JEA GEC CCCT Conversion Appendix D 

PSD Air Permit Application D-1 September 2008 

Appendix D 

BACT Analysis 
Best Available Control Technology Analysis 

for

JEA – Greenland Energy Center 

Units 1 and 2 

Combined Cycle Combustion Turbines

Submitted by 

JEA

September 2008 

Project No. 149588 
JEA GEC CCCT Conversion Table of Contents 

149588 TC-1 

Table of Contents 

Acronym List ......................................................................................................................1

1.0 Introduction and Executive Summary ................................................................. 1-1 

2.0 BACT Analysis Basis .......................................................................................... 2-1 

2.1 Regulatory Basis ...................................................................................... 2-1 

2.1.1 Applicable NSPS Emissions Limits .......................................... 2-2 

2.2 Unit Operations and Baseline Emissions Basis ....................................... 2-3 

2.2.1 GEC Units 1 and 2 CCCT ......................................................... 2-3 

2.3 Economic Basis........................................................................................ 2-6 

3.0 GEC Units 1 and 2 NOx and CO BACT Analysis............................................... 3-1 

3.1 Step 1--Identify All NOX Control Technologies......................................3-1 

3.1.1 Water or Steam Injection ............................................................... 3-2 

3.1.2 Dry Low-NOx Burners................................................................... 3-2 

3.1.3 XONON ......................................................................................... 3-2 

3.1.4 Selective Non-Catalytic Reduction................................................ 3-3 

3.1.5 SCONOx......................................................................................... 3-3 

3.1.6 Selective Catalytic Reduction........................................................ 3-4 

3.2 Step 1--Identify All CO Control Technologies........................................3-5 

3.2.1 Dry Low-NOx Burners and Good Combustion Control ................ 3-6 

3.2.2 CO Oxidation Catalyst................................................................... 3-6 

3.2.3 SCONOx......................................................................................... 3-7 

3.3 Step 2--Eliminate Technically Infeasible NOX Options ..........................3-7 

3.3.1 Water or Steam Injection ............................................................... 3-7 

3.3.2 Dry Low-NOx Burners................................................................... 3-8 

3.3.3 XONON ......................................................................................... 3-8 

3.3.4 Selective Non-Catalytic Reduction................................................ 3-8 

3.3.5 SCONOx......................................................................................... 3-8 

3.3.6 Selective Catalytic Reduction........................................................ 3-8 

3.4 Step 2-Eliminate Technically Infeasible CO Options.............................. 3-9 

3.4.1 Dry Low-NOx Burners and Good Combustion Control ................ 3-9 

3.4.2 CO Oxidation Catalyst................................................................. 3-10 

3.4.3 SCONOx....................................................................................... 3-10 

3.5 Step 3-Rank Combined NOX and CO Control Technology 

Effectiveness.......................................................................................... 3-10 

3.6 Step 4-Evaluate Most Effective Combined NOX and CO Controls.......3-12 

3.6.1 SCONOx Energy Impacts ............................................................ 3-13 

3.6.2 SCONOx Environmental Impacts ................................................ 3-13 
JEA GEC CCCT Conversion Table of Contents 

149588 TC-2 

3.6.3 SCR Energy Impacts.................................................................... 3-14 

3.6.4 SCR Environmental Impacts........................................................ 3-14 

3.6.5 Oxidation Catalyst Energy Impacts ............................................. 3-15 

3.6.6 Oxidation Catalyst Environmental Impacts................................. 3-15 

3.6.7 Economic Impacts for SCR (2.0 ppmvd )/ Oxidation 

Catalyst Versus SCONOX........................................................ 3-16 

3.6.7.1 Capital Costs for SCR (2.0 ppmvd) / Oxidation Catalyst 

and SCONOx. .......................................................................... 3-16 

3.6.7.2 Operating Costs for SCR/Oxidation Catalyst Versus 

SCONOx. ................................................................................. 3-19 

3.6.7.3 Total Annualized Costs for SCR (2 ppmvd) / Oxidation 

Catalyst Versus SCONOx........................................................ 3-20 

3.6.7.4 Conclusions............................................................................... 3-20 

3.7 Step 4-Evaluate Most Effective NOX Controls......................................3-22 

3.7.1 Economic Impacts for SCR ......................................................... 3-22 

3.7.2 Economic Impacts for SCR (2.0 ppmvd NOX) System ............... 3-22 

3.8 Step 4-Evaluate Most Effective CO Controls........................................ 3-25 

3.8.1 Economic Impacts for Oxidation Catalyst................................... 3-25 

3.8.2 Capital Cost for Oxidation Catalyst............................................. 3-25 

3.8.3 Operating Costs for Oxidation Catalyst....................................... 3-25 

3.8.4 Total Annualized Costs for Oxidation Catalyst........................... 3-26 

Step 5-Select NOX BACT ..................................................................................3-29 

3.9 Step 5-Select CO BACT ........................................................................ 3-29 

4.0 GEC Units 1 and 2 CCCTs PM/PM10 BACT Analysis ....................................... 4-1 

5.0 GEC Units 1 and 2 CCCTs SO2 BACT Analysis................................................ 5-1 

6.0 GEC Units 1 and 2 CCCTs H2SO4 BACT Analysis............................................ 6-1 

7.0 GEC Units 1 and 2 CCCTs Cooling Tower......................................................... 7-1 

Attachment 1: NOx Control Technology Review List................................................. A1-1 

Attachment 2: CO Control Technology Review List .................................................. A2-1 
JEA GEC CCCT Conversion Table of Contents 

149588 TC-3 

Contents (Continued) 

Tables

Table 1-1 BACT Determination Summary .............................................................. 1-5 

Table 2-1 Combustion Turbine Design Basis ......................................................... 2-4 

Table 2-2 Baseline Emission Rates for each CCCT -- GEC Units 1 or 2................ 2-5 

Table 2-3 GEC Units 1 or 2 CCCT Baseline Uncontrolled Emissions (per CT)..... 2-6 

Table 2-4 Project Economic Evaluation Criteria ..................................................... 2-7 

Table 3-1 Summary of Step 2--Eliminate Technically Infeasible Options.............. 3-9 

Table 3-2 Summary of Step 2--Eliminate Technically Infeasible CO Options ..... 3-10 

Table 3-3 Estimated NOx and CO Emissions from Alternate Control 

 Technologies for GEC Units 1 and 2 CCCTs (per CT)......................... 3-12 

Table 3-4 NOx/CO Combined Control Alternative Capital Cost ($) for Each

 CCCT (GEC Units 1 and 2)................................................................... 3-18 

Table 3-5 NOx/CO Combined Control Alternative Annualized Cost ($) for 

 Each CCCT (GEC Units 1 and 2).......................................................... 3-21 

Table 3-6 NOx Emission Control Alternative Capital Cost for GEC 

 Units 1 and 2 .......................................................................................... 3-23 

Table 3-7 NOx Emissions Control Annualized Cost ($) for Each CCCT 

 (GEC Units 1 and 2) .............................................................................. 3-24 

Table 3-8 CO Reduction System Capital Cost ($) for Each CCCT 

 (GEC Units 1 and 2) .............................................................................. 3-27 

Table 3-9 CO Control Annualized Cost ($) for Each CCCT 

 (GEC Units 1 and 2) .............................................................................. 3-28 

Table 3-10 GEC Units 1 and 2 CCCTs NOx BACT Determination ........................ 3-29 

Table 3-11 GEC Units 1 and 2 CCCTs CO BACT Determination.......................... 3-30 
JEA GEC CCCT Conversion Acronym List 

149588 AL-1 

Acronym List 

AQC Air Quality Control 

BACT Best Available Control Technology 

bhp Brake Horsepower 

bhph Brake Horsepower Hour 

Btu British Thermal Unit 

CAA Clean Air Act 

CEMS Continuous Emissions Monitoring System 

CFR Code of Federal Regulations 

CO Carbon Monoxide 

CCCT Combined Cycle Combustion Turbine 

CT Combustion Turbine 

CTG Combustion Turbine Generator 

DB Duct Burner 

FMPA Florida Municipal Power Agency 

FPL Florida Power and Light Company 

GEC Greenland Energy Center 

g/bhph Grams per Brake Horsepower Hour 

H2SO4 Sulfuric Acid Mist 

h/yr Hours per Year 

HHV Higher Heating Value 

HRSG Heat Recovery Steam Generator 

kW Kilowatt 

kWh Kilowatt Hour 

LAER Lowest Achievable Emission Rate 

Lb/h Pound per Hour 

L/G Liquid-To-Gas 

LNB Low NOx Burner 

MBtu Million British Thermal Unit 

MW Megawatt 

NESCAUM Northeast States for Coordinated Air Use Management 

NO2 Nitrogen Dioxide 

NOx Nitrogen Oxides 

NSPS New Source Performance Standard 

NSR New Source Review 

OAQPS Office of Air Quality Planning And Standards 
JEA GEC CCCT Conversion Acronym List 

149588 AL-2 

OEM Original Equipment Manufacturer 

Pb Lead 

PM/PM10 Particulate Matter/Particulate Matter Less than 10 Microns 

PSD Prevention of Significant Deterioration 

RACT Reasonably Available Control Technology 

RBLC RACT/BACT/LAER Clearinghouse 

SARA Superfund Amendments and Reauthorization Act of 1986 

SCCT Simple Cycle Combustion Turbine 

SCR Selective Catalytic Reduction 

SNCR Selective Noncatalytic Reduction 

SO2 Sulfur Dioxide 

SO3 Sulfur Trioxide 

STG Steam Tubine Generator 

tpy Tons per Year 

ULSFO Ultra-Low Sulfur Fuel Oil 

USEPA United States Environmental Protection Agency 

VOC Volatile Organic Compound 
1.0 Introduction and 

 JEA GEC CCCT Conversion Executive Summary 

149588 1-1 

1.0 Introduction and Executive Summary 

 JEA is proposing to convert the two simple cycle combustion turbines (CTs), 

Units 1 and 2, at the Greenland Energy Center (GEC) into a 2 x 1 combined cycle 

configuration. The GEC is located in southeastern Duval County, Florida and is 

currently undergoing construction permitting for the two simple cycle units. The 

combined cycle configuration will consist of the same two General Electric (GE) 7FA 

combustion turbines that are currently being permitted as simple cycle units, but will now 

each include a heat recovery steam generator (HRSG) with supplemental natural gasfired duct burners. The simple cycle functionality of each combustion turbine will be 

retained post-combined cycle conversion. Having already been subject to major source 

permitting and a BACT determination, the proposed simple cycle combustion turbine 

stacks will function as a bypass stack for simple cycle operation after the combined cycle 

conversion. The proposed conversion Project will include the combined cycle conversion 

of the simple cycle units and a mechanical draft cooling tower. There will be no other 

additions to the ancillary units already included as part of the simple cycle operations.

Table 1-1 lists a summary of the proposed BACT determinations and associated 

emission rates for Units 1 and 2 combined cycle combustion turbine (CCCT) operation with 

supplemental duct burners. GEC Units 1 and 2 CCCT, also referred to as the Project, will 

fire natural gas primarily, with up to 500 hours per turbine per year of ultra-low sulfur fuel 

oil (ULSFO, 0.0015 percent sulfur by weight) as a backup fuel. The duct burners will 

utilize only natural gas as the fuel source. Emissions for the BACT analysis are based on a 

per CCCT basis of firing natural gas for a maximum of 8,760 hours per year. Each unit will 

operate between 50 and 100 percent of full load. 

 It should be noted that the emissions for the BACT analysis are based on 

100 percent load conditions at ambient air temperature of 59° F and 60 percent relative 

humidity (60% RH) (hereinafter referred to as ISO conditions). 

The Project is classified as a New Source Review/Prevention of Significant 

Deterioration (NSR/PSD) major emission source, and as a result of the calculated 

potential emissions (See Section 2.4 of the air permit application document), is subject to 

a Best Available Control Technology (BACT) review for sulfur dioxide (SO2), nitrogen 

oxides (NOx), carbon monoxide (CO), particulate matter (PM)/PM10, and sulfuric acid 

mist (H2SO4). The Project is not subject to review for volatile organic compounds 

(VOC), lead (Pb), hydrogen sulfide (H2S), vinyl chloride, total fluorides, mercury, or 

total reduced sulfur compounds. 

As required under the NSR/PSD regulations, the BACT analysis presented herein 

employed a “top-down,” five-step analysis process to determine the appropriate emission 
1.0 Introduction and 

 JEA GEC CCCT Conversion Executive Summary 

149588 1-2 

control technologies and emissions limitations for the Project. The BACT analysis was 

conducted for the GEC Units 1 and 2 combined cycle conversion and the mechanical 

draft cooling tower. The BACT analysis was conducted in accordance with the United 

States Environmental Protection Agency’s (USEPA’s) recommended methodology: 

x Step 1--Identify All Control Technologies. 

x Step 2--Eliminate Technically Infeasible Options. 

x Step 3--Rank Remaining Control Technologies by Control Effectiveness. 

x Step 4--Evaluate Most Effective Controls. 

x Step 5--Select BACT. 

Step 1--Identify All Control Technologies 

 The first step in a “top-down” analysis is to identify all available control options 

for the emission unit in question. Identifying all the potential available control options 

consists of those air pollution control technologies or techniques with a practical potential 

for application to the emission unit and the regulated pollutant under evaluation. The 

potential available control technologies and techniques include lower emitting processes, 

practices, and post-combustion controls. Lower emitting practices can include fuel 

cleaning, treatment, or innovative fuel combustion techniques that are classified as precombustion controls. Post-combustion controls would be the various add-on controls for 

the pollutant being controlled. 

Step 2--Eliminate Technically Infeasible Options 

 The second step of the “top-down” analysis is to identify the technical feasibility 

of the control options identified in Step 1, which are evaluated with respect to sourcespecific factors. A control option that is determined to be technically infeasible is 

eliminated. “Technically infeasible” is defined as a clearly documented case of a control 

option that has technical difficulties that would preclude the successful use of the control 

option because of physical, chemical, and engineering principles. After completion of 

this step, technically infeasible options are then eliminated from the BACT review 

process.

 In Step 2, the control option is identified as technically feasible. A “technically 

feasible” control option is defined as a control technology that has been installed and 

operated successfully at a similar type of source of comparable size under review 

(demonstrated). If the control option cannot be demonstrated, the analysis gets more 

involved. When determining if a control option has not been demonstrated, two key 

concepts need to be analyzed. The first concept, availability, is defined as technology 

that can be obtained through commercial channels or is otherwise available within the 

common sense meaning of the term. A technology that is being offered commercially by 
1.0 Introduction and 

 JEA GEC CCCT Conversion Executive Summary 

149588 1-3 

vendors or is in licensing and commercial demonstration is deemed an available 

technology. Technologies that are in development (concept stage/research and patenting) 

and testing stages (bench-scale/laboratory testing/pilot scale testing) are classified as not 

available. The second concept, “applicability,” is defined as an available control option 

that can reasonably be installed and operated on the source type under consideration. In 

summary, the commercially available technology is applicable if it has been previously 

installed and operated at a similar type of source of comparable size, or a source with 

similar gas stream characteristics. 

Step 3--Rank Remaining Control Technologies by Control Effectiveness 

 The third step of the “top-down” analysis is to rank all the remaining control 

alternatives not eliminated in Step 2, based on control effectiveness for the pollutant 

under review. If the BACT analysis proposes the top control alternative, there would be 

no need to provide cost and other detailed information in regard to other control options 

that would provide less control. 

Step 4--Evaluate Most Effective Controls 

 Once the control effectiveness is established in Step 3 for all the feasible control 

technologies identified in Step 2, additional evaluations of each technology are performed 

to make a BACT determination in Step 4. The impacts of the technology implementation 

on the viability of the control technology at the source are evaluated. The evaluation 

process of these impacts is also known as “Impact Analysis.” The following impact 

analyses are performed: 

x Energy evaluation of alternatives. 

x Environmental evaluation of alternatives. 

x Economic evaluation of alternatives. 

The first impact analysis addresses the energy evaluation of alternatives. The 

energy impact of each evaluated control technology is the energy penalty or benefit 

resulting from the operation of the control technology at the source. Direct energy 

impacts include such items as the auxiliary power consumption of the control technology 

and the additional draft system power consumption to overcome the additional system 

resistance of the control technology in the flue gas flow path. The costs of these energy 

impacts are defined either in additional fuel costs or the cost of lost generation, which 

impacts the cost-effectiveness of the control technology.

The second impact analysis addresses the environmental evaluation of 

alternatives. Non-air quality environmental impacts are evaluated to determine the cost 

to mitigate the environmental impacts caused by the operation of a control technology. 
1.0 Introduction and 

 JEA GEC CCCT Conversion Executive Summary 

149588 1-4 

Examples of non-air quality environmental impacts include polluted water discharge and 

solids or waste generation. The procedure for conducting this analysis should be based 

on a consideration of site-specific circumstances. 

The third and final impact analysis addresses the economic evaluation of 

alternatives. This analysis is performed to indicate the cost to purchase and operate the 

control technology. The capital and operating/annual cost is estimated based on the 

established design parameters. Information for the design parameters should be obtained 

from established sources that can be referenced. However, documented assumptions can 

be made in the absence of references for the design parameters. The estimated cost of 

control is represented as an annualized cost ($/year) and, with the estimated quantity of 

pollutant removed (tons/year), the cost-effectiveness ($/tons) of the control technology is 

determined. The cost-effectiveness describes the potential to achieve the required 

emissions reduction in the most economical way. The cost-effectiveness compares the 

potential technologies on an economical basis. Two types of cost-effectiveness are 

considered in a BACT analysis: average and incremental cost-effectiveness. Average 

cost-effectiveness is defined as the total annualized cost of control divided by the annual 

quantity of pollutant removed for each control technology. The incremental costeffectiveness is a comparison of the cost and performance level of a control technology to 

the next most stringent option. It has a unit of (dollars/incremental ton removed). The 

incremental cost-effectiveness is a good measure of viability when comparing 

technologies that have similar removal efficiencies. 

Step 5--Select BACT 

 The highest ranked control technology that is not eliminated in Step 4 is proposed 

as BACT for the pollutant and emission unit under review. 

 As summarized in Table 1-1, the aforementioned BACT analysis process resulted 

in the following control technology and emissions level determinations for the Project’s 

affected air emissions sources and pollutants. The ton per year emissions presented in 

Appendix C are proposed as BACT emission caps. 
1.0 Introduction and 

 JEA GEC CCCT Conversion Executive Summary 

149588 1-5 

Table 1-1 

BACT Determination Summary 

Emission Unit: Nominal 547 MW and 524 MW Net CCCT Units 1 and 2 (2 X 1 F-Class PG7241FA ) when 

firing natural gas and ULSFO, respectively 

Pollutant Control Technology Emission Basis 

Compliance 

Method 

CEMS Avg. 

Period

NOx DLN/SCR (for 

natural gas 

combustion) 

WI/SCR (for ULSFO 

combustion) 

Natural Gas: 2.0 ppmvd @ 15% 

O2

ULSFO: 8.0 ppmvd @ 15% O2

Stack Test, 3-Run 

Avg. 

24-hr block 

CO Good Combustion 

Controls 

Natural Gas: 7.6 ppmvd @ 15% 

O2 with DBs; 4.1 ppmvd @ 15% 

O2 w/o DBs; 

ULSFO: 8.0 ppmvd @ 15% O2

Stack Test, 3-Run 

Avg. 

24-hr block 

PM/PM10 Natural Gas (2.0 gr 

S/100 SCF) 

ULSFO (0.0015% S) 

Good Combustion 

Practices

10% Opacity USEPA Method 9 

Fuel Sulfur Records 

NA

SO2 Natural Gas (2.0 gr 

S/100 SCF) 

ULSFO (0.0015% S) 

NA Fuel Sulfur Records NA 

H2SO4 Natural Gas (2.0 gr 

S/100 SCF) 

ULSFO (0.0015% S) 

NA Fuel Sulfur Records NA 

Emission Unit: Cooling Tower 

Pollutant Control Technology Emission Basis 

PM/PM10 Drift Eliminators 0.0005% drift rate 

CEMS = Continuous Emissions Monitoring System. 

SCR = Selective Catalytic Reduction. 

ULSFO = Ultra-low sulfur fuel oil 
JEA GEC CCCT Conversion 2.0 BACT Analysis Basis 

149588 2-1 

2.0 BACT Analysis Basis 

 This section describes the basis of the Project’s BACT analysis, converting the 

two simple cycle CTs at the GEC into a 2 x 1 combined cycle configuration. Information 

provided in this section also includes details on the BACT methodology and approach, as 

well as the parameters and factors used in developing the analysis. The BACT analysis 

for GEC Units 1 and 2 CCCT operation is based on certain regulatory requirements and 

project assumptions. The following is a summary of the requirements and assumptions 

for which this BACT analysis is based. 

2.1 Regulatory Basis 

 The Clean Air Act Amendments of 1990 (CAA) established revised conditions 

for the approval of pre-construction permit applications under the PSD program. One of 

these requirements is that BACT be installed to control all pollutants regulated under the 

Act that are emitted in significant amounts from new major sources or major 

modifications.

 The applicable state regulations governing this process define BACT in Rule 62-

210.200(37), F.A.C. as:

“Best Available Control Technology” or “BACT” – An emission limitation, 

including a visible emissions standard, based on the maximum degree of 

reduction of each pollutant emitted which the Department, on a case by case 

basis, taking into account energy, environmental and economic impacts, and 

other costs, determines is achievable through application of production 

processes, and available methods, systems and techniques (including fuel 

cleaning or treatment or innovative fuel combustion techniques) for control of 

each such pollutant.”

However, BACT cannot be less stringent than the emissions limits established by 

an applicable New Source Performance Standard (NSPS). 

 To bring consistency to the BACT process, the USEPA provides as guidance to 

the states the use of a “top-down” approach to BACT determinations, which utilizes the 

five-step analysis process previously summarized. In practice, the top-down BACT 

analysis determines the most stringent control technology and emissions limitation 

combination available for a similar source or source category of emission units. At the 

head of the list in the top-down analysis methodology are the control technologies and 

emissions limits that represent the Lowest Achievable Emission Rate (LAER) 

determinations, which, under NSR/PSD regulations, represent the most effective control 

alternative that must be considered under the BACT analysis process.
JEA GEC CCCT Conversion 2.0 BACT Analysis Basis 

149588 2-2 

 The following informational databases, clearinghouses, and documents were used 

to identify recent control technology determinations for similar source categories and 

emission units for this BACT analysis: 

x USEPA’s RACT/BACT/LAER Clearinghouse (RBLC). 

x USEPA’s National Combustion Turbine Projects Spreadsheet. 

x Federal/State/Local new source review permits, permit applications, and 

associated inspection/test reports. 

x Technical journals, newsletters, and reports. 

x Information from air quality control (AQC) technology suppliers. 

x Engineering design on other projects. 

 If it cannot be shown that the top level of control is infeasible (for a similar type 

source and fuel category) on the basis of technical, economic, energy, or environmental 

impact considerations, then that level of control must be declared to represent BACT for 

the respective pollutant and air emissions source. Alternatively, upon proper 

documentation that the top level of control is not feasible for a specific unit and pollutant 

based on a site- and project-specific consideration of the aforementioned screening 

criteria (e.g., technical, economic, energy, and environmental considerations), then the 

next most stringent level of control is identified and similarly evaluated. This process 

continues until the BACT level under consideration cannot be eliminated by any 

technical, economic, energy, or environmental consideration. BACT cannot be 

determined to be less stringent than the emissions limits established by an applicable 

New Source Performance Standard (NSPS) for the affected air emissions source. 

2.1.1 Applicable NSPS Emissions Limits 

 As previously discussed, a proposed BACT emissions limit, established in 

accordance with the top-down, five-step process, cannot be determined to be less 

stringent than the emissions limit(s) established by the applicable NSPS regulations 

found in 40 CFR Part 60. The following NSPS emissions limitations are applicable to the 

Project’s air emissions sources. 

2.1.1.1 NSPS Subpart KKKK – Standards of Performance for Stationary 

Combustion Turbines. As new stationary CCCTs, GEC Units 1 and 2 will be subject 

to NSPS Subpart KKKK. Additionally, because the Project is subject to Subpart KKKK, 

it is not subject to Subpart GG or Subpart Da for the CT and HRSG duct burners, 

respectively. Applicable NSPS Subpart KKKK emissions limitations for the Project are 

as follows: 
JEA GEC CCCT Conversion 2.0 BACT Analysis Basis 

149588 2-3 

x NOx--15 ppm at 15 percent O2 or 54 ng/J of useful output (0.43 lb/MWh) – new 

turbines firing natural gas with > 850 MBtu/hr heat input. 

x NOx--42 ppm at 15 percent O2 or 160 ng/J of useful output (1.3 lb/MWh) – new 

turbines firing fuel oil with > 850 MBtu/hr heat input. 

x NOx--96 ppm at 15 percent O2 or 590 ng/J of useful output (4.7 lb/MWh) – 

turbines operating at less than 75 percent of peak load – turbines with > 30 MW 

output.

x SO2--The rule includes a fuel emission standard or a fuel sulfur standard 

equivalent to potential SO2 emissions of 0.060 lb SO2/MBtu.

2.2 Unit Operations and Baseline Emissions Basis 

 GEC Units 1 and 2 CCCT will fire natural gas primarily, with up to 500 hours per 

turbine per year of ULSFO as a backup fuel. The duct burners will utilize only natural gas 

as the fuel source. Emissions for the BACT analysis are based on a per CCCT basis firing 

natural gas a maximum of 8,760 hours per year. The unit will operate between 50 and 

100 percent of full load.

2.2.1 GEC Units 1 and 2 CCCT 

 Table 2-1 presents the BACT design basis for the Project’s CCCT. Table 2-2 

shows the baseline emission rates for each CCCT at 100 percent base load at the ISO inlet 

air temperature of 59° F for natural gas and sixty percent relative humidity (60% RH), 

hereinafter referred to as ISO conditions. The emissions shown in Table 2-2 are based on 

the use of dry low NOx burners during natural gas firing with the operation of the natural gas 

fired duct burners at 100 percent load. The duct burners will fire only natural gas. The 

lb/MBtu values are based on the higher heating value (HHV) of the expected fuel to be fired 

and are based on the combined heat input to the combustion turbine and the duct burners. 

Table 2-3 shows the uncontrolled emissions for each CCCT. 

 GEC Units 1 and 2 CCCT will fire natural gas 8,760 hours per year with up to 500 

hours firing ultra-low sulfur fuel oil (ULSFO) with 0.0015 percent sulfur by weight as a 

backup fuel. However, consistent with previous applications and determinations for 

combined cycles with very limited backup fuel capability, this BACT analysis is based on 

100 percent operation on natural gas. 
JEA GEC CCCT Conversion 2.0 BACT Analysis Basis 

149588 2-4 

Table 2-1 

Combustion Turbine Design Basis(1) 

Size Nominal 547 MW and 524 MW net 

CCCT Units 1 and 2 (2 X 1 F-Class 

PG7241FA ) when firing natural 

gas and ULSFO, respectively 

Combustion Turbine Generator (CTG) 

 Heat Input 1,778.3 MBtu/h(1)

HRSG Duct Burners 

 Heat Input 188.6 MBtu/h(1)

Operating Hours 8,760 h/yr 

Fuel Natural Gas 

(1)Based on the Higher Heating Value when firing Natural Gas, 100% Load, 

Duct Firing, at ISO conditions. 
JEA GEC CCCT Conversion 2.0 BACT Analysis Basis 

149588 2-5 

Table 2-2 

Baseline Emission Rates for each CCCT -- GEC Units 1 or 2 

Emission Parameter 

Units 1a

 or 2a

Natural Gas, 100% Load,

Duct Firing, at ISO Conditions 

NOx , ppmvd at 15% O2 10.3 

NOx, lb/h 72.7 

NOx, lb/MBtu (HHV) 0.0369 

CO, ppmvd at 15% O2 7.6 

CO, lb/h 32.7 

CO, lb/MBtu (HHV) 0.0166 

PM/PM10 (front and back), lb/hb 29.1

PM/PM10 (front and back), lb/MBtu (HHV)b 0.0148

SO2, lb/hc 8.01

SO2, lb/MBtu (HHV)c 0.0041

H2SO4, lb/hb 4.88

H2SO4, lb/MBtub 0.00274

a

Emissions are based on firing natural gas in the CT and HRSG duct burners at 

100 percent of base load at ISO Conditions. 

b

PM/PM10 and H2SO4 values include the affects of 20 percent SO2 oxidation in the 

CT and 10 percent SO2 oxidation in the duct burners. 

c

SO2 values include the effects of 3 percent SO2 oxidation in the Selective Catalytic 

Reduction System. Based on a natural gas sulfur content of 2 grains/100 scf 
JEA GEC CCCT Conversion 2.0 BACT Analysis Basis 

149588 2-6 

Table 2-3 

GEC Units 1 or 2 CCCT Baseline Uncontrolled Emissions 

(per CT) 

Emission Parameter Natural Gas Firinga

NOx, tons per year (tpy) 318.43 

CO, tpy 143.23 

PM/PM10 (front and back), tpy 127.46

SO2, tpy 35.08

H2SO4, tpy 21.37

a

GEC Units 1 or 2 CCCT emissions are based on firing natural gas in the CT and HRSG 

duct burners at 100 percent of base load at ISO Conditions.

2.3 Economic Basis 

The economic analyses used to determine the capital and annualized costs of the 

control technologies were based on USEPA methodologies shown in the USEPA “Best 

Available Control Technology Draft Guidance Document” (October 1990), “Top Down” 

Best Available Control Technology Guidance Document” (March 1990), The Office of 

Air Quality Planning and Standards (OAQPS) Control Cost Manual (February 1996, 

Fifth Edition), internal owner cost factors, and vendor budgetary cost quotes. 

 Table 2-11 lists the economic criteria used in the analysis of BACT alternatives. 

The capital recovery factor was calculated based on the present worth discount rate and 

economic life of the equipment or the assumed catalyst life. 
JEA GEC CCCT Conversion 2.0 BACT Analysis Basis 

149588 2-7 

Table 2-4 

Project Economic Evaluation Criteria 

Economic Parameters Value 

Contingency, percent 10 

Escalation, percent 2.5 

Present Worth Discount Rate, percent 5.0 

Economic Life, years 25 

Capital Recovery Factor, (25 years) 0.07095 

SCR Catalyst Life, years 3 

SCONOx Catalyst Life, years 5 

CO Catalyst Life, years 6 

Catalyst Capital Recovery Factor (3 years) 0.3672 

Catalyst Capital Recovery Factor (6 years) 0.1970 

SCONOx Catalyst Capital Recovery Factor (5 years) 0.2310 

Labor Cost, $/man-hour (2008) 53 

Natural Gas Cost, $/MBtu (2008) 8.10 

Aqueous Ammonia Cost, $/ton (2008 ) 194 

Energy Cost, $/kWh (2008) 0.063 

Sales Tax, percent N/A 
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3.0 GEC Units 1 and 2 NOx and CO BACT Analysis 

 This section presents the top-down, five-step BACT process used to evaluate and 

determine the Project’s NOx and CO emissions limits for GEC Units 1 or 2 CCCT. As 

this analysis will demonstrate, the proposed NOx BACT was determined to be the use of 

selective catalytic reduction to achieve an emission limit of 2 ppmvd at 15 percent O2

while firing natural gas and 8.0 ppmvd at 15 percent O2 while firing ultra-low sulfur fuel 

oil. The proposed CO BACT was determined to be the use of good combustion controls 

while firing natural gas or ultra-low sulfur fuel oil with less than 0.0015 percent sulfur by 

weight.

3.1 Step 1--Identify All NOX Control Technologies 

 The first step in a top-down analysis, according to the EPA’s October 1990, Draft 

New Source Review Workshop Manual, is to identify all available control options. 

Available control options are those air pollution control technologies or techniques with a 

practical potential for application to the emission unit and the NOx emissions limit that is 

being evaluated. The results of this search for all combined-cycle combustion turbines 

are listed in Attachment 1: NOX Control Technology Review List.

 NOx is defined as the combination of nitrogen oxide (NO) and nitrogen dioxide 

(NO2). Typically, the NOx that is formed in combustion turbines consists of 60 percent 

NO, with the balance occurring as NO2. NOx emissions formed through the oxidation of 

the fuel bound nitrogen are called fuel NOx. NOx emissions formed through the 

oxidation of a portion of the nitrogen contained in the combustion air are called thermal 

NOx and are a function of combustion temperature. NOx production in a gas turbine 

combustor occurs predominantly within the flame zone, where localized high 

temperatures sustain the NOx-forming reactions. The overall average gas temperature 

required to drive the turbine is well below the flame temperature, but the flame region is 

required to achieve stable combustion. 

 Nitrogen oxide control methods may be divided into two categories: in-combustor 

NOx formation control and post-combustion emission reduction. An in-combustor NOx

formation control process reduces the quantity of NOx formed in the combustion process. 

A post-combustion technology reduces the NOx emissions in the flue gas stream after the 

NOx has been formed in the combustion process. Both of these methods may be used 

alone or in combination to achieve the various degrees of NOx emissions required. The 

six different types of emission controls reviewed by this BACT analysis are as noted 

below.

x In-Combustor Type: 
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 Water/Steam Injection. 

 Dry Low-NOx (DLN) Burners. 

 Xonon.

x Post-Combustion Type: 

 Selective Non-Catalytic Reduction (SNCR). 

 SCONOx.

 Selective Catalytic Reduction (SCR). 

The rationale behind whether the above technologies are evaluated as NOx control 

for BACT is included in the following subsections. 

3.1.1 Water or Steam Injection 

 NOx emissions from GEC Units 1 or 2 CCCT can be controlled by either water or 

steam injection. This type of control injects water or steam into the primary combustion 

zone with the fuel. The water or steam serves to reduce NOx formation by reducing the 

peak flame temperature. The degree of reduction in NOx formation is proportional to the 

amount of water injected into the combustion turbine. A limit exists, however, on the 

amount of water that can be injected into the system before reliability of the combustion 

turbine is seriously degraded and operational life is affected. This type of control can 

also be counterproductive with regard to CO and VOC emissions that are formed as a 

result of incomplete combustion. Furthermore, this in-combustor control technology is 

typically used when firing fuel oil, or on much smaller units. 

3.1.2 Dry Low-NOx Burners 

 NOx formation can be limited by lowering combustion temperatures and by 

staging combustion (i.e., creating a reducing atmosphere followed by an oxidizing 

atmosphere). The use of dry low-NOx (DLN) burners as a way to reduce flame 

temperature is one common NOx control method. These combustor designs are called 

DLN burners because, when firing natural gas, injecting water into the combustion 

chamber is not necessary to achieve low NOx emissions. Most industry gas turbine 

manufacturers today have developed this type of lean premix combustion system as the 

state of the art for NOx controls in combustion turbines. This method is exclusively 

utilized when firing natural gas.

3.1.3 XONON 

 Another form of in-combustor control is XONON. This technology, developed 

by Catalytica Combustion Systems, is designed to avoid the high temperatures created in 

conventional combustors. The XONON combustor operates below 2,700° F at full 

power generation, which significantly reduces NOx emissions without raising, and 
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possibly even lowering, emissions of CO and unburned hydrocarbons. XONON uses a 

proprietary flameless process in which fuel and air react on the surface of a catalyst in the 

turbine combustor to produce energy in the form of hot gases, which drive the turbine. 

This emerging technology is being commercialized by several joint ventures that 

Catalytica has with turbine manufacturers. 

3.1.4 Selective Non-Catalytic Reduction 

 Selective non-catalytic reduction (SNCR) is one method of post-combustion 

control. SNCR selectively reduces NOx into nitrogen and water vapor by reacting the 

flue gas with a reagent. SNCR systems can use either ammonia (Thermal DeNOx) or 

urea (NOxOUT) as reagents. 

The SNCR system is dependent upon the reagent injector location and 

temperature to achieve proper reagent/flue gas mixing for maximum NOx reduction. 

SNCR systems require a fairly narrow temperature range for reagent injection in order to 

achieve a specific NOx reduction efficiency. The optimum temperature range for 

injection of ammonia or urea is 1,550° to 1,900° F. The NOx reduction efficiency of an 

SNCR system decreases rapidly at temperatures outside the optimum temperature 

window. Injection of reagent below this temperature window results in excessive 

ammonia emissions (ammonia slip). Injection of reagent above the temperature window 

results in increased NOx emissions. 

 The exhaust temperature at the exit of the combustion turbine is between 1074o to 

1200o F. Therefore, the exhaust temperature is less than the optimum temperature range 

for the application of this technology. It is not technically feasible to apply this 

technology to this Project and it will be eliminated from further evaluation in this BACT 

analysis. 

3.1.5 SCONOx

 A second, post-combustion technology from EmeraChem, LLC is EMX

TM

(SCONOx), which utilizes a coated oxidation catalyst to remove both NOx and CO 

without a reagent such as ammonia. EmeraChem purchased SCONOX from Goal Line 

Environmental Technologies and ABB Alstom Power. 

The SCONOx system utilizes hydrogen (H2) (which is created by reforming 

natural gas) as the basis for a proprietary catalyst regeneration process. The system 

consists of a platinum-based catalyst coated with potassium carbonate (K2CO3) to oxidize 

both NOx and CO, thereby reducing total plant emissions. CO emissions are decreased 

by the oxidation of CO to carbon dioxide (CO2). The catalyst is installed in the flue gas 

at a point where the temperature is between 300° to 700° F. EmeraChem guarantees the 
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performance of the catalyst for 3 years. When the catalyst reaches the end of its service 

life, it can be recycled to recover the precious metal contained within the catalyst. 

 The SCONOx catalyst is very susceptible to fouling by sulfur in the flue gas. The 

impact of sulfur can be minimized by a sulfur absorption SCOSOx catalyst. The SCOSOx

catalyst is located upstream of the SCONOx catalyst. The SO2 is oxidized to sulfur 

trioxide (SO3) by the SCOSOx catalyst. The SO3 is then deposited on the catalyst and 

removed from the catalyst when it is regenerated. The SCOSOx catalyst is regenerated 

along with the SCONOx catalyst.

 The SCONOx catalyst will require that it be re-coated or “washed” every 6 

months to 1 year. The frequency of washing is dependent on the sulfur content in the fuel 

and the effectiveness of the SCOSOx catalyst. The "washing" consists of removing the 

catalyst modules from the unit and placing each module in a potassium carbonate reagent 

tank, which is the active ingredient of the catalyst. The SCOSOx catalyst will also 

require washing, but due to limited operating experience with the SCOSOx catalyst, it is 

uncertain how often this will be required. However, it is expected that the SCOSOx

catalyst will require annual washing. 

 The current SCONOx catalyst technology is in its second generation. The first 

generation operated for approximately 10 months on a small LM-2500 combined cycle 

combustion turbine unit before the SCONOx system was taken out of service because of 

poor regeneration gas distribution.

 The USEPA has stated its concerns (November 19, 1999 letter from USEPA 

Region I) with the technical uncertainties of the SCONOx system and was apprehensive 

about applying SCONOx technology to large combined cycle turbines that burn primarily 

natural gas. The combustion turbine proposed for this project is approximately 170 MW, 

which is outside the operating range (32 MW) of the SCONOx system currently operating 

at the Federal Cold Storage Cogeneration facility in California. 

3.1.6 Selective Catalytic Reduction 

 Another post-combustion method of NOx control is selective catalytic reduction 

(SCR). SCR systems have been used quite extensively in CTG/HRSG projects for the 

past ten years. The SCR process combines vaporized ammonia with NOx in the presence 

of a catalyst to form nitrogen and water. The vaporized ammonia is injected into the 

combustion turbine exhaust gases prior to passage through the catalyst bed. The use of 

SCR results in small levels of ammonia emissions (ammonia slip). As the catalyst 

degrades ammonia slip will increase to approximately 5 -10 ppmvd (dependent on system 

design), ultimately requiring catalyst replacement. 

 The performance and effectiveness of SCR systems are directly dependent on the 

temperature of the flue gas when it passes through the catalyst. Vanadium/titanium 

catalysts have been used on the majority of SCR system installations. The flue gas 
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temperature range for optimum SCR operation using a conventional vanadium/titanium 

catalyst is approximately 600 to 750° F. At temperatures above 850° F permanent 

damage to the vanadium/titanium catalyst occurs. For GEC Units 1 and 2 CCCTs, the 

flue gas temperature in the HRSG of the CTG/HRSG would typically range from 600° F 

to 800° F. Accordingly, a vanadium/ titanium catalyst can be installed for GEC Units 1 

and 2 CCCTs. Therefore, the vanadium/titanium-based catalyst will be evaluated further 

for these units. 

Because the SCR system requires the regulation of ammonia injection based on 

the NOx emission monitors, the accuracy of the emission reading directly influences the 

amount of actual error in the ammonia injection rate. Therefore, erroneous emission 

readings can result in excess ammonia levels even when the actual NOx value is below 

the permitted value. This may result in excessive ammonia “slip” being discharged to the 

atmosphere with little or no improvement in NOx emissions. Reduction of the NOx

emission concentrations to levels below 2.0 ppmvd also raises concerns with the 

additional ammonia that may be emitted to obtain further reduced levels. Although SCR 

catalyst vendors have indicated that ammonia emissions will not be increased, these 

vendors are not solely responsible for guaranteeing ammonia slip. The distribution of the 

ammonia in the duct is the key parameter since localized maldistribution of the ammonia 

will cause the ammonia to pass through the catalyst without reacting with the NOx. The 

proper distribution of the gas and ammonia is difficult to obtain when both reactants, NOx

and NH3, are at such low concentrations. This distribution would be even more difficult, 

if not impossible, to maintain during transient operations, such as load changes, when 

flow patterns are changing. Changes in operation from one stable load to another stable 

load may present problems since the flow patterns and the loads may be different. Since 

the catalyst vendors are not responsible for the ammonia distribution, they typically limit 

their guarantees to some distribution level. Such conditions to reduce NOx emissions to 

levels below 2.0 ppmvd that increase ammonia emissions will be counter productive to 

the reduction of overall emissions since ammonia presents an emission problem itself. 

 This SCR method of post-combustion control will be considered in this BACT 

analysis to control NOx emissions. 

3.2 Step 1--Identify All CO Control Technologies 

The first step in a top-down analysis, according to the USEPA’s October 1990, 

Draft New Source Review Workshop Manual, is to identify all available control options. 

Available control options are those air pollution control technologies or techniques with a 

practical potential for application to the emission unit and the CO emission limit that is 

being evaluated. The results of this search for all combined-cycle combustion turbines 

are listed in Attachment 2: CO Control Technology Review List.
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Typically, measures taken to minimize the formation of NOx during combustion 

inhibit complete combustion, which increase the emissions of CO. Carbon monoxide is 

formed during the combustion process due to incomplete oxidation of the carbon 

contained in the fuel. CO formation is limited by ensuring complete and efficient 

combustion of the fuel in the combustion turbine. High combustion temperatures, 

adequate excess air, and good air/fuel mixing during combustion minimize CO 

emissions. 

 Carbon monoxide control methods may be divided into two categories: incombustor CO formation control and post-combustion emission reduction. An incombustor CO formation control process minimizes the quantity of CO formed in the 

combustion process. A post-combustion technology reduces the CO emissions in the flue 

gas stream after the CO has been formed in the combustion process. Both of these 

methods may be used alone or in combination to achieve the various degrees of CO 

emissions required. The three different types of emission controls reviewed by this 

BACT analysis are as noted below. 

x In-Combustor Type: 

 Dry Low-NOx (DLN) Burners. 

x Post-Combustion Type: 

 Oxidation Catalyst. 

 SCONOx.

The rationale behind whether the above technologies are evaluated as CO control 

for BACT is included in the following subsections. 

3.2.1 Dry Low-NOx Burners and Good Combustion Control 

 The development of good combustion practice improvements with state of the art 

DLN burners has reduced CO emissions as compared to those previously obtained by the 

use of water injection as the main NOx control method. These improved combustion 

characteristics have allowed minimization of CO emissions without sacrificing NOx

control performance. For this reason, the use of low NOx burners that use good 

combustion practices is the standard method of also controlling CO emissions. 

3.2.2 CO Oxidation Catalyst 

 A current CO reduction technology available that will not impact NOx emissions 

is the use of an oxidation catalyst to convert the CO to CO2. The oxidation catalyst is 

typically a precious metal catalyst. None of the catalyst components are considered 

toxic. No reagent injection is necessary and oxidizing catalysts, dependent on the 

uncontrolled emission level, are capable of reducing a significant amount of the CO 
3.0 GEC Units 1 and 2 

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emissions. A 73.7 percent CO reduction rate (i.e. 7.6 ppm to 2.0 ppm) has been assumed 

for this BACT analysis. 

3.2.3 SCONOx

 Another CO control technology that was previously discussed for NOx control is 

the SCONOx process. The SCONOx system reduces CO emissions by oxidizing the CO 

to CO2. The demonstrated application for this technology is currently limited to 

combined cycle combustion turbine units under 40 MW. The combustion turbine 

proposed for this project is approximately 170 MW, which is outside the operating range 

(32 MW) of the SCONOx system currently operating at the Federal Cold Storage 

Cogeneration facility in California.

3.3 Step 2--Eliminate Technically Infeasible NOX Options 

Step 2 of the BACT analysis involves the evaluation of all the identified available 

control technologies in Step 1 of the BACT analysis to determine their technical 

feasibility. A control technology is technically feasible if it has been previously installed 

and operated successfully at a similar type of source of comparable size, or there is 

technical agreement that the technology can be applied to the source. Available and 

applicable are the two terms used to define the technical feasibility of a control 

technology. The following subsections review the control technologies identified in Step 

1 of the NOX BACT analysis and determine if they are technically feasible. Table 3-1 

summarizes the evaluation of the technically feasible NOX options. 

3.3.1 Water or Steam Injection 

 Water or steam injection can be an effective NOX control method for a turbine 

burning natural gas or fuel oil. However, demineralized water must be used and 

additional capital cost is required because an onsite demineralized system must be built 

and the annual operation of this system can be a significant expense in the unit operation. 

The development of dry low-NOx burners has replaced the use of wet controls, except for 

certain cases, such as oil firing. New dry low-NOX burners can achieve lower levels of 

NOX compared to wet controls. Since GEC Units 1 and 2 CCCTs will fire natural gas as 

the primary fuel with ULSFO as a backup, water injection will only be used during 

ULSFO firing and will not be evaluated for the primary operating case of natural gas in 

this BACT analysis. 
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3.3.2 Dry Low-NOx Burners 

 Dry low-NOx burners are a demonstrated technology of controlling NOX

emissions from a combined-cycle combustion turbine and commercially available from 

several vendors. Dry low-NOX burners are considered technically feasible and will be 

considered further.

3.3.3 XONON 

 Although XONON technology has been applied to small turbines, such as a 

Kawasaki M1A-13X (1.5 MW) combustion turbine, it has not been applied to utility size 

combustion turbines such as proposed for GEC Units 1 and 2 CCCTs. It is expected that 

application of this technology to utility size combustion turbines will require a period of 

“scale up” and testing before it can be determined that this technology can demonstrate in 

practice a given NOx emission limit. Because this technology has not been applied to 

utility size combustion turbines firing natural gas, it is not considered to be technically 

feasible for GEC Units 1 and 2 CCCTs. As such, this method of combustion control will 

be eliminated from further evaluation for control of NOx emissions in this BACT 

analysis. 

3.3.4 Selective Non-Catalytic Reduction 

Selective non-catalytic reduction (SNCR) optimum temperature range for 

injection of ammonia or urea is 1,550° to 1,900° F. The exhaust temperature at the exit 

of the combustion turbine is between 1074o to 1200o F. Therefore, the exhaust 

temperature is less than the optimum temperature range for the application of this 

technology. It is not technically feasible to apply this technology to this Project and it 

will be eliminated from further evaluation in this BACT analysis. 

3.3.5 SCONOx

 The application of this technology is currently limited to natural gas combined 

cycle combustion turbine units under 40 MW. However, EmeraChem, LLC is EMX

TM

(SCONOx) offers their product for GE 7FAs which makes it available. In addition, 

SCONOX has not been previously installed and operated at a similar type and size of 

turbine. However, in the interest of providing a complete technology analysis, SCONOx

will be evaluated in the BACT for NOx control. 

3.3.6 Selective Catalytic Reduction 

 Selective Catalyst Reduction (SCR) systems are a demonstrated technology of 

controlling NOX emissions from a combined-cycle combustion turbine and commercially 
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available from several vendors. SCR systems are considered technically feasible and will 

be considered further.

Table 3-1 

Summary of Step 2--Eliminate Technically Infeasible Options 

Technically Feasible (Yes/No) 

Technology Alternative Available Applicable 

Water or Steam Injection Yes No – Wet injection has limited NOX

removal. Not a primary control 

technology for natural gas fired 

turbines. 

Dry Low-NOX Burners Yes Yes 

XONON Yes No – There are no documented 

installations on utility sized 

combustion turbines firing natural gas. 

SNCR Yes No – The exhaust temperature of the 

combustion turbine is less than the 

SNCR’s optimum temperature range. 

SCONOX Yes Yes 

SCR Yes Yes 

3.4 Step 2-Eliminate Technically Infeasible CO Options 

Step 2 of the BACT analysis involves the evaluation of all the identified available 

control technologies in Step 1 of the BACT analysis to determine their technical 

feasibility. A control technology is technically feasible if it has been previously installed 

and operated successfully at a similar type of source of comparable size, or there is 

technical agreement that the technology can be applied to the source. Available and 

applicable are the two terms used to define the technical feasibility of a control 

technology. The following subsections review the control technologies identified in Step 

1 of the CO BACT analysis and determine if they are technically feasible. Table 3-2 

summarizes the evaluation of the technically feasible CO options. 

3.4.1 Dry Low-NOx Burners and Good Combustion Control 

 The development of good combustion practice improvements with state of the art 

DLN burners are a demonstrated technology of controlling CO emissions from a simplecycle combustion turbine and commercially available from several vendors. DLN 
3.0 GEC Units 1 and 2 

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burners and good combustion control are considered technically feasible and will be 

considered further.

3.4.2 CO Oxidation Catalyst 

 CO oxidation catalysts are a demonstrated technology of controlling CO 

emissions from a simple-cycle combustion turbine and commercially available from 

several vendors. CO oxidation catalysts are considered technically feasible and will be 

considered further.

3.4.3 SCONOx

The application of this technology is currently limited to natural gas combined cycle 

combustion turbine units under 40 MW. However, EmeraChem, LLC is EMX

TM

(SCONOx) offers their product for GE 7FAs which makes it available. In addition, 

SCONOX has not been previously installed and operated at a similar type and size of 

turbine. However, in the interest of providing a complete technology analysis, SCONOx

will be evaluated in the BACT for CO control. 

Table 3-2 

Summary of Step 2--Eliminate Technically Infeasible CO Options 

Technically Feasible (Yes/No) 

Technology Alternative Available Applicable 

DLN Burners and Good 

Combustion Control 

Yes Yes 

CO Oxidation Catalyst Yes Yes 

SCONOX Yes Yes 

3.5 Step 3-Rank Combined NOX and CO Control Technology 

Effectiveness

In-combustor NOx and CO control by advanced combustion controls using dry low 

NOx burners is the least stringent control technology considered for the Project. However, 

the use of a combination SCR/oxidation catalyst system or the SCONOx system are 

technologies capable of achieving significantly lower emissions than the application of dry 

low NOx burners alone. Because the SCONOx system is capable of reducing NOx and CO, 

emissions, the NOx and CO BACT analyses have been combined to avoid double counting 
3.0 GEC Units 1 and 2 

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the SCONOx technology, thus inflating its economic impacts. The following control 

technologies will be evaluated in this BACT analysis and are ranked in order of relative 

control effectiveness: 

x In-combustor NOx and CO control consisting of DLN combustors to limit 

outlet emissions during natural gas firing for all operating loads for the 

Project is considered the base case scenario. All modern combustion 

turbines of the type proposed for this Project include DLN combustors. 

x The addition of an SCR system and oxidation catalyst to reduce outlet 

NOx emissions from the natural gas fired CTG/HRSG with duct burner to 

the level of 2.0 ppmvd and CO to 2.0 ppmvd emissions for the natural gas 

fired CTG/HRSG with duct burners. 

x The addition of a SCONOx system to reduce outlet NOx emissions from the 

natural gas fired CTG/HRSG with duct burner to the NOx level of 

2.0 ppmvd and CO emissions to 2.0 ppmvd. 

 The following evaluation considers energy, environmental, and economic impacts 

for the NOx and CO combined technology scenarios evaluated. Table 3-3 outlines the 

expected NOx and CO emissions rates from the evaluated emissions control alternatives of 

dry low NOx burners (i.e. good combustion controls), SCR/CO catalyst, and SCONOx.

SCR/CO catalyst and SCONOx are considered the most stringent NOx and CO emissions 

control alternatives as they achieve the lowest outlet emission rate. Therefore, if SCONOx is 

not found viable via energy, environmental, or economic impacts for the combined 

emissions reduction, the SCONOx technology will be eliminated from consideration, and a 

BACT evaluation would be done for control of NOx and CO emissions separately. 
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Table 3-3 

Estimated NOx and CO Emissions from Alternate Control 

Technologies for GEC Units 1 or 2 CCCTs 

(per CT) 

Control Technology Alternatives 

LNB/Good

Combustion 

Controls

SCR/CO

Catalyst SCONOx

NOx Emissions 

ppmvd (at 15 percent O2) 10.3 2.0 2.0 

lb/h 72.7 14.1 14.1 

tons per year (tpy)a 318.4 61.8 61.8 

percent reduction N/A 80.6% 80.6% 

NOx Emission Reduction (tpy) Base 256.6 256.6 

CO Emissions 

ppmvd (at 15 percent O2) 7.6 2.0 2.0 

lb/h 32.7 8.6 8.6 

tons per year (tpy)a 143.2 37.7 37.7 

percent reduction N/A 73.7% 73.7% 

CO Emission Reduction (tpy) Base 105.5 105.5 

a

Total emissions are based on 8,760 hours per year firing natural gas, 100% Load, Duct 

Firing, at ISO Conditions. 

3.6 Step 4-Evaluate Most Effective Combined NOX and CO 

Controls

In the following subsections, the NOX and CO combined control technologies are 

evaluated in a comparative approach with respect to their energy, environmental, and 

economic impacts on GEC Units 1 and 2 CCCT. The following are the evaluated 

technologies: SCONOX, SCR, and Oxidation Catalyst. 
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3.6.1 SCONOx Energy Impacts 

The use of a SCONOx system will increase the energy requirements on the system 

compared to use of dry low NOx burners alone. The SCONOx system will increase the 

backpressure on the combustion turbine by about 4 inches water gauge (in. w.g.). This 

will reduce the output for each CCCT by approximately 0.3 percent and increase the lost 

power generation. In addition, the period required for catalyst washing will result in 

increasing the lost power generation. Wahlco-Metroflex estimated the unit will be offline 

for a 24 hour period once per year to accommodate the washing process. Furthermore, 

there will be an energy loss due to steam consumption from the regeneration system. 

Steam is used as the carrier medium for the regeneration gas for the SCONOx system. 

Wahlco-Metroflex estimated that approximately 5,000 lb/h of steam would be used in the 

regeneration production for each combustion turbine. These three effects will be added 

together to determine the total lost power generation and are included in the annualized 

cost estimate. The SCONOx system will have minimal effect on power consumption that 

will be necessary to operate the damper actuators and regeneration system. WahlcoMetroflex estimated that approximately 15 kW would be consumed during operation of 

each SCONOx system. This increase in power consumption will be included in the 

annualized cost estimate. The natural gas required for the production of the regeneration 

gas will increase the annualized cost associated with using the SCONOx system. The 

annualized cost of natural gas consumption is included in the annualized cost analysis. 

3.6.2 SCONOx Environmental Impacts 

 The SCONOx catalyst is composed of precious metals coated with potassium 

carbonate. When the potassium carbonate coating can no longer be regenerated, the 

precious metal content of the remaining catalyst can be recycled. Although recycling the 

potassium carbonate is a positive aspect of this technology, the oxidation of CO and VOC 

that results from the application of this technology directly results in an increased 

production of CO2, a greenhouse gas. There is currently a worldwide effort to reduce 

industrial emissions of CO2 because of its contribution to global climate change. 

Installation of a SCONOx system would directly counter this initiative. 

 The SCONOx catalyst will oxidize approximately 1.0 percent of the SO2 in the 

flue gas to SO3. The SO3 will then react with the moisture in the flue gas to form sulfuric 

acid mist in the atmosphere. Any sulfuric acid mist formed will increase the amount of 

particulate matter emitted in the flue gas. The particulate matter will predominately 

consist of PM10.
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3.6.3 SCR Energy Impacts 

 The use of an SCR system impacts the energy requirements of GEC Units 1 and 2 

CCCTs. An SCR system requires an ammonia storage, handling and delivery system, 

which would include vaporizers and blowers to vaporize and dilute the ammonia reagent 

for injection. In addition, an SCR system catalyst would increase the backpressure on 

each combustion turbine. The SCR system would add about 2.6 inches water gauge (in. 

w.g.) backpressure to the unit for the NOx reduction to 2.0 ppmvd. This would reduce the 

output of each CCCT by approximately 492 kW. 

3.6.4 SCR Environmental Impacts 

 The vanadium content of the SCR catalyst contributes to its classification as a 

hazardous waste. Therefore, spent catalyst may need to be handled and disposed of 

following hazardous waste procedures. Because of this, recycling of SCR catalysts for 

vanadium has become common. 

 The use of ammonia in an SCR system introduces an element of environmental risk. 

Ammonia is listed as a hazardous substance under Title III Section 302 of the Superfund 

Amendments and Reauthorization Act of 1986 (SARA). However, the storage and use of 

ammonia has been a relatively routine practice in utility power plants and industrial plant 

processes and is also regulated by USEPA’s Chemical Accident Prevention Provisions. 

This BACT analysis is based on the use of aqueous ammonia that can be stored and used 

more safely than anhydrous ammonia. According to the Committee on Toxicology of the 

National Academy of Sciences and the Committee on Medical and Biological Effects of 

Environmental Pollutants (both of the National Research Council), the following 

threshold concentrations exist for ammonia: 

Human Response Concentration (ppm) 

Immediate throat irritation Equal to or greater than 400 

Eye irritation Equal to or greater than 700 

Coughing Equal to or greater than 1,700 

Life threatening for short exposure 2,500 to 6,500 

Rapidly fatal for short exposure 5,000 to 10,000 

 Some ammonia slip from the GEC Units 1 and 2 CCCT stacks are unavoidable 

due to the imperfect distribution of the reagent and catalyst deactivation. Although 

ammonia emissions are not regulated nationally, the Northeast States for Coordinated Air 

Use Management (NESCAUM) has recommended an ammonia slip emissions limit of 

10 ppmvd, unless that limit is shown to be inappropriate. Ammonia slip from an SCR 

system is one of the major design consideration that establishes catalyst life. Therefore, 
3.0 GEC Units 1 and 2 

JEA GEC CCCT Conversion NOx and CO BACT Analysis 

149588 3-15 

lower ammonia slip requirements ultimately limit catalyst life and dictate associated 

catalyst replacement. Exceeding the NESCAUM’s recommendation, FDEP proposed an 

ammonia slip of 5 ppmvd for Treasure Coast, a combined cycle combustion turbine unit 

utilizing SCR. Based on the recent Treasure Coast air permit, an ammonia slip design 

value of 5 ppmvd at 15 percent O2 is used for this analysis.

 The SCR catalyst will oxidize approximately 2 to 3 percent of the SO2 in the flue 

gas to SO3. Once the flue gas cools below approximately 600° F, the ammonia present in 

the flue gas may react with SO3 to form ammonium sulfate and bisulfate salts. This 

formation may be dependent on the particular plume dispersion characteristics at the 

given time of stack discharge, which is dependent upon the temperature reached once the 

flue gas has left the stack. However, if the ammonia sulfate compounds are not formed, 

the SO3 will react with the moisture in the flue gas to form sulfuric acid mist in the 

atmosphere. Any ammonium sulfate and bisulfate salts and sulfuric acid mist formed 

will increase the amount of particulate matter emitted in the flue gas. The particulate 

material will predominately consist of matter less than PM10. As the catalyst gradually 

deactivates, more ammonia must be injected to compensate and maintain the desired NOx

reduction. This results in an increased amount of ammonia slip for a given level of 

performance. Increased ammonia slip in turn results in additional ammonia salt 

formation which could result in increased opacity and particulate emissions from GEC 

Units 1 and 2 CCCTs. 

3.6.5 Oxidation Catalyst Energy Impacts 

 An oxidation catalyst reactor located downstream of the combustion turbine 

exhaust will increase the backpressure on the combustion turbine. The additional 

backpressure of about 1.2 inches, water gauge, will reduce each combustion turbine 

output by approximately 227 kW. The cost of lost power revenue due to the 

backpressure is included in the economic analysis. 

3.6.6 Oxidation Catalyst Environmental Impacts 

 The major environmental disadvantage that exists when using an oxidation 

catalyst to reduce CO emissions is that a percentage of the SO2 in the flue gas will 

oxidize to SO3. The higher the operating temperature, the higher the SO2 to SO3

oxidation potential. It is estimated that approximately 20 percent of the SO2 in the flue 

gas will oxidize to SO3 as a result of the oxidation catalyst being installed after the 

combustion turbine outlet with high temperatures. The SO3 will react with the moisture in 

the flue gas to form sulfuric acid mist (H2SO4). The increase in H2SO4 emissions would 

increase PM10 emissions. 
3.0 GEC Units 1 and 2 

JEA GEC CCCT Conversion NOx and CO BACT Analysis 

149588 3-16 

 Spent oxidation catalyst is made up of precious metals that are not considered 

toxic. This allows the catalyst to be handled and disposed of following normal waste 

procedures. Because of the precious metal content of the catalyst, the oxidation catalyst 

can also be recycled to recover the precious metals. 

 As mentioned previously, the installation of an oxidation catalyst will also 

increase the backpressure on the turbine, thereby decreasing efficiency. This decrease in 

efficiency will lead to increased emissions of all pollutants on a unit power output basis. 

The oxidation of CO also directly results in increased production of CO2, a greenhouse 

gas. There is currently a worldwide effort to reduce industrial emissions of CO2 because 

of its contribution to global climate change. Installation of an oxidation catalyst would 

directly counter this initiative. 

3.6.7 Economic Impacts for SCR (2.0 ppmvd )/ Oxidation Catalyst Versus 

SCONOX

 The use of an SCR/oxidation catalyst or SCONOx has significant economic 

impacts to GEC Units 1 and Unit 2 CCCTs. An analysis of the economic impact is 

provided in this section.

3.6.7.1 Capital Costs for SCR (2.0 ppmvd) / Oxidation Catalyst and 

SCONOx. 

Table 3-4 presents the capital costs for installing an SCR/oxidation catalyst and SCONOx

system on each CCCT during natural gas firing to achieve a NOx outlet emission level of 

2.0 ppmvd and a CO outlet emission rate of 2.0 ppmvd. Note, the same SCR/oxidation 

catalyst and SCONOx systems have been designed to accommodate firing natural gas as 

the primary fuel and ULSFO as a backup fuel. The cost of the SCR/oxidation catalyst 

system includes the ammonia receiving, storage, transfer, vaporization, and injection; 

catalytic reactor housing, ductwork; controls and instrumentation and freight. The catalyst 

costs were not included in the total capital investment (TCI) cost but assessed as an annual 

cost. The cost of the SCONOx system includes the catalyst, regenerative gas distribution 

system, catalytic reactor housing, controls and instrumentation, and freight. The BOP cost 

for the SCR/oxidation catalyst and SCONOx system consist of 8 percent of the purchased 

equipment costs (PEC) for foundation and supports, 14 percent for handling and erection, 

4 percent for electrical installation, 2 percent for piping, 1 percent for insulation, and 

1 percent for painting. Capital costs were based on budgetary quotations from equipment 

manufacturers and other engineering estimates. 

 Quotations for the SCR and oxidation catalyst material were based on 

vanadium/titanium and precious metal type catalysts, respectively. The direct installation 

costs included the balance of plant items such as foundations, insulation and lagging and 

painting and were calculated as percentages of the total purchased equipment costs. The 
3.0 GEC Units 1 and 2 

JEA GEC CCCT Conversion NOx and CO BACT Analysis 

149588 3-17 

total capital investment was calculated as the summation of the total direct cost (DC) and 

total indirect costs (IC) per OAQPS cost methods. The indirect capital costs for the 

SCR/Oxidation Catalyst systems are percentages of the total direct costs (DC) and are 

site specific. The indirect capital costs for the SCONOx system are percentages of the 

SCONOx system DC. 

 There are many potential items and uncertainties that are not captured by the cost items 

included in the estimate, such as possible changes between cost quotes and contract values, 

changes in operating conditions, process contingency, increased equipment cost, scope 

changes, labor/wage increases, and schedule acceleration. In addition, the Electric Power 

Research Institute published the document titled, NOx Emissions: Best Available Control 

Technology, A Gas Turbine Permitting Guidebook in November 1991 and list under NOx

control cost (Page 5-5) the following text: 

“Based on experience with other cost methodology sources, the contingency factor 

recommended by the OAQPS Manual (3% of the total equipment cost) is a lowerbound estimate. Standard EPA guidance for pollution control costing is a 

contingency factor of 10 to 50% of the sum of direct and indirect costs.10 A 

contingency factor of 20% of the sum of direct and indirect costs was used in the 

economic analyses conducted by the EPA in support of the NSPS for industrial and 

small boilers and municipal waste combustors.11,12. Based on this range of values, 

it is recommended that individual utilities use the contingency factor that would 

normally be used in-house in procurement or rate estimation procedures, and 

document the validity of the factor for the case in question. The factor 

recommended by OAQPS should be used as a default value when more appropriate 

information is not available.” 

Therefore a 10 percent contingency factor has been assumed for this project. 

 Based on the analysis in this section, the total capital investment for the 

SCR/oxidation catalyst control system is calculated as the sum of the total direct and 

indirect capital costs per OAQPS cost methods. The total capital investment for each 

CCCT controlling NOx and CO to 2.0 ppmvd and 2.0 ppmvd, respectively is estimated to 

be $5,243,000.

 The total capital investment for the SCONOx control system is calculated as the 

sum of the total direct and indirect capital costs per OAQPS cost methods. The total 

 10U.S. Environmental Protection Agency, A Standard Procedure for Cost Analysis of Pollution Control 

Operations: Volume I, EPA 600/8-79-018a, June 1979. 

11U.S. Environmental Protection Agency, Industrial Boiler SO2 Cost Report, EPA 450/3-85-011, 

November 1984. 

12U.S. Environmental Protection Agency, Municipal Waste Combustors – Background 

Information for Proposed Standards: Control of NOx Emissions, EPA 450/3-89-27d, August 1989. 
3.0 GEC Units 1 and 2 

JEA GEC CCCT Conversion NOx and CO BACT Analysis 

149588 3-18 

capital investment for each CCCT controlling NOx and CO to 2.0 ppmvd and 2.0 ppmvd, 

respectively is estimated to be $27,912,000. 

Table 3-4 

NOx/CO Combined Control Alternative Capital Cost ($) for Each CCCT

(GEC Units 1 and 2) 

 DLN 

SCONOx

($) 

SCR/OX Cat 

($) Remarks 

Direct Capital Cost Cost based on emissions in Table 3-3 

Catalysts N/A Included 1,717,000 Est. from BASF/CERAM 

Catalyst R. Housing 

/Ductwork 

N/A Included 705,000 Estimated from Turner EnviroLogic 

SCONOx System N/A 16,000,000 0 Vendor Estimate 

Control/Instrumentation N/A 150,000 195,000 Estimated; includes controls and 

monitoring equipment. 

Ammonia (Storage & 

Injection) 

N/A N/A 985,000 Estimated from Turner EnviroLogic 

and previous projects. 

Purchased Equipment 

Costs (PEC) 

N/A 16,150,000 3,602,000 

Sales Tax 0 0 Not applicable to JEA 

Freight N/A 1,615,000 361,000 10% of PEC 

Balance of Plant N/A 5,491,000 1,081,000 30% of PEC. See text for 

background information on this item 

Total Direct Cost (DC) N/A 23,256,000 5,044,000 

Indirect Capital Costs 

Contingency N/A 2,326,000 504,000 10% of DC 

Engineering and 

Supervision 

N/A 2,326,000 504,000 10% of DC for SCONOx. 10% of 

DC for SCR and 10% of DC for CO 

catalyst.

Construction & Field 

Expense 

N/A 1,163,000 253,000 5% of DC 

Construction Fee N/A 2,326,000 504,000 10% of DC 

Start-up Assistance N/A 465,000 101,000 2% of DC 

Performance Test N/A 50,000 50,000 Assumed $50,000 emission test. 

Total Indirect Capital 

Costs (IC) 

Base 8,656,000 1,916,000 

Installed Costs (DC+IC) Base 31,912,000 6,960,000 

Less Catalyst Base 4,000,000 1,717,000 Catalyst is viewed as an O&M value. 

Total Capital Investment 

(TCI ) 

Base 27,912,000 5,243,000 TCI = DC + IC – Catalyst 
3.0 GEC Units 1 and 2 

JEA GEC CCCT Conversion NOx and CO BACT Analysis 

149588 3-19 

3.6.7.2 Operating Costs for SCR/Oxidation Catalyst Versus SCONOx.

Table 3-5 presents the annualized operating costs using a SCR/oxidation catalyst and 

SCONOx system to achieve NOx outlet emissions of 2.0 ppmvd and CO emissions of 

2.0 ppmvd while firing natural gas for GEC Units 1 and 2 CCCTs. Annualized operating 

costs for the SCR/oxidation catalyst include catalyst replacement, energy impacts, operating 

personnel, maintenance, reagent and heat rate penalty. Throughout the life of the plant, 

catalyst elements for both the SCR and the oxidation catalyst will require periodic 

replacement. As the SCR catalyst becomes deactivated, ammonia slip emissions will 

increase. At the point ammonia slip approaches 5 ppmvd the catalyst must be replaced. 

The oxidation catalyst will degrade from normal operation that will be evident by an 

increase in CO emissions, thereby requiring replacement of the oxidation catalyst. 

Currently, SCR and oxidation catalyst manufacturers are willing to guarantee a catalyst life 

of three years of equivalent operating hours. 

 Ammonia consumption rates were based on a stoichiometric ratio of 1.1 for 

reacting NOx. The heat rate penalty cost (lost power generation) item reflects the cost 

due to the SCR and oxidation catalyst backpressure losses. The additional backpressure 

will derate the combustion turbine resulting in lost electric sales revenue. The costs 

associated with these impacts are included in the annualized cost estimate. 

 The use of either an SCR/oxidation catalyst system or a SCONOx system 

increases the energy requirements of the project. The SCR system requires vaporizers 

and blowers to vaporize and dilute the ammonia reagent for injection. SCONOx

consumes power to open and close the catalyst dampers and to produce the regenerating 

gas. The maintenance costs will consist of routine system maintenance for each system. 

However, there is an additional annual maintenance cost for washing the 

SCONOx/SCOSOx catalyst. Therefore, the SCONOx system will include the additional 

O&M cost for catalyst washing. 

 The indirect annual costs include capital recovery, overhead, administrative charges 

and insurance. The overhead annual cost is estimated to be 60 percent of the O&M costs. 

According to the OAQPS Cost Manual there are two types of overhead, payroll and plant.

Payroll overhead expenses include workmen's compensation, social security, vacations, 

group insurance and other fringe benefits. Plant overhead is not tied into O&M of the 

control system, but is related to plant protection, control labs, employee amenities, plant 

lighting, parking areas, and landscaping. The OAQPS Cost Manual allows one to 

combine these overhead cost into one sum. The administrative cost covers sales, research 

and development, accounting, and other home office expenses. The insurance cost was 

based on 1 percent of the total capital investment for each system. 
3.0 GEC Units 1 and 2 

JEA GEC CCCT Conversion NOx and CO BACT Analysis 

149588 3-20 

3.6.7.3 Total Annualized Costs for SCR (2 ppmvd) / Oxidation Catalyst 

Versus SCONOx.

Total annualized costs for the SCR and oxidation catalyst control systems are 

calculated as the sum of operating costs plus the system capital recovery cost. The 

system capital recovery cost is the product of the system capital recovery factor (CRF) and 

the total capital investment (TCI). Table 3-5 shows the total annualized cost for a 

SCR/Oxidation Catalyst systems for each CCCT firing natural gas is estimated to be 

$1,952,000, which is approximately a third of the cost of a SCONOX system having a total 

annualized cost of $6,693,000.

3.6.7.4 Conclusions. Based on the fact that the SCR/oxidation catalyst system is a 

lower capital cost system and has lower annualized costs than the SCONOx system, the 

SCONOx system will not be further evaluated as part of the BACT analysis. The 

remainder of the BACT analysis will concentrate on evaluating technologies for the 

control of each pollutant separately. 
3.0 GEC Units 1 and 2 

JEA GEC CCCT Conversion NOx and CO BACT Analysis 

149588 3-21 

Table 3-5 

NOx/CO Combined Control Alternative Annualized Cost ($) for Each CCCT 

(GEC Units 1 and 2) 

 DLN SCONOx ($) 

SCR/OX

Cat ($) Remarks 

Direct Annual Cost Cost based on emissions in Table 3-3 

Catalyst Replacement N/A 1,116,000 615,000 Includes freight, installation, 3-yr 

capital recovery factor SCR catalyst 

(3-yr life), 6-yr capital recovery 

factor for OX cat (6-yr life), and 5-yr 

capital recovery factor for SCONOx 

(5-yr life). 

Operation and 

Maintenance 

N/A 68,000 39,000 See text for background information 

on this item 

Maintenance Materials N/A 48,000 23,000 

Reagent Feed N/A N/A 155,000 Assumes 1.1 stoichiometric ratio 

Natural Gas Consumption N/A 66,000 0 

Power Consumption N/A 110,000 205,000 Includes injection blower and 

vaporization of ammonia 

Lost Power Generation N/A 2,191,000 272,000 

Back pressure on combustion turbine. 

Includes seven days of lost power 

generation time for catalyst/system 

cleaning for SCONOX 

Annual Distribution Check N/A 116,000 40,000 Estimated as 0.5% of the total direct 

cost for SCONOX and 1% for SCR 

Total Direct Annual Cost N/A 3,715,000 1,349,000 

Indirect Annual Costs 

Overhead N/A 41,000 23,000 60% of O&M Cost 

Administrative Charges N/A 638,000 139,000 2% of Installed Cost 

Property Taxes N/A 0 0 Not included 

Insurance N/A 319,000 69,000 1% of Installed Cost 

Capital Recovery N/A 1,980,000 372,000 Capital Recovery Excluding Catalyst 

Total Indirect Annual Costs N/A 2,978,000 603,000 

Total Annualized Cost N/A 6,693,000 1,952,000 
3.0 GEC Units 1 and 2 

JEA GEC CCCT Conversion NOx and CO BACT Analysis 

149588 3-22 

3.7 Step 4-Evaluate Most Effective NOX Controls 

 The following section identifies economic impacts of the NOx only BACT 

analysis. This section will not include a discussion of energy and environmental impacts, 

as they are the same as those discussed in the combined control BACT evaluation for 

NOx and CO as listed in Section 3.6. 

3.7.1 Economic Impacts for SCR 

 The control of NOx emissions separate from CO emission control is possible 

through the application of a SCR to GEC Units 1 and 2 CCCTs without additional CO 

emission controls. To determine the BACT levels for NOx controls without the influence 

of the CO emission controls a separate economic analysis is required. An analysis of the 

economic impact of SCR as a separate control technology for NOx emissions of 2.0 

ppmvd firing natural gas is provided in this section. The BACT costs presented in this 

analysis are based on operating the combustion turbine, with duct firing, at 100 percent 

base load for 8,760 hours per year on natural gas. 

3.7.2 Economic Impacts for SCR (2.0 ppmvd NOX) System

The use of an SCR has significant economic impacts to the JEA Project. The 

application of SCR on GEC Units 1 and 2 CCCTs must incorporate special design and 

operational/maintenance criteria, such as periodic catalyst replacements and increased 

associated plant outage costs. A detailed description of the economic impacts of SCR 

was provided previously in Subsection 3.6.7 and will not be repeated. 

3.7.2.1 Capital Costs for SCR (2.0 ppmvd NOX).

Table 3-6 summarizes the economic capital cost for implementing SCR on each 

CCCT. Based on the analysis in this section, the total installed capital costs for the SCR 

control system is calculated as the sum of the total direct and indirect capital costs per 

OAQPS cost methods. The total capital investment cost of SCR for each CCCT 

controlling NOx to 2.0 ppmvd is estimated to be $4,421,000. 

3.7.2.2 Total Annualized Costs for SCR (2.0 ppmvd NOX).

Total annualized costs for the SCR control systems are calculated as the sum of 

operating costs plus the system capital recovery cost. The system capital recovery cost is 

the product of the system capital recovery factor (CRF) and the total capital investment 

(TCI). Table 3-7 shows the total annualized cost for SCR systems are estimated to be 
3.0 GEC Units 1 and 2 

JEA GEC CCCT Conversion NOx and CO BACT Analysis 

149588 3-23 

$1,724,000. This annualized cost for the each CCCT SCR system results in a cost 

effectiveness of approximately $6,719 per ton of NOx removed. 

Table 3-6 

NOX Emission Control Alternative Capital Cost for GEC 

Units 1 and 2 

DLN SCR ($) Remarks 

Direct Capital Cost Cost based on emissions in Table 3-3. 

Catalyst N/A 1,102,000 Estimated from CERAM 

Catalyst R. Housing /Ductwork N/A 630,000 Estimated from Turner EnviroLogic 

Control/Instrumentation N/A 150,000 Estimated; includes controls and 

monitoring equipment. 

Ammonia (Injection/Dilution/ 

Storage) 

N/A 985,000 Estimated from Turner EnviroLogic 

Purchased Equipment Costs 

(PEC) N/A 2,867,000 

Sales Tax 0 Not applicable to JEA. 

Freight N/A 287,000 10% of PEC 

Balance of Plant N/A 860,000 30% of PEC. See text for background 

information on this item. 

Total Direct Cost (DC) Base 4,014,000 

Indirect Capital Costs 

Contingency N/A 401,000 10% of DC 

Engineering and Supervision N/A 401,000 10% of DC 

Construction & Field Expense N/A 201,000 5% of DC 

Construction Fee N/A 401,000 10% of DC 

Start-up Assistance N/A 80,000 2% of DC 

Performance Test N/A 25,000 Assumed $25,000 

Total Indirect Capital Costs (IC) Base 1,509,000 

Installed Costs (DC + IC) 5,523,000 

Less SCR Catalyst Cost 1,102,000 Catalyst is viewed as an O&M value. 

Total Capital Investment, TCI Base 4,421,000 
3.0 GEC Units 1 and 2 

JEA GEC CCCT Conversion NOx and CO BACT Analysis 

149588 3-24 

Table 3-7 

NOX Emissions Control Annualized Cost ($) for Each CCCT 

(GEC Units 1 and 2) 

 DLN SCR ($) Remarks 

Direct Annual Cost Cost based on emissions in Table 3-3 

Catalyst Replacement N/A 488,000 

Includes freight, installation, and 3-yr 

capital recovery factor based on 3-yr 

guaranteed catalyst life 

Operation and Maintenance N/A 39,000 See text for background information 

Maintenance Materials N/A 23,000 See text for background information 

Reagent Feed N/A 155,000 Assumes 1.1 stoichiometric ratio 

Power Consumption N/A 205,000 Includes injection blowers and 

vaporization of ammonia 

Lost Power Generation N/A 272,000 Back pressure on combustion turbine 

Annual Distribution Check N/A 40,000 Estimated as 1 % of the total direct cost 

Total Direct Annual Cost N/A 1,222,000 

Indirect Annual Costs N/A 

Overhead N/A 23,000 60% of Operation and Maintenance cost 

Administrative Charges N/A 110,000 2% of Installed Costs 

Property Taxes N/A 0 Not included 

Insurance N/A 55,000 1% of Installed Costs 

Capital Recovery N/A 314,000 Capital recovery excluding catalyst 

Total Indirect Annual Cost N/A 502,000 

Total Annualized Cost N/A 1,724,000 

NOx Annual Emissions, tpy 318.4 61.8 Emission taken from Table 3-3 

NOx Emissions Reduction, tpy N/A 256.6 Emissions calculated in Table 3-3 

NOx Total Cost Effectiveness, $/ton N/A 6,719 Total Analyzed Cost/Emissions 

Reduction 
3.0 GEC Units 1 and 2 

JEA GEC CCCT Conversion NOx and CO BACT Analysis 

149588 3-25 

3.8 Step 4-Evaluate Most Effective CO Controls 

The following section identifies economic impacts of the CO only BACT 

analysis. This section will not include a discussion of energy and environmental impacts, 

as they are the same as those discussed in the combined control BACT evaluation for 

NOx and CO as listed in Section 3.6. 

3.8.1 Economic Impacts for Oxidation Catalyst 

 The use of an oxidation catalyst has significant economic impacts to the JEA 

Project. An analysis of the economic impact is provided in this section. An analysis of 

the economic impact of oxidation catalyst as a separate control technology for CO 

emissions of 2.0 ppmvd firing natural gas is provided in this section. The BACT costs 

presented in this analysis are based on operating the combustion turbine, with duct firing, 

at 100 percent base load for 8,760 hours per year on natural gas. 

3.8.2 Capital Cost for Oxidation Catalyst 

 Table 3-8 presents the capital costs for installing an oxidation catalyst on each 

CCCT during natural gas firing to achieve a CO outlet emission level of 2.0. The capital 

costs for the systems includes the oxidation catalyst, oxidation catalyst reactor housing, 

controls and instrumentation, sales taxes and freight, and were based on budgetary 

quotations from equipment manufacturers and other engineering estimates. The direct 

installation costs included the balance of plant items such as foundations, insulation and 

lagging, and painting, and were calculated as percentages of the total purchased 

equipment costs (PEC). The total capital investment was calculated as the summation of the 

total direct cost (DC) and total indirect costs (IC) per OAQPS cost methods. The indirect 

capital costs for the SCR/Oxidation Catalyst systems are percentages of the total direct cost 

(DC) and are site specific. The three percent contingency value suggested in the OAQPS 

Cost Control Manual is judged to be inaccurate as compared to actual values typically 

used in the construction field for this level of estimating, as discussed in Section 3.6.7.1. 

 Total capital costs for the oxidation catalyst control system to reduce CO is 

calculated as the sum of the direct and indirect installed costs. The total capital 

investment per unit for an oxidation catalyst system to reduce CO emissions from each 

CCCT is estimated to be $822,000. 

3.8.3 Operating Costs for Oxidation Catalyst 

Table 3-9 presents the annualized operating costs and emission rates using an 

oxidation catalyst to achieve a 74 percent reduction in CO emissions while firing natural 
3.0 GEC Units 1 and 2 

JEA GEC CCCT Conversion NOx and CO BACT Analysis 

149588 3-26 

gas on each CCCT. Annualized operating costs for the system includes catalyst 

replacement and lost power generation. Throughout the life of the plant, catalyst elements 

will require periodic replacement. Currently, catalyst manufacturers are willing to 

guarantee an oxidation catalyst life of three years of equivalent operating hours for an 

oxidation catalyst, however, it was assumed to be six years. 

3.8.4 Total Annualized Costs for Oxidation Catalyst 

 Total annualized costs for the oxidation control system is calculated as the sum of 

operating costs plus the system capital recovery cost. The system capital recovery cost is 

the product of the system capital recovery factor (CRF) and the total installed costs. Firing 

natural gas, the total annualized cost for a 2.0 ppmvd CO oxidation catalyst systems for 

each CCCT are estimated to be $228,000. This annualized cost for each CCCT results in 

a cost effectiveness of approximately $2,161 per ton of CO removed. 
3.0 GEC Units 1 and 2 

JEA GEC CCCT Conversion NOx and CO BACT Analysis 

149588 3-27 

Table 3-8 

CO Reduction System Capital Cost ($) for Each CCCT 

(GEC Units 1 and 2) 

Good 

Combustion 

Controls/DLN 

Oxidation 

Catalyst

($) Remarks 

Direct Capital Cost Cost based on emissions in Tables 3-3. 

Oxidation Catalyst N/A 615,000 Estimated from BASF 

Catalyst Reactor Housing N/A 75,000 

Control/Instrumentation N/A 45,000 Estimated; includes controls and 

monitoring equipment. 

Purchased Equipment Costs 

(PEC) N/A 735,000 

Sales Tax N/A 0 Not applicable to JEA 

Freight N/A 74,000 10% of PEC 

Balance of Plant N/A 221,000 30% of PEC. See text for background 

information on this item. 

Total Direct Cost (DC) Base 1,030,000 

Indirect Capital Costs N/A 

Contingency N/A 103,000 10% of DC 

Engineering and 

Supervision N/A 103,000 10% of DC 

Construction & Field 

Expense N/A 52,000 5% of DC 

Construction Fee N/A 103,000 10% of DC 

Start-up Assistance N/A 21,000 2% of DC 

Performance Test N/A 25,000 Assumed value of $25,000 

Total Indirect Capital Costs 

(IC) Base 407,000 

Installed Costs (DC +IC) 1,437,000 

Less Catalyst N/A 615,000 Catalyst is viewed as an O&M Value. 

Total Capital Investment, 

TCI Base 822,000 
3.0 GEC Units 1 and 2 

JEA GEC CCCT Conversion NOx and CO BACT Analysis 

149588 3-28 

Table 3-9 

CO Control Annualized Cost ($) for Each CCCT 

 (GEC Units 1 and 2) 

Good 

Combustion 

Controls/DLN 

Oxidation 

Catalyst

($) Remarks 

Direct Annual Cost Cost based on emissions in Tables 4-1. 

Catalyst Replacement N/A 127,000 

Includes freight, installation, and 6-yr 

capital recovery factor based on 6 yr 

guaranteed catalyst life. 

Operation and Maintenance N/A 0 Not applicable for Oxidation Catalyst 

Lost Power Generation 0 Back pressure on combustion turbine 

Total Direct Annual Cost N/A 127,000 

Indirect Annual Costs 

Overhead N/A 0 Not Applicable because of zero O&M 

Administrative Charges N/A 29,000 2% of Installed Costs 

Property Taxes N/A 0 Not included 

Insurance N/A 14,000 1% of Installed Costs 

Capital Recovery N/A 58,000 Capital recovery excluding catalyst. 

Total Indirect Annual Costs N/A 101,000 

Total Annualized Cost Base 228,000 

CO Annual Emissions, tpy 143.2 37.7 Emissions taken from Table 3-3. 

CO Emissions Reduction, 

tpy N/A 105.5 Emissions taken from Table 3-3. 

CO Total Cost Effectiveness, 

$/ton N/A 2,161 Total Annualized Cost/Emissions Reduction 
3.0 GEC Units 1 and 2 

JEA GEC CCCT Conversion NOx and CO BACT Analysis 

149588 3-29 

Step 5-Select NOX BACT 

Based on the cost effectiveness value for the SCR catalyst it is determined that 

add-on controls to further reduce NOX emissions are warranted. JEA has determined that 

the top NOx control alternative when firing natural gas (primary fuel), Dry Low-NOX 

(DLN) Burners with SCR catalyst, represents NOx BACT for GEC Units 1 and 2 CCCTs, 

corresponding to an emissions limit of 2 ppmvd at 15 percent O2 on a 24 hour average 

basis. The top NOx control alternative when firing ULSFO (backup fuel), Water 

Injection (WI) with SCR catalyst, represents NOx BACT for the GEC Unit 1 and Unit 2, 

corresponding to an emissions limit of 8.0 ppmvd at 15 percent O2 on a 24 hour average 

basis. Table 3-10 summarizes the Project’s NOx BACT determination for GEC Units 1 

and 2.

Table 3-10 

GEC Units 1 and 2 CCCTs NOx BACT Determination 

Control Technology Emission Limit 

DLN Burners with SCR (for 

natural gas combustion) 

NG: 2.0 ppmvd @ 15% O2 (24-hr avg.) 

WI/SCR (for ULSFO 

combustion) 

ULSFO: 8.0 ppmvd @ 15% O2 (24-hr avg.) 

3.9 Step 5-Select CO BACT 

Based on the high cost effectiveness value for the oxidation catalyst it is 

determined that add-on controls to further reduce CO emissions are unwarranted given 

the low CO emission characteristics of GEC Units 1 and 2 CCCTs 4 firing natural gas as 

the primary fuel. As a basis for review, the cost-effectiveness guidelines are pollutantspecific, considering the control technology, environmental sensitivity, and 

determinations from similar BACT trends for that pollutant in the affected region and 

across the country. JEA believes that an oxidation catalyst is not BACT for this project. 

This determination is independent of the NOX control determination. The CO BACT 

assessment is firmly based on the energy, environmental, and economic impacts detailed 

in the application, as well as recent Department determinations for similar units at similar 

emission levels. In those determinations, the Department has found that add-on controls 

to further reduce CO emissions are unwarranted given the already low emissions 
3.0 GEC Units 1 and 2 

JEA GEC CCCT Conversion NOx and CO BACT Analysis 

149588 3-30 

characteristics of this particular gas turbine firing natural gas as the primary fuel. A few 

of those particular determinations are FPL Turkey Point, TECO Bayside Power Station, 

FMPA Treasure Coast, Progress Energy Hines Power Block 4, and most recently FMPA 

Cane Island Unit 4, which are all documented in Attachment 2. The CO BACT costeffectiveness for JEA has determined that the CO BACT for GEC Units 1 and 2 CCCTs 

during natural gas firing with and without the operation of the natural gas fired duct burners 

at 100 percent load is good combustion controls. The CO BACT emission limit with and 

without duct burners operating is a stack test limit of 7.6 ppmvd at 15 percent O2 and 4.1 

ppmvd at 15 percent O2, respectively. The top CO control alternative when firing 

ULSFO, good combustion controls, represents CO BACT for the GEC Units 1 and Unit 2 

CCCTs, corresponding to an emissions limit of 8.0 ppmvd at 15 percent O2 on a 24-hour 

block. The CEMS average limit firing natural gas or ULSFO is proposed as 8.0 ppmvd 

@ 15% O2, and 24-hour block average. Table 3-11 summarizes the Project’s CO BACT 

determination for GEC Units 1 and 2 CCCTs. 

Table 3-11 

GEC Units 1 and 2 CCCTs CO BACT Determination 

Control Technology Emission Limit 

Good Combustion Controls NG: 7.6 ppmvd @ 15% O2 (stack test, 3-run

average) with DBs;

4.1 ppmvd @ 15% O2 (stack test, 3-run average) 

w/o DBs;

ULSFO: 8.0 ppmvd @ 15% O2 (stack test, 3-run

average)

NG or ULSFO: 8.0 ppmvd @ 15% O2 (CEMS, 

24-hour block average) 
4.0 GEC Units and 2 

JEA GEC CCCT Conversion CCCTs PM/PM10 BACT Analysis 

149588 4-1 

4.0 GEC Units 1 and 2 CCCTs PM/PM10 BACT Analysis 

 The objective of this analysis was to determine BACT for PM/PM10 emissions from 

GEC Units 1 and 2 CCCTs. This includes the combustion turbine and supplemental firing 

from duct burners in the HRSG as a total unit. 

 PM/PM10 emissions from the combustion turbines are a result of incomplete 

combustion and trace particulate parameters in the fuel. The emissions of particulate matter 

from GEC Units 1 and 2 CCCTs will be controlled by ensuring as complete combustion of 

the fuel as possible. The NSPS for combustion turbines do not establish a particulate 

emission limit. Natural gas contains only trace quantities of non-combustible material. As 

for ULSFO, it contains small quantities of non-combustible material. 

 The manufacturer's standard operating procedures include filtering the turbine inlet air 

and combustion controls. The BACT/LAER Clearinghouse documents do not list any 

post-combustion particulate matter control technologies being used on combustion 

turbines. Consistent with the previous determinations as referenced by the State of Florida, 

such as the FPL West County, FMPA Treasure Coast, FPL Turkey Point, FPL Martin, FPL 

Manatee, FPL Fort Myers, FMPA Cane Island Unit 4, Santa Rosa and the City of 

Tallahassee projects, the use of combustion controls and natural gas as the primary fuel 

(ULSFO as backup) is considered BACT for particulate matter and is proposed for GEC 

Units 1 and 2 CCCTs. 
5.0 GEC Units 1 and 2 

JEA GEC CCCT Conversion CCTs SO2 BACT Analysis 

149588 5-1 

5.0 GEC Units 1 and 2 CCCTs SO2 BACT Analysis 

 The objective of this analysis was to determine BACT for SO2 emissions from 

GEC Units 1 and 2 CCCTs.

 Typically, natural gas has only trace amounts of sulfur that is used as an odorant. As 

for ULSFO, it has very low amounts of sulfur as well. The selection of natural gas fuel 

and ULSFO provides inherently low SO2 emissions. Emissions of SO2 can be 

controlled by limiting sulfur content in the fuel, limiting fuel oil usage, or by a postcombustion flue gas desulfurization (FGD) system. The fuel for this project is natural 

gas with a maximum expected sulfur content of 2.0 grains per 100 standard cubic feet. In 

addition, when the unit is firing fuel oil, the unit will fire ultra-low sulfur fuel oil which 

has a sulfur content of 0.0015 percent sulfur by weight. 

To date, no supplemental SO2 emission controls, such as flue gas desulfurization system 

(FGD) systems have been imposed on simple cycle combustion turbines. Such a system 

would be both technically and economically prohibitive.

 Therefore, BACT for GEC Units 1 and 2 CCCTs is the use of natural gas or 

ULSFO. The basis of this determination is firing natural gas and ULSFO on the 

limitation on hours of operation as previously stated. 
6.0 GEC Units 1 and 2 

JEA GEC CCCT Conversion CCCTs H2SO4 BACT Analysis 

149588 6-1 

6.0 GEC Units 1 and 2 CCCTs H2SO4 BACT Analysis 

 The objective of this analysis was to determine BACT for sulfuric acid mist 

(H2SO4) emissions from GEC Units 1 and 2 CCCTs. Emissions of H2SO4 can be 

controlled by limiting sulfur content in the fuel. The natural gas and ULSFO to be utilized 

for GEC Units 1 and 2 CCCTs will contain less than 2 grains per 100 standard cubic feet 

and 0.0015 percent sulfur by weight, respectively. The selection of low sulfur fuel (both 

natural gas and ULSFO) provides inherently low SO2 emissions, thus controlling the 

formation of sulfuric acid mist. In addition, no supplemental SO3 emission controls, such as 

FGD systems or H2SO4 abatement systems, have been imposed on natural gas fired or 

ULSFO fired combustion turbines by regulatory agencies. 

 Therefore, BACT for GEC Units 1 and 2 CCCTs is the use of good combustion 

controls while firing natural gas or ULSFO. The basis of this determination is firing 

natural gas and ULSFO on the limitation on hours of operation as previously stated. 
7.0 GEC Units 1 and 2 

JEA GEC CCCT Conversion CCCTs Cooling Tower 

149588 7-1 

7.0 GEC Units 1 and 2 CCCTs Cooling Tower 

A new eight-cell linear mechanical draft cooling tower will be used to dissipate 

heat from the condensing water of the Project’s steam turbine. Particulate from cooling 

towers is generated by the presence of dissolved and suspended solids in the cooling 

tower circulation water, which is potentially lost as “drift” or moisture droplets that are 

suspended in the air moving out of the cooling tower. A portion of the water droplets 

emitted from the tower exhausts will evaporate, leaving the suspended or dissolved solids 

in the atmosphere. 

The particulate emissions from the cooling towers can be controlled by 

minimizing the amount of water drift that occurs and/or minimizing the amount of 

dissolved solids in the water. This can be accomplished by using high efficiency drift 

eliminators, a decreased number of cycles of circulating water concentration, or a 

combination of both. The number of cycles of water concentration is limited by the 

amount of water available for use, since lower levels of concentration require increased 

cooling tower blowdown and more water intake to offset the blowdown.

A review of drift eliminators as particulate control technology for cooling towers 

concluded that they are technically feasible. There are no significant energy, 

environmental, or economic impacts that would preclude the use of drift eliminators as 

particulate control technologies as presented in this evaluation. 

The proposed cooling tower BACT for this Project is the use of drift eliminators 

for particulate control, with a cooling tower design drift rate of 0.0005 percent. 
 Attachment 1 

JEA GEC CCCT Conversion Nox Control Technology Review List 

149588 A1-1

Attachment 1: NOx Control Technology Review List 
JEA GEC CCCT Conversion Attachment 1 

149588 A1-2 
JEA GEC CCCT Conversion Attachment 1 

149588 A1-3 
JEA GEC CCCT Conversion Attachment 1 

149588 A1-4 
JEA GEC CCCT Conversion Attachment 2 

CO Control Technology Review List 

149588 A2-1 

Attachment 2: CO Control Technology Review List
JEA GEC CCCT Conversion Attachment 2 

149588 A2-2 
JEA GEC CCCT Conversion Attachment 2 

149588 A2-3 
JEA GEC CCCT Conversion Attachment 2 

149588 A2-4