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. 149588JEA 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 NO x and CO BACT Analysis............................................... 3-1 3.1 Step 1--Identify All NO X Control Technologies......................................3-1 3.1.1 Water or Steam Injection ............................................................... 3-2 3.1.2 Dry Low-NO x Burners................................................................... 3-2 3.1.3 XONON ......................................................................................... 3-2 3.1.4 Selective Non-Catalytic Reduction................................................ 3-3 3.1.5 SCONO x ......................................................................................... 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-NO x Burners and Good Combustion Control ................ 3-6 3.2.2 CO Oxidation Catalyst................................................................... 3-6 3.2.3 SCONO x ......................................................................................... 3-7 3.3 Step 2--Eliminate Technically Infeasible NO X Options ..........................3-7 3.3.1 Water or Steam Injection ............................................................... 3-7 3.3.2 Dry Low-NO x Burners................................................................... 3-8 3.3.3 XONON ......................................................................................... 3-8 3.3.4 Selective Non-Catalytic Reduction................................................ 3-8 3.3.5 SCONO x ......................................................................................... 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-NO x Burners and Good Combustion Control ................ 3-9 3.4.2 CO Oxidation Catalyst................................................................. 3-10 3.4.3 SCONO x ....................................................................................... 3-10 3.5 Step 3-Rank Combined NO X and CO Control Technology Effectiveness.......................................................................................... 3-10 3.6 Step 4-Evaluate Most Effective Combined NO X and CO Controls.......3-12 3.6.1 SCONO x Energy Impacts ............................................................ 3-13 3.6.2 SCONO x Environmental Impacts ................................................ 3-13JEA 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 SCONO X ........................................................ 3-16 3.6.7.1 Capital Costs for SCR (2.0 ppmvd) / Oxidation Catalyst and SCONO x . .......................................................................... 3-16 3.6.7.2 Operating Costs for SCR/Oxidation Catalyst Versus SCONO x . ................................................................................. 3-19 3.6.7.3 Total Annualized Costs for SCR (2 ppmvd) / Oxidation Catalyst Versus SCONO x ........................................................ 3-20 3.6.7.4 Conclusions............................................................................... 3-20 3.7 Step 4-Evaluate Most Effective NO X Controls......................................3-22 3.7.1 Economic Impacts for SCR ......................................................... 3-22 3.7.2 Economic Impacts for SCR (2.0 ppmvd NO X ) 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 NO X BACT ..................................................................................3-29 3.9 Step 5-Select CO BACT ........................................................................ 3-29 4.0 GEC Units 1 and 2 CCCTs PM/PM 10 BACT Analysis ....................................... 4-1 5.0 GEC Units 1 and 2 CCCTs SO 2 BACT Analysis................................................ 5-1 6.0 GEC Units 1 and 2 CCCTs H 2 SO 4 BACT Analysis............................................ 6-1 7.0 GEC Units 1 and 2 CCCTs Cooling Tower......................................................... 7-1 Attachment 1: NO x Control Technology Review List................................................. A1-1 Attachment 2: CO Control Technology Review List .................................................. A2-1JEA 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 NO x and CO Emissions from Alternate Control Technologies for GEC Units 1 and 2 CCCTs (per CT)......................... 3-12 Table 3-4 NO x /CO Combined Control Alternative Capital Cost ($) for Each CCCT (GEC Units 1 and 2)................................................................... 3-18 Table 3-5 NO x /CO Combined Control Alternative Annualized Cost ($) for Each CCCT (GEC Units 1 and 2).......................................................... 3-21 Table 3-6 NO x Emission Control Alternative Capital Cost for GEC Units 1 and 2 .......................................................................................... 3-23 Table 3-7 NO x 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 NO x BACT Determination ........................ 3-29 Table 3-11 GEC Units 1 and 2 CCCTs CO BACT Determination.......................... 3-30JEA 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
H 2 SO 4 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 NO x Burner MBtu Million British Thermal Unit MW Megawatt NESCAUM Northeast States for Coordinated Air Use Management NO 2 Nitrogen Dioxide NO x Nitrogen Oxides NSPS New Source Performance Standard NSR New Source Review OAQPS Office of Air Quality Planning And StandardsJEA GEC CCCT Conversion Acronym List

149588 AL-2 OEM Original Equipment Manufacturer Pb Lead PM/PM 10 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 SO 2 Sulfur Dioxide SO 3 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 Compound1.0 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 noweach 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 dr aft 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 CCC T, 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 (SO 2 ), nitrogen oxides (NO x ), carbon monoxide (CO), particulate matter (PM)/PM 10 , and sulfuric acid mist (H 2 SO 4 ). The Project is not subject to review for volatile organic compounds (VOC), lead (Pb), hydrogen sulfide (H 2 S), 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 emission1.0 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. Lo wer emitting practices can include fuelcleaning, 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 feasibilityof 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 preclud e the successful use of the control option because of physical, chemical, and engineering principles. After completion of this step, technically infeasible options ar e 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 by1.0 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 perfor med 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 annualquantity 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 an d 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
NO x DLN/SCR (for natural gas combustion) WI/SCR (for ULSFO combustion) Natural Gas: 2.0 ppmvd @ 15% O 2

ULSFO: 8.0 ppmvd @ 15% O 2 Stack Test, 3-Run Avg. 24-hr block

CO Good Combustion Controls Natural Gas: 7.6 ppmvd @ 15% O 2 with DBs; 4.1 ppmvd @ 15% O 2 w/o DBs; ULSFO: 8.0 ppmvd @ 15% O 2 Stack Test, 3-Run Avg. 24-hr block

PM/PM 10 Natural Gas (2.0 gr S/100 SCF) ULSFO (0.0015% S)
Good Combustion Practices 10% Opacity USEPA Method 9
Fuel Sulfur Records NA

SO 2 Natural Gas (2.0 gr S/100 SCF) ULSFO (0.0015% S) NA Fuel Sulfur Records NA

H 2 SO 4 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/PM 10 Drift Eliminators 0.0005% drift rate CEMS = Continuous Emissions Monitoring System. SCR = Selective Catalytic Reduction. ULSFO = Ultra-low sulfur fuel oilJEA 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 NO x --15 ppm at 15 percent O 2 or 54 ng/J of useful output (0.43 lb/MWh) – new turbines firing natural gas with > 850 MBtu/hr heat input.

x NO x --42 ppm at 15 percent O 2 or 160 ng/J of useful output (1.3 lb/MWh) – new turbines firing fuel oil with > 850 MBtu/hr heat input.

x NO x --96 ppm at 15 percent O 2 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 SO 2 --The rule includes a fuel emission standard or a fuel sulfur standard equivalent to potential SO 2 emissions of 0.060 lb SO 2 /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 NO x 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 1 a or 2 a Natural Gas, 100% Load, Duct Firing, at ISO Conditions

NO x , ppmvd at 15% O 2 10.3
NO x , lb/h 72.7
NO x , lb/MBtu (HHV) 0.0369 CO, ppmvd at 15% O 2 7.6 CO, lb/h 32.7 CO, lb/MBtu (HHV) 0.0166
PM/PM 10 (front and back), lb/h b 29.1
PM/PM 10 (front and back), lb/MBtu (HHV) b 0.0148
SO 2 , lb/h c 8.01
SO 2 , lb/MBtu (HHV) c 0.0041
H 2 SO 4 , lb/h b 4.88
H 2 SO 4 , lb/MBtu b 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/PM 10 and H 2 SO 4 values include the affects of 20 percent SO 2 oxidation in the CT and 10 percent SO 2 oxidation in the duct burners.

c SO 2 values include the effects of 3 percent SO 2 oxidation in the Selective Catalytic Reduction System. Based on a natural gas sulfur content of 2 grains/100 scfJEA 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 Firing a

NO x , tons per year (tpy) 318.43 CO, tpy 143.23
PM/PM 10 (front and back), tpy 127.46
SO 2 , tpy 35.08
H 2 SO 4 , 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
SCONO x 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
SCONO x 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/A3.0 GEC Units 1 and 2 JEA GEC CCCT Conversion NO x and CO BACT Analysis

149588 3-1 

### 3.0 GEC Units 1 and 2 NO x 

### and CO BACT Analysis

This section presents the top-down, five-step BACT process used to evaluate and determine the Project’s NO x and CO emissions limits for GEC Units 1 or 2 CCCT. As this analysis will demonstrate, the proposed NO x BACT was determined to be the use of selective catalytic reduction to achieve an emission limit of 2 ppmvd at 15 percent O 2 while firing natural gas and 8.0 ppmvd at 15 percent O 2 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 NO X 

### 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 NO x emissions limit that is being evaluated. The results of this search for all combined-cycle combustion turbines are listed in Attachment 1: NO X Control Technology Review List. NO x is defined as the combination of nitrogen oxide (NO) and nitrogen dioxide (NO 2 ). Typically, the NO x that is formed in combustion turbines consists of 60 percent NO, with the balance occurring as NO 2 . NO x emissions formed through the oxidation of the fuel bound nitrogen are called fuel NO x . NO x emissions formed through the oxidation of a portion of the nitrogen contained in the combustion air are called thermal NO x and are a function of combustion temperature. NO x production in a gas turbine combustor occurs predominantly within the flame zone, where localized high temperatures sustain the NO x -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 NO x formation control and post-combustion emission reduction. An in-combustor NO x formation control process reduces the quantity of NO x formed in the combustion process. A post-combustion technology reduces the NO x emissions in the flue gas stream after the NO x has been formed in the combustion process. Both of these methods may be used alone or in combination to achieve the various degrees of NO x emissions required. The six different types of emission controls reviewed by this BACT analysis are as noted below.

x In-Combustor Type:3.0 GEC Units 1 and 2 JEA GEC CCCT Conversion NO x and CO BACT Analysis

149588 3-2  Water/Steam Injection.

 Dry Low-NO x (DLN) Burners.

 Xonon.

x Post-Combustion Type:

 Selective Non-Catalytic Reduction (SNCR).

 SCONO x .

 Selective Catalytic Reduction (SCR). The rationale behind whether the above technologies are evaluated as NO x control for BACT is included in the following subsections.

3.1.1 Water or Steam Injection NO x 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 NO x formation by reducing the peak flame temperature. The degree of reduction in NO x 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-NO x

Burners NO x 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-NO x (DLN) burners as a way to reduce flame temperature is one common NO x 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 NO x emissions. Most industry gas turbine manufacturers today have developed this type of lean premix combustion system as the state of the art for NO x 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 NO x emissions without raising, and3.0 GEC Units 1 and 2 JEA GEC CCCT Conversion NO x and CO BACT Analysis

149588 3-3 possibly even lowering, emissions of CO and unburned hydrocarbons. XONON uses a proprietary flameless process in which fuel and air react on th e surface of a catalyst in the turbine combustor to produce energy in the fo rm 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 NO x into nitrogen and water vapor by reacting the flue gas with a reagent. SNCR systems can use either ammonia (Thermal DeNO x ) or urea (NO x OUT) as reagents. The SNCR system is dependent upon the reagent injector location and temperature to achieve proper reagent/flue gas mixing for maximum NO x reduction. SNCR systems require a fairly narrow temperature range for reagent injection in order to achieve a specific NO x reduction efficiency. The optimum temperature range for injection of ammonia or urea is 1,550° to 1,900° F. The NO x 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 NO x 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 w ill be eliminated from further evaluation in this BACT analysis.

3.1.5 SCONO x A second, post-combustion technology from EmeraChem, LLC is EM X TM (SCONO x ), which utilizes a coated oxidation catalyst to remove both NO x and CO without a reagent such as ammonia. EmeraChem purchased SCONO X from Goal Line Environmental Technologies and ABB Alstom Power. The SCONO x system utilizes hydrogen (H 2 ) (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 (K 2 CO 3 ) to oxidize both NO x and CO, thereby reducing total plant emissions. CO emissions are decreased by the oxidation of CO to carbon dioxide (CO 2 ). The catalyst is installed in the flue gas at a point where the temperature is between 300° to 700° F. EmeraChem guarantees the3.0 GEC Units 1 and 2 JEA GEC CCCT Conversion NO x and CO BACT Analysis

149588 3-4 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 SCONO x catalyst is very susceptible to fouling by sulfur in the flue gas. The impact of sulfur can be minimized by a sulfur absorption SCOSO x catalyst. The SCOSO x catalyst is located upstream of the SCONO x catalyst. The SO 2 is oxidized to sulfur trioxide (SO 3 ) by the SCOSO x catalyst. The SO 3 is then deposited on the catalyst and removed from the catalyst when it is regenerated. The SCOSO x catalyst is regenerated along with the SCONO x catalyst. The SCONO x 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 SCOSO x 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 SCOSO x catalyst will also require washing, but due to limited operating experience with the SCOSO x catalyst, it is uncertain how often this will be required. However, it is expected that the SCOSO x catalyst will require annual washing. The current SCONO x 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 SCONO x 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 SCONO x system and was apprehensive about applying SCONO x 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 SCONO x system currently operating at the Federal Cold Storage Cogeneration facility in California.

3.1.6 Selective Catalytic Reduction Another post-combustion method of NO x 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 NO x 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 gas3.0 GEC Units 1 and 2 JEA GEC CCCT Conversion NO x and CO BACT Analysis

149588 3-5 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 NO x 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 NO x value is below the permitted value. This may result in excessive ammonia “slip” being discharged to the atmosphere with little or no improvement in NO x emissions. Reduction of the NO x 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 NO x . The proper distribution of the gas and ammonia is difficult to obtain when both reactants, NO x and NH 3 , 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 NO x 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 NO x 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.3.0 GEC Units 1 and 2 JEA GEC CCCT Conversion NO x and CO BACT Analysis

149588 3-6 Typically, measures taken to minimize the formation of NO x 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-NO x (DLN) Burners.

x Post-Combustion Type:

 Oxidation Catalyst.

 SCONO x . 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-NO x

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 NO x control method. These improved combustion characteristics have allowed minimization of CO emissions without sacrificing NO x control performance. For this reason, the use of low NO x 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 NO x emissions is the use of an oxidation catalyst to convert the CO to CO 2 . 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 CO3.0 GEC Units 1 and 2 JEA GEC CCCT Conversion NO x and CO BACT Analysis

149588 3-7 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 SCONO x Another CO control technology that was previously discussed for NO x control is the SCONO x process. The SCONO x system reduces CO emissions by oxidizing the CO to CO 2 . 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 SCONO x system currently operating at the Federal Cold Storage Cogeneration facility in California.



### 3.3 Step 2--Eliminate Technically Infeasible NO X 

### 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 NO X BACT analysis and determine if they are technically feasible. Table 3-1 summarizes the evaluation of the technically feasible NO X options.

3.3.1 Water or Steam Injection Water or steam injection can be an effective NO X 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-NO x burners has replaced the use of wet controls, except for certain cases, such as oil firing. New dry low-NO X burners can achieve lower levels of NO X 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.3.0 GEC Units 1 and 2 JEA GEC CCCT Conversion NO x and CO BACT Analysis

149588 3-8 3.3.2 Dry Low-NO x

Burners Dry low-NO x burners are a demonstrated technology of controlling NO X emissions from a combined-cycle combustion turbine and commercially available from several vendors. Dry low-NO X 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 NO x 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 NO x 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 temperatur e 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 SCONO x The application of this technology is currently limited to natural gas combined cycle combustion turbine units under 40 MW. However, EmeraChem, LLC is EM X TM (SCONO x ) offers their product for GE 7FAs which makes it available. In addition, SCONO X 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, SCONO x will be evaluated in the BACT for NO x control.

3.3.6 Selective Catalytic Reduction Selective Catalyst Reduction (SCR) systems are a demonstrated technology of controlling NO X emissions from a combined-cycle combustion turbine and commercially3.0 GEC Units 1 and 2 JEA GEC CCCT Conversion NO x and CO BACT Analysis

149588 3-9 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 NO X removal. Not a primary control technology for natural gas fired turbines. Dry Low-NO X 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. SCONO X 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-NO x

Burners and Good Combustion Control The development of good combustion practice improvements with state of the artDLN burners are a demonstrated technology of controlling CO emissions from a simplecycle combustion turbine and commercially available from several vendors. DLN3.0 GEC Units 1 and 2 JEA GEC CCCT Conversion NO x and CO BACT Analysis

149588 3-10 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 c onsidered technically feasible and will be considered further.

3.4.3 SCONO x The application of this technology is currently limited to natural gas combined cycle combustion turbine units under 40 MW. However, EmeraChem, LLC is EM X TM (SCONO x ) offers their product for GE 7FAs which makes it available. In addition, SCONO X 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, SCONO x 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 SCONO X Yes Yes



### 3.5 Step 3-Rank Combined NO X 

### and CO Control Technology Effectiveness

In-combustor NO x and CO control by advanced co mbustion controls using dry low NO x burners is the least stringent control technology considered for the Project. However, the use of a combination SCR/oxidation catalyst system or the SCONO x system are technologies capable of achieving significantly lower emissions than the application of dry low NO x burners alone. Because the SCONO x system is capable of reducing NO x and CO, emissions, the NO x and CO BACT analyses have been combined to avoid double counting3.0 GEC Units 1 and 2 JEA GEC CCCT Conversion NO x and CO BACT Analysis

149588 3-11 the SCONO x 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 NO x 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 NO x 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 SCONO x system to reduce outlet NO x emissions from the natural gas fired CTG/HRSG with duct burner to the NO x level of 2.0 ppmvd and CO emissions to 2.0 ppmvd. The following evaluation considers energy, environmental, and economic impacts for the NO x and CO combined technology scenarios evaluated. Table 3-3 outlines the expected NO x and CO emissions rates from the evaluated emissions control alternatives of dry low NO x burners (i.e. good combustion controls), SCR/CO catalyst, and SCONO x . SCR/CO catalyst and SCONO x are considered the most stringent NO x and CO emissions control alternatives as they achieve the lowest outl et emission rate. Therefore, if SCONO x is not found viable via energy, environmental, or economic impacts for the combined emissions reduction, the SCONO x technology will be eliminated from consideration, and a BACT evaluation would be done for control of NO x and CO emissions separately.3.0 GEC Units 1 and 2 JEA GEC CCCT Conversion NO x and CO BACT Analysis

149588 3-12 Table 3-3 Estimated NO x 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 SCONO x NO x Emissions ppmvd (at 15 percent O 2 ) 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%
NO x Emission Reduction (tpy) Base 256.6 256.6

CO Emissions ppmvd (at 15 percent O 2 ) 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 nat ural gas, 100% Load, Duct Firing, at ISO Conditions.



### 3.6 Step 4-Evaluate Most Effective Combined NO X 

### and CO Controls In the following subsections, the NO X 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: SCONO X , SCR, and Oxidation Catalyst.3.0 GEC Units 1 and 2 JEA GEC CCCT Conversion NO x and CO BACT Analysis

149588 3-13 3.6.1 SCONO x

Energy Impacts The use of a SCONO x system will increase the energy requirements on the system compared to use of dry low NO x burners alone. The SCONO x 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 SCONO x 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 SCONO x system will have minimal effect on power consumption thatwill be necessary to operate the damper actuators and regeneration system. WahlcoMetroflex estimated that approximately 15 kW would be consumed during operation of each SCONO x 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 SCONO x system. The annualized cost of natural gas consumption is included in the annualized cost analysis.

3.6.2 SCONO x

Environmental Impacts The SCONO x 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 CO 2 , a greenhouse gas. There is currently a worldwide effort to reduce industrial emissions of CO 2 because of its contribution to global climate change. Installation of a SCONO x system would directly counter this initiative. The SCONO x catalyst will oxidize approximately 1.0 percent of the SO 2 in the flue gas to SO 3 . The SO 3 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 PM 10 .3.0 GEC Units 1 and 2 JEA GEC CCCT Conversion NO x and CO BACT Analysis

149588 3-14 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 NO x 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 Che mical 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 NO x 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 Treasu re Coast air permit, an ammonia slip design value of 5 ppmvd at 15 percent O 2 is used for this analysis. The SCR catalyst will oxidize approximately 2 to 3 percent of the SO 2 in the flue gas to SO 3 . Once the flue gas cools below approximately 600° F, the ammonia present in the flue gas may react with SO 3 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 SO 3 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 par ticulate matter emitted in the flue gas. The particulate material will predominately consist of matter less than PM 10 . As the catalyst gradually deactivates, more ammonia must be injected to compensate and maintain the desired NO x 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 SO 2 in the flue gas will oxidize to SO 3 . The higher the operating temperature, the higher the SO 2 to SO 3 oxidation potential. It is estimated that approximately 20 percent of the SO 2 in the flue gas will oxidize to SO 3 as a result of the oxidation catalyst being installed after the combustion turbine outlet with high temperatures. The SO 3 will react with the moisture in the flue gas to form sulfuric acid mist (H 2 SO 4 ). The increase in H 2 SO 4 emissions would increase PM 10 emissions.3.0 GEC Units 1 and 2 JEA GEC CCCT Conversion NO x 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 CO 2 , a greenhouse gas. There is currently a worldwide effort to reduce industrial emissions of CO 2 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 SCONO X The use of an SCR/oxidation catalyst or SCONO x 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 SCONO x . Table 3-4 presents the capital costs for installing an SCR/oxidation catalyst and SCONO x system on each CCCT during natural gas firing to achieve a NO x outlet emission level of 2.0 ppmvd and a CO outlet emission rate of 2.0 ppmvd. Note, the same SCR/oxidation catalyst and SCONO x 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, st orage, 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 SCONO x system includes the catal yst, regenerative gas distribution system, catalytic reactor housing, controls and instrumentation, and freight. The BOP cost for the SCR/oxidation catalyst and SCONO x 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. The3.0 GEC Units 1 and 2 JEA GEC CCCT Conversion NO x and CO BACT Analysis

149588 3-17 total capital investment was calculated as the su mmation 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 SCONO x system are percentages of the SCONO x 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, NO x Emissions: Best Available Control Technology, A Gas Turbine Permitting Guidebook in November 1991 and list under NO x control cost (Page 5-5) the following text: “Based on experience with other cost m ethodology sources, the contingency factorrecommended 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 NO x and CO to 2.0 ppmvd and 2.0 ppmvd, respectively is estimated to be $5,243,000. The total capital investment for the SCONO x control system is calculated as the sum of the total direct and indirect capital costs per OAQPS cost methods. The total

10 U.S. Environmental Protec tion Agency, A Standard Procedure for Cost Analysis of Pollution Control Operations: Volume I, EPA 6 00/8-79-018a, June 1979.

11 U.S. Environmental Protection Agency, In dustrial Boiler SO 2 Cost Report , EPA 450/3-85-011, November 1984.

12 U.S. Environmental Protection Agency, M unicipal Waste Combustors – Background Information for Proposed Sta ndards: Control of NO x Emissions , EPA 450/3-89-2 7d, August 1989.3.0 GEC Units 1 and 2 JEA GEC CCCT Conversion NO x and CO BACT Analysis

149588 3-18 capital investment for each CCCT controlling NO x and CO to 2.0 ppmvd and 2.0 ppmvd, respectively is estimated to be $27,912,000.

Table 3-4 NO x /CO Combined Control Alternative Capital Cost ($) for Each CCCT (GEC Units 1 and 2)

DLN SCONO x ($) SCR/OX Cat ($) 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

SCONO x 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 SCONO x . 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 – Catalyst3.0 GEC Units 1 and 2 JEA GEC CCCT Conversion NO x and CO BACT Analysis

149588 3-19 3.6.7.2 Operating Costs for SCR/Oxidation Catalyst Versus SCONO x . Table 3-5 presents the annualized ope rating costs using a SCR/oxidation catalyst and SCONO x system to achieve NO x 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 r ate 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 e quivalent operating hours. Ammonia consumption rates were based on a stoichiometric ratio of 1.1 for reacting NO x . 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 SCONO x system increases the energy requirements of the project. The SCR system requires vaporizers and blowers to vaporize and dilute the ammonia reagent for injection. SCONO x 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 SCONO x /SCOSO x catalyst. Therefore, the SCONO x system will include the additional O&M cost for catalyst washing. The indirect annual costs include capital recover y, 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 NO x and CO BACT Analysis

149588 3-20 3.6.7.3 Total Annualized Costs for SCR (2 ppmvd) / Oxidation Catalyst Versus SCONO x . 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 SCONO X 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 SCONO x 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 NO x and CO BACT Analysis

149588 3-21 Table 3-5 NO x /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 15 5,000 Assumes 1.1 stoichiometric ratio Natural Gas Consumption N/A 66,000 0 Power Consumption N/A 11 0,000 205,000 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 1,952,0003.0 GEC Units 1 and 2 JEA GEC CCCT Conversion NO x and CO BACT Analysis

149588 3-22 

### 3.7 Step 4-Evaluate Most Effective NO X 

### Controls The following section identifies economic impacts of the NO x 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 NO x and CO as listed in Section 3.6.

3.7.1 Economic Impacts for SCR The control of NO x 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 NO x 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 NO x 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 NO X ) 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 NO X

). 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 NO x to 2.0 ppmvd is estimated to be $4,421,000.

3.7.2.2 Total Annualized Costs for SCR (2.0 ppmvd NO X

). 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 be3.0 GEC Units 1 and 2 JEA GEC CCCT Conversion NO x 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 NO x removed.

Table 3-6 NO X Emission Control Alternative Capital Cost for GEC Units 1 and 2

DLN SCR ($) Remarks Direct Capital Cost Cost based on em issions in Table 3-3. Catalyst N/A 1,102,000 Estimated from CERAM Catalyst R. Housing /Duct work N/A 630,000 Estimated from Turner EnviroLogic

Control/Instrumenta tion 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 40 1,000 10% of DC Engineering and Supervision N/A 401,000 10% of DC Construction & Field Expens e 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 4,421,0003.0 GEC Units 1 and 2 JEA GEC CCCT Conversion NO x and CO BACT Analysis

149588 3-24 Table 3-7 NO X 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, installati on, 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

NO x Annual Emissions, tpy 318.4 61.8 Emission taken from Table 3-3
NO x Emissions Reduction, tpy N/A 256.6 Emissions calculated in Table 3-3

NO x Total Cost Effectiveness, $/ton N/A 6,719 Total Analyzed Cost/Emissions Reduction3.0 GEC Units 1 and 2 JEA GEC CCCT Conversion NO x 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 NO x 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 natural3.0 GEC Units 1 and 2 JEA GEC CCCT Conversion NO x 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 recover y factor (CRF) and the total installed costs. F iring 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 NO x 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 em issions 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 (D C +IC) 1,437,000 Less Catalyst N/ A 615,000 Catalyst is view ed as an O&M Value. Total Capital Investment, TCI Base 822,0003.0 GEC Units 1 and 2 JEA GEC CCCT Conversion NO x 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, installati on, 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 Reduction3.0 GEC Units 1 and 2 JEA GEC CCCT Conversion NO x and CO BACT Analysis

149588 3-29 

### Step 5-Select NO X 

### BACT

Based on the cost effectiveness value for the SCR catalyst it is determined that add-on controls to further reduce NO X emissions are warranted. JEA has determined that the top NO x control alternative when firing natural gas (primary fuel), Dry Low-NOX (DLN) Burners with SCR catalyst, represents NO x BACT for GEC Units 1 and 2 CCCTs, corresponding to an emissions limit of 2 ppmvd at 15 percent O 2 on a 24 hour average basis. The top NO x control alternative when firing ULSFO (backup fuel), Water Injection (WI) with SCR catalyst, represents NO x BACT for the GEC Unit 1 and Unit 2, corresponding to an emissions limit of 8.0 ppmvd at 15 percent O 2 on a 24 hour average basis. Table 3-10 summarizes the Project’s NO x BACT determination for GEC Units 1 and 2.

Table 3-10 GEC Units 1 and 2 CCCTs NO x BACT Determination

Control Technology Emission Limit DLN Burners with SCR (for natural gas combustion) NG: 2.0 ppmvd @ 15% O 2 (24-hr avg.)

WI/SCR (for ULSFO combustion) ULSFO: 8.0 ppmvd @ 15% O 2 (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 asthe 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 NO X 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 emissions3.0 GEC Units 1 and 2 JEA GEC CCCT Conversion NO x 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 FMPACane 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 O 2 and 4.1 ppmvd at 15 percent O 2 , 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 O 2 on a 24-hour block. The CEMS average limit firing natural gas or ULSFO is proposed as 8.0 ppmvd @ 15% O 2, 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% O 2 (stack test, 3-run average) with DBs; 4.1 ppmvd @ 15% O 2 (stack test, 3-run average) w/o DBs; ULSFO: 8.0 ppmvd @ 15% O 2 (stack test, 3-run average) NG or ULSFO: 8.0 ppmvd @ 15% O 2 (CEMS, 24-hour block average)4.0 GEC Units and 2 JEA GEC CCCT Conversion CCCTs PM/PM 10 BACT Analysis

149588 4-1 

### 4.0 GEC Units 1 and 2 CCCTs PM/PM 10 

### BACT Analysis

The objective of this analysis was to determine BACT for PM/PM 10 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/PM 10 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 p revious 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 SO 2 BACT Analysis

149588 5-1 

### 5.0 GEC Units 1 and 2 CCCTs SO 2 

### BACT Analysis

The objective of this analysis was to determine BACT for SO 2 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 SO 2 emissions. Emissions of SO 2 can becontrolled 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 un it will fire ultra-low sulfur fuel oil which has a sulfur content of 0.0015 percent sulfur by weight. To date, no supplemental SO 2 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 H 2 SO 4 BACT Analysis

149588 6-1 

### 6.0 GEC Units 1 and 2 CCCTs H 2 

### SO 4 

### BACT Analysis

The objective of this analysis was to determine BACT for sulfuric acid mist (H 2 SO 4 ) emissions from GEC Units 1 and 2 CCCTs. Emissions of H 2 SO 4 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, respec tively. The selection of low sulfur fuel (both natural gas and ULSFO) provides inherently low SO 2 emissions, thus controlling the formation of sulfuric acid mist. In addition, no supplemental SO 3 emission controls, such as FGD systems or H 2 SO 4 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 No x Control Technology Review List

149588 A1-1



### Attachment 1: NO x 

### Control Technology Review ListJEA GEC CCCT ConversionAttachment 1149588A1-2JEA GEC CCCT ConversionAttachment 1149588A1-3JEA GEC CCCT ConversionAttachment 1149588A1-4JEA GEC CCCT Conversion Attachment 2 CO Control Technology Review List

149588 A2-1 

### Attachment 2: CO Control Technology Review ListJEA GEC CCCT ConversionAttachment 2149588A2-2JEA GEC CCCT ConversionAttachment 2149588A2-3JEA GEC CCCT ConversionAttachment 2149588A2-4