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 CO MPANY, LLC; FACILITY ID NO: 1010373
AIR PERMIT NO. 1 010373

- 007

- AC / PSD

- FL

- 402

Dear Mr. Worley :

Shady Hills Power Company, LLC , a subsidiary of GE Energy Financial Services, o wns 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 combus tion 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 simpl e 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
he ater, 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 Pro t ection ( F DEP) in May 2008. The Project was issued a PSD permit from the FDEP (Permit No. 1010373

- 012

- A C,
PSD

- FL

- 402A) on April 6, 2012.

The project will result in an increase and a net increase greater than 75,000 TPY CO 2 e and an increase
and a net increase in GHG emissions on a mass basis greater than zero TPY. In addition to the CTs,
CO 2 e 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 c omparison 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

- port ion 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 w o r ld of



## c a p a bilities
delivered 

## local l y 

# NEW SOURCE REVIEW FO R
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

- 89556REPORTSeptember 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 CONT ROL 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 Fu els

................................ ................................ ................................ ........................ 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

– SF 6

................................ ................................ ................................ ............. 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

................................ ................................ .................. 32September 2012 ii 103

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### 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 Cyc le 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 Appen dix 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 AnalysisSeptember 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) e ach, 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 Me rchant 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 ga llon 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 off

take agreements while maximizing site output and minimizing costs within the existin g 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 powe r 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 “gener ally 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 intermediat e 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

pursui ng 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 agre ements 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. Th erefore the evaluationSeptember 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 th e

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 upd ate 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 t he 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 info rmation 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 attache d 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

li kely 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 reviewsSeptember 2012 3 103

- 89556

and examination of available agency data, neith er 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 ensur e 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, 201 2, 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 goph er 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 durin g 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 Octob er 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 indir ectly 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 Departme nt 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) andSeptember 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 cha racteristics 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, requestin g 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 Ju ne 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 (CO 2 )

 Nitrous oxide (N 2 O )

 Methane (CH 4 )

 Hydrofluorocarbons (HFCs)

 Perfluorocarbons (PFCs)

 Sulfur hexafluoride (SF 6 )

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 (NO
x )

, particulate matter (PM, PM 10 ), 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 NO
x , PM, PM 10 , and CO. As shown in Table 1, the expansion Project will result in an increase

and a net increase greater than 75,000 TPY CO 2 e and an increase and a net increase in GHG emissions

on a mass basis greater than zero TPY. In addition to the CTs, CO 2 e 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 thu s the maximum potential

emissions are utilized for comparison with PSD review thresholds. No offsetting emissions are availableSeptember 2012 5 103

- 89556

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

provided and the Projec t 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 pe rmitting 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 ef fect 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 prepare d 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 CONT ROL TECHNOLOGY (BACT ) ANALYSIS

This section presents t he 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 regulatio ns 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 a nd 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 contr ol

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 per mit 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 effect ive 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 a ll 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 cann ot 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 tec hnology 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 reg ulated NSR

pollutants (e.g., NO X , SO 2 , PM/PM 10 /PM 2.5 , 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 ana lysis 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: CO 2 , N 2 O, CH 4 , HFCs, PFCs, and SF 6 . Natural gas and distillate fuel oil combustion

resul t in GHG emissions of CO 2 , N 2 O, and CH 4 only. CO 2 , N 2 O, and CH 4 are the principal GHGs that

will be emitted at the Shady Hills Generating Station. CO 2 emissions will result from the oxidation of

carbon in the fuel. CH 4 emissions will result from incomplete combustion and N 2 O 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 GHG s (SF 6 and CH 4 ). 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, re sulting 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

d esigned 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 boile r 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 Revie w 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 “availab le” 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 authorit ies 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 stora ge (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 c onsidered 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 CO 2 than oil, and just under 45 percent less CO 2 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 E nergy Efficiency

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

CO 2 – energy efficiency and carbon capture and storage (CCS). 3 The first of these, energy efficiency,

falls under the general category of lo wer

- 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 collat eral 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. Thi s provides the benefits of lower fuel costs and reduced air pollutant

emissions (including CO 2 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 Ti tle V Permitting

Guidance for Greenhouse Gases,” March 2011, EPA classifies CCS as an add

- on pollution control

technology that is “available” for large CO 2 - emitting facilities including fossil fuel

- fired power plants and

industrial facilities with high

- purity CO 2 streams. As a result, EPA requires that CCS be considered in

Step 1 of the BACT analysis.

CCS is composed of three main components: CO 2 capture and/or compression, transport, and long

- term,

perpetual storage.

Carbon Capture

- Before CO 2 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 CO 2 diluted with nitrogen. According to the US Department of Energy, flue gas fro m the combustion of fossil

fuels contains approximately 5

– 15 percent CO2. 4 For effective carbon sequestration, the CO 2 in these

exhaust gases must be separated and concentrated.

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

for capturing CO 2 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

- b ased 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 CO 2 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 CO 2 separation and capture include the following:

• Absorption (ch emical and physical)

• Adsorption (physical and chemical)

• Low

- temperature distillationSeptember 2012 10 103

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• Gas separation membranes

• Mineralization and bio

- mineralization. “ 5

Carbon Transport

– After the CO 2 is captured, it must be transported to a carbon sequestration site

. Pipelines are the most common method for transporting large quantities of CO 2 over long distances.

Shipping CO 2 via pipeline involves compressing gaseous CO 2 to a pressure above 1,160 pounds per

square inch (psi), to increase CO 2 density and make it eas ier and less expensive to ship. A CO 2 pipeline

would be similar to a high pressure natural gas pipeline and is available. CO 2 also can be transported as

a liquid in seagoing vessels or via tankers on roads or railways. In these instances, the CO 2 is hel d in

insulated tanks at low temperatures and relatively low pressures.

Carbon Storage

– In a CCS system, CO 2 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 CO 2 is injected into the deep

geologic formations through drilled wells. Under high pressure, CO 2 turns to liquid and can move through

a formation as a fluid. Once injected, the liquid CO 2 tends to be buoyant and will flow upward until it

encounters a barrier of non

- porous rock, which can trap the CO 2 and prevent further upward migration.

When CO 2 i s 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 CO 2 trapping as well: CO 2 molecules can dissolve in b rine, 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 CO 2 . There is ongoing research f ocused 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 o cean.



### 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 feasi ble 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 un der 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 source

specific and unit

- specific factors (considering physical, chemical, a nd engineering principles).September 2012 11 103

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### 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 CT s 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 wil l

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 o rder 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 w hen 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 P roject 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 late st 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 w as 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, Feb ruary 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 requiremen ts 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 o n 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

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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 NO
x 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

approx imately 35,000 ga llons per day (GPD) of water when operating on natural gas primary fuel, and

approx imately 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 approx imately 330,000

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

back

- up fuel operation s ). Reclaimed wate r 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 exi sting

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, EF S 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 (S WFWMD) 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 o n 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 feas ible 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 w etlands and other surface water bodies. (See generally section 4.0, Basis of

Review for Water Use Permits)

.September 2012 13 103

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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 level s 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 establi sh 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 managemen t 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 tha t 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, t he 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 wou ld 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 St orage (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 BACTSeptember 2012 14 103

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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 ca n 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 add

on controls that are typica lly 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, 2011 6 , 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 turbin es.

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 charge d 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 1 3, 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 promo te

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 strateg ic 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 ca rbon

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

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“ The Sunniland Trend (Trend) in south Florida is an arcuate trend about 235 kilometers long b y 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 (CO 2 ) sequestrati on 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 r ange 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 CO 2 , which could potentially support

CO 2 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 CO 2 storage capacities that are

potentially available in depleted oil and gas basins if all porous units, inclu ding 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 adjace nt to the northeast corner of the study area,

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

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

Tampa Electric Co mpany

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

for the removal of sulfur and the capture of CO 2 from the Tampa Electric Polk Power Station’s 250

- megawatt integrated gasification combined cycle (IGCC) unit. The latest publica lly available information

indicates that the project is designed to capture CO 2 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 p lant’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

Sh ady 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 CO 2 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 co ntracts 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 geologi c formations for the

long

- term CO 2 storage. Even if the type of equipment needed to accomplish the compression, capture,

and storage of CO 2 are determined to be generally available from commercial vendors, the CCS

technology has not been demonstrated on s imple

- 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 und er 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 t echnologies, CCS, clean fuels, and energy efficiency are technically feasible

technologies. Of these technically feasible technologies, CCS followed by the selection of natural gas asSeptember 2012 18 103

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the primary fuel offers the highest pollutant control effectiveness, fol lowed 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

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### 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

elim inated 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 emission s 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. S ite 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 CO 2 transport;

The Harvard Kennedy School has prepare d 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 CO 2 s eparated

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

turbines. Based on a cost of $ 70 per short ton of CO 2 , and an estimated annual CO 2 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 CO 2 is estimated to be greater than 2 3 % of the total capital cost of the

Project. Given the costs to remove the CO 2 , the overall costs of CCS (which would include tra nsportation,

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

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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 b e 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 GHGs 9 states that clean fuels which would reduce GHG emissions should be

considered while recognizing at the same time that the BACT analysis doe s 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 f iring, 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 Proj ect 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 maxim um of 750 hrs/yr if

one CT is constructed and an aggregate of 1,000 hours if both CTs are constructed. The cost

effectiveness analysis assumes maximum annual permitted operating hours, and calculates the

incremental cost, including both capital and operati ng costs associated with achieving incremental CO 2 emission reduction from the LM6000 and LMS100 technologies in terms of $/ton of CO 2 avoided. As

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

same gene ration 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 Greenhous e Gases,” U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, EPA

- 457/B

- 11

- 001, March 2011.September 2012 21 103

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ton CO 2e 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 ox idation 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 NO
x (ppmvd @15% O 2 ) CO (ppmvd @ 15% O 2 )

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% O 2 and CO emissions guaranteed at levels equal to 25 ppmvd

@15% O 2 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 NH 4 in the form of catalyst slip. Assuming typical vendo r guarantees of 9 ppm NH 4 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 NH 4 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 NH 4 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 a ssociated with operation

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

emissions to CO 2 , resulting in a negligible environmental benefit. Although aeroderivative CTs of this

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

while resulting in no significant benefit in CO 2 e reduction, the LM6000 was evaluated as a representative

smaller aeroderivative CT. In fact, Attachment H, Table 5

- 3, of Puge t Sound Energy’s PSD PermitSeptember 2012 22 103

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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 meas urement 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 e lectrical 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 fo ssil

- 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 prop osed 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 CO 2 are about 119 lb CO 2 /MMBtu for

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

Mount Ver non, 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

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natural gas and 163 lb CO 2 /MMBtu for distillate oil. Table 3 provides CO 2 e 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 equival ent (CO 2 e) 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 CO 2 e emissions BACT Limits for “normal operation”

and for “startup/shutdown events” for each fuel. The proposed CO 2 e 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 CO 2 e 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 CO 2 e per MWh ( HHV, Gross Output, ISO Condition s) 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 1,9 28 lb CO 2 e 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

1 st 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 s upply 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 per formance 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 3.0September 2012 24 103

- 89556

percent turbine performance degradation margin between major overhauls and ov er 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 CO 2 e 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 CO 2 e 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 CO 2 e 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 f low 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 th e

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 tha t load.

Compliance with the CO 2 e 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 CO 2 e emissions based on 40 CFR Part 75 methodologies (CO 2 emissions) and 40 CFR Part 98

,methodologies (CH 4 and N 2 O 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 C FR Part 75 Appendix D. CO 2 e 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 CO 2

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

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• Natur al gas

- firing CO 2 lb/MMBtu = 1,040 scf/MMBtu x (1/385) scf CO 2 /lb

- mole x 44

lb/lb

- mole = 118.9 lb/MMBtu

o CO 2 lb/ 12

- Month Rolling Period = Heat Input MMBtu/ 12

- Month Rolling

Period x 118.9 lb CO 2 /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 CH 4 and N 2 O lb/ 12

- Month Rolling Period is derived as follows:

o Natural gas

- firing CH 4 lb/ 12

- Month Rolling Period = Heat Input MMBtu/ 12

- Month Rolling Period x 2.2E

- 3 lb/MMBtu Natural gas

- f iring N 2 O lb/ 12

- Month Rolling Period = Heat Input MMBtu/ 12

- Month Rolling Period x 2.2E

4 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 HH V and corrected to ISO

conditions.

• CO 2 e lb/ 12

- Month Rolling Period = CO 2 lb/ 12Month Rolling Period + (21 x CH 4

lb/ 12

- Month Rolling ) + (310 x N 2 O lb/ 12

- Month Rolling )

• CO 2 e lb/MWh = (CO 2 e lb/ 12

- Month Rolling ) / (MW/ 12

- Month Rolling ) (gross)

 Where MWh is gros s 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 CO 2 lb/MMBtu = 1,420 scf/MMBtu x (1/385) scf CO 2 /lb

- mole x 44 lb/lb

mole = 162.3 lb/MMBtu

o CO 2 lb/ 12

- Month Rolling Period = Heat Input MMBtu/ 12

- Month Rolling

Period x 162.3 lb CO2/MMBtuSeptember 2012 26 103

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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 CH 4 and N 2 O lb/ 12

- Month

Rolling Period is derived as follows:

• CH 4 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

• N 2 O 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.

CO 2 e lb/ 12

- Month Rolling Period = CO 2 lb/ 12

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

- Month Rolling Period) + (310 x N 2 O lb/ 12

- Month Rolling Period) (40 CFR 98 and 52.21)

o CO 2 e lb/MWh = (CO 2 e 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 da ta 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 CO 2 e 12

- month average is calculated each calendar

month based on the summat ion 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 shut down

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 tha t 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

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### 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 biodie sel, 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 sta rtup (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 201 2) 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 appreciab ly 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 component s 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, m oisture 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 biod iesel 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 Biodie sel 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 d ata 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 fe edstock 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 prefere nces 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 CO 2 is the only technically feasible and cost effective BACT measure

for the diesel engines.



### 2.2.1 **BACT Emission Ra te** 

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

CO 2e 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), CO 2 e emissions from diesel firing of the emergency generator are

estimated to be 398 short TPY based on 500 ho urs 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 Gav in 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 /

220 4 x 2000 (40 CFR Part 98 Table C

- 1)

• CH 4 Short TPY = (3.0E

- 3) x 2.204 x Heat Input MMBtu/hr / 2204 x 2000

• N 2 O Short TPY = (6.0E

- 4) x 2.204 x Heat Input MMBtu/hr / 2204 x 2000

• CO 2 e Short TPY = CO 2 TPY + (21 x CH4 TPY) + (310 x N 2 O 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 wil l 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, processi ng, 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 hea t 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 t hat 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) main tains 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 specifi ed, new

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

Natural

- Gas

- Line

- Heater

. 15 Based on 40 CFR Part 98 methodologies, CO 2 e 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

• CO 2 Short TPY = 53.02 kg CO 2 /MMBtu x Annual Heat Inpu t (MMBtu) x 2.204 /

2204 x 2000 (40 CFR Part 98 Table C

- 1)

• CH 4 Short TPY = (1.0E

- 3) x 2.204 x Heat Input MMBtu/hr / 2204 x 2000

• N 2 O Short TPY = (1.0E

- 4) x 2.204 x Heat Input MMBtu/hr / 2204 x 2000

• CO 2 e Short TPY = CO 2 TPY + (21 x CH 4 TPY) + (310 x N 2 O 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 fi nal 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

- OAR

2009

- 0923, accessed at ht tp://www.epa.gov/climatechange/emissions/downloads10/Subpart

W_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 add resses
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 p etroleum products are assumed to contain no CH 4 or CO 2

. Therefore, it is also assumed

that there are no CH 4 or CO 2 emissions from the working and breathing losses of tanks containing

“weathered” crud e 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.go v/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

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### 2.5 Electrical Breaker

– SF 6
The Project includes one new electrical breaker that is expected to contain SF 6 . Industrial circuit

breakers typically contain sulfur hexafluoride (SF 6 ) for the purpose of electrical insulation and interruption

of electrical current. SF 6 has been, and continues to b e, broadly used in the U.S. due to its dielectric

strength and arc

- quenching characteristics. Flammable insulating oils have been largely replaced with

SF 6 . SF 6 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 SF 6 . 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 SF 6 for use in

circu it breakers because SF 6 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 Partners hip’s primary objective is to reduce SF6 emissions via cost

effective 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,

u tilities often find economical solutions to reduce SF6 emissions

.

Modern SF 6 circuit breakers are designed as totally enclosed pressure systems with minimal potential for

fugitive SF 6 emissions. The Proposed SF 6 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 circu it 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 SF 6 Partnership has recogni zed that there is no clear alternative to using SF 6 in combination with

fugitive SF 6 emissions detection, repair, and replacement strategies. 16 Thus, the only technically feasible

option is use of sealed SF 6 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 SF 6 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. SF 6 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 bee n 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 an d 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 i f 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 “SF 6 Emission Reduction Partnership for Electric Power Systems,” 2010 Annual Report, U.S. Environmental Protection Agency, December 2011 (http://www.epa.gov/electr icpower

- sf6/resources/index.html).September 2012 33 103

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and repair is considered BAC T. 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 c an be detected by

personnel.

### TABLESN2O Emissions (a) CH4Emissions (a) CO2e Emissions (b)EmissionEmissionEmissionHeat Input Operation Annual Heat Input Factor Annual Emissions Factor Annual Emissions Factor Annual EmissionsEmission RateUnit (MMBtu/hr) (Hr/yr) (MMBtu/yr) (lb/MMBtu) (Short tons/yr) (lb/MMBtu) (Short tons/yr) (lb/MMBtu) (Short tons/yr) (Short tons/yr)Emergency Generator9.735004,864 163.0 396 1.32E-03 3.22E-03 6.6E-03 1.61E-02398Fuel Gas Heater10876087,600 116.9 5118 2.20E-04 9.65E-03 2.2E-03 9.65E-025123(a) Table C-2, Subpart C, 40 CFR Part 98. Emissionfactors in kg/MMBtu were converted to lb/MMBtu by multiplying by 2.204.(b ) CO2e = CO2 + (21 x CH4) + (310 x N2O)Source: Golder, 2012TABLE 4. Shady Hills Expansion: GHG Emissions for the Proposed Emergency Generator and Fuel Gas HeaterCO2Emissions (a)TABLE 3. Shady Hills Expansion: Proposed CO2e emission limits - per TurbineGas-fired operationsUnit loadOutput, MW(gross)Heat Rate,Btu/kWh (LHV,gross)Heat Rate,Btu/kWh (HHV,gross) operating hours %Annual operatinghoursGeneration,MWh/yrlb/mmBtu (HHVbasis) lb/hr lb/yr lb/MWh100%2188,8269,79750%1,445314,835119254,040367,088,1731,16650%10911,26512,50450%1,445157,417119162,120234,264,0661,488Totals472,252601,352,2391,273Design margin5.0%Performance degradation margin3.0%1,377Proposed GHG limit on NGNormal Operations12-Month Rolling Averagelb/MWh at ISO1,377Start-up and Shut-down12-Month Rolling AverageShort tons per SU-SD event21Oil-fired operationsUnit loadOutput, MW(gross)Heat Rate,Btu/kWh (LHV,gross)Heat Rate,Btu/kWh (HHV,gross) operating hours %Annual operatinghoursGeneration,MWh/yrlb/mmBtu (HHVbasis) lb/hr lb/yr lb/MWh100%2239,50910,17550%25055,658163368,88392,220,7871,65750%11111,67012,48750%25027,829163226,35856,589,6212,033Totals83,487148,810,4081,782Design margin5.0%Performance degradation margin3.0%1,928Proposed GHG limit on ULSD n)Normal Operations12-Month Rolling Averagelb/MWh at ISO1,928Start-up and Shut-down12-Month Rolling AverageShort tons per SU-SD event28Notes:12CO2e - includes CO2, N2O, and CH4 and is based on 40 CFR Part 75 and Part 98 factors.3ISO = 59 deg. F., 60% relative humidity4Assumes 5% margin for design basis and 3% margin for degradation between major overhauls and the life of unit.5CO2e lb/MMBtu Emission Factors based on Table 1. CO2e = CO2 + (21 x CH4) + (310 x N2O)6Startup Shutdown Emission based on CO2e Emission Factor and Estimated Fuel Consumption fer event: 338 MMBtu/event, and 339MMBtu/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, 2012CO2e EmissionsCO2e EmissionsThe above GHG limits take into consideration a number of operating, design and maintenance factors typical of combustion turbine generating facilities. The limits consider (a)operation across the range from minimum load to full load output, which is important for flexible, quick-starting resources under a utility's dispatch control; (b) design standardstypical of construction contracts and equipment manufacturer’s supply contracts, which contain commercial terms for minimum performance test acceptance criteria; and (c)typical performance degradation of combustion turbines between major overhauls and the life of the equipment even with implementation of best maintenance practices.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 va lue * 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 estim ate 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 y ears horizon. * Output and heat rate values above are net of plan t auxiliary loads and incorporate a degradation all owance over the 20 year horizon. * Fixed charge rate used above for evaluation consi stent with long-term investment considerations Source: EFS 2012, Sigma 2012. Table 2a. Shady Hills Expansion: Cost Effectiveness Analysis for Alternative Simple Cycle Generation T echnologies Alternate scenario - Only 1 unit installed2 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 va lue * 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 estim ate 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 y ears horizon. * Output and heat rate values above are net of plan t auxiliary loads and incorporate a degradation all owance over the 20 year horizon. * Fixed charge rate used above for evaluation consi stent with long-term investment considerations Source: EFS 2012, Sigma 2012. Table 2. Shady Hills Expansion: Cost Effectiveness Analysis for Alternative Simple Cycle Generation T echnologies
Base scenario - Both units installedGrossPer UnitHeat Input Heat Input Power OutputOutputUnit (MMBtu/hr) (MMBtu/hr) (MW) (lb/hr) (tons/hr) (lb/hr)(tons/hr) (lb/hr) (tons/hr) (lb/hr) (tons/hr)(lb/MWh)(7FA.05) LHV HHV100% Load, 59 F, 60% Relative Humidity (ISO), Natural Gas-Firing, CT OnlyCT11,923 2,135 218118.9 228,645 114.3 2.20E-04 0.4 0.0002 2.2E-03 4.2 0.0021254,040 127CT21,923 2,135 218118.9 228,645 114.3 2.20E-04 0.4 0.0002 2.2E-03 4.2 0.0021254,040 1273,846 4,269 435.8 457,289 228.6 1 0.0004 8 0.004508,081 2541,166Design Margin5%PerformanceDegradation Margin3%1,261100 % Load, ISO, Oil-Firing, CT OnlyCT12,117 2,265 223162.3 343,589 171.8 1.32E-03 2.8 0.0014 6.6E-03 14.0 0.0070368,883184CT22,117 2,265 223162.3 343,589 171.8 1.32E-03 2.8 0.0014 6.6E-03 14.0 0.0070368,883 1844,234 4,530 445.3687,178 343.6 6 0.0028 28 0.014737,767 3691,657Design Margin5%PerformanceDegradation Margin3%1,792Annual Operating Scenario No. 1Annual Average Case Baseload, 59 F, 3390 Hours perYear of Natural Gas Firing and Zero Hours per Yearof Oil Firing.(Short TPY) (lb/MWh)CT1430,598 1,261CT2430,598 1,261Total (2 CTs) 861,196Annual Operating Scenario No. 2Annual Average Case Baseload, 59 F, 2890 Hours perYear of Natural Gas Firing and 500 Hours per Year of Oil Firing.(Short TPY) (lb/MWh)CT1459,309 1,339CT2459,309 1,339Total (2 CTs) 918,618Annual Operating Scenario No. 3Annual Average Case Baseload, 59 F, 1640 Hours perYear of Natural Gas Firing and 750 Hours per Year of Oil Firing.(Short TPY) (lb/MWh)CT1Total (1 CT) 346,644 1,434CT Maximum Annual Emissions (Scenario No. 2)918,618Short TPYEmergency Generator398Short TPYFuel Gas Heater5,123Short TPYTotal Annual CO2e Emissions (Incudes Startup and Shutdown Emissions)(e)924,139 Short TPYPSD Review Threshold75,000Short TPY(a) Appendix G - Determination of CO2Emissions, 40 CFR Part 75. Natural gas-firing CO2lb/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 CO2Emissions, 40 CFR Part 75. Oil-firing CO2lb/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. Emissionfactors 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 operatingcase based on ISO conditions, 100% load @ 59 deg. F, 60 % relative humidity.Source: Golder, 2012.Adjusted lb/MWh for Margin(d)CO2e Emissions (c)Emission Emission EmissionFactor Emission Rate Factor Emission Rate Factor Emission Rate Emission Rate(lb/MMBtu) (lb/MMBtu) (lb/MMBtu)Adjusted lb/MWh for Margin(d)TABLE 1. GHG Emissions for the Proposed Shady Hills Expansion Project Compared to PSD Review ThreshodCO2Emissions (a) N2O Emissions (b) CH4Emissions (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 Shad y Hills, LLC.

1 4240 Merchant Energy Way

S pring 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 L OCATION

This is the final air construction permit , which authorizes the construction of tw o nominal 22 3 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 o n 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

k ilometers (k m ) 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 ( Appendice s ). 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 chan ges 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 issuan ce of this final permit, a ny 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 Depart ment 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 f ee t 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 ar e equipped with d ry l ow

- nitrogen oxides (NO X 

### ) combustors and water injection capability. The three combustion turbines are regulated under Phase II of the Federal Acid Rain Program. This facility operates during p eak hours of electrical use.

PROPOSED PROJECT

The proposed site expansion project is to install two, dual

- fuel nominal 22 3 MW GE 7FA.05 simple cycle

combustion turbine

- electrical generators , two 75

- f ee t exhaust stacks, a n emergency generator, a natural gas

heater and a nominal 2.8

- million gallon distillate fuel oil storage tank.

Th e new emission units will be assigned the following emissions unit identification number (E.U. ID No.) within the Department’s Air Re source Management System (ARMS) :

Facility ID No. 1010373

ID No. Description

005 22 3 MW General Electric Model 7FA .05 simple cycle combustion turbine

- electrical generator

006 22 3 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 G as H eater

009 2.8 million gallon distillate fuel oil storage tank

REGULATORY CLASSIFIC ATION

The facility is not a major source of hazardous air pollutants (HAP).

The facility operates units subject to the acid r ain 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(P SD), 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 REQU IREMENTS

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 (O PC) 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 O PC 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 Co ntrol 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

, Subp art ZZZZ ; and

i. Appendix I . NSPS

, Subpart Dc, Standards of Performance for Small Industrial

- Commercial

Insti tutional 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

- 21 0, 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 appl ication 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 constructi on 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 e ach 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 REQU IREMENTS

Shady Hills Generating Station, Site Expansion Air Permit No. 1010373

- 012

- AC

Permit Modification and Reissuance PSD

- FL

- 402A Page 5 of 1 7 

### c

. At such time tha t 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 i n Tallahassee and a copy to the Region 4 o ffice 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 operat ion 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 thi s 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 informatio n 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 unit s

.

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

te mperature 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 : D etermination s of the Best Available Control Technology (BACT) w ere conducted

for nitrogen oxides ( NO X 

### ), initial carbon monoxide ( CO ) and particulate matter ( PM/PM 10 

### /PM 2.5 

### )

. [Rule 62

- 210.200 (BACT), F.A.C.]

2. NSPS Requirements : The s e unit s shall comply with the applicable NSPS in 40 CFR 60, including: Subpart A (General Provisions) and Subpart KKKK (Standards of Performance for Stationar y Gas Turbines)

. See Appendices F and G o f this permit. The BACT emissions standards for NO X 

### and the fuel sulfur specifications are as stringent as, or more stringent than the NO X 

### and sulfur dioxide ( SO 2 

### ) limits imposed by the applicable NSPS provisions. Some separate r eporting 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 DESCRIPTIO N

3. Combustion Turbines : The permittee is authorized to install, tune, operate, and maintain two GE

Mod el 7 FA .05 combustion turbine

- electrical generator set s 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 NO X 

### ( DLN 2.6) combustion system with the GE Start

- up NO X 

### technology feature to control NO X 

### 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 NO X 

### . Thereafter, the system shall be m aintained 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 NO X 

### emissions from the combustion turbine s when firing distillate fuel oil. Prior to the initial emissions performance tests, the water injection system shall be tuned to achieve sufficiently low NO X 

### values to meet
the NO X 

### 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 REQUIREM ENTS

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 (P otential to emit ) and 62

- 212.400

, F.A.C. ; BACT for PM/PM 10 

### /PM 2.5 

### ]

### 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 y ear

. 2. If only one combustion turbine is installed, then it may operate no more than 3,390 hours per year.

b. ULSD Fuel O il 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 1,6 40 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

- 210.20 0(PTE), F.A.C.]

9. Simple Cycle, Intermittent Operation : The turbine s 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 s team 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 p roposal of the

BACT as if the unit had never been built. [Rules 62

- 212.400(12) and 6 2

- 212.400(BACT), F.A.C.]

EMISSIONS AND TESTIN G REQUIREMENTS

10. Emission Standards : E missions from the combustion turbines shall not exceed the following standard s.

Pollutant Emission Standard a,b Basis Compliance Method c Averaging Time

NO X Gas 15.0 ppmvd @15% O 2 NSPS KKKK

CEMS 4

- hr rolling avg.

9.0 ppmvd @15% O 2 BACT 24

- hr block avg.

69.5 lb/hour d One 24

- hr block d

Oil 42.0 ppmvd @15% O 2 NSPS KKKK , BACT 4

- hr rolling avg.

370.9 lb/hour d BACT One 24

- hr block d

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/PM 10 /PM 2.5 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 (NO X ) concentration emission standards are expressed in parts per million by volume, dry, corrected to 15 percent oxygen, abbreviated as ppmvd @15% O 2 . Carbon monoxide (CO) concentration emissions standards in ppmvd
are not corrected to 15% O 2
. 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 th e performance curves and/or equations provided to the Department pursuant to Condition 8 above.

c. CEMS means continuous emissions mon itoring system.

d. One time initial compliance demonstration by CEMS

. Subject to the n o tification requirements in 62

- 297. 310(7)(a)9., F.A.C.
The demonstration period shall i nclude all valid hours within the designated 24

- hour block and not less than three v alid hours during the block . Pound/hour NO X values reported as NO 2 equivalent of nitrous oxide (NO) plus nitrogen dioxide (NO 2 )

.

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 combus tion design and operation of the combustion turbines represent BACT for PM/PM 10 /PM 2.5 emissions and effectively limit the potential SO 2 project emissions to values less than 40 tons/year. Compliance with the fuel specifications, carbon monoxide (CO) stand ards, 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.



### [Ru les 62

- 4.070(3), 62

- 210.200, 62

- 212.400, 62

- 297 and 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 applyin g 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 N O X 

### Emissions

- Instrumental

9 Visual Determination of Opacity

10 Determination of Carbon Monoxide Emissions from Stationary Sources

20 Determination of NO X 

### , 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 Moni toring 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% o r 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 ma ss 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 6 2

- 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 s hall 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 NO X 

### , CO an d 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 1 st 

### to Septe mber 30 th 

### ) while firing natural gas

. CO and v isible emissions tests shall also be performed while firing fuel oil

, on each combustion turbine that is fired with

fu e l 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 NO X 

### shall be demonstrated with data collected from the required CEMS

. [Rules 62

- 4.070, and 62

- 210.200(BACT), F.A.C.]

17. Spe cial 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 prov ide 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. R ule 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. Sh utdown 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 preve nted 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 C ondition 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 f ollowed. As provided by the Department’s authority in Rule 62

- 210.700(5), F.A.C., the following provisions and those given in Condition 2 1 are adjustments to maximum and minimum factors 

### in Rule 62

- 210.700(1), F.A.C.

a. Limiting Data Exclusion. If the comp liance 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, m alfunction, 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 sam e 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 C ondition 20 0 :

a. Startup and Shutdown : Up to 6 0 minutes of CEMS data may be excluded for each combustion turbine
startup and shutdo wn cycle . For startups and shutdowns of less than 6 0 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 malf

unction. 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 permit tee 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, shu tdown, 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 MONITORIN G REQUIREMENTS

23. CEM S : Subject to the following, the permittee shall install, calibrate , operate, and maintain a CEMS to
measure and record the emissions of NO X 

### 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 ti me of the initial compliance demonstration.

a. NO X 

### Monitor: Each NO X 

### 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 NO X 

### monitor shall be performed using EPA Method 20 o r 7E in Appendix

A of 40 CFR 60.

b. Diluent Monitor: The oxygen (O 2 

### ) or carbon dioxide (CO 2 

### ) content of the flue gas shall be monitored at

the location where NO X 

### is monitored to correct the measured emissions rates to 15% O 2 

### . If a CO 2 

### monitor is installed, the O 2 

### 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 4 0 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 NO X 

### 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 pe r 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 sh all 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 f ired 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. I f 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 Average s : 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

concentration s 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 f rom the corresponding CEMS compliance demonstration subject to the provisions of C onditions 20 and 21 1 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 FO R ANNUAL EMISSIONS

26. CEMS Annual Emissions Requirement : The owner or operator shall use data from the NO X 

### CEMS when calculating annual emissions for purposes of computing actual emissions, baseline actual emission s, 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 accou nt 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 swit ching). 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 upda ted 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 demonst rated 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 D4 084

- 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 fil e 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 sulfu r 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 C ompliance 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 an d 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. Malf unction 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 NO X 

### 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 calculation s should also be provided. In addition, the report shall
summarize the NO X 

### 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 ea ch 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 T urbine O ption

– Fuel Oil Use Notification : If only one combustion turbine is constructed, t he 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 t hat calendar year

. [Rule 62

- 4.070 , F.A.C.]

FINAL BACT DETERMINA TION FOR CARBON MONO XIDE

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, t he 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 i dentification 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 s ubmitted 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 i nitial 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 proj ect 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 Defi nition), and 62

- 212.400, F.A.C.]

### SECTION 3. EMISSIONS UNIT SPECIFIC CONDITIONS

B

. 2500 kW Emergency Generator (EU

- 00 7 )

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 i s 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, S ubpart 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 Rec iprocating Internal

Combustion e ngine 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 e mergency 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 Reciproca ting Internal Combustion Engines , section 63.6590(c) and Rule 62

- 204.800(11)(b)82., F.A.C. ]

EQUIPMENT SPECIFICAT IONS

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 PERFOR MANCE 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 mi llion (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 Gen erator Emission Limit s :

Emergency Generator ( > 560 kilowatts ) CO ( g/kW

- hr) 1 

### PM

( g/kW

- hr) NMHC 2 

### +NO X



### ( g/kW

- hr) Diesel Fuel 3



### (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 NO X 

### . 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 un it. As an alternative, an EPA c ertification 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 use d 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

- 00 7 )

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 Oxide s E missions from Stationary Sources

10 Determination of Carbon Monoxide Emissions from Stationary Sources

NOTIFICATION, REPORTING AND RECORD S

9. Notifications : Initial notification s are required pursuant to 40 CFR 60.7, 40 CFR 63.9, and 40 CFR 63.6590 (b) (i) for the 2500 k

W 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 CONDI TIONS

C

. Natural Gas Heater (EU

- 00 8 )

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. [Applica tion ]

PERFORMANCE RESTRICT IONS

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

- 2 10.200(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 APPLICABI LITY

4. Small Boiler BACT : The natural gas h eater 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 SO 2 

### emissions. For this project, BACT for PM and SO 2 

### 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 CF R 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 Industrial

Commercial

- 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 fir e 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 : I nitial 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

- 00 9 )

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, Recons truction, or Modification Commenced After July 23, 1984. [ Application; 40 CFR 60.110b( b )]

EQUIPMENT SPECIFICAT IONS

2. Equipment : The permittee is authorized to operate, and maintain one nominal 2.8 million gallon distillate fuel oil storage tank to provid e fuel oil to Units 005 and 006 or to other units on the site. [ Application ]

EMISSIONS AND PERFOR MANCE REQUIREMENTS

3. Hours of Operation : The hours of operation are not re stricted (8,760 hours per year). [Application]

NOTIFICATION, REPORT ING 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

Caption Text

# 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 p ermit:

• For any required purpose at a facility operating un der a federally enforceable state air operation permit (FESOP) or Title V air operation permit;

• For a proposed project subject to prevention of sig nificant deterioration (PSD) review, nonattainment new source review, or maximum achievable control te chnology (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 applicab ility limit (PAL). Air Operation Permit – Use this form to apply for:

• An initial federally enforceable state air operatio n permit (FESOP); or

• An initial, revised, or renewal Title V air operati on 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 applic able):

### 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 r enew a plantwide applicability limit (PAL).
Air construction permit to establish, revise, or r enew a plantwide applicability limit (PAL), and separate air construction permit to authorize c onstruction 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 revisio n, 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 6 2-213.405, F.A.C. In such case, you must also check the following box:
I hereby request that the department waive the pro cessing time requirements of the air construction permit to acco mmodate 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 De terioration Analysis, and Final FDEP Permit No. 1010373-012-AC, PSD-FL-402A, for the Shady Hill s 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 a ssociated facilities. The GE 7FA.05 units will each be equipped with evaporative cooling. Th e annual maximum capacity factor of the plant will be 39 percent per CT, which is equivalen t to operating 6,554,565 MMBtu/CT/year (3,390 hours/year) at full load per CT). Natural g as will be used as the primary fuel, and fuel oil will be used as a backup fuel. The project will re quire 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 re newal 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 responsibl e officials, the “application responsible official” need not be the “primary responsible offi cial.”
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, treasu rer, or vice-president of the corporation in charge of a principal business function, or any oth er 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 othe r public agency, either a principal executive officer or ranking elected official. The designated representative at an Acid Rain sourc e or CAIR source.


### 3. Application Responsible Official Mailing Address

... Organization/Firm:

Street Address:

City: State: Zip Code:
4. Application Responsible Official Telephone Numbe rs... Telephone: ( ) - ext. Fax: ( ) -
5. Application Responsible Official E-mail Address:
6. Application Responsible Official Certification:

I, the undersigned, am a responsible official of th e Title V source addressed in this air permit appli cation. I hereby certify, based on information and belief f ormed after reasonable inquiry, that the statements made in this application are true, accurate and com plete and that, to the best of my knowledge, any estimates of emissions reported in this application are based upon reasonable techniques for calculati ng emissions. The air pollutant emissions units and a ir pollution control equipment described in this application will be operated and maintained so as t o comply with all applicable standards for control of air pollutant emissions found in the statutes of th e State of Florida and rules of the Department of

Environmental Protection and revisions thereof and all other applicable requirements identified in thi s application to which the Title V source is subject. I understand that a permit, if granted by the department, cannot be transferred without authoriza tion from the department, and I will promptly notif y the department upon sale or legal transfer of the f acility or any permitted emissions unit. Finally, I certify that the facility and each emissions unit a re in compliance with all applicable requirements t o which they are subject, except as identified in com pliance 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” i s identified in Section I that is not the facility “primary responsible official.”
1. Facility Primary Responsible Official Name:

2. Facility Primary Responsible Official Mailing Ad dress... 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 Add ress:

### 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 a ll other changes proposed in this application for air permit. Refer to instructions to distinguish between a “major source” and a “synthet ic 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 Hazard ous Air Pollutants (HAPs)

5. Synthetic Minor Source of Air Pollutants, Other t han 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 CF R Part 60)

9. One or More Emissions Units Subject to Emission G uidelines (40 CFR Part 60)

10. One or More Emissions Units Subject to NESHAP (40 C FR 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 Su bpart KKKK - Standards of Performance for Stationary Gas Turbines.

Emergency Generator, emission unit 007:

• NSPS Subpart IIII – Standards of Performance for St ationary 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 K b – Standards of Performance for Volatile Organic Liq uid Storage Vessels (Including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruc tion, 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/PM 10

/ PM 2.5 A N

CO A N

VOC A N

SO 2 A N

NO

x A N

CO 2 e 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 Commen t:

### DEP Form No. 62-210.900(1) – Form

Effective: 03/11/2010 11

C. FACILITY ADDITIONAL INFORMATION

Additional Requirements for All Applications, Excep t as Otherwise Stated

1. Facility Plot Plan: (Required for all permit applications, except Title V air operation permit revision applications if this information was submi tted 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 wa s submitted to the department within the previous five years and would not be altered as a r esult of the revision being sought) 

### Attached, Document ID: See Note 

### Previously Submitted, Date:

3. Precautions to Prevent Emissions of Unconfined P articulate Matter: (Required for all permit applications, except Title V air operation p ermit 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, Modificati on, 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 62-212.5 00(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 P ermit 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 chan ge in applicable requirements)
3. Compliance Report and Plan: (Required for all initial/revision/renewal applicat ions) 

### 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 applicat ion 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 Tit le VI: (If applicable, required for initial/renewal applications only) 

### Attached, Document ID:
Equipment/Activities Onsite but Not Required to b e 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 Operati on 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 A cid 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 NO X 

### 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 Turbine s



### III. EMISSIONS UNIT INFORMATION

Title V Air Operation Permit Application

- For Title V air operation permitting only, emissions units are classified as regulate d, unregulated, or insignificant. If this is an application for a n 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. Insignifican t 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 subjec t 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 th rough 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 Permi t 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 p ermitting 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 emissio ns 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 submitt ing 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 Turbine s



### A. GENERAL EMISSIONS UNIT INFORMATION

Title V Air Operation Permit Emissions Unit Classification

1. Regulated or Unregulated Emissions Unit? (Check one, if a pplying 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

em issions 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 turbine s. 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



### 1 0

. Generator Nameplate Rating: 223 MW/CT b



### 1 1

. 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 Turbine s



### Emissions Unit Control Equipment /Method: Control 1 

### of 1



### 1. Control Equipment/Method Description:
Water injection for N O

x control (distillate oil firing). Dry Low NO

x burner for NO

x control (natural gas burning).



### 2. Control Device or Method Code: 028, 0 25



### 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 Turbine s



### B. EMISSIONS UNIT CAPACITY INFORMATION
(Optional for unregulated emissions uni ts

. )

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/hr a



### 4. Maximum Incineration Rate: pounds /hr
tons/day

5. Requested Maximum Op erating 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 rat es: Natural gas firing

- 1,923 MMBtu /hr

Dist illate 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 perc ent 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 fir ing 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 Turbine s



### 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 Emissi on 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 

### acfm a 

### 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/Longi tude... Latitude (DD/MM/SS) 28/22/00 

### Longitude (DD/MM/SS) 82/3 3 / 3 0



### 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 Turbine s



### D. SEGMENT (PROCESS/FUEL) INFORMATION

Segment Description and Rate: Segment 1 

### of 2



### 1. Segment D escription (Process/Fuel Type) :

Internal Combustion Engines; Electric Generation; Natu ral

- 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. 0 6 

### 5. Maximum Annual Rate:
6,983 Per CT 

### 6. Estimated Annual Activity

Facto r:

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/ft 3

. Maximum hourly rate = 1923 MMBtu/hr /933 MMBtu/MM ft3 = 2 .06 MM ft3/hr

Maximum annual rate = 2.06 M M 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 Tot al 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

Max imum hourly rate = 2,117 MMBtu/hr /1 32 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 Turbine s



### 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

Effect ive: 03/11/2010 21 EMISSIONS UNIT INFORMATION POLLUTANT DETAIL INFORMATION

Section [1] of [ 4 ] Page [1] of [ 1 

### ]
Simple

- Cycle Combustion Turbine s 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):

t o tons/year

6. Emission Factor: Multi

- Component, See Table 1



### Reference: Appendix G, 40 CFR Part 75 and 40 CFR Part 98 

### 7. Emissions

M ethod 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 1,0 00 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.

1 1

. Potential

, Fugitive

, and Actual Emissions Comment:

### DEP Form No. 62

- 210.900(1)

– Form

Effect ive: 03/11/2010 22 EMISSIONS UNIT INFORMATI ON POLLUTANT DETAIL INFORMATION

Section [1] of [ 4 ] Page [1] of [ 1 

### ]
Simple

- Cycle Combustion Turbine s CO2e



### F2. EMISSIONS UNIT POLLUTANT DETAIL INFORMATION

-

ALLOWABLE EMISSIONS
Complete Subsection F2 if the pollutant identified in Subs ection 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 an d 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 Complian ce:

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 Turbine s



### I. EM ISSIONS 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 Specif ication : (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. Procedu res 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 resul t of the revision being sought) 

### Attached, Document ID: See Note 

### Previously Submitted, Date
Not Applic able (construction application)

5. Operation and Maintenance Plan : (Required for all permi t 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, Do cument ID: See Note 

### Previously Submitted, Date
Not Applicable

6. Compliance Demonstration Report s/Records: Attached, Document ID:

Test Date(s)/Pollutant(s) Tested:

Pre viously 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 demon stration 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 tim e of application, or a compliance plan must be submitte d 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 Sh ady 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 Turbine s



### 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 (Rule s 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 Monito ring : 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 insignifi cant. If this is an application for a n 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

u nit 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 requir ed 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 exemp t 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 comp leted 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

a ir 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 o peration 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 addr essed 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 addres ses, 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 addre sses, 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)

Aci d Rain Unit

CAIR Unit

9

. Package Unit:

Manufacturer: Model Number:

1 0

. Generator Nameplate Rating: 1 MW



### 1 1

. 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 Descri ption:

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 E quipment/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 a nd 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.)

E mission 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 Emis sion 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:

a cfm 

### 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. S egment D escription (Process/Fuel Type) :

Diesel



### 2. Source Classification Code (SCC):

2

- 01

- 001

- 02 

### 3. SCC Units:

10 00 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. Pollut ant 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 u nregulated 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. Comple te 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:

1,5 92 

### lb/hour 398 

### tons/year 4. Synthetically Limited?

Yes No

5. Range of Estimated Fugitive Emissions (as applicable):

t o 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 P eriod:
5 years 10 years

10

. Calculation of Emissions:

See Table 4

.



### 1 1

. 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 Ge nerator 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 a nd 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. All owable 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 E missions 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, e xcept 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 N ote 

### 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 previ ous 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 permi t 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, Do cument 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 Applic able (const ruction 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 a ltered as a result of the revision being sought) 

### Attached, Document ID: See Note 

### Previously Submitted, Date
Not Applicable

6. Compliance Demonstration Report s/Records:

Atta ched, 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 applica tion. For Title V air operation permit applications, all required compliance demonstration reports/records mu st 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 P ermit 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 R equirements 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 (Rule s 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 Faciliti es : (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 Hill s 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 : Atta ched, Document ID: Not Applicable

3. Alternative Methods of Operation : Attached, Document ID: Not Applicable

4. Alternative Modes of Operation (Emissions Trading) : Attached, D ocument 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 insignific ant. If this is an application for a n 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

un it 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 require d 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 compl eted 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

ai r 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 h ard 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

S ection [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 ope ration 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 addres sed 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 addresse s, 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 address es, 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: 00 8



### 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 R ain Unit

CAIR Unit

9

. Package Unit:

Manufacturer: Model Number:

1 0

. Generator Nameplate Rating:

1 1

. Emissions Unit Comment:

### DEP Form No. 62

- 210.900(1)

– Form

Effective: 03/11/2010 39 EMISSIONS UNIT INFORMATION

Section [3] of [4]

Natu ral 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 Schedu le

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 Poi nt Description and Type

1. Identification of Point on Plot Plan or Flow Diagram : 00 8 

### 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 Flo w 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) 82/3 3 / 3 0



### 15. Emission Point Comment:

### DEP Form No. 62

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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 D escription (Process/Fuel Type) :

Natural gas



### 2. Source Classification Code (SCC): 3. SCC Units:
1,000,000 SCF



### 4. Maximum Hourly Rate:

0.01 1 

### 5. Maximum Annual Rate:

96.4 

### 6. Estimate d 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. E stimated 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)

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Effective: 03/11/2010 43 EMISSIONS UNIT INFORMATION

Section [3] of [4]

Natural Gas Heater



### E. EMISSIONS UNIT POLLUTANTS

List of Pollutants E mitted 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

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– 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 INFO RMATION

– 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 constructi on 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. Poll utant 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):

t o 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 Act ual Emissions (if required):

tons/year 9.b. Projected Monitoring Period:
5 years 10 years

10

. Calculation of Emissions:

See Table 4

.



### 1 1

. Potential

, Fugitive

, and Actual Emissions Comment:

### DEP Form No. 62

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– Form

Effective: 03/11/2010 45 EMISSIONS UNIT INFORMATION POLLUTANT DET AIL 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 All owable 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 Al lowable

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 (De scription 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 fo r 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)



### A ttached, 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 Equipme nt : (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 i nformation 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 Applic able (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 f

ive 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 Report s/Reco rds: 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) Tes ted: 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 demo nstration 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 INFORMATI ON (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 (Rule s 62

- 212.400 (4)(d) and 62

- 212.500(4)(f), F.A.C.) : Attached, Document ID: See Note 

### Not Applicable

3. Descriptio n 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 Deterioratio n 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 Monitor ing : 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 a n 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 unregulate d 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 uni ts 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 permit ting 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 requ ired) 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/R enewal 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 ex empt 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 applica tion 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, revise d 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 Inf

ormation 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:

1 0

. Generator Nameplate Rating:

1 1

. Emissions Unit Comment:

### DEP Form No. 62

- 210.900(1)

– Form

Effective: 03/11/2010 50 EMISSION S 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: Con trol 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 unre gulated 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. Req uested 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) IN FORMATION
(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) 82/3 3 / 3 0



### 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 D escription (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:

0.0 01 5 

### 8. Maximum % Ash: 9. Million Btu per SCC Unit:

10. Segment Comment:

See Air Permit Application and Prevention of Significa nt 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 dis tillate oil (No.2) throughput ( working losses)


### 4. Maximum Hourly Rate: 5. Maximum Annual Rate: 6. Estimated Annual Activity

Factor:

7. Maximum % Sulfur:

0.0 01 5 

### 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 Storag e 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 p ermit 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/yea r 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 POLLU TANT 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 Un its: 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. Basi s 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 ADDI TIONAL 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 : (Requir ed 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 a nd 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 Applic able (construction application)

5. Operation and Maintenance Plan : (Required for all permit applications, except Titl e 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 Report s/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 th e 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 a nd 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 Require ments 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 (Rule s 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 ne w stack sampling facilities only) 

### Attached, Document ID: Not Applicable

Additional Requirements for Title V Air Operation Permit Applications

1. Identification of Applicable Requirements : Attache d, Document ID:

2. Compliance Assurance Monitoring : Attached, Document ID: Not Applicable

3. Alternative Methods of Operation : Attached, Document ID: Not Applicable

4. Alt ernative Modes of Operation (Emissions Trading) : Attached, Document ID: Not Applicable

Additional Requirements Comment

### APPENDIX C
USFWS CONSULTATION

Caption Text1 

### 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 determine d that the project is not likely to adversely affec t 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_Rausche nberger@fws.gov" <Heath_Rauschenberger@fws.gov>

cc "Belden, Roy S (GE Capital) (roy.belden@ge.com)" <r oy.belden@ge.com>, "Larocca, David" <DLaRocca@golder.com>, "Osbourn, Scott" <Sco tt_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 refer enced project is attached for
your review.

Please do not hesitate to contact me if you have an y 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\10 389556a ecology\final\ecological assessment report_cover lett er_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

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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 SPECI ES 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 threat ened, 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 (endanger ed) were identified by the Florida Natural Areas Inventory and/or the Southwest Florida Water Managem ent 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 Mari ne Fisheries Service (NMFS) on October 7, 2011 and March 29, 2012, and described the project, its locati on, and the site characte ristics. Based on this information, he determined that no spec ies regulated by the NMFS will be di rectly or indire ctly affected by the proposed project, and therefore, consultation with NMFS is not required.

In addition, Golder contacted the North Florida Ecologic al Services Office of the USFWS on October 7, 2011 and March 29, 2012 to discuss the proposed project with y ou. During our conversations, you indicated that the USFWS would like to review the ecological asse ssment 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 St ation Ecological Assessment Report

HTA/DTL/lcrH:\PROJECTS\2010proj\10389556 GE Shady Hills Revision\10389556a\10389556A Ecology\FINAL\Attachment B Ecological Assessment Repo rt.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

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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 ST ATION, ECOLOGICAL ASSESSMENT, PASCO COUNTY, FLORIDA

Dear Mr. Belden:

On August 18, 2011, Golder As sociates Inc. conducted an ec ological 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 Conserva tion Commission (FFWCC) to be endangered, threatened, or of sp ecial 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 likel y be claimed by the US Army Co rps 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 fi nal 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 oper ates 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-megawa tt (MW) General Electric model PG7241FA (GE 7FA) simple cycle combustion turbine- electric generators, three 75-foot exhaust st acks, and one 2.8 million gallon fuel oil storage tank. EFS Shady Hills LLC (Shady Hills) prop oses to license, construct, and operate two additional new simple-cycle units at t he 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 us e dry low-nitrogen oxide combustion techno logy. The primary fuel of the CTs will be natural gas with distillate fuel o il used as backup fuel. The Proposed Project w ill require an additional gas heater for the two new CTs. The present heater at the facility is onl y sized for the existing three GE 7FA CTs. In addition, since the present generator is ma rginally 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 (F LUCFCS) (Florida Department of Transportation 1999) (Figure 2). The Proposed Project site and immediate vicinity incl ude the following land uses: low density residential (FLUCFCS 110), industrial (FLUCFCS 150), open land (FLUCFCS 190), cropland and pasturelandMr. 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 (F LUCFCS 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 us e and cover/habitat classifications within and immediately adjacent to the generating station site t hat may be utilized by listed wildlife species.



### Uplands

Golder’s analysis of the Southwest Florida Wate r 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 spec ies: coniferous (p ine) plantations (FLUCFCS 441), disturbed land (FLUCFCS 740), and electric power facilitie s (FLUCFCS 831). These upland land cover types are described in more detail in the table below.

Table 1: Upland Habitat Classification s 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) wa s identified in the norther n portion of the Proposed Project site, just west of the proposed new fuel o il 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 Habi tat 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 Em ergency Management Agency (FEMA) floodplain database, the Proposed Project site is not located within t he 100-year floodplain (Figure 3). In addition, Golder’s
review of the National Wetlands In ventory database confirmed that no we tlands 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 Co nservation 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 perc ent slopes, consists of excessively drained soils with a depth to water table below 80 inches that ty pically occur in sandhill co mmunities. Tavares sand, 0 to 5 percent slopes consists of moderately well-drain ed soils that typically occu r 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 pedestri an 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 pl ants that are listed by the USFWS or the Florida Department of Agriculture and Co nsumer Services (FDACS) as end angered, threatened, of special concern, or commercially exploi ted. Listed animal species are t hose 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 Pa sco County, Florida from the USFWS (USFWS 2010a) (Attachment 1). Additionally, Golder obtained stat e 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). T he 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 vi cinity 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 spec ies 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 Fl ora 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 ra pid 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 comm ercially exploited plants. The FNAI list of threatened and endangered pl ants was used to determine which threatened and endangered plants occur within Pasco County, since t he FNAI list incorporates both the FDACS (state)- and USFWS (federal)-listed status (FNAI 2010).

According to the FNAI, no listed plant species hav e been documented within 1 square mile of the Proposed Project site. However, FNAI’s Biodiversity Ma trix Report identified 15 lis ted 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 ar ea 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 t hat 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 pres ence 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 hav e 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 (Att achment 2). However, the FNAI identified six listed wildlife species likely to occur and eight with a potent ial to occur within 1 square mile of the Proposed Project site. Out of the 14 FFWCC (state)-listed specie s identified by the FNAI as occurring or having a potential to occur, only 2 are federally listed (by th e 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 th reatened. This snake can occur within a broad range of suitable habitats, from scrub and sandhill to wet prairies. In it s 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 Proj ect 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 approxim ately 1,000 ft south of the Proposed Project site (SWFWMD RAI 2010). Because of the lack of preferred nes ting 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 w ood stork colony (Embassy, USFWS 2010) is located approximately 10.2 miles southwest of the Proposed Project site, and the site fa lls within five colonies’ 15-mile core foraging area radii (Figure 7). No impacts to wood storks or thei r 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 spec ies 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 bu rrows for shelter (FNAI 2001). It is unlikely that the gopher frog is present due to the lack of its preferred habi tat 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 (F FWCC 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 designat ed 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 th reatened. Gopher tortoises are commonly found in dry upland habitats, such as sandhills, scrub, xeric oa k 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 i dentified 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 perm it will be required from the FFWCC, and gopher tortoises will need to be relo cated to either on- or off-site areas pursuant to FFWCC guidelines.

Florida Pine Snake ( Pituophis melanoleucus mugitus )

The Florida pine snake often coexists with gophe r tortoises and southeastern pocket gophers ( Geomys pinetis ) in sandhills, old fields and pastures, sand pi ne scrub, and scrubby flatwoods (FNAI 2001). This species is currently listed as a species of specia l concern by the FFWCC; however, the Florida pine snake underwent a biological status review in J une 2011 and was approved for protection status as a threatened species (FFWCC 2011). Management plans ar e currently being prepared for all state-listedMr. 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 no rtheastern portion of the Proposed Project site. The observation was made in t he vicinity of both gopher tortoise and southeastern pocket gopher burr ows. Gopher tortoise bu rrows within the Proposed Project site will most likely need to be excavated and commensal species relocated. If pi ne snakes are encountered during gopher tortoise relocation activities, they will be relocated to an approved recipient site, along wi th 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 FFW CC; however, the Florida burrowing owl underwent a biological status review in June 2011 and wa s approved for protection status as a threatened species (FFWCC 2011). Management plans are currently being prepared for all statelisted species that do not have rec ent 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 FFW CC. They prefer freshwater lakes, marshes, swamps, and streams for foraging, and cypres s trees for roosting (FNAI 2001). This species was identified by FNAI within wetland sy stems approximately 1.0 mile southeast and 1.1 miles southwest of the Proposed Project site. Although this species likely forages within fres hwater marshes and wet prairies in the vicinity of the site, it is not like ly that the little blue heron nests in the area, because the closest documented breeding bird colony (Atlas Number 2674) is locate d 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 ar e 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 conc ern by the FFWCC. It is widel y distributed in Florida in both fresh- and saltwater systems (FNAI 2001). This species was identified by FNAI within wetland systems approximately 1.0 mile s outheast of the Proposed Project site. Although this species likely forages within freshwater marshes and wet prairies in t he 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 Pr oposed 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 (F FWCC 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 designat ed 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 co ncern by the FFWCC. It inhabits a variety of wetland habitats, including freshwater and brackish marshes, sa lt flats, forested wetlands, wet prairies, swales, and man-made ditches (FNAI 2001). This species wa s 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 t he site, it is not likely that the white ibis nests in the area because the closest documented breeding bird co lony (Atlas Number 2674) is located approximately 1.5 miles southeast of the Proposed Project site. No ad verse impacts to the white ibis are anticipated due to the Proposed Project.

This species is currently listed as a species of sp ecial 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 (F FWCC 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 designat ed 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, wh ile northern migrants typically arriving in September and departing by March are not listed. Kestrels seen in Florida duri ng 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 Americ an kestrel commonly inhabits open areas, such as open pine habitats, woodland edges, prairies, and pastures (FNAI 2001).

A southeastern American kestrel wa s identified by FNAI within t he transmission line right-of-way approximately 0.6 mile to the west of the Proposed Project site. Sout heastern American kestrels nest between mid-March and early June. Current recomm ended management guidelines state that a 492-ftradius buffer zone should be maintained around any acti ve nest sites and distur bance inside the nest-site buffer should be minimized during the courtship, br eeding, and nesting period (i.e., January to August) (Lane and Fischer 1997). Adverse impacts to the s outheastern 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 pastu res throughout Flor ida, while the non-listed mi grant greater sandhill crane ( G. canadensis tabida ) generally arrives in October an d departs by March (FNAI 2001).

SWFWMD staff previously identified a nesting pair of sandhill cranes with in 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 protecti ve 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 identifi ed 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 spec ial concern by the FFWCC. They prefer xeric upland habitats with sandy soils, such as scrub, sandhill, a nd ruderal sites, and they o ften inhabit burrows of the gopher tortoise (FNAI 2001). Due to the presence of gopher tortoises and t heir 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 FFW CC; however, the Florida mouse underwent a biological status review in June 2011 and was approved for removal from the statedesignated protected species list (F FWCC 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 designat ed 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, pastu res, and other open, ruderal habitats with scattered pines and oaks (FNAI 2001). Because of the presence of pasture an d 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 t he Proposed Project site, the FFWCC would most likely require some protective meas ures 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 threat ened. They prefer large upland forests and large swamps (FNAI 2001). It is unlikely that the Florida black bear is present within t he immediate proximity of the Proposed Project site due to the lack of lar ge, 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 spec ial 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 (F FWCC 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 designat ed 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 Fl orida’s Bald Eagle Management Plan. Bald eagles typically inhabit areas close to coastal areas, bays, ri vers, 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 closestMr. 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 approximat ely 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 (t hreatened) 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 constr uction commencement date and the survey results submitted to FFWCC with supporting permit applicati on documents. Construction activities may not begin until the gopher tortoise relocation permit has be en 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 reloca tion 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 s nakes, 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 encounter ed, work in the area will be st opped and will not re commence until the indigo snake has safely evac uated the area on its own.

Please do not hesitate to contact Heather Ahrens at (813) 287-1717 if you hav e 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 FN AI Listed Species Occurrences Figure 7, Wood Stork Core Nest ing 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 Ma trix Report and Associated Tables

HTA/DTL/lcrMr. 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 Commi ssion). 2003. Florida’s breeding bird atlas: A collaborative study of Flor ida’s birdlife. Online: http://www.myfwc.com/bba/ (accessed September 2011).

FFWCC. 2010. Bald Eagle Nest Locator. Online: https://public.myfwc.com/FWRI/E agleNests/nestlocator.aspx (accessed August 2011).

FFWCC. 2011. Biological Status Review for FFWCC's Imperiled Species. Online: http://myfwc.com/media/1354992/St affListingReco mmendations_2011.pdf (accessed September 2011).

Florida Department of Transportation. 1999. Surv eying 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 Pl ants 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 Pr ofile: Southeastern American Kestrel ( Falco sparverius paulus ) on Military Installations in the Southeastern Unit ed States. Technical Report SERDP-97-4, August 1997. Mississippi: U.S. Army Corps of Engineers.

NatureServe. 2009. NatureServe Explorer: An online encyclopedia of life, Vers ion 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 In formation. Shady Hills Power Company, LLC, Water Use Application No. 20012052.004.

US Department of Agriculture. 2010. Natural Reso urces Conservation Service. Web Soil Survey, Pasco County, Florida. http://websoilsurvey. nrcs.usda.gov/app/W ebSoilSurvey.aspx (accessed August 2011).

USFWS (US Fish and Wildlife Service). 2007. Na tional Bald Eagle Management Guidelines.

USFWS 2010a. Federally Listed Species in Pasco County, Florida. Online: http://www.fws.gov/northflor ida/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).

### FIGURES589 24S17E23 24S17E24

24S17E25 24S17E26

24S17E35

24S17E36 24S18E19

24S18E30

24S18E31

25S17E02 25S18E06 25S17E01 water

GIS

REVIEW DESIGN SCALE:F:\PROJECTS\201PROJ\103-895

CHECK 0 FILE No. 1 0 3 -895 % 00  PROJECT No. 1 0 3-895 

JG A S SHOWN JG

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 BOUNDARYH U D S O N A V E M E R C H A N T E N E R G Y W A Y 110

150 210 210

190

190 190

434 434

441 534

641 641 641

641 641 641 641 830 644 441 534

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 FILE No. 103-89556B002 PROJECT No. 103-89556

JG AS SHOWN JG

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 FACILITIESAE A

A A

A S H A D Y H I L L S R D

H U D S O N A V E H A R M O N D R N A G L E

C

T

H E L M C T

S L O A N C T

H A Y S R D M E R C H A N T E N E R G Y W A Y H A

Y S R D C R E L A D R

H U D S O N A V ESOFT W I N D

L N

GIS

REVIEW DESIGN SCALE:F:\PROJECTS\2010 PROJ\103-89556 GE Shady Hills Revision\B - Ecology\Figures\103-89556B006 FLOOD ZONES.mxd

CHECK 0 FILE No. 103-89556B006 PROJECT No. 103-89556

JG AS SHOWN JG

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.M E R C H A N T E N E R G Y W A Y

H U D S O N A V E 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 FILE No. 103-89556B003 PROJECT No. 103-89556

JG AS SHOWN JG

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 WETLANDM E R C H A N T E N E R G Y W A Y

H U D S O N A V E 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 FILE No. 103-89556B005 PROJECT No. 103-89556

JG AS SHOWN JG

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 WATERWhite

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 FILE No. 103-89556B004 PROJECT No. 103-89556

JG AS SHOWN JG

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 ROADCITRUS
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 FILE No. 103-89556B007 PROJECT No. 103-89556

JG AS SHOWN JG

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 ROADGT01 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 FILE No. 103-89556B008 PROJECT No. 103-89556

JG AS SHOWN JG

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, FLORIDAFederally 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 ReviewsFederally 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 TABLESNOTE: 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 occurren ce 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 document ed occurrence in the vicinity and there is suitable habitat for that species or community with in 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.or g 

# Florida Natural Areas Inventory
Biodiversity Matrix Query Results

UNOFFICIAL REPOR T Created 9/9/2011
(Contact the FNAI Data Services Coordinator at 850.224.8207

for information on an official Standa rd Data Report) 

### Pa g e 1 of 3 FNAI Biodiversit y Matrix

9/9/2011 htt p ://data.labins.or g /ma pp in g /FNAI

_ BioMatrix/GridSearch.cfm?sel

_ id=23978&extent=54

...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 

### Pa g e 2 of 3 FNAI Biodiversit y Matrix

9/9/2011 htt p ://data.labins.or g /ma pp in g /FNAI

_ BioMatrix/GridSearch.cfm?sel

_ id=23978&extent=54

...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 Invent ory represent the single most comprehensive source of

information available on the locations of rare species and other sign ificant ecological resource s 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 no t be held liable for the accuracy and comp leteness of these data, or opinions or conclusions drawn from these data. FNAI is not inviting reli ance on these data. Inventory data are designed for the purposes of conservation planning and scientific research and ar e 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. 

### Pa g e 3 of 3 FNAI Biodiversit y Matrix

9/9/2011 htt p ://data.labins.or g /ma pp in g /FNAI

_ BioMatrix/GridSearch.cfm?sel

_ id=23978&extent=54

...

### APPENDIX D
USFWS AND NMMS CORRE SPONDENCE

Caption Text1 

### 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 with in the proposed project site(18 burrows total, of w hich 14 are potentially occupied), there is a potential for the eastern indigo snake to be present. Standard p rotection measures for the eastern indigo snake will be enfor ced 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 pro ject site. In addition, no dredge or fill activitie s are proposed within wetlands or other surface waters.

My understanding from our conversations is that the USFWS would like to review the ecological due dili gence report before making a determination on whether the projec t will affect listed species. It is also my underst anding that we may submit the ecological due diligence report directly to USFWS for review, or we can wait until the USEP A forwards the information to the USFWS as part of the Section 7 C onsultation process.

Please do not hesitate to contact me if you have an y 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 con tain proprietary information for the exclusive use of the intended recipient. Any use, distribution or copying of this transmission, other than by the intended recip ient, is strictly prohibited. If you are not the in tended recipient, please notify the sender and dele te all copies. Electronic media is susceptible to unauthorized mod ification, deterioration, and incompatibility. Acco rdingly, the electronic media version of any work p roduct may not be relied upon.

Please consider the environment before printing thi s 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, sp ecies regulated by NMFS for this area (i.e., gulf sturgeon and sea tur tles) would not be present on site. It is also my understanding that the NMFS does not send no effect determination correspo ndence.

Please do not hesitate to contact me if you have an y 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 con tain proprietary information for the exclusive use of the intended recipient. Any use, distribution or copying of this transmission, other than by the intended recip ient, is strictly prohibited. If you are not the in tended recipient, please notify the sender and dele te all copies. Electronic media is susceptible to unauthorized mod ification, deterioration, and incompatibility. Acco rdingly, the electronic media version of any work p roduct may not be relied upon.

Please consider the environment before printing thi s email.

### APPENDIX E
CULTURAL RESOURCE AN ALYSIS

Caption TextH: \ 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 Assoc iates and the GA globe design are trademarks of Golder Associates Corporation August 1 7 , 2012 1 0 3

- 895 5 6

M s. 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 RESOURCE S DESKTOP ANALYSIS FOR SHADY HILLS EPA PSD PERMIT

Dear M s

. Kammerer :

On behalf of EFS Shady Hills

, LLC (Shady Hills) Golder Associates Inc (Golder) is submitting to the
Florida Division of Hi storical Resources (FDHR) the following cultural resour ces desktop analysis

. Golder respectively requests FDHR’s concurrence that no additional cultural resource s 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 ope rates the Shady Hills Generating S tation located at 14240 Merchant Energy Way, Shady Hills, Pasco County, Florida. Shady Hills is proposing to e xpand the Shady Hills Generating Station with the addition of two nominal 2 18

- 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 th at 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 P roject are located in unincorporated Pasco County, Florida within Section 25, Township 24S , and Range 17E (Figure s 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 lay down area during the construction of the e xisting Shady Hills Generating Station faciliti e s.



### PREVIOUSLY CONDUCTED SURVEYS AND PREVIOUS LY RECORDED
CULTURAL RESOURCES W ITH IN THE PROJECT SITE AND PROJEC T AREA

Golder requested from the Florida Department of State Division of Historical Resources a sea rch of the Florida Master Site File (FMSF) to identify known cultural resource s locations within the P roject location
and surrounding area . This information is based on the most current FMSF data. Golder acknowledgesM s. 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 in ventory of cultural resourc es and their significance, and therefore may not reflect existing conditions.

According to t he FMSF , there were no previously recorded archaeological sites or historic structures
within the P roject S ite. 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 s ites are single artifact or isolated finds that are prehistoric but lack pottery. Site s PA00324 and PA00321 are in eligible for listing on the National Register of Historic Place s

.

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

rec ommends that the FDHR confirm s 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 IN C.

Kelly L. Hartman Scott Osbourn
Environmental and Land Use Planner Senior Consultant and Associate

David Larocca Senior Engineer

Attachment s : Figure 1

, Site Location

— Topographic

Figure 2

, Site Location

— Aerial

cc: Roy Belden

– GE Energy Financial Services, EFS Shady Hills, LLC

K L H / SO/ DL/ l c r

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D L 0 4 / 1 3 / 2 0 1 2Golder, 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