

Project Site 

441 

Coniferous 

(pine) 

Plantations 

This upland habitat consists of rows of planted 

slash pines (Pinus elliottii), sparsely interspersed 

with ruderal understory species such as dog 

fennel (Eupatorium capillifolium), cogon grass 

(Imperata cylindrica), and common ragweed 

(Ambrosia artemisiifolia). 1.62 

740 Disturbed Land 

This upland habitat was previously used as a 

construction laydown/staging area and 

consequently includes gravel perimeter roads 

throughout. Vegetated areas are dominated by 

ruderal species, including bahiagrass (Paspalum 

notatum), Spanish needles (Bidens alba), dog 

fennel, cogon grass, sedges (Cyperus spp.), 

Mexican clover (Richardia brasiliensis), crowfoot 

grass (Dactyloctenium aegyptium), common 

ragweed, and Japanese climbing fern (Lygodium 

japonicum). Additional species observed, although 

in smaller quantities, include prickly pear cactus 

(Opuntia humifusa), sky-blue lupine (Lupinus 

diffusus), and goldenaster (Pityopsis graminifolia). 10.71 

831 

Electric Power 

Facilities 

This land use consists of the existing generating 

station and associated facilities, including 

buildings and parking lots. Any vegetated areas 

consist of small grassy patches composed of 

bahia or other grasses. 15.56 

TOTAL 27.89 

Wetlands and Other Surface Waters 

Based on analysis of the SWFWMD land use maps and Golder’s site reconnaissance effort, one surface 

water (FLUCFCS 534, reservoir/stormwater pond) was identified in the northern portion of the Proposed 

Project site, just west of the proposed new fuel oil storage tank. No wetlands were identified within the 

site. Wetland and surface water land cover/habitat types adjacent to the Proposed Project site include: 

reservoirs, less than 10 acres (FLUCFCS 534), freshwater marshes (FLUCFCS 641), and emergent 

aquatic vegetation (FLUCFCS 644). 
Mr. Roy Belden August 17, 2012 

GE Energy Financial Services 3 103-89556A 

Attachment B Ecological Assessment Report.docx 

Table 2: Wetland and/or Other Surface Water Habitat Classifications within the Proposed Project 

Site 

FLUCFCS 

Code Description 

Acreage within 

Proposed 

Project Site 

534 

Reservoirs, less 

than 10 acres 

This surface water/stormwater pond is located in 

the northern portion of the Proposed Project site, 

just west of the proposed new fuel oil storage tank. 2.19 

TOTAL 2.19 

Based on Golder’s analysis of the Federal Emergency Management Agency (FEMA) floodplain database, 

the Proposed Project site is not located within the 100-year floodplain (Figure 3). In addition, Golder’s 

review of the National Wetlands Inventory database confirmed that no wetlands are, or were historically, 

located within or immediately adjacent to the Proposed Project site (Figure 4). 

Soils 

According to the U.S. Department of Agriculture Natural Resources Conservation Service, there are two 

soil types within the Proposed Project site: Candler Fine sand, 0 to 5 percent slopes (±29.72 acres) and 

Tavares sand, 0 to 5 percent slopes (±0.36 acres) (Figure 5). 

The dominant soil type, Candler Fine sand, 0 to 5 percent slopes, consists of excessively drained soils 

with a depth to water table below 80 inches that typically occur in sandhill communities. Tavares sand, 0 

to 5 percent slopes consists of moderately well-drained soils that typically occur within low ridges. This 

soil type typically has a depth to water table of 40 to 60 inches for 6 to 12 months of the year and below 

60 inches during periods of drought. 

Listed Species 

On August 18, 2011 via vehicular and pedestrian transects, Golder personnel assessed land 

cover/habitats for the presence of species that are considered threatened, endangered, and/or species of 

special concern. Listed plant species are those plants that are listed by the USFWS or the Florida 

Department of Agriculture and Consumer Services (FDACS) as endangered, threatened, of special 

concern, or commercially exploited. Listed animal species are those animals that are listed as 

endangered, threatened, or of special concern federally by the USFWS or within the state of Florida by 

the FFWCC. 

To allow it to focus site reconnaissance efforts on potentially occurring species, Golder obtained a list of 

federally listed plant and wildlife species for Pasco County, Florida from the USFWS (USFWS 2010a) 

(Attachment 1). Additionally, Golder obtained state and federally listed species occurrence data for an 

area within a 1-mile radius of the Proposed Project site from the Florida Natural Areas Inventory (FNAI), 

which maintains a database of known occurrences of listed species throughout Florida (FNAI Biodiversity 

Matrix Unit 23978, Attachment 2 and Figure 6). The FFWCC Bald Eagle Nest Locator database (FFWCC 

2010) and breeding bird atlas (FFWCC 2003) were also used to identify the location and status of any 

bald eagle nests or breeding bird colonies in the vicinity of the Proposed Project site (Figure 6). The 

USFWS Wood Stork Colony and Core Foraging Area database (USFWS 2010b) was used to identify 

wood stork colonies and core foraging areas in the vicinity of the Proposed Project site (Figure 7). 

All observations of listed and non-listed wildlife species within and adjacent to the Proposed Project site 

were documented. These observations included direct sightings of species or signs of their presence, 

including tracks, scat, nests, carcasses, and, typically with avifauna and amphibians, calls. 

FNAI database species occurrences and listed species identified during the site visit are described below. 
Mr. Roy Belden August 17, 2012 

GE Energy Financial Services 4 103-89556A 

Attachment B Ecological Assessment Report.docx 

Flora 

Initiated in 1984, the Preservation of Native Flora of Florida Act (Sections 581.011 and 581.185(2), 

Florida Statutes, and Chapter 5B-40.001, FAC, defines plant species in Florida that are protected 

because of danger of extinction or rapid decline, or that are commercially exploited, thus averting damage 

to native plant populations. Agency permits as well as permission from the landowner are required to 

harvest or disturb plants listed in this act, and a permit is required to sell commercially exploited plants. 

The FNAI list of threatened and endangered plants was used to determine which threatened and 

endangered plants occur within Pasco County, since the FNAI list incorporates both the FDACS (state)- 

and USFWS (federal)-listed status (FNAI 2010). 

According to the FNAI, no listed plant species have been documented within 1 square mile of the 

Proposed Project site. However, FNAI’s Biodiversity Matrix Report identified 15 listed plant species with a 

potential to occur in the vicinity of the Proposed Project site in Pasco County, Florida (Attachment 2). Of 

the 15 listed plant species, only one, Carter’s warea (Warea carteri), is federally listed as endangered, 

while the state lists 11 of the 15 plant species as endangered and the remaining 4 as threatened. FNAI’s 

closest recorded occurrence of a listed plant species, pondspice (Litsea aestivalis), which is listed by the 

FDACS as endangered, is located in a residential area just south of State Road 52 (approximately 4.5 

miles southwest of the Proposed Project site) (FNAI 2007). 

Because of its industrial nature, it is unlikely that listed or endemic plant species occur within the 

Proposed Project site, nor were any of these listed or endemic plant species observed at the time of the 

site reconnaissance. 

Fauna 

The presence and potential for occurrence of important faunal species in the Proposed Project site were 

determined from evaluation of the presence or absence of habitat types, literature review (including FNAI 

and FFWCC Bald Eagle Nest Locator database queries), aerial photo interpretation, and preliminary site 

reconnaissance. 

Natural habitats within the Proposed Project site have been historically altered primarily for industrial 

purposes, and planted pines are of moderately lower value to wildlife. 

According to the FNAI (FNAI 2010), no listed species have been documented within 1 square mile of the 

Proposed Project site in Pasco County, Florida (Attachment 2). However, the FNAI identified six listed 

wildlife species likely to occur and eight with a potential to occur within 1 square mile of the Proposed 

Project site. Out of the 14 FFWCC (state)-listed species identified by the FNAI as occurring or having a 

potential to occur, only 2 are federally listed (by the USFWS). All 14 species are discussed in greater 

detail below. 

Federally Listed Species 

Reptiles 

Eastern Indigo Snake (Drymarchon couperi) 

The eastern indigo snake as is listed as federally threatened. This snake can occur within a broad range 

of suitable habitats, from scrub and sandhill to wet prairies. In its northern range, it is often commensal 

with the gopher tortoise, using their burrows for shelter during the winter (FNAI 2001). Due to the 

presence of gopher tortoises within the Proposed Project site, there is a potential for the eastern indigo 

snake to be present. 
Mr. Roy Belden August 17, 2012 

GE Energy Financial Services 5 103-89556A 

Attachment B Ecological Assessment Report.docx 

Birds 

Wood Stork (Mycteria americana) 

The wood stork as is listed as federally endangered. Wood storks prefer nesting in cypress swamps and 

mixed forested wetlands, and they forage mainly in shallow water in freshwater marshes, swamps, lagoons, 

ponds, tidal creeks, flooded pastures, and ditches (FNAI 2001). SWFWMD staff previously identified several 

wood storks foraging within freshwater marshes approximately 1,000 ft south of the Proposed Project site 

(SWFWMD RAI 2010). Because of the lack of preferred nesting habitat, it is unlikely that this species nests 

nearby; however, it may occasionally forage in the vicinity of the Proposed Project site.

The closest documented wood stork colony (Embassy, USFWS 2010) is located approximately 10.2 miles 

southwest of the Proposed Project site, and the site falls within five colonies’ 15-mile core foraging area 

radii (Figure 7). No impacts to wood storks or their habitats are anticipated due to construction/operation 

of the Proposed Project. 

State-listed Species 

Amphibians 

Gopher Frog (Rana capito) 

The gopher frog is currently listed by the FFWCC as a species of special concern. It is typically found in 

sandhill and scrub habitat in the vicinity of isolated wetlands or large ponds, and is considered to be a 

commensal species to the gopher tortoise, using their burrows for shelter (FNAI 2001). It is unlikely that the 

gopher frog is present due to the lack of its preferred habitat within the immediate vicinity of the Proposed 

Project site. 

This species is currently listed as a species of special concern by the FFWCC; however, the gopher frog 

underwent a biological status review in June 2011 and was approved for removal from the statedesignated protected species list (FFWCC 2011). Management plans are currently being prepared for all 

state-listed species that do not have recent management plans completed. FFWCC will continue to 

maintain a separate Species of Special Concern category until all the species have been reviewed and 

those species are either designated as State-designated Threatened, or given a management plan and 

removed from the list. 

Reptiles 

Gopher Tortoise (Gopherus polyphemus) 

The FFWCC currently lists the gopher tortoise as threatened. Gopher tortoises are commonly found in dry 

upland habitats, such as sandhills, scrub, xeric oak hammock, and dry pine flatwoods. They are also 

found in pastures and old fields (FNAI 2001). Eighteen gopher tortoise burrows, of which 14 were 

potentially occupied, were identified within the Proposed Project site (Figure 8). 

If gopher tortoise burrows can be avoided by a buffer that is greater than or equal to 25 feet (ft) in radius, 

no permit is required. If impacts to burrows cannot be avoided, a relocation permit will be required from 

the FFWCC, and gopher tortoises will need to be relocated to either on- or off-site areas pursuant to 

FFWCC guidelines. 

Florida Pine Snake (Pituophis melanoleucus mugitus) 

The Florida pine snake often coexists with gopher tortoises and southeastern pocket gophers (Geomys 

pinetis) in sandhills, old fields and pastures, sand pine scrub, and scrubby flatwoods (FNAI 2001). This 

species is currently listed as a species of special concern by the FFWCC; however, the Florida pine 

snake underwent a biological status review in June 2011 and was approved for protection status as a 

threatened species (FFWCC 2011). Management plans are currently being prepared for all state-listed 
Mr. Roy Belden August 17, 2012 

GE Energy Financial Services 6 103-89556A 

Attachment B Ecological Assessment Report.docx 

species that do not have recent management plans completed. FFWCC will continue to maintain a 

separate Species of Special Concern category until all the species have been reviewed and those 

species are either designated as State-designated Threatened, or given a management plan and 

removed from the list. 

The Florida pine snake was observed within the disturbed land habitat in the northeastern portion of the 

Proposed Project site. The observation was made in the vicinity of both gopher tortoise and southeastern 

pocket gopher burrows. Gopher tortoise burrows within the Proposed Project site will most likely need to 

be excavated and commensal species relocated. If pine snakes are encountered during gopher tortoise 

relocation activities, they will be relocated to an approved recipient site, along with gopher tortoises and 

other commensal species, in accordance with regulatory permit guidelines. 

Birds 

Florida Burrowing Owl (Athene cunicularia floridana) 

The Florida burrowing owl is listed as a species of special concern by the FFWCC. It lives in burrows in 

sandy soils associated with cattle pastures, prairies, and sandhills (FNAI 2001). No burrowing owls, nor 

their burrows, were observed within the Proposed Project site during the site reconnaissance effort. No 

adverse impacts to burrowing owls are anticipated due to the Proposed Project. 

This species is currently listed as a species of special concern by the FFWCC; however, the Florida 

burrowing owl underwent a biological status review in June 2011 and was approved for protection status 

as a threatened species (FFWCC 2011). Management plans are currently being prepared for all statelisted species that do not have recent management plans completed. FFWCC will continue to maintain a 

separate Species of Special Concern category until all the species have been reviewed and those 

species are either designated as State-designated Threatened, or given a management plan and 

removed from the list. 

Little Blue Heron (Egretta caerulea) 

The little blue heron is listed as a species of special concern by the FFWCC. They prefer freshwater lakes, 

marshes, swamps, and streams for foraging, and cypress trees for roosting (FNAI 2001). This species was 

identified by FNAI within wetland systems approximately 1.0 mile southeast and 1.1 miles southwest of the 

Proposed Project site. Although this species likely forages within freshwater marshes and wet prairies in the 

vicinity of the site, it is not likely that the little blue heron nests in the area, because the closest documented 

breeding bird colony (Atlas Number 2674) is located approximately 1.5 miles southeast of the Proposed 

Project site. No adverse impacts to little blue herons are anticipated due to the Proposed Project. 

This species is currently listed as a species of special concern by the FFWCC; however, the little blue 

heron underwent a biological status review in June 2011 and was approved for protection status as a 

threatened species (FFWCC 2011). Management plans are currently being prepared for all state-listed 

species that do not have recent management plans completed. FFWCC will continue to maintain a 

separate Species of Special Concern category until all the species have been reviewed and those 

species are either designated as State-designated Threatened, or given a management plan and 

removed from the list. 

Snowy Egret (Egretta thula) 

The snowy egret is listed as a species of special concern by the FFWCC. It is widely distributed in Florida 

in both fresh- and saltwater systems (FNAI 2001). This species was identified by FNAI within wetland 

systems approximately 1.0 mile southeast of the Proposed Project site. Although this species likely 

forages within freshwater marshes and wet prairies in the vicinity of the site, it is not likely that the snowy 

egret nests in the area, because the closest documented breeding bird colony (Atlas Number 2674) is 

located approximately 1.5 miles southeast of the Proposed Project site. No adverse impacts to snowy 

egrets are anticipated due to the Proposed Project. 
Mr. Roy Belden August 17, 2012 

GE Energy Financial Services 7 103-89556A 

Attachment B Ecological Assessment Report.docx 

This species is currently listed as a species of special concern by the FFWCC; however, the snowy egret 

underwent a biological status review in June 2011 and was approved for removal from the statedesignated protected species list (FFWCC 2011). Management plans are currently being prepared for all 

state-listed species that do not have recent management plans completed. FFWCC will continue to 

maintain a separate Species of Special Concern category until all the species have been reviewed and 

those species are either designated as State-designated Threatened, or given a management plan and 

removed from the list. 

White Ibis (Eudocimus albus) 

The white ibis is listed as a species of special concern by the FFWCC. It inhabits a variety of wetland 

habitats, including freshwater and brackish marshes, salt flats, forested wetlands, wet prairies, swales, 

and man-made ditches (FNAI 2001). This species was identified by FNAI within wetland systems 

approximately 1.1 miles southwest of the Proposed Project site. Although this species likely forages within 

freshwater marshes and wet prairies in the vicinity of the site, it is not likely that the white ibis nests in the 

area because the closest documented breeding bird colony (Atlas Number 2674) is located approximately 

1.5 miles southeast of the Proposed Project site. No adverse impacts to the white ibis are anticipated due 

to the Proposed Project. 

This species is currently listed as a species of special concern by the FFWCC; however, the white ibis 

underwent a biological status review in June 2011 and was approved for removal from the statedesignated protected species list (FFWCC 2011). Management plans are currently being prepared for all 

state-listed species that do not have recent management plans completed. FFWCC will continue to 

maintain a separate Species of Special Concern category until all the species have been reviewed and 

those species are either designated as State-designated Threatened, or given a management plan and 

removed from the list. 

Southeastern American Kestrel (Falco sparverius paulus) 

The southeastern American kestrel is found throughout Florida year-round, but seasonal occurrence is 

complicated by the arrival of northern migrants in winter (FNAI 2001). The subspecies that breeds in 

Florida is classified by the FFWCC as threatened, while northern migrants typically arriving in September 

and departing by March are not listed. Kestrels seen in Florida during May through June are the resident 

southeastern American kestrels. Neither the American kestrel nor the southeastern subspecies are listed 

federally by the USFWS. The southeastern American kestrel commonly inhabits open areas, such as 

open pine habitats, woodland edges, prairies, and pastures (FNAI 2001). 

A southeastern American kestrel was identified by FNAI within the transmission line right-of-way 

approximately 0.6 mile to the west of the Proposed Project site. Southeastern American kestrels nest 

between mid-March and early June. Current recommended management guidelines state that a 492-ftradius buffer zone should be maintained around any active nest sites and disturbance inside the nest-site 

buffer should be minimized during the courtship, breeding, and nesting period (i.e., January to August) 

(Lane and Fischer 1997). Adverse impacts to the southeastern American kestrel are not anticipated due 

to the Proposed Project. 

Florida Sandhill Crane (Grus canadensis pratensis) 

The FFWCC lists the Florida sandhill crane as threatened. It is found year-round in prairies, freshwater 

marshes, and pastures throughout Florida, while the non-listed migrant greater sandhill crane 

(G. canadensis tabida) generally arrives in October and departs by March (FNAI 2001). 

SWFWMD staff previously identified a nesting pair of sandhill cranes within freshwater marshes 

approximately 1,000 ft south of the Proposed Project site (SWFWMD Request for Additional Information 

[RAI] 2010). The FFWCC recommends a 400-ft protective buffer around active crane nests. The crane 

nesting season is February to May, and the guidelines do not mention any protective measures for cranes 

outside the nesting season. If nesting cranes were identified within or adjacent to the site, it is likely that 

the FFWCC would require some protective measures. 
Mr. Roy Belden August 17, 2012 

GE Energy Financial Services 8 103-89556A 

Attachment B Ecological Assessment Report.docx 

Mammals 

Florida Mouse (Podomys floridanus) 

The Florida mouse is listed as a species of special concern by the FFWCC. They prefer xeric upland 

habitats with sandy soils, such as scrub, sandhill, and ruderal sites, and they often inhabit burrows of the 

gopher tortoise (FNAI 2001). Due to the presence of gopher tortoises and their burrows within the 

Proposed Project site, it is moderately likely that the Florida mouse is present as well. 

This species is currently listed as a species of special concern by the FFWCC; however, the Florida 

mouse underwent a biological status review in June 2011 and was approved for removal from the statedesignated protected species list (FFWCC 2011). Management plans are currently being prepared for all 

state-listed species that do not have recent management plans completed. FFWCC will continue to 

maintain a separate Species of Special Concern category until all the species have been reviewed and 

those species are either designated as State-designated Threatened, or given a management plan and 

removed from the list. 

Sherman’s Fox Squirrel (Sciurus niger shermani) 

The Sherman’s fox squirrel is listed as a species of special concern by the FFWCC. They commonly 

inhabit sandhills, pine flatwoods, pastures, and other open, ruderal habitats with scattered pines and oaks 

(FNAI 2001). Because of the presence of pasture and other open, ruderal habitats with scattered pines 

and oaks to the east of the Proposed Project site, it is moderately likely that the Sherman’s fox squirrel is 

present adjacent to the Proposed Project site. 

If the Sherman’s fox squirrel were encountered on the Proposed Project site, the FFWCC would most 

likely require some protective measures for fox squirrels. In Golder’s experience, the FFWCC will permit 

development within 125 ft of active fox squirrel nests as long as the nest and young are not disturbed. 

The fox squirrel nesting season typically occurs twice a year, between January and February, and 

between June and August (NatureServe Explorer 2008). 

Florida Black Bear (Ursus americanus floridanus) 

The FFWCC lists the Florida black bear as threatened. They prefer large upland forests and large 

swamps (FNAI 2001). It is unlikely that the Florida black bear is present within the immediate proximity of 

the Proposed Project site due to the lack of large, contiguous tracts of forested wetlands and mixed 

hardwood-conifer forests. Adverse impacts to the Florida black bear are not anticipated from the 

construction of the Proposed Project. 

This species is currently listed as a species of special concern by the FFWCC; however, the Florida black 

bear underwent a biological status review in June 2011 and was approved for removal from the statedesignated protected species list (FFWCC 2011). Management plans are currently being prepared for all 

state-listed species that do not have recent management plans completed. FFWCC will continue to 

maintain a separate Species of Special Concern category until all the species have been reviewed and 

those species are either designated as State-designated Threatened, or given a management plan and 

removed from the list. 

Non-listed Species 

Although the bald eagle (Haliaeetus leucocephalus) is not currently classified by the USFWS or the 

FFWCC as threatened or endangered, it is protected under the federal Bald and Golden Eagle Protection 

Act and the Migratory Bird Treaty Act, as well as Florida’s Bald Eagle Management Plan. Bald eagles 

typically inhabit areas close to coastal areas, bays, rivers, lakes, or other bodies of water that provide 

concentrations of food sources (FNAI 2001). Impacts to bald eagles may be avoided through adherence 

to the national bald eagle management guidelines (USFWS, 2007) of a construction setback of 330 to 

660 ft from any active nests. According to the FFWCC Bald Eagle Nest Locator database, the closest 
Mr. Roy Belden August 17, 2012 

GE Energy Financial Services 9 103-89556A 

Attachment B Ecological Assessment Report.docx 

bald eagle nest (Nest ID PS008) is located approximately 2.8 miles northeast of the Proposed Project 

site. The Proposed Project is not anticipated to have adverse impacts on nesting bald eagles. 

Non-listed species observed on the site include mourning doves (Zenaida macroura), wild turkey 

(Meleagris gallopavo), holes/burrows of nine-banded armadillo (Dasypus novemcinctus) and 

southeastern pocket gopher, and the skull of a gray fox (Urocyon cinereoargenteus). 

CONCLUSIONS AND RECOMMENDATIONS 

Based on Golder’s field reviews and examination of available agency data, no federally listed species 

were observed within the Proposed Project site. Adverse impacts from the Proposed Project to federally 

listed flora or fauna are not anticipated. 

Two state-designated species, the gopher tortoise (threatened) and the Florida pine snake (species of 

special concern), were observed within the Proposed Project site during the site reconnaissance effort. 

Pursuant to FFWCC’s gopher tortoise permitting guidelines, a gopher tortoise survey should be 

conducted within 90 days of the anticipated construction commencement date and the survey results 

submitted to FFWCC with supporting permit application documents. Construction activities may not begin 

until the gopher tortoise relocation permit has been approved by the FFWCC and gopher tortoises have 

been relocated to an FFWCC-approved recipient site. Typically, up to one Florida pine snake 

encountered during gopher tortoise excavation activities may be relocated to the approved recipient site; 

however, encounters with and/or relocation of additional pine snakes will require further consultation with 

the FFWCC. 

USFWS’ standard protection measures for the eastern indigo snake will be enforced during construction 

of the Proposed Project to ensure eastern indigo snakes, if present, are not harmed. These protection 

measures include, but are not limited to, training contractors in the proper identification of eastern indigo 

snakes (and Florida pine snakes); and posting signs on the construction site to aid in the proper 

identification of indigo snakes and the procedures to follow if an indigo snake is encountered. If an 

eastern indigo snake is encountered, work in the area will be stopped and will not recommence until the 

indigo snake has safely evacuated the area on its own. 

Please do not hesitate to contact Heather Ahrens at (813) 287-1717 if you have any questions regarding 

the ecological assessment conducted within the generating station site. 

Sincerely, 

GOLDER ASSOCIATES INC. 

 Heather T. Ahrens David T. Larocca 

Senior Ecologist Senior Engineer 

Attachments: Figure 1, Site Location 

 Figure 2, Land Use/Land Cover 

Figure 3, FEMA Flood Zones 

Figure 4, National Wetlands Inventory 

Figure 5, Soils 

Figure 6, Bald Eagle Nests and FNAI Listed Species Occurrences 

Figure 7, Wood Stork Core Nesting Colonies and Foraging Areas 

Figure 8, Gopher Tortoise Burrow Locations 

Attachment 1, Federally Listed Plant and Wildlife Species for Pasco County, Florida 

Attachment 2, FNAI Biodiversity Matrix Report and Associated Tables 

HTA/DTL/lcr 
Mr. Roy Belden August 17, 2012 

GE Energy Financial Services 10 103-89556A 

Attachment B Ecological Assessment Report.docx 

REFERENCES 

Federal Emergency Management Agency. 1996. Flood Zone Maps. 

FFWCC (Florida Fish and Wildlife Conservation Commission). 2003. Florida’s breeding bird atlas: A 

collaborative study of Florida’s birdlife. Online: http://www.myfwc.com/bba/ (accessed September 

2011). 

FFWCC. 2010. Bald Eagle Nest Locator. Online: 

https://public.myfwc.com/FWRI/EagleNests/nestlocator.aspx (accessed August 2011). 

FFWCC. 2011. Biological Status Review for FFWCC's Imperiled Species. Online: 

http://myfwc.com/media/1354992/StaffListingRecommendations_2011.pdf (accessed September 

2011). 

Florida Department of Transportation. 1999. Surveying and Mapping Office, Land Use, Cover and Forms 

Classification System. 

FNAI (Florida Natural Areas Inventory). 2007. Element Occurrence Point Data. Online: http://www.fnai.org

(accessed September 2011). 

FNAI. 2001. Field Guide to the Rare Plants and Animals of Florida. Online: 

http://www.fnai.org/FieldGuide/search_001.cfm (retrieved September 2010). 

FNAI. 2010. FNAI Biodiversity Index, Matrix Units 23978. Online: 

http://data.labins.org/mapping/FNAI_BioMatrix/GridSearch.cfm?sel_id=21964,22206&extent= 

527458,418366.65625,530676.75,419976.03125 (retrieved September 2011). 

Lane, J. and R.A. Fischer. 1997. Species Profile: Southeastern American Kestrel (Falco sparverius 

paulus) on Military Installations in the Southeastern United States. Technical Report SERDP-97-4, 

August 1997. Mississippi: U.S. Army Corps of Engineers. 

NatureServe. 2009. NatureServe Explorer: An online encyclopedia of life, Version 7.1. NatureServe, 

Arlington, Virginia. Online: http://www.natureserve.org/explorer (accessed October 2010). 

Southwest Florida Water Management District. 2009. GIS Data and Maps. Online: 

http://www.swfwmd.state.fl.us/data/gis/layer_library/ (accessed August 2011). 

SWFWMD. April 30, 2010. Request for Additional Information. Shady Hills Power Company, LLC, Water 

Use Application No. 20012052.004. 

US Department of Agriculture. 2010. Natural Resources Conservation Service. Web Soil Survey, Pasco 

County, Florida. http://websoilsurvey.nrcs.usda.gov/app/WebSoilSurvey.aspx (accessed August 

2011). 

USFWS (US Fish and Wildlife Service). 2007. National Bald Eagle Management Guidelines. 

USFWS 2010a. Federally Listed Species in Pasco County, Florida. Online: 

http://www.fws.gov/northflorida/CountyList/Pasco.htm (accessed May 2011). 

USFWS. 2010b. Wood Stork Colony and Core Foraging Areas. Online: 

http://www.fws.gov/northflorida/WoodStorks/wood-storks.htm (retrieved 2010). 
FIGURES 
589

24S17E23

24S17E24

24S17E26 24S17E25

24S17E35

24S17E36

24S18E19

24S18E30

24S18E31

25S17E02 25S18E06 25S17E01

water

GIS

REVIEW

DESIGN SCALE:

F:\PROJECTS\201 PROJ\103-895

CHECK

0

PROJECT No. 103-895 FILE No. 103-895%00

JG

JG AS SHOWN

SO

REFERENCES

1. APPROXIMATE PROJECT LOCATION: GOLDER ASSOCIATES INC., 2011

2. ROADS: FLORIDA DEPARTMENT OF TRANSPORTATION, 2011

3. TOWNSHIP-RANGE-SECTION: FLORIDA RESOURCES & ENVIRONMENTAL ANALYSIS CENTER, 2003

4. COUNTY BOUNDARIES: FLORIDA GEOGRAPHIC DATA LIBRARY, 2008

5. USGS TOPOGRAPHIC MAP: NATIONAL GEOGRAPHIC SOCIETY, 2010

2,000 0 2,000

Feet

FIGURE 1

PROJECT

TITLE

SHADY HILLS

SITE LOCATION

REV.

06/13/2011

06/13/2011

07/25/2011

REV. DATE DES REVISION DESCRIPTION GIS CHK RVW

LEGEND

PASCO

COUNTY

589

55

45

52

19

41

HERNANDO

COUNTY

PASCO

COUNTY

REGIONAL MAP

APPROXIMATE PROJECT

LOCATION

TOLL ROAD

US ROAD

STATE ROAD

COUNTY ROAD

TOWNSHIP-RANGE

-SECTION

COUNTY BOUNDARY
HUDSON AVE

MERCHANT ENERGY WAY

110

150

210

210

190

190

190

434

434

441

534

641

641

641

641

641

641

641

830

441 644

534

740

441

831

GIS

REVIEW

DESIGN SCALE:

F:\PROJECTS\2010 PROJ\103-89556 GE Shady Hills Revision\B - Ecology\Figures\103-89556B002 LAND USE.mxd

CHECK

0

PROJECT No. 103-89556 FILE No. 103-89556B002

JG

JG AS SHOWN

HA

REFERENCES

1. APPROXIMATE PROJECT BOUNDARY: GOLDER ASSOCIATES INC., 2011

2. LAND USE/LAND COVER: SOUTHWEST FLORIDA WATER MANAGEMENT

DISTRICT (SWFWMD), 2009

3. 2010 AERIAL: SOUTHWEST FLORIDA WATER MANAGEMENT DISTRICT

AND WOLLPERT, INC., 2010

400 0 400

Feet

FIGURE 2

PROJECT

TITLE

SHADY HILLS

LAND USE/LAND COVER

REV.

08/16/2011

08/16/2011

08/16/2011

REV. DATE DES REVISION DESCRIPTION GIS CHK RVW

LEGEND

APPROXIMATE PROJECT BOUNDARY

LAND USE/LAND COVER BOUNDARY

LAND 

USE 

CODE

DESCRIPTION

110 RESIDENTIAL, LOW DENSITY (LESS THAN TWO DWELLING UNITS PER ACRE)

150 INDUSTRIAL

190 OPEN LAND

210 CROPLAND AND PASTURELAND

434 HARDWOOD - CONIFEROUS MIXED

441 CONIFEROUS PLANTATIONS

534 RESERVOIRS LESS THAN 10 ACRES

641 FRESHWATER MARSHES

644 EMERGENT AQUATIC VEGETATION

740 DISTURBED LAND

830 UTILITIES

831 ELECTRIC POWER FACILITIES
AE

A

A

A

A

SHADY HILLS RD

HUDSON AVE

HARMON DR NAGLE 

CT

HELM CT

SLOAN CT

HAYS RD

MERCHANT ENERGY WAY

HAYS RD

CRELA DR

HUDSON AVE

SOFT

WIND LN

GIS

REVIEW

DESIGN SCALE:

F:\PROJECTS\2010 PROJ\103-89556 GE Shady Hills Revision\B - Ecology\Figures\103-89556B006 FLOOD ZONES.mxd

CHECK

0

PROJECT No. 103-89556 FILE No. 103-89556B006

JG

JG AS SHOWN

SO

REFERENCES

1. APPROXIMATE PROJECT BOUNDARY: GOLDER ASSOCIATES INC., 2011

2. FLOOD ZONES: FEDERAL EMERGENCY MANAGEMENT AGENCY (FEMA), 1996

3. 2009 AERIAL: I-CUBED, 2010

1,000 0 1,000

Feet

FIGURE 3

PROJECT

TITLE

SHADY HILLS

FEMA FLOOD ZONES

REV.

08/16/2011

08/16/2011

08/16/2011

REV. DATE DES REVISION DESCRIPTION GIS CHK RVW

LEGEND

ALL UNSHADED AREAS ARE ZONE X AND DO NOT FALL WITHIN A FLOOD

ZONE.

NOTE

APPROXIMATE PROJECT BOUNDARY

FLOOD ZONES

A - AN AREA INUNDATED BY 100-YEAR FLOODING,

FOR WHICH NO BASE FLOOD ELEVATIONS HAVE

BEEN DETERMINED.

AE - AN AREA INUNDATED BY 100-YEAR FLOODING,

FOR WHICH BASE FLOOD ELEVATIONS HAVE

BEEN DETERMINED.
MERCHANT ENERGY WAY

HUDSON AVE

PEM1A

PAB4H

PAB3H

PAB3H

PEM1A

PEM1A

PAB3H

PEM1F

GIS

REVIEW

DESIGN SCALE:

F:\PROJECTS\2010 PROJ\103-89556 GE Shady Hills Revision\B - Ecology\Figures\103-89556B003 NWI.mxd

CHECK

0

PROJECT No. 103-89556 FILE No. 103-89556B003

JG

JG AS SHOWN

HA

REFERENCES

1. APPROXIMATE PROJECT BOUNDARY: GOLDER ASSOCIATES INC., 2011

2. NATIONAL WETLANDS INVENTORY (NWI): U.S. FISH AND WILDLIFE SERVICE,

DIVISION OF HABITAT AND RESOURCE CONSERVATION, 2008

3. 2010 AERIAL: SOUTHWEST FLORIDA WATER MANAGEMENT DISTRICT AND

WOLLPERT, INC., 2010

400 0 400

Feet

FIGURE 4

PROJECT

TITLE

SHADY HILLS

NATIONAL WETLANDS INVENTORY

REV.

08/16/2011

08/16/2011

08/16/2011

REV. DATE DES REVISION DESCRIPTION GIS CHK RVW

LEGEND

PEM1A = PALUSTRINE; EMERGENT; PERSISTENT; TEMPORARILY FLOODED

PAB3H = PALUSTRINE; AQUATIC BED; ROOTED VASCULAR; PERMANENTLY FLOODED

PAB4H = PALUSTRINE; AQUATIC BED; FLOATING VASCULAR; PERMANENTLY FLOODED

PEM1F = PALUSTRINE; EMERGENT; PERSISTENT; SEMIPERMANENTLY FLOODED

APPROXIMATE PROJECT BOUNDARY

NATIONAL WETLANDS

INVENTORY WETLAND
MERCHANT ENERGY WAY

HUDSON AVE

13

6

6

6

6

23

99

GIS

REVIEW

DESIGN SCALE:

F:\PROJECTS\2010 PROJ\103-89556 GE Shady Hills Revision\B - Ecology\Figures\103-89556B005 SOILS.mxd

CHECK

0

PROJECT No. 103-89556 FILE No. 103-89556B005

JG

JG AS SHOWN

HA

REFERENCES

1. APPROXIMATE PROJECT BOUNDARY: GOLDER ASSOCIATES INC., 2011

2. SOILS: U.S. DEPARTMENT OF AGRICULTURE, NATURAL RESOURCES

CONSERVATION SERVICE, 2010

3. 2010 AERIAL: SOUTHWEST FLORIDA WATER MANAGEMENT DISTRICT

AND WOLLPERT, INC., 2010

400 0 400

Feet

FIGURE 5

PROJECT

TITLE

SHADY HILLS

SOILS

REV.

08/16/2011

08/16/2011

08/16/2011

REV. DATE DES REVISION DESCRIPTION GIS CHK RVW

LEGEND

APPROXIMATE PROJECT BOUNDARY

SOIL BOUNDARY

MAP UNIT 

SYMBOL

MAP UNIT NAME

06 TAVARES SAND, 0 TO 5 PERCENT SLOPES

13 CANDLER FINE SAND, 0 TO 5 PERCENT SLOPES

23 BASINGER FINE SAND, DEPRESSIONAL

99 WATER
White

Ibis

Snowy

Egret

Gopher

Tortoise

Southeastern

American

Kestrel

Pondspice

Little

Blue

Heron

Little

Blue

Heron

GOPHER TORTOISE

AND FLORIDA

PINE SNAKE

PS008

587

45

52

589

41

GIS

REVIEW

DESIGN SCALE:

F:\PROJECTS\2010 PROJ\103-89556 GE Shady Hills Revision\B - Ecology\Figures\103-89556B004 LISTED SPECIES.mxd

CHECK

0

PROJECT No. 103-89556 FILE No. 103-89556B004

JG

JG AS SHOWN

HA

REFERENCES

1. APPROXIMATE PROJECT LOCATION AND LISTED SPECIES OBSERVED

BY GOLDER: GOLDER ASSOCIATES INC., 2011

2. ELEMENT OCCURRENCE: FLORIDA NATURAL AREAS INVENTORY, 2006

3. BALD EAGLE NEST LOCATIONS: FLORIDA FISH AND WILDLIFE

CONSERVATION COMISSION, 2010

4. ROADS: FLORIDA DEPARTMENT OF TRANSPORTATION, 2011

5. 2009 AERIAL: I-CUBED, 2010

1 0 1

Miles

FIGURE 6

PROJECT

TITLE

SHADY HILLS

BALD EAGLE NESTS

AND FNAI LISTED SPECIES OCCURRENCES

REV.

08/16/2011

08/16/2011

08/16/2011

REV. DATE DES REVISION DESCRIPTION GIS CHK RVW

LEGEND

APPROXIMATE PROJECT LOCATION

LISTED SPECIES

OBSERVED BY GOLDER

FNAI LISTED SPECIES/ELEMENT

OCCURRENCE

BALD EAGLE NEST

1 MILE RADIUS

TOLL ROAD

US ROAD

STATE ROAD

COUNTY ROAD
CITRUS

COUNTY

HERNANDO

COUNTY

HILLSBOROUGH

COUNTY

PASCO

COUNTY

PINELLAS

COUNTY

SUMTER

COUNTY

569

60

568

597

628

700

579

580

700

50A

54A

566

553

56

48

575

39

581

54

50

43

586

583

35

590

582

685

574

618

600

595

93

589

93A

55

45

400

52

301B

98

301

301

41B

41

41

98

92

19A

19

275

275

75

75

4

Weeki

Wachee

Greenbrooke

Seven

Springs

Embassy

Heron

Point

GIS

REVIEW

DESIGN SCALE:

F:\PROJECTS\2010 PROJ\103-89556 GE Shady Hills Revision\B - Ecology\Figures\103-89556B007 WOOD STORKS.mxd

CHECK

0

PROJECT No. 103-89556 FILE No. 103-89556B007

JG

JG AS SHOWN

HA

REFERENCES

1. APPROXIMATE PROJECT LOCATION: GOLDER ASSOCIATES

INC., 2011

2. FLORIDA WOOD STORK NESTING COLONIES AND CORE

FORAGING AREAS: US FISH AND WILDLIFE SERVICE, 2010

3. ROADS: FLORIDA DEPARTMENT OF TRANSPORTATION, 2011

4. COUNTY BOUNDARIES: FLORIDA GEOGRAPHIC DATA

LIBRARY, 2008

8 0 8

Miles

FIGURE 7

PROJECT

TITLE

SHADY HILLS

WOOD STORK NESTING COLONIES AND

CORE FORAGING AREAS

REV.

08/16/2011

08/16/2011

08/16/2011

REV. DATE DES REVISION DESCRIPTION GIS CHK RVW

LEGEND

APPROXIMATE PROJECT LOCATION

FLORIDA WOOD STORK NESTING COLONY

15-MILE FLORIDA WOOD STORK

CORE FORAGING AREA RADIUS

COUNTY BOUNDARY

INTERSTATE

TOLL ROAD

US ROAD

STATE ROAD
GT01 GT02

GT03

GT04

GT18 GT05

GT06

GT07 GT08

GT09

GT10

GT11

GT12

GT13

GT14

GT15

GT16

GT17

GIS

REVIEW

DESIGN SCALE:

F:\PROJECTS\2010 PROJ\103-89556 GE Shady Hills Revision\B - Ecology\Figures\103-89556B008 GT LOCATIONS.mxd

CHECK

0

PROJECT No. 103-89556 FILE No. 103-89556B008

JG

JG AS SHOWN

HA

REFERENCES

1. APPROXIMATE PROJECT BOUNDARY: GOLDER ASSOCIATES INC., 2011

2. GOPHER TORTOISE BURROW LOCATIONS: GOLDER ASSOCIATES INC.,

08/2011

3. 2010 AERIAL: SOUTHWEST FLORIDA WATER MANAGEMENT DISTRICT

AND WOLLPERT, INC., 2010

200 0 200

Feet

FIGURE 8

PROJECT

TITLE

SHADY HILLS

GOPHER TORTOISE BURROW LOCATIONS

REV.

08/18/2011

08/16/2011

08/18/2011

REV. DATE DES REVISION DESCRIPTION GIS CHK RVW

LEGEND

APPROXIMATE PROJECT BOUNDARY

ACTIVE GOPHER TORTOISE BURROW

INACTIVE GOPHER TORTOISE BURROW

ABANDONED GOPHER TORTOISE BURROW
ATTACHMENT 1 

FEDERALLY LISTED PLANT AND WILDLIFE SPECIES 

FOR PASCO COUNTY, FLORIDA 
Federally Listed Species in Pasco County, Florida | North Florida ESO Jacksonville

http://www.fws.gov/northflorida/CountyList/Pasco.htm[5/12/2011 3:53:18 PM]

Southeast Region

North Florida Ecological Services Office

Federally Listed Species in Pasco County, Florida

This information is provided as a guide to project planning, and is not a substitute for site-specific surveys.

Such surveys may be needed to assess species' presence or absence, as well as the extent of project effects

on listed species and/or designated critical habitat.

The following table lists those federally-listed species known to be present in the county.

Code Key: E = Endangered, T = Threatened, CH = Critical Habitat Designated

Category Species Common Name Species Scientific Name Code

Mammals West Indian (Florida) Manatee Trichechus manatus latirostris E/CH

Birds

Piping Plover Charadrius melodus T

Florida Scrub-jay Aphelocoma coeruluscens T

Wood Stork Mycteria americana E

Red-cockaded Woodpecker Picoides borealis E

Fish Gulf Sturgeon Acipenser oxyrhynchus desotoi T

Reptiles

Eastern Indigo Snake Dymarchon corais couperi T

Green Sea Turtle Chelonia mydas E

Kemp's Ridley Sea Turtle Lepidochelys kempii E

Leatherback Sea Turtle Dermochelys coriacea E

Loggerhead Sea Turtle Caretta caretta T

Amphibians None

Mollusks None

Crustaceans None

Plants None

Home Species: North Florida County Species: South Florida County Species: Panhandle County

For a list of State species by county use the Florida Natural Areas Inventory's Tracking Lists at

http://www.fnai.org/trackinglist.cfm

For State listed species details, please go to http://myfwc.com/imperiledspecies//

NOTE: Bald eagles were removed from the endangered species list in June 2007 because their populations recovered

sufficiently. However, the protections under the Bald and Golden Eagle Act (Eagle Act) continue to apply. Please see the

eagle information on our Landowner Tools page or our national website at http://www.fws.gov/migratorybirds/baldeagle.htm

for information regarding new permit requirements under the Eagle Act.

Welcome

Our Strategic Plan

Area of Responsibility

Our Office Location

Contact Us

Current News Releases

News Archives

Landowner Tools

Programs and Resources

Partners for Fish and Wildlife

Coastal Program

Habitat Conservation Plans

Federally-listed Species in

Florida

Students & Teachers

Related Sites of Interest

Key North Florida

Species

Bald Eagle

Florida Manatee

Eastern Indigo Snake

Florida Scrub-Jay

Sea Turtles

Whooping Crane

Wood Stork

General Information

Hunting-Fishing Licenses &

Permits

Injured/Nuisance Wildlife

Wildlife Law Violations

Other USFWS

Resources

Service Office Finder

Office Directory

Southeast Region Contacts

Federal Register Notices

Regional Five-Year Reviews
Federally Listed Species in Pasco County, Florida | North Florida ESO Jacksonville

http://www.fws.gov/northflorida/CountyList/Pasco.htm[5/12/2011 3:53:18 PM]

Send comments on our web site or general questions to North Florida office. 

If you need special assistance please contact the Public Affairs Officer.

Last updated: November 12, 2010

Home | Southeast Region | South Florida ES Office | Panama City ES Office | U.S. Fish and Wildlife Service Home Page | Department

of Interior

USA.gov | About the U.S. Fish and Wildlife Service | Information Quality | Accessibility | Privacy | Notices | Disclaimer | FOIA
ATTACHMENT 2 

FLORIDA NATURAL AREAS INVENTORY 

BIODIVERSITY MATRIX REPORT AND ASSOCIATED TABLES 
 

NOTE: The Biodiversity Matrix includes only rare species and natural communities tracked by FNAI. 

Report for 1 Matrix Unit: 23978 

Matrix Unit ID: 23978

0 Documented Elements Found 

0 Documented-Historic Elements Found 

9 Likely Elements Found 

Descriptions

DOCUMENTED - There is a documented occurrence 

in the FNAI database of the species or community 

within this Matrix Unit.

DOCUMENTED-HISTORIC - There is a documented 

occurrence in the FNAI database of the species or 

community within this Matrix Unit; however the 

occurrence has not been observed/reported within 

the last twenty years. 

LIKELY - The species or community is known to 

occur in this vicinity, and is considered likely within 

this Matrix Unit because: 

 1. documented occurrence overlaps this and 

adjacent Matrix Units, but the documentation 

isn’t precise enough to indicate which of those 

Units the species or community is actually 

located in; or

2. there is a documented occurrence in the 

vicinity and there is suitable habitat for that 

species or community within this Matrix Unit. 

POTENTIAL - This Matrix Unit lies within the known 

or predicted range of the species or community 

based on expert knowledge and environmental 

variables such as climate, soils, topography, and 

landcover.

Scientific and Common Names Global 

Rank

State 

Rank

Federal 

Status

State 

Listing

Ardea alba 

Great Egret G5 S4 N N 

Egretta caerulea G5 S4 N SSC 

1018 Thomasville Road

Suite 200-C 

Tallahassee, FL 32303 

850-224-8207 

850-681-9364 fax 

www.fnai.org

Florida Natural Areas Inventory

Biodiversity Matrix Query Results

UNOFFICIAL REPORT

Created 9/9/2011

(Contact the FNAI Data Services Coordinator at 850.224.8207

 for information on an official Standard Data Report) 

FNAI Biodiversity Matrix Page 1 of 3

http://data.labins.org/mapping/FNAI_BioMatrix/GridSearch.cfm?sel_id=23978&extent=54... 9/9/2011
Matrix Unit ID: 23978 

30 Potential Elements for Matrix Unit 23978 

Little Blue Heron 

Egretta thula 

Snowy Egret G5 S3 N SSC 

Eudocimus albus 

White Ibis G5 S4 N SSC 

Falco sparverius paulus 

Southeastern American Kestrel G5T4 S3 N ST 

Grus canadensis pratensis 

Florida Sandhill Crane G5T2T3 S2S3 N ST 

Mesic flatwoods G4 S4 N N 

Mycteria americana 

Wood Stork G4 S2 LE FE 

Sandhill G3 S2 N N 

Scientific and Common Names Global 

Rank

State 

Rank

Federal 

Status

State 

Listing

Aimophila aestivalis 

Bachman's Sparrow G3 S3 N N 

Athene cunicularia floridana 

Florida Burrowing Owl G4T3 S3 N SSC 

Calopogon multiflorus 

Many-flowered Grass-pink G2G3 S2S3 N LE 

Centrosema arenicola 

Sand Butterfly Pea G2Q S2 N LE 

Coelorachis tuberculosa 

Piedmont Jointgrass G3 S3 N LT 

Digitaria floridana 

Florida Crabgrass G1 S1 N N 

Drymarchon couperi 

Eastern Indigo Snake G3 S3 LT FT 

Gopherus polyphemus 

Gopher Tortoise G3 S3 N ST 

Gymnopogon chapmanianus 

Chapman's Skeletongrass G3 S3 N N 

Heterodon simus 

Southern Hognose Snake G2 S2 N N 

Lechea cernua 

Nodding Pinweed G3 S3 N LT 

Litsea aestivalis 

Pondspice G3 S2 N LE 

Matelea floridana 

Florida Spiny-pod G2 S2 N LE 

Monotropsis reynoldsiae 

Pygmy Pipes G1Q S1 N LE 

Mustela frenata peninsulae 

Florida Long-tailed Weasel G5T3 S3 N N 

Nemastylis floridana 

Celestial Lily G2 S2 N LE 

Neofiber alleni 

Round-tailed Muskrat G3 S3 N N 

Nolina atopocarpa 

Florida Beargrass G3 S3 N LT 

Notophthalmus perstriatus 

Striped Newt G2G3 S2S3 N N 

Panicum abscissum 

Cutthroat Grass G3 S3 N LE 

FNAI Biodiversity Matrix Page 2 of 3

http://data.labins.org/mapping/FNAI_BioMatrix/GridSearch.cfm?sel_id=23978&extent=54... 9/9/2011
Pituophis melanoleucus mugitus 

Florida Pine Snake G4T3 S3 N SSC 

Platanthera integra 

Yellow Fringeless Orchid G3G4 S3 N LE 

Podomys floridanus 

Florida Mouse G3 S3 N SSC 

Pteroglossaspis ecristata 

Giant Orchid G2G3 S2 N LT 

Rana capito 

Gopher Frog G3 S3 N SSC 

Salix floridana 

Florida Willow G2 S2 N LE 

Sciurus niger shermani 

Sherman's Fox Squirrel G5T3 S3 N SSC 

Triphora craigheadii 

Craighead's Nodding-caps G1 S1 N LE 

Ursus americanus floridanus 

Florida Black Bear G5T2 S2 N ST* 

Warea carteri 

Carter's Warea G3 S3 LE LE 

Disclaimer

The data maintained by the Florida Natural Areas Inventory represent the single most comprehensive source of 

information available on the locations of rare species and other significant ecological resources statewide. However, the 

data are not always based on comprehensive or site-specific field surveys. Therefore, this information should not be 

regarded as a final statement on the biological resources of the site being considered, nor should it be substituted for 

on-site surveys. FNAI shall not be held liable for the accuracy and completeness of these data, or opinions or 

conclusions drawn from these data. FNAI is not inviting reliance on these data. Inventory data are designed for the 

purposes of conservation planning and scientific research and are not intended for use as the primary criteria for 

regulatory decisions. 

Unofficial Report

These results are considered unofficial. FNAI offers a Standard Data Request option for those needing certifiable data. 

FNAI Biodiversity Matrix Page 3 of 3

http://data.labins.org/mapping/FNAI_BioMatrix/GridSearch.cfm?sel_id=23978&extent=54... 9/9/2011
APPENDIX D

USFWS AND NMMS CORRESPONDENCE 
1

Larocca, David

From: Ahrens, Heather

Sent: Wednesday, April 04, 2012 2:38 PM

To: Heath_Rauschenberger@fws.gov

Cc: Osbourn, Scott; Larocca, David

Subject: Shady Hills Generating Station ESA Consultation

Dr. Rauschenberger, 

 

Thank you for taking time out of your busy schedule to discuss the referenced project with me on March 29 as well as 

during our original conversation on October 7, 2011. As we discussed:

1. The proposed project is located within an existing industrial site in Pasco County, Florida.

2. Due to the presence of gopher tortoise burrows within the proposed project site(18 burrows total, of which 14 

are potentially occupied), there is a potential for the eastern indigo snake to be present. Standard protection 

measures for the eastern indigo snake will be enforced during construction of the proposed project to ensure 

eastern indigo snakes are not harmed. 

3. The proposed project does not include discharge of heated water. 

4. No wetlands were identified within the proposed project site. In addition, no dredge or fill activities are 

proposed within wetlands or other surface waters.

My understanding from our conversations is that the USFWS would like to review the ecological due diligence report 

before making a determination on whether the project will affect listed species. It is also my understanding that we may 

submit the ecological due diligence report directly to USFWS for review, or we can wait until the USEPA forwards the 

information to the USFWS as part of the Section 7 Consultation process.

Please do not hesitate to contact me if you have any questions or concerns regarding this matter.

Regards,

Heather Todd Ahrens | Senior Ecologist | Golder Associates Inc. 

5100 West Lemon Street, Suite 208, Tampa, Florida, USA 33609 

T: +1 (813) 287-1717 | D: +1 (813) 769-5307 | F: +1 (813) 287-1716 | C: +1 (813) 407-8846 | E: 

Heather_Ahrens@golder.com | www.golder.com 

This email transmission is confidential and may contain proprietary information for the exclusive use of the intended recipient. Any use, distribution or copying of 

this transmission, other than by the intended recipient, is strictly prohibited. If you are not the intended recipient, please notify the sender and delete all copies. 

Electronic media is susceptible to unauthorized modification, deterioration, and incompatibility. Accordingly, the electronic media version of any work product may 

not be relied upon. 

Please consider the environment before printing this email. 
1

Larocca, David

From: Ahrens, Heather

Sent: Thursday, March 29, 2012 10:42 AM

To: Kyle.Baker@noaa.gov

Cc: Osbourn, Scott; Larocca, David

Subject: Shady Hills Generating Station ESA Consultation

Kyle, 

Thank you for taking time out of your busy schedule to discuss the referenced project with me today as well as during 

our original conversation on October 7, 2011. My understanding from our conversations is that the NMFS would make a 

no effect determination because the site is located inland in Pasco County, Florida, and therefore, species regulated by 

NMFS for this area (i.e., gulf sturgeon and sea turtles) would not be present on site. It is also my understanding that the 

NMFS does not send no effect determination correspondence. 

Please do not hesitate to contact me if you have any questions or concerns regarding this matter. 

Regards, 

Heather Todd Ahrens | Senior Ecologist | Golder Associates Inc. 

5100 West Lemon Street, Suite 208, Tampa, Florida, USA 33609 

T: +1 (813) 287-1717 | D: +1 (813) 769-5307 | F: +1 (813) 287-1716 | C: +1 (813) 407-8846 | E: 

Heather_Ahrens@golder.com | www.golder.com 

This email transmission is confidential and may contain proprietary information for the exclusive use of the intended recipient. Any use, distribution or copying of 

this transmission, other than by the intended recipient, is strictly prohibited. If you are not the intended recipient, please notify the sender and delete all copies. 

Electronic media is susceptible to unauthorized modification, deterioration, and incompatibility. Accordingly, the electronic media version of any work product may 

not be relied upon. 

Please consider the environment before printing this email. 
 APPENDIX E

CULTURAL RESOURCE ANALYSIS 

 

 
H:\PROJECTS\2010proj\10389556 GE Shady Hills Revision\Reference Material\Cultural Resources\Shady Hills - Cultural Resource Desktop Analysis Letter Report to 

Agency_V2.docx

Golder Associates Inc.

5100 W. Lemon Street, Suite 208

Tampa, FL 33609 USA

Tel: (813) 287-1717 Fax: (813) 287-1716 www.golder.com

Golder Associates: Operations in Africa, Asia, Australasia, Europe, North America and South America

Golder, Golder Associates and the GA globe design are trademarks of Golder Associates Corporation

August 17, 2012 103-89556

Ms. Laura Kammerer

Deputy State Historic Preservation Officer for Review and Compliance 

Florida Division of Historical Resources

R.A. Gray Building

500 South Bronough Street

Tallahassee, FL 32399-0250

RE: CULTURAL RESOURCES DESKTOP ANALYSIS FOR SHADY HILLS EPA PSD PERMIT

Dear Ms. Kammerer:

On behalf of EFS Shady Hills, LLC (Shady Hills) Golder Associates Inc (Golder) is submitting to the 

Florida Division of Historical Resources (FDHR) the following cultural resources desktop analysis. Golder 

respectively requests FDHR’s concurrence that no additional cultural resources investigation is required 

to demonstrate compliance with Section 106 of the National Historic Preservation Act (NHPA).

INTRODUCTION

A subsidiary of Shady Hills, the Shady Hills Power Company, LLC, owns and operates the Shady Hills 

Generating Station located at 14240 Merchant Energy Way, Shady Hills, Pasco County, Florida. Shady 

Hills is proposing to expand the Shady Hills Generating Station with the addition of two nominal 218-

megawatt (MW) simple cycle combustion turbine-electric generators and associated ancillary equipment

(Project.) The proposed expansion is a major modification to the existing facility and subject to Prevention 

of Significant Deterioration (PSD) for specific air emissions. The Florida Department of Environmental 

Protection has issued a final air construction permit (Air Permit No. 1010373-012-AC PSD-FL-402A) for 

the project for all applicable air pollutants except greenhouse gas (GHG).

EPA Region IV is the permitting authority for the GHG-portion of the expansion project under a Federal 

Implementation Plan (FIP) that became effective on December 30, 2010. Federal law requires that a federal 

agency’s actions be in compliance with Section 106 of the NHPA. On behalf of Shady Hills, Golder 

conducted a desktop analysis to demonstrate compliance with Section 106, NHPA. This analysis includes

identification and review of any previously recorded cultural resources within and adjacent to the project site.

PROJECT LOCATION 

The Shady Hills Generating Station and Project are located in unincorporated Pasco County, Florida

within Section 25, Township 24S, and Range 17E (Figures 1 and 2). The Shady Hills property is 

approximately 30 acres. The Project will be located adjacent to the east side of the existing generators,

and the associated switchyard will be located adjacent to the east side of the existing switchyard. The 

area where the additional generators and switchyard will be located was previously used as a 

construction laydown area during the construction of the existing Shady Hills Generating Station facilities.

PREVIOUSLY CONDUCTED SURVEYS AND PREVIOUSLY RECORDED 

CULTURAL RESOURCES WITHIN THE PROJECT SITE AND PROJECT AREA

Golder requested from the Florida Department of State Division of Historical Resources a search of the 

Florida Master Site File (FMSF) to identify known cultural resources locations within the Project location 

and surrounding area. This information is based on the most current FMSF data. Golder acknowledges 
Ms. Laura Kammerer August 15, 2012

Florida Division of Historical Resources 2 103-89556

Shady Hills - Cultural Resource Desktop Analysis Letter Report to Agency_V2.docx

that the FMSF is not a comprehensive inventory of cultural resources and their significance, and therefore 

may not reflect existing conditions.

According to the FMSF, there were no previously recorded archaeological sites or historic structures 

within the Project Site. There were two resources identified within 0.3 mile north and southeast of the 

Project Site: Site PA00324 (MATHIS) and Site PA00321 (Bell Pond West). Both sites are single artifact or 

isolated finds that are prehistoric but lack pottery. Sites PA00324 and PA00321 are ineligible for listing on 

the National Register of Historic Places.

Based on the characteristics of the proposed Project and previous disturbance by the existing power 

plant, Golder anticipates the Project will have no impacts on cultural resources, and therefore 

recommends that the FDHR confirms in writing that no further investigation of cultural resources is 

required for the proposed Project. 

If you have any questions, please feel free to contact the undersigned at (813) 287-1717.

Sincerely,

GOLDER ASSOCIATES INC.

Kelly L. Hartman Scott Osbourn

Environmental and Land Use Planner Senior Consultant and Associate 

David Larocca

Senior Engineer 

Attachments: Figure 1, Site Location—Topographic 

Figure 2, Site Location—Aerial 

cc: Roy Belden – GE Energy Financial Services, EFS Shady Hills, LLC

KLH/SO/DL/lcr
FIGURES
GIS

REVIEW

DESIGN SCALE:

F:\PROJECTS\2010\103-89556 GE Shady Hills Revision\C - Cultural Resource Proposal\Figures\103-89556C002 AERIAL.mxd

CHECK

0

PROJECT No. 103-89556 FILE No. 103-89556C002

JDG

JDG AS SHOWN

KLH

REFERENCES 1. APPROXIMATE PROJECT LOCATION: GOLDER ASSOCIATES INC., 2011

2. AERIAL: ARC GIS ONLINE - BING MAPS AERIAL; MICROSOFT CORPORATION AND ITS DATA

SUPPLIERS, 2010

300 0 300

Feet

FIGURE 2

PROJECT

TITLE

SHADY HILLS GENERATING STATION

SITE LOCATION - AERIAL

REV.

04/13/2012

04/10/2012

04/13/2012

REV. DATE DES REVISION DESCRIPTION GIS CHK RVW

LEGEND

APPROXIMATE SITE BOUNDARY

APPROXIMATE EXPANSION

PROJECT AREA

DL 04/13/2012
589

GIS

REVIEW

DESIGN SCALE:

F:\PROJECTS\2010\103-89556 GE Shady Hills Revision\C - Cultural Resource Proposal\Figures\103-89556C001 SITE LOCATION.mxd

CHECK

0

PROJECT No. 103-89556 FILE No. 103-89556C001

JDG

JDG AS SHOWN

KLH

REFERENCES 1. APPROXIMATE PROJECT BOUNDARY: GOLDER ASSOCIATES INC., 2011

2. ROADS: FLORIDA DEPARTMENT OF TRANSPORTATION, 2011

3. COUNTY BOUNDARIES: FLORIDA GEOGRAPHIC DATA LIBRARY, 2008

4. USGS TOPOGRAPHIC MAP: NATIONAL GEOGRAPHIC SOCIETY, 2010

2,000 0 2,000

Feet

FIGURE 1

PROJECT

TITLE

SHADY HILLS GENERATING STATION

SITE LOCATION - TOPOGRAPHIC

REV.

04/13/2012

04/10/2012

04/13/2012

REV. DATE DES REVISION DESCRIPTION GIS CHK RVW

LEGEND

PASCO

COUNTY

589

55

45

52

19

41

HERNANDO

COUNTY

PASCO

COUNTY

REGIONAL MAP APPROXIMATE SITE

BOUNDARY

APPROXIMATE EXPANSION

PROJECT AREA

TOLL ROAD

US ROAD

STATE ROAD

COUNTY ROAD

COUNTY BOUNDARY

DL 04/13/2012
Golder, Golder Associates and the GA globe design are trademarks of Golder Associates Corporation

Golder Associates Inc.

5100 W. Lemon Street, Suite 208

Tampa, FL 33609 USA 

Tel: (813) 287-1717

Fax: (813) 287-1716