Notice of Intent Application

Transcription

1 Utah Power Plant Units 1, 2, and 3 Repowering Notice of Intent Application Submitted to Utah Division of Air Quality Prepared for Kennecott Utah Copper LLC Prepared by: December 2010

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3 Notice of Intent Application Submitted to Utah Division of Air Quality Prepared for Kennecott Utah Copper LLC December 2010

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5 Contents Acronyms and Abbreviations... v 1.0 Introduction Project Description Facility Description Project Description Emissions Summary Regulatory Review State Air Permitting Requirements Federal Air Permitting Requirements Emission Standards Monitoring and Reporting Netting Analysis Definitions Demonstrating a Minor Net Increase Netting Demonstration for the Repowering Project Best Available Control Technology BACT Analysis Requirements Applicability Top-down BACT Process BACT Analysis Energy Impact Analysis Environmental Impact Analysis Combustion Turbine Generator Comparable Permitted Emissions Combustion Turbine Generator BACT Combustion Turbine BACT for NO x Duct Burner BACT for NO x Combustion Turbine BACT for CO and VOC Duct Burner BACT for CO and VOC BACT Analysis for SO Theoretical Formation and Control of SO BACT Analysis for PM Combustion Turbine BACT for PM Duct Burner BACT for PM Startup and Shutdown Analysis BACT Summary Greenhouse Gas Emissions Analysis GHG Tailoring Rule Netting Demonstration for GHG Emissions \\SNOWBIRD\PROJ\KENNECOTTUTAHCOPPER\379707MAPBING\NOI_2010\FINAL iii

6 CONTENTS (CONTINUED) 7.3 Proposed CO 2e Plantwide Applicability Limit Noncriteria Pollutant Impacts Model Selection Receptors Building Downwash Meteorological Data Model Results References Tables 2-1 Startup and Shutdown Conditions 3-1 Hourly Emissions for Unit 5 Combustion Turbine with Duct Burner 3-2 Annual Emissions Unit 5 with Duct Burner 5-1 Annual PTE Emissions Unit UPP Units 1, 2, and 3 Average Actual Emissions for Past 2 Years 5-2 Netting Demonstration 6-1 NO x Control Alternatives KUC NO x BACT Analysis 6-2 CO and VOC Control Technology Ranking for Combustion Turbines 6-3 BACT Startup/Shutdown Emissions 6-4 BACT and LAER Analysis 7-1 Potential Annual Emissions Unit GHG Netting Demonstration 8-1 Source Parameters 8-2 Combustion Turbines Installation HAP Modeling Results Figures 2-1 Site Location Map 2-2 Proposed Site Layout Drawing 2-3 Process Flow Diagram of Unit 5 with Steam Supply to the Existing Units 1, 2, and 3 Steam Turbines 8-1 KUC UPP Receptor Grid 8-2 Magna, Utah 5-Year Wind Rose Attachment Input and Output Modeling Files Appendices A RBLC Summary B Emissions Calculations C HAPs Analysis iv IS SLC\KUC UPP NOI FINAL_V4.DOCX

7 Acronyms and Abbreviations F degree(s) Fahrenheit AO approval order BACT best available control technology CAA Clean Air Act CatOx catalytic oxidation CFR Code of Federal Regulations CO carbon monoxide CO 2 carbon dioxide CO 2e carbon dioxide equivalent DLN dry low nitrogen oxide EPA U.S. Environmental Protection Agency GHG greenhouse gas HAP hazardous air pollutant hr hour(s) HRSG heat recovery steam generator KUC Kennecott Utah Copper, LLC LAER lowest achievable emission rate lb pound(s) mg/m 3 milligram(s) per cubic meter MMBtu million British thermal units MW megawatt(s) NAAQS National Ambient Air Quality Standards NAD83 North American Datum of 1983 NED National Elevation Dataset NO 2 nitrogen dioxide NOI Notice of Intent NO x nitrogen oxide NSCR non-selective catalytic reduction NSPS New Source Performance Standards NSR new source review O 2 PAL PM oxygen plantwide applicability limit particulate matter IS SLC\KUC UPP NOI FINAL_V4.DOCX v

8 ACRONYMS AND ABBREVIATIONS (CONTINUED) PM 10 PM 2.5 PPA ppm ppmvd PSD PTE RACT RBLC scf SCR SIP SNCR SO 2 SO 3 tpy UAC UDAQ UPP UTM VOC particulate matter less than 10 micrometers in aerodynamic diameter particulate matter less than 2.5 micrometers in aerodynamic diameter pre-project actual part(s) per million part(s) per million by volume, dry prevention of significant deterioration potential to emit reasonable available control technology RACT/BACT/LAER Clearinghouse standard cubic foot (feet) selective catalytic reduction State Implementation Plan selective non-catalytic reduction sulfur dioxide sulfur trioxide tons per year Utah Administrative Code Utah Division of Air Quality Utah Power Plant Universal Transverse Mercator volatile organic compound vi IS SLC\KUC UPP NOI FINAL_V4.DOCX

9 1.0 Introduction Kennecott Utah Copper, LLC (KUC) is submitting this Notice of Intent (NOI) to secure an approval order (AO) to repower Units 1, 2, and 3 at the Utah Power Plant (UPP) in Salt Lake County. KUC is proposing the shutdown of the Units 1, 2, and 3 boilers and the addition of one combustion turbine in a one-on-one combined-cycle configuration. The combustion turbine will be equipped with a heat recovery steam generator (HRSG) that will include supplemental natural gas firing (duct firing). The gas turbine and duct burner will produce heat that will be made into steam in the HRSG for use in the existing steam turbines and generators from UPP Units 1, 2, and 3. The new combined-cycle combustion turbine unit will be designated as UPP Unit 5 (Unit 5). Commercial operation of the new Unit 5 will begin in 2014 and will have a nominal generating capacity of approximately 275 megawatts (MW) in combined-cycle operation with the existing Units 1, 2, and 3 steam turbine generators. Units 1, 2, and 3 boilers at the UPP will shut down prior to operation of the new gas turbine. State-of-the-art pollution controls are proposed for the combined-cycle combustion turbine and HRSG. Dry low nitrogen oxide (DLN) combustors and the selective catalytic reduction (SCR) system will control nitrogen oxide (NO x) emissions. The catalytic oxidation (CatOx) system will control carbon monoxide (CO) emissions and volatile organic compounds (VOCs), including formaldehyde. Good combustion practices and burning pipeline quality natural gas will minimize emissions of the remaining pollutants. The new emissions from the combustion turbine will be either partially or totally offset through a netting process by the reduction in emissions from shutting down the Boilers 1, 2, and 3. The proposed Unit 5 will result in a net reduction of emissions for most pollutants, some of them large reductions. The change in emissions from the proposed project has been calculated as follows: 1,544 tons per year (tpy) reduction of NO x, 92 tpy increase of CO, tpy reduction of particulate matter (PM) less than 10 micrometers in aerodynamic diameter (PM 10), 22 tpy reduction of primary PM less than 2.5 micrometers in aerodynamic diameter (PM 2.5), 1,961 tpy reduction of sulfur dioxide (SO 2), and 18 tpy increase of VOCs. For greenhouse gasses (GHGs) expressed as carbon dioxide (CO 2) equivalent (CO 2e), a plantwide applicability limit (PAL) is requested to limit CO 2e to a minor increase in plantwide emissions of less than 75,000 tons CO 2e. IS SLC\KUC UPP NOI FINAL_V4.DOCX 1-1

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11 2.0 Project Description 2.1 Facility Description The UPP is located near the city of Magna in Salt Lake County, Utah. A site location map is provided in Figure 2-1 and a proposed facility layout drawing is in Figure 2-2. Units 1, 2, and 3 at the UPP, which are involved with this project, are rated at 100 MW combined capacity. The UPP is currently operating under AO DAQE-AN , issued on May 14, Project Description The proposed Unit 5 will include repowering Units 1, 2, and 3 at the UPP. The existing Units 1, 2, and 3 boilers will cease operation before the new gas turbine will start operation in Figure 2-3 shows the process flow diagram of the new combined-cycle unit. Unit 5 will include one combustion turbine in a one-on-one combined-cycle configuration. The combustion turbine will be equipped with an HRSG that will include supplemental natural gas firing (duct firing) and inlet air cooling. The steam from the HRSG will be used to operate the existing Units 1, 2, and 3 steam turbines. A stack on the HRSG will be provided to release the exhaust gases into the atmosphere. The heat balance for power plant base load operation is shown in Appendix B for ambient air temperatures of 11 degrees Fahrenheit ( F), 59 F, and 94 F. In a combined-cycle plant, equipment is added to capture the waste heat from the combustion turbine generator. The hot exhaust gases from the combustion turbine generator flow through an HRSG to produce steam to drive the existing steam turbine generators. The HRSG will include systems to control Unit 5 stack emissions. The combustion turbine will use DLN combustion technology to minimize NO x formation. SCR and CatOx systems will be added to control emissions of NO x, CO, and VOCs. Use of pipeline-quality natural gas will minimize emissions of PM 10, PM 2.5, and SO 2. The maximum heat input for the combustion turbine with duct firing associated with the project is 2,082 million British thermal units per hour (MMBtu/hr) higher heating value. Pipeline-quality natural gas will be used in the combustion turbines and duct burners. With the addition of SCR, stack emissions of NO x will be limited to 2 parts per million by volume, dry (ppmvd), at 15 percent oxygen (O 2). The SCR process will use aqueous ammonia. Ammonia slip, or the concentration of unreacted ammonia in the exiting exhaust gas, will be limited to less than 5 ppmvd at 15 percent O 2. KUC will install a new aqueous ammonia storage and handling system at the UPP to supply the SCR. Stack emissions of CO will be limited by a CatOx system to 2 ppmvd at 15 percent O 2. VOC emissions at the stack will be limited to 2 ppmvd at 15 percent O 2. IS SLC\KUC UPP NOI FINAL_V4.DOCX 2-1

12 UPP UNITS 1, 2, AND 3 REPOWERING: NOTICE OF INTENT APPLICATION During the course of the year, Unit 5 will start up and shut down periodically. The amount of time that Unit 5 is shut down defines whether the subsequent startup is a cold or hot start (i.e., the longer the unit is shut down, the colder the temperature of the equipment that needs to be brought back up to proper temperature for operation). Startup conditions are defined in Table 2-1. Durations for each startup condition and shut down are also shown in Table 2-1. The startup cycle duration ends when the gas turbine reaches steady-state emission rates. The shutdown cycle duration begins when the combustion turbine is at base load and ends when fuel flow to the gas turbine is discontinued. On an annual basis, KUC estimates that Unit 5 will have a maximum of 330 hot starts and 15 cold starts. A maximum of 345 shut downs are anticipated per year. TABLE 2-1 Startup and Shutdown Conditions Condition Time since Shutdown Startup or Shutdown Duration (minutes) Annual Number of Events Hot Startup Less than 8 hours Cold Startup More than 72 hours Shutdown FIGURE 2-1 Site Location Map Magna, UT Project Location 2-2 IS SLC\KUC UPP NOI FINAL_V4.DOCX

13 UPP UNITS 1, 2, AND 3 REPOWERING: NOTICE OF INTENT APPLICATION FIGURE 2-2 Proposed Site Layout Drawing Existing UPP Proposed Unit 5 FIGURE 2-3 Process Flow Diagram of Unit 5 with Steam Supply to the Existing Units 1, 2, and 3 Steam Turbines IS SLC\KUC UPP NOI FINAL_V4.DOCX 2-3

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15 3.0 Emissions Summary Emissions estimates for Unit 5 include one combustion turbine operating in combined-cycle mode with supplemental duct firing. The detailed emission calculations are provided in Appendix B. The emissions were calculated in two ways to provide maximum estimates. For the criteria pollutants, the highest emissions occur when the unit is in startup or shutdown mode with the emissions controls not fully functioning. For example, SCR and CatOx systems are not fully functioning during those periods due to temperature limitations. Accordingly, the maximum annual emissions of the criteria pollutants are calculated with the turbine operating with all of the possible startup and shutdown events described previously in Section 2. For the emissions of CO 2e, the maximum annual emissions occur when the unit is burning the maximum amount of fuel. The maximum amount of the CO 2e emissions is discussed in Section 7 later in this document. Table 3-1 shows the estimated hourly emissions for the combustion turbine operating on pipeline-quality natural gas. Emissions of NO x, CO, and VOCs are based on best available control technology (BACT) emission rates of 2 parts per million (ppm) at 15 percent O 2, 2 ppm at 15 percent O 2, and 2 ppm at 15 percent O 2, respectively. Emissions for SO 2, PM 10, and PM 2.5 are based on turbine design data and engineering estimates. TABLE 3-1 Hourly Emissions for Unit 5 Combustion Turbine with Duct Burner Turbine with Duct Burner Pollutant Normal Operations NO x Emissions (lb/hr) 15.1 CO Emissions (lb/hr) 9.2 SO 2 Emissions (lb/hr) 3.5 PM 10 Emissions (lb/hr) 18.3 PM 2.5 Emissions (lb/hr) 18.3 VOC Emissions (lb/hr) 5.3 NOTE: lb/hr = pounds per hour Annual criteria pollutant emissions from Unit 5 are shown in Table 3-2. Emission estimates assume 330 hot starts and 15 cold starts per year. A maximum of 345 shut downs are anticipated per year. Emissions associated with startups (cold and hot) and shut downs are shown in Table 6-3. The annual emissions are calculated based on operating the combustion turbine and duct burners at full load for the entire year, less the time Unit 5 is in start up or shut down. Emissions from the shutdown hours associated with the cold start definition IS SLC\KUC UPP NOI FINAL_V4.DOCX 3-1

16 UPP UNITS 1, 2, AND 3 REPOWERING: NOTICE OF INTENT APPLICATION (15 cold starts 72-hour shut down/cold start up = 1,080 total hours) were also not included in the criteria pollutant totals. TABLE 3-2 Annual Emissions Unit 5 with Duct Burner Pollutant Turbine with Duct Burner Normal Operations (tpy) Start up/shut down (tpy) Total Annual (tpy) NO x Emissions CO Emissions SO 2 Emissions PM 10 Emissions PM 2.5 Emissions VOC Emissions IS SLC\KUC UPP NOI FINAL_V4.DOCX

17 4.0 Regulatory Review The purpose of this section is to provide appropriate explanation and rationale regarding the applicability of regulations to the proposed modification. This review is divided into the following three major sections: (1) state and federal air permitting requirements, (2) state and federal air pollution emission standards, and (3) monitoring and reporting requirements. 4.1 State Air Permitting Requirements The State of Utah has been granted authority by the U.S. Environmental Protection Agency (EPA) to implement and enforce the federal Clean Air Act (CAA) (pursuant to the State Implementation Plan [SIP] review and approval process) and federal air permitting requirements that are embodied within the state rules. The general requirements for permits and permit revisions are codified under the state environmental protection regulations Utah Administrative Code (UAC) R307 (Environmental Quality, Air Quality) (Utah Division of Air Quality [UDAQ], 2009). Permit: NOI and AO (UAC R ) The addition of the natural gas turbine and HRSG at the UPP will require the issuance of an AO pursuant to UAC R , Permit: New and Modified Sources. KUC is required by UAC R to submit to UDAQ an NOI application and obtain a UDAQ-issued AO prior to initiating construction activities associated with the proposed project. UAC R requires the NOI to include the following: A description of the project A description and characteristics of emissions An analysis of BACT for the proposed source or modification A location map Because the project is located in a nonattainment area for PM (PM 10) and will not be defined as a major modification, this project will not be subject to UAC R , Analysis of Alternatives. Permit: New and Modified Sources in Nonattainment Areas and Maintenance Areas (UAC R , UAC R , UAC R , UAC R , and UAC R ) This rule establishes the procedures and requirements for evaluating the emissions impact of new or modified sources in a nonattainment area. The project site is located in Salt Lake County, which is a nonattainment area for PM 10, PM 2.5, and SO 2 and is a maintenance area for ozone. Therefore, the project is subject to the requirements in UAC R , which describes the PM 10 emission standards for Salt Lake County and UAC R , which describes the ozone nonattainment and maintenance area general requirements. As specified in UAC R , modified sources which result in an emission increase equal to or exceeding 25 tons per year of combined PM 10, SO 2, and NO x shall offset those emissions as specified in the rule. For the UPP project, there will be a net reduction in IS SLC\KUC UPP NOI FINAL_V4.DOCX 4-1

18 UPP UNITS 1, 2, AND 3 REPOWERING: NOTICE OF INTENT APPLICATION emissions of PM 10 of 102 tpy, a net reduction in emissions of SO 2 of 1,961 tpy, and a net reduction in emissions of NO x of 1,544 tpy. Since there will be a net reduction in combined PM 10, SO 2 and NO X, no emissions offsets will be required. Permits: Prevention of Significant Deterioration (PSD) of Air Quality (UAC R ) UAC R implements the federal PSD permitting program for major sources and major modifications in attainment areas and maintenance areas as required by 40 Code of Federal Regulations (CFR) The project site is located in an area classified as nonattainment for PM 10, PM 2.5, and SO 2; maintenance for ozone; and attainment for all remaining criteria pollutants. Because the net change in emissions from the proposed modification will be below the significant net emission increase threshold (as defined in R and 40 CFR 52.21[b][23]), the requirements of the PSD program (UAC R and 40 CFR 52.21) will not apply to the proposed modification. Visibility (UAC R ) UAC R describes the requirements for the UDAQ review of any proposed new major source or major source modification to evaluate the impact of its emissions on visibility in any mandatory Class I area. UDAQ is required to review emission impact analysis results to determine whether the proposed major source modification will have an adverse impact on visibility in any Class I area. If the review determines that the impact will be adverse, pre- or post-construction monitoring may be required for the facility. Because the proposed modification will result in a decrease in emissions of PM 10, SO 2 and NO x, which can affect visibility and is not a major modification, this project is not subject to UAC R Permits: Emissions Impact Analysis (UAC R ) This rule establishes the procedures and requirements for evaluating the emissions impact of new or modified sources that require an AO to ensure that the source will meet the National Ambient Air Quality Standards (NAAQS). This rule also establishes the procedures and requirements for evaluating the emissions impact of hazardous air pollutants (HAPs). Finally, this rule establishes the procedure for establishing an emission rate based on the good engineering practice stack height as required by 40 CFR The proposed modification will not be subject to UAC R since there will not be an emissions increase for any criteria pollutants from the project in excess of values specified in UAC R Air dispersion modeling was required for HAPs (formaldehyde), UAC R , and is discussed in Section Federal Air Permitting Requirements The general requirements for permits and permit revisions are codified under the CAA at 40 CFR 51, 52, and 70. EPA administers the Title V federal operating permit program. Major Source New Source Review (NSR)/PSD (40 CFR 51 and 52) UDAQ has been delegated full authority by EPA for administering the federal PSD and NSR rules, as previously described. Operating Permit Program (40 CFR 70) UDAQ has been delegated full authority by EPA for administering the federal Title V operating permit program. The proposed project will require the filing of an application for 4-2 IS SLC\KUC UPP NOI FINAL_V4.DOCX

19 UPP UNITS 1, 2, AND 3 REPOWERING: NOTICE OF INTENT APPLICATION a modification to the existing Title V operating permit for the UPP within 12 months of the start up of Unit Emission Standards Following is a summary of the Utah emission standards that are applicable to this project: UAC R Standards of Performance for new stationary sources. 40 CFR 60 incorporated by reference. New Source Performance Standards (40 CFR 60) In 40 CFR 60, EPA established emission performance standards for specific categories of sources. These standards include emission limitations for various regulated pollutants and provide a variety of requirements for monitoring, recordkeeping, and reporting of emissions and other information. Any emissions unit subject to a New Source Performance Standards (NSPS) subpart is also subject to the general provisions under 40 CFR 60 Subpart A (codified at 40 CFR 60.1 through 60.18). In addition to the general provisions, the proposed modification will be subject to the following subparts of 40 CFR 60, which describe applicability, emission limitations, compliance requirements, monitoring requirements, reporting requirements, and performance testing requirements: Subpart KKKK: Standards of Performance for Stationary Combustion Turbines that commence construction after February 18, The proposed modification will include one natural gas fired gas turbine that is subject to Subpart KKKK. This rule also applies to duct burners that are incorporated into combined-cycle projects. Subpart KKKK exempts the combustion turbine and duct burner from the requirements of Subparts Db and GG which could otherwise apply. Subpart YYYY: National Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines. This section applies to combustion turbines that are a major source of HAPs. UPP is not major for HAPs and therefore this section does not apply. 4.4 Monitoring and Reporting After an AO is issued by UDAQ, KUC will be required to conduct monitoring, submit emission reports, ensure that equipment meets certain specifications, and conduct other activities as UDAQ requires, including the following: Meet the reporting requirements specified in UAC R in the event of an unavoidable break down Submit and retain an air emission inventory and perform testing and monitoring as required in UAC R Conduct emissions testing in accordance with UAC R Install a continuous emission monitoring system and submit related reports to UDAQ as specified in UAC R IS SLC\KUC UPP NOI FINAL_V4.DOCX 4-3

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21 5.0 Netting Analysis This section presents the details on the netting analysis. As noted previously in Section 1.0, the proposed repowering of Units 1, 2, and 3 with a natural gas turbine will result in a net reduction in criteria pollutant emissions of PM 10, PM 2.5, SO 2, and NO x. The pollutants of CO and VOC will have an insignificant increase in annual emissions. 5.1 Definitions Definition of a Major Source The PSD/NSR program regulates major sources of air pollution in areas classified as attainment/nonattainment with respect to meeting the NAAQS. The program defines a listed source such as UPP as major when, on a pollutant-specific basis, it has a potential to emit (PTE) greater than or equal to 100 tpy. The UPP is an existing major source. Definition of a Major Modification An existing major source is subject to PSD and NSR review only if it undertakes a major modification (40 CFR 52.21[b][2][i]). Major modification is defined as any physical change in or change in the method of operation of a major stationary source that would result in both a significant emissions increase and a significant net emissions increase of any pollutant subject to regulation under the CAA (40 CFR 52.21[b][3]). While the emissions increase associated with Unit 5 will be significant, the net emissions increase, including the reduction in emissions associated with shutting down Boilers 1, 2, and 3, will result in a net emissions change that is not significant. Emissions Increase Associated with Unit 5 Unit 5 emissions are shown previously in Table 3-2, which is repeated here as Table 5-1. TABLE 5-1 Annual PTE Emissions Unit 5 Pollutant Total Annual PTE (tpy) NO x Emissions CO Emissions SO 2 Emissions PM 10 Emissions PM 2.5 Emissions VOC Emissions IS SLC\KUC UPP NOI FINAL_V4.DOCX 5-1

22 UPP UNITS 1, 2, AND 3 REPOWERING: NOTICE OF INTENT APPLICATION 5.2 Demonstrating a Minor Net Increase To demonstrate that a planned physical change will not result in a significant net emissions increase at a source, the source must show that the emissions increase associated with that change, along with all other contemporaneous increases and decreases in actual emissions, will be less than the significant emission rates. The emission increase associated with Unit 5 is shown in the preceding subsection. As noted, UPP Units 1, 2, and 3 will be shut down prior to commencing operation of Unit 5 and will therefore result in a contemporaneous emission decrease for most pollutants. These pollutants that do increase will have increases below the significant thresholds Determining the Baseline Emissions Period The baseline actual emissions prior to the change are referred to in this permit application as pre-project actual (PPA) emissions. In determining PPA emissions, a source is required to establish a baseline period, which is a 24-month consecutive period within the 10-year period immediately preceding either the commencement of actual construction or submittal of the application, whichever is earlier. Actual emissions establish a baseline for comparison against future potential emissions or PTE Under those provisions, the annual emissions inventory data from Units 1, 2, and 3 for the 24 months from January 1, 2008, to December 31, 2009, are used to establish the PPA emissions Determining Contemporaneous Emissions Period The contemporaneous period begins 5 years prior to the commencement of construction of the project and extends to the date that the emissions increase from the particular change will occur (40 CFR 52.21[b][48][ii]). The contemporaneous period for this project therefore extends from 2007 (five years prior to the start of construction in 2012) to the start of operations in As the emission decrease associated with the shutdown of Units 1 through 3 will occur within the contemporaneous period. Summary of Contemporaneous Emissions Decreases Table 5-2 summarizes the baseline actual emissions for Units 1, 2, and 3 at the UPP. The baseline actual emissions are based on the average of actual emissions reported in the annual emission inventory for all pollutants from the past 2 years from January 1, 2008, to December 31, The annual emissions inventory did not require the reporting of PM 2.5 and, therefore, we are not relying on it. The PM 10 emissions listed in Table 5-2 include both filterable and condensable portions as determined from stack testing. The PM 2.5 emissions are estimated as a portion of PM IS SLC\KUC UPP NOI FINAL_V4.DOCX

23 UPP UNITS 1, 2, AND 3 REPOWERING: NOTICE OF INTENT APPLICATION TABLE 5-2 UPP Units 1, 2, and 3 Average Actual Emissions for Past 2 Years Pollutant 2009 Actual Emissions (UPP U1-3) (tpy) 2008 Actual Emissions (UPP U1-3) (tpy) Average Actual Emissions (UPP U1-3) (tpy) NO x 1,590 1,641 1,616 CO PM PM SO 2 1,859 2,091 1,975 VOC NOTES: PM 10 emissions include both condensable and filterable emissions. Actual PM 2.5 emissions assumed to be PM 10 (0.533) emissions for coal-fired boilers Because Boilers 1, 2, and 3 will be shut down prior to the start up of Unit 5, they represent contemporaneous, creditable emission decreases. There are no other contemporaneous emission increases or decreases. 5.3 Netting Demonstration for the Repowering Project Table 5-2 shows the netting demonstration, including comparison to the significant thresholds. Note that for no pollutant will there be a significant net emissions increase, and for NO x, PM 10, PM 2.5, and SO 2, there will be net emissions decreases. For natural gas combustion, nearly all PM 10 is PM 2.5 so it is assumed for this analysis that PM 2.5 equals PM 10. TABLE 5-2 Netting Demonstration Pollutant Contemporaneous Emission Decrease (tpy) Unit 5 PTE (tpy) Net Change in Emissions (tpy) Significant Increase Thresholds (tpy) Significant Emissions Increase? (tpy) NO x 1, , No CO No PM No PM No SO 2 1, , No VOC No NOTES: Emissions of PM 10 include both the condensable and filterable portions. Emissions of PM 2.5 assumed to be equal to PM 10. KUC proposes to comply with the GHG requirements by agreeing not to significantly increase GHG emissions. This is more fully discussed later in Section 7. IS SLC\KUC UPP NOI FINAL_V4.DOCX 5-3

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25 6.0 Best Available Control Technology The following sections present the required BACT analyses. 6.1 BACT Analysis Requirements Applicability UDAQ outlines the requirement for completing a State of Utah minor-source BACT analysis under the following rules: R : The Executive Secretary shall issue an approval if it is determined through plan review that the following conditions have been met: (1) The degree of pollution control for emissions, to include fugitive emissions and fugitive dust, is at least best available control technology except as otherwise provided in these regulations. R : Best Available Control Technology (BACT) means an emission limitation and/or other controls to include design, equipment, work practice, operation standard or combination thereof, based on a maximum degree of reduction of each pollutant subject to regulation under the Clean Air Act and/or the Utah Air Conservation Act emitted from or which results from any emitting installation, which the Air Quality Board, on a case-by-case basis taking into account energy, environmental and economic impacts and other costs, determines is achievable for such installation through application of production process and available methods, systems and techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for control of each such pollutant. In no event shall application of BACT result in emission of pollutants which will exceed the emissions allowed by section 111 or 112 of the Clean Air Act Top-down BACT Process This NOI generally follows the top-down method for making BACT determinations as set forth in EPA s New Source Review Workshop Manual (EPA, 1990): Step 1: Identify all control technologies Step 2: Eliminate technically infeasible options Step 3: Rank remaining control technologies by control effectiveness Step 4: Evaluate most-effective controls and document results Step 5: Select BACT Each of these steps, described herein, has been conducted for NO x, CO, VOCs, SO 2, and PM 10. IS SLC\KUC UPP NOI FINAL_V4.DOCX 6-1

26 UPP UNITS 1, 2, AND 3 REPOWERING: NOTICE OF INTENT APPLICATION BACT Analysis A top-down BACT analysis takes into account energy, environmental, economic, and other costs associated with each alternative technology Energy Impact Analysis Two forms of energy impacts that may be associated with a control option for an electric power generating unit can be identified as follows: An increase in energy consumption resulting from increased heat rate (reduced efficiency) may be shown as a reduction of electrical generation resulting from the application of the control technology due to increased parasitic load or back pressure that reduces the generation produced by the turbine. The reduced unit availability may be due to additional maintenance requirements for the applied control technology Environmental Impact Analysis Increases and decreases in other criteria or non-criteria pollutants may occur with the use of some technologies and should also be identified. Non-air impacts, such as solid waste disposal and increased water consumption, may be an issue as well. 6.2 Combustion Turbine Generator Comparable Permitted Emissions The new combustion turbine planned for the KUC power generation project will come from a group of machines from different vendors that are similar in operation and emissions. Because of these similarities, information from EPA s reasonably available control technology (RACT)/BACT/lowest achievable emission rate (LAER) Clearinghouse (RBLC) and combustion turbine permit information provide a good comparative basis for the BACT analysis. Therefore, for this analysis, the same evaluation criteria and RBLC comparative information (RBLC selection criteria: Large Combustion Turbines > 25 MW firing natural gas fuel) was used, and the information is presented in tabular format in Appendix A. 6.3 Combustion Turbine Generator BACT Combustion Turbine BACT for NOx Identify All Control Technologies There are three basic means of controlling NO x emissions from combustion turbines wet combustion controls, dry combustion controls, and post-combustion controls. Wet and dry combustion controls act to reduce the formation of NO x during the combustion process, while post-combustion controls remove NO x from the exhaust stream. Potential NO x control technologies for combustion turbines include the following: Wet combustion controls Water injection Steam injection Dry combustion controls 6-2 IS SLC\KUC UPP NOI FINAL_V4.DOCX

27 UPP UNITS 1, 2, AND 3 REPOWERING: NOTICE OF INTENT APPLICATION DLN combustors Catalytic combustors (e.g., XONON ) Post controls SCR Selective non-catalytic reduction (SNCR) Non-selective catalytic reduction (NSCR) SCONOx Previous BACT Determinations. Table A-1 in Appendix A summarizes a database search of EPA s RBLC for combined-cycle gas turbine project code for projects from 2007 to present. The SCR technology is the most-stringent control alternative listed in the RBLC. Of the SCR projects, the most stringent is a 2-ppmvd NOx (corrected to 15 percent O2) BACT limit using SCR. KUC believes that a limit of 2 ppmvd NOx represents BACT for this project. Eliminate Technically Infeasible Options. This section discusses in more detail the performance and technical feasibility of available NO x control technologies. Wet Combustion Controls. Steam or water injection directly into the turbine combustor is one of the most common NO x control techniques for combustion turbines. These wet injection techniques lower the flame temperature in the combustor and thereby reduce thermal NO x formation. Water or steam injection also allows more fuel to be burned without overheating critical turbine parts, thereby increasing the combustion turbine s maximum power output. The water or steam-to-fuel injection ratio is the most significant factor affecting the performance of wet combustion controls. Water injection will be considered further in the next step. Dry Combustion Controls. The following are the two dry combustion control options for reducing NO x emissions from combustion turbines: DLN combustors Catalytic combustors (e.g., XONON) DLN Combustors. Combustion modifications that lower NO x emissions without wet injection include lean combustion, reduced combustor residence time, lean premixed combustion, and two-stage rich/lean combustion. Lean combustion uses excess air (greater than stoichiometric air-to-fuel ratio) in the combustor primary combustion zone to cool the flame, thereby reducing the rate of thermal NO x formation. Reduced combustor residence times are achieved by introducing dilution air between the combustor and the turbine sooner than with standard combustors. The combustion gases are at high temperatures for a shorter time, which also reduces the amount of thermal NO x formation. The most advanced combustion control for NO x formation is referred to as DLN combustors. The DLN technology uses lean, premixed combustion to keep peak combustion temperatures low, thus reducing the formation of thermal NO x. Lean premix combustors have been developed for gas-fired turbines and the more advanced designs are capable of achieving a 70 to 95 percent NO x reduction with NO x concentrations from 5 to 25 ppmvd. This technology is already incorporated into the combustion turbine design. Therefore, the lean premix DLN technology is feasible for KUC. IS SLC\KUC UPP NOI FINAL_V4.DOCX 6-3

28 UPP UNITS 1, 2, AND 3 REPOWERING: NOTICE OF INTENT APPLICATION Catalytic Combustors. One advertised type of dry combustion control is a catalytic combustor, such as Catalytica s XONON, which uses a catalyst inside the combustor where the air/fuel mixture passes through the catalyst as combustion occurs at much lower temperatures when compared with a standard combustor. This reduction in the combustion temperature greatly reduces the formation of thermal NO x. Emissions of NO x from catalytic combustors are typically below 5 ppmvd. In October 1998, Catalytica Combustion Systems demonstrated the XONON system on a 1.5-MW combustion turbine located in Santa Clara, California. While this system has achieved NO x concentrations below 3 ppm, catalytic combustors have not been applied commercially to gas turbines in a larger size range. The XONON system is not commercially available for the KUC gas turbine or comparable equipment at this time. Therefore, this technology is not considered feasible for use on the KUC combustion turbines and is eliminated in this BACT analysis. Post-combustion Controls. The following are the four post combustion control options for reducing NO x emissions from combustion turbines: SCR SNCR NSCR SCONO x SCR. SCR is a post combustion technique that controls both thermal and fuel NO x emissions by reducing NO x with a reagent (generally ammonia or urea) in the presence of a catalyst to form water and nitrogen. NO x conversion is sensitive to exhaust gas temperature, and performance can be limited by contaminants in the exhaust gas that may mask the catalyst (sulfur compounds, PM, heavy metals, and silica). SCR is used in numerous gas turbine installations throughout the U.S., almost exclusively in conjunction with other wet or dry NO x combustion controls. SCR requires the consumption of a reagent (ammonia or urea) and periodic catalyst replacement. As NO x emission rates have dropped, the level of sophistication has increased in terms of the ammonia injection system and process controls. The temperature range required for this catalytic reduction process is typically between 570 F and 750 F, which usually exists within the high-pressure section of the HRSG. Generally, this requires that the high-pressure evaporator tube bank of the HRSG be split to accommodate the SCR unit. If the catalyst bed is not located in the proper temperature zone of the HRSG, either the reaction efficiency will be reduced if the temperature is too low, resulting in increased ammonia slip, or the catalyst may be damaged if the temperature is too high. During start up, the SCR is not operational until the catalyst surface reaches the nominal operating temperature (570 F). This will result in a short period (up to 10 minutes) of higher NO x emissions due to decreased catalyst activity at lower temperatures and limitations on the amount of ammonia that can be emitted. SCR is capable of over 90 percent NO x removal. However, the use of SCR can result in secondary PM 10 (ammonium nitrate) and unreacted gaseous ammonia emissions (ammonia slip) due to the use of ammonia. This technology is considered feasible for KUC. 6-4 IS SLC\KUC UPP NOI FINAL_V4.DOCX

29 UPP UNITS 1, 2, AND 3 REPOWERING: NOTICE OF INTENT APPLICATION SNCR. SNCR involves injection of ammonia or urea with proprietary conditioners into the exhaust gas stream without a catalyst. SNCR technology requires gas temperatures in the range of 1,200 F to 2,000 F and is most commonly used in boilers. The exhaust temperatures for the KUC gas turbines are in the 1,000 F to 1,100 F range, which is well below the minimum SNCR operating temperature. Some method of exhaust gas reheat, such as additional fuel combustion, will be required to achieve exhaust temperatures compatible with SNCR operations, and this requirement makes SNCR technologically infeasible for this application. Even when technically feasible, SNCR is unlikely to achieve NO x reductions in excess of 80 to 85 percent. NSCR. NSCR uses a catalyst without injected reagents to reduce NO x emissions in an exhaust gas stream. NSCR is typically used in automobile exhaust catalytic converters and rich-burn stationary internal combustion engines and employs a platinum/rhodium catalyst. NSCR is effective only in a stoichiometric or fuel-rich environment where the combustion gas is nearly depleted of oxygen, and this condition does not occur in turbine exhaust where the oxygen concentrations are typically between 14 and 16 percent. For this reason, NSCR is not technologically feasible for this application. SCONOx. SCONOx is a proprietary CatOx and adsorption technology that uses a single catalyst for the control of NO x, CO, and VOC emissions. The catalyst is a monolithic design, made from a ceramic substrate with both a proprietary platinum-based oxidation catalyst and a potassium carbonate adsorption coating. The catalyst simultaneously oxidizes nitric oxide to nitrite (NO2), CO to CO 2, and VOCs to CO 2 and water, while NO 2 is adsorbed onto the catalyst surface where it is chemically converted to and stored as potassium nitrates and nitrites. The SCONOx potassium carbonate layer has a limited adsorption capacity and requires regeneration approximately every 12 to 15 minutes in normal service. Estimates of control system efficiency vary. ABB Environmental has indicated that the SCONOx system is capable of achieving a 90 percent reduction in NO x, a 90 percent reduction in CO to a level of 2 ppmvd, and an 80 to 85 percent reduction in VOC emissions. SCONOx has not been installed on large combustion turbines, and the feasibility of the scale-up of the SCONOx system for large turbines has not been demonstrated. Therefore, SCONOx is not considered to be a viable NO x control technology for projects of the size of KUC. The SCONOx system is considered to be not technologically feasible for the purposes of this analysis. Based on the previous discussions, the following NO x control technologies are available and potentially technologically feasible for the proposed project: Water injection DLN combustors SCR Rank Remaining Control Technologies by Control Effectiveness The remaining technically feasible control technologies are ranked by NO x control effectiveness in Table 6-1. Water injection is inferior to DLN for NO x control and cannot be used with DLN. Thus it is eliminated from further consideration. IS SLC\KUC UPP NOI FINAL_V4.DOCX 6-5

30 UPP UNITS 1, 2, AND 3 REPOWERING: NOTICE OF INTENT APPLICATION TABLE 6-1 NOx Control Alternatives KUC NOx BACT Analysis Technology Expected NO x Emission Rate (ppmvd at 15% O 2) Operational Impacts Technically Feasible? Water or Steam Injection 25 Cannot be used with DLN Yes DLN burners (current CT design) 9 Decreased CTG output and efficiency Yes SCR 2 5 ppmvd ammonia slip, decreased CTG efficiency due to additional pressure drop Yes Available Control Options and Technical Feasibility SCR is a technically feasible NO x control option that could be added to an inherent combustion turbine design of DLN combustors. Economic Impacts. The addition of an SCR system is generally the most expensive, as well as having the capability of achieving the highest NO x reduction, of all of the NO x control options. Since KUC has committed to the installation of SCR and the design of 2 ppm NO x is the lowest emissions rate noted in the RBLC information in Table A-1 in Appendix A, no additional economic comparison between alternatives is necessary for the KUC BACT analysis. Environmental Impacts. The use of SCR will result in ammonia emissions from each unit. Ammonia slip results because it is impossible to provide perfect mixing or an infinite residence time for chemical reaction between the ammonia and the nitrogen oxides. Theoretically, given perfect conditions, the stoichiometric amount of ammonia could be added, resulting in complete reaction of all NO x and all ammonia molecules. In reality, because of imperfect conditions and variable turbine operating conditions, a stoichiometric excess of ammonia must be added to meet target NO x emissions. This stoichiometric excess is emitted from the stack as ammonia slip. Thus, there is an approximate inverse relationship between effluent NO x and ammonia concentrations. The only practical way to reduce ammonia slip is to increase the effluent NO x. The use of SCR at KUC will result in ammonia emissions due to a design ammonia slip limit of 5 ppmvd at 15 percent O 2. The ammonia emissions resulting from the use of SCR may have an environmental impact through their potential to form secondary PM such as ammonium sulfate and ammonium nitrate in the atmosphere. Because of the complex nature of the chemical reactions and dynamics involved in the formation of secondary particulates, it is difficult to estimate the amount of secondary PM that will be formed from the emission of a given amount of ammonia. A second potential environmental impact that may result from the use of SCR involves the storage and transport of aqueous ammonia. Although ammonia is toxic if swallowed or inhaled and can irritate or burn the skin, eyes, nose, or throat, it is a commonly used 6-6 IS SLC\KUC UPP NOI FINAL_V4.DOCX

31 UPP UNITS 1, 2, AND 3 REPOWERING: NOTICE OF INTENT APPLICATION material that is typically handled safely and without incident. Thus, the potential environmental impact due to aqueous ammonia storage at the KUC does not justify the elimination of SCR as a control alternative. Energy Impacts. Use of the SCR system creates additional pressure drop in the turbine exhaust. The pressure drop anticipated for the proposed SCR system has been factored into consideration of the potential impacts of the technology. Determination of BACT Emission Rates The BACT analysis performed for NO x control includes the following: Review of published BACT guidelines for natural gas fired combined-cycle gas turbines Review of recent BACT decisions for natural gas fired combined-cycle gas turbines Table A-1 in Appendix A summarizes a database search of EPA s RBLC for combined-cycle gas turbine Project Code for projects from 2007 to present.of the SCR projects, the most stringent is a 2-ppmvd NO x (corrected to 15 percent O 2) BACT limit using SCR. Conclusion The KUC project can meet the proposed BACT NOx emission limit of 2.0 ppmvd at 15 percent O 2 and will not cause significant energy, economic, or environmental impacts. This SCR option will also result in potential ammonia slip emissions of 5 ppmvd Duct Burner BACT for NOx Available technologies for control of NO x emissions from duct burners are comparable to those for combustion turbines. SCR and DLN technology are applicable and available. Duct burners fire fuel into the exhaust from combustion turbines. The extra fuel consumes only oxygen present in the turbine exhaust with no addition of extra air. Thus, it is impossible to control a duct burner using an add-on control device separately from the combustion turbine. SCR would represent the next most-stringent control available for the duct burners. Thus the same control limits that would apply to the turbines would also apply to the duct burners. Because the balance of the BACT analysis would be identical to that for the turbines, it will not be repeated in this section. It should be noted that the proposed 2.0-ppmvd (corrected to 15 percent O 2) limit for NO x is for the combined turbine plus duct burner and is more stringent than comparable 2.0-ppmvd limits for combined-cycle projects without duct burners Combustion Turbine BACT for CO and VOC Theoretical Formation and Control of CO and VOC CO and VOC emissions are caused by incomplete fuel combustion, which can result from insufficient residence time at high temperature or incomplete mixing of fuel and air. In gas turbines, the use of dilution air as a NO x control method and operation at low or medium loads can increase CO and VOC emissions. Thus, many NO x control methods, such as water/steam injection, lean combustion, and low flame temperatures, can increase CO and IS SLC\KUC UPP NOI FINAL_V4.DOCX 6-7

32 UPP UNITS 1, 2, AND 3 REPOWERING: NOTICE OF INTENT APPLICATION VOC emissions. A good combustor design will minimize the formation of CO and VOC while reducing the combustion temperature and NO x emissions. Catalytic combustion could be used to balance the conflicting NO x and CO/VOC control mechanisms during combustion. The system would use a flameless combustion system where fuel and air react on a catalyst surface, preventing the formation of NO x while achieving low CO and VOC emission factors. Finally, CatOx could be used to oxidize CO and VOC to CO 2 and water vapor after combustion. Catalysts for these systems usually include precious metals such as platinum, palladium, or rhodium. The oxidation reaction occurs without the need to add additional reactants. The emissions of formaldehyde, a HAP, will be affected by the same operating conditions that affect the emissions of CO and VOC. Therefore, the use of CatOx will also reduce the emissions of formaldehyde. Determination of BACT Emission Rates The BACT analysis performed for CO and VOC control includes the following: Review of published BACT guidelines for natural-gas fired combined-cycle gas turbines Review of recent BACT decisions for natural-gas fired combined-cycle gas turbines Previous BACT Determinations for CO and VOC. A database search of the EPA s RBLC for recent combined-cycle gas with project code for projects from 2007 to present is summarized in Appendix A, Table A-2 for CO and Table A-3 for VOC. CatOx is the most stringent control listed in the RBLC. Of the CatOx projects, the most stringent is a 1.8-ppmvd CO with several recent units at much higher levels of 9 ppm or more. The moststringent level for VOC BACT is 1.2 ppmvd (corrected to 15 percent O 2) for combined-cycle units with duct burners but several recent units have BACT levels that range from 1.8 to well over 2 ppmvd VOC. Technical Feasibility The following technologies were considered in the technical feasibility analysis: CatOx Catalytic combustion (XONON) DLN burners CatOx. CatOx systems have a proven track record at locations where BACT was required. Emission guarantees in the range of 2.0 ppmvd CO and 1.0 ppmvd VOC (corrected to 15 percent O 2) have been permitted. Oxidation catalysts are considered to be technologically feasible and will be advanced for ranking. Catalytic Combustion. The XONON system, manufactured by Catalytica, shows promise in future application for simultaneously reducing NO x, CO, and VOC emissions. As discussed in the BACT for NO x section in this document, the XONON is not currently commercially available for large combustion turbines and, therefore, is not technically feasible for UPP Unit IS SLC\KUC UPP NOI FINAL_V4.DOCX

33 UPP UNITS 1, 2, AND 3 REPOWERING: NOTICE OF INTENT APPLICATION DLN Burners. Good combustor design and operation are the most common methods of controlling CO and VOC emissions from combustion turbines. The DLN burner technology is already incorporated into the combustion turbine design. The existing gas turbine DLN combustors operate at 9 ppmvd CO and 1.4 ppmvd VOC (corrected to 15 percent O 2), which represents state-of-the-art design for CO and VOC control. Therefore, the DLN technology is feasible for UPP Unit 5. Ranking of Remaining Alternatives The remaining alternatives are CatOx and DLN combustors. These technologies are ranked in Table 6-2. TABLE 6-2 CO and VOC Control Technology Ranking for Combustion Turbines Technology CO Emission Rate (ppmvd at 15% O 2) VOC Emission Rate (ppmvd at 15% O 2) Technically Feasible? DLN Combustors 9 1 to 10 Yes CatOx Yes Available Control Options and Technical Feasibility The installation of a CatOx system is a technically feasible CO and VOC control option, which can be added to the current design of DLN burners. Economic Impacts. The addition of CatOx is generally the most expensive, as well as having the capability of achieving the highest CO and VOC reduction, of all of the control options. The KUC project has committed to the installation of CatOx. Emissions of 1.8 ppmvd CO and 1.2 ppmvd VOC are the lowest values noted in the RBLC information for combinedcycle installations with duct burners, and comparative data are presented in Tables A-2 and A-3 in Appendix A. Therefore, no additional economic comparison between alternatives is necessary for the Unit 5 BACT analysis. Energy Impacts. Use of the CatOx system does create additional pressure drop in the turbine exhaust. Typical losses are 1.5 to 3.0 inches of water. As described, this can result in (1) an increase in energy consumption resulting from increased heat, which reduces electrical generation resulting from the application of the control technology due to increased parasitic load or back pressure and (2) reduced unit availability due to additional maintenance requirements for the applied control technology. The pressure drop anticipated for a CatOx system is not considered excessive but is factored into consideration of the potential impacts of the technology. Environmental Impacts. The primary environmental impact associated with the use of an oxidation catalyst is an increase in PM 10 emissions due to the additional oxidation of sulfur and ammonia present in the combustion turbine exhaust gas. The combustion turbine oxidizes any sulfur compounds in the natural gas (either naturally occurring or added as an odorant) to SO 2. The SO 2 would be further oxidized to sulfur trioxide (SO 3) across the oxidation catalyst and when combined with ammonia will be emitted as ammonium sulfate, which is considered PM. IS SLC\KUC UPP NOI FINAL_V4.DOCX 6-9

34 UPP UNITS 1, 2, AND 3 REPOWERING: NOTICE OF INTENT APPLICATION Review of published BACT guidelines for natural gas fired combined-cycle gas turbines Review of recent BACT decisions for natural gas fired combined-cycle gas turbines A database search of EPA s RBLC for recent combined-cycle gas with Project Code for projects from 2007 to present is summarized in Appendix A, Table A-2 for CO and Table A-3 for VOC. CatOx is the most-stringent control listed in the RBLC. The moststringent level for VOC BACT is 1.2 ppmvd (corrected to 15 percent O 2) for combined-cycle units with duct burners but several recent units have BACT levels that range from 1.8 to well over 2 ppmvd VOC. Conclusion. Even though the RBLC results shows the lowest CO emission of 1.8 ppmvd, the current Unit 5 CO design emissions rate, including impact from duct burners of 2.0 ppmvd, represents the next lowest value. A CO emissions rate of 2.0 ppmvd has been determined to be achievable for the project; therefore, KUC believes that limit of 2.0 ppmvd CO is the BACT emission level for CO. A VOC emissions rate of 2.0 ppmvd has been determined to be achievable for the project; therefore, KUC believes that limit of 2.0 ppmvd is the BACT emission level for VOC. The current gas turbine DLN combustors with CatOx can meet these proposed BACT CO and VOC emission limits and will not cause significant energy or environmental impacts Duct Burner BACT for CO and VOC As previously described, duct burners fire fuel into the exhaust from combustion turbines. The extra fuel consumes only oxygen present in the turbine exhaust with no addition of extra air. Thus, it is impossible to control a duct burner using an add-on control device separately from the combustion turbine. The cost-effectiveness evaluation of good combustion technology with CatOx presented for the combustion turbines considers the CO and VOC contribution of both the turbines and duct burners. This technology is cost effective to control the combination of turbine plus duct burner. Because the balance of the BACT analysis would be identical to that for the turbines, it will not be repeated in this section. It should be noted that the proposed 2.0-ppmvd (corrected to 15 percent O 2) limit for CO and VOC is actually for the combined turbine plus duct burner and is more stringent than comparable limits for combined-cycle projects without duct burners. 6.4 BACT Analysis for SO Theoretical Formation and Control of SO2 Emissions of SO 2 from gas-fired power plants results from combustion of natural gas in the combustion turbines and duct burners. Pipeline-quality natural gas contains only up to 0.6 grain per 100 standard cubic feet (scf) of sulfur, and combustion of the natural gas oxidizes all sulfur compounds to SO 2. The low concentration of sulfur compounds in natural gas results in low SO 2 emission rates from this equipment IS SLC\KUC UPP NOI FINAL_V4.DOCX

35 UPP UNITS 1, 2, AND 3 REPOWERING: NOTICE OF INTENT APPLICATION Available Control Options and Technical Feasibility No feasible add-on SO 2 controls have been used on pipeline-quality natural gas fired combustion turbines and duct burners. Determination of BACT Emission Rates A review of EPA s RBLC for recent SO 2 BACT determinations for combustion turbines and duct burners has identified low-sulfur pipeline-quality natural gas as LAER for recent projects. The Unit 5 combustion turbine and duct burners will emit SO 2. The project s SO 2 emissions are directly proportional to the sulfur content of the pipeline-quality natural gas the project will be burning. The use of low-sulfur pipeline-quality natural gas is consistent with recent BACT determinations and is considered BACT for this equipment, and no other controls exist for these emission sources. However it should be noted that the emissions of SO 2 from Unit 5 will be much less than is presently emitted from Units 1, 2 and BACT Analysis for PM Combustion Turbine BACT for PM10 Theoretical Formation and Control of PM10 Particulate emissions from gas-fired power plants result from two primary mechanisms. First, combustion of natural gas in the combustion turbines and duct burners results in low-level emissions of particulates, which originate from combustion products or from dust in the combustion air. Emissions of PM from natural gas combustion are normally negligible. These emissions are primarily a result of carryover of noncombustible trace elements (dust) present in the natural gas fuel. Particulate emissions can also result from dust particles present in inlet combustion air and are dependent on the efficiency of the filtration devices that clean the dust particles out of the inlet air that goes to the combustor. Particulate emissions of hydrocarbon resulting from incomplete combustion can result from liquid or solid fuels but are not a significant result of natural gas combustion. No feasible add-on control mechanisms exist for controlling these emissions other than the particulate filters used in the natural gas fuel system and the inlet combustion air system. Available Control Options and Technical Feasibility As mentioned previously, little can be done to limit particulate emissions from natural gas combustion, and EPA does not consider particulate emissions a concern in this process. EPA confirms this in AP-42, Section 3.1, which acknowledges that PM emissions are negligible with natural gas firing (EPA, 2000). Particulate emissions are also not considered a concern in the NSPS for stationary gas turbines (40 CFR 60, Subpart GG), which requires no PM controls for gas turbines. EPA also stated in the promulgation portion of the NSPS that particulate emissions from stationary gas turbines are minimal (44 Federal Register 52798, September 10, 1979). EPA s position is further confirmed from review of EPA s RBLC information for PM emission controls (see Appendix A), which indicates that additional control equipment is not used to control PM emissions. Since control equipment was not installed, it is assumed IS SLC\KUC UPP NOI FINAL_V4.DOCX 6-11

36 UPP UNITS 1, 2, AND 3 REPOWERING: NOTICE OF INTENT APPLICATION that the state agency or EPA did not require it. As long as good combustion practices are performed, PM emissions are not considered to be a concern. Turbine manufacturer s guarantees of particulate emissions are highly variable and depend on the anticipated natural gas quality, ambient dust concentrations, quality of water used for inlet air chillers (which increases the power plant efficiency, thus reducing emissions of other pollutants), and the amount of risk accepted by the manufacturer. Particulate emissions estimates are typically conservative due to the lack of feasible methods of control. Determination of BACT Emission Rates The BACT analysis performed for PM 10 control includes the following: Review of published BACT/LAER guidelines for natural gas fired combined-cycle gas turbines Review of recent BACT/LAER decisions for natural gas fired combined-cycle gas turbines Previous BACT Determinations for PM10. A review of EPA s RBLC for recent combined-cycle gas turbine projects is summarized in Table A-5 of Appendix A. Good combustion practices and clean fuels are the control technologies listed in the RBLC. Of the projects listed, the most stringent BACT limit listed is lb/mmbtu PM 10. Summary. Clean-burning natural gas will be the only fuel used for UPP Unit 5, and is accepted as BACT. The combustion turbine and duct burner will emit no more than lb/mmbtu of PM Duct Burner BACT for PM10 The RBLC database was reviewed for recent combustion turbine projects. None of the projects listed included any specific particulate emission limits for duct burners separate from overall plant emission limits. Duct burners fire fuel into the exhaust from combustion turbines. The extra fuel consumes only oxygen present in the turbine exhaust with no addition of extra air. Thus, it is impossible to control a duct burner using an add-on control device separately from the combustion turbine. The Unit 1 duct burners will fire only clean-burning natural gas, and use of clean-burning natural gas is accepted as BACT. 6.6 Startup and Shutdown Analysis To identify and quantify Unit 5 combustion turbine and duct burner emissions during all periods of operation, startup and shutdown activities are analyzed in this section. The combustion turbine operating in combined-cycle will have significantly different startup and shutdown sequences and emissions profile from units operating in simple cycle. While simple-cycle combustion turbines may reach full load quickly, in as short as 10 minutes from initiating the startup sequence, the cold-start scenario for the combinedcycle start up is estimated to take as long as 182 minutes to complete IS SLC\KUC UPP NOI FINAL_V4.DOCX

37 UPP UNITS 1, 2, AND 3 REPOWERING: NOTICE OF INTENT APPLICATION Table 6-3 summarizes startup and shutdown emissions for UPP Unit 5. Start up is defined as the time from combustion turbine burner ignition until emissions compliance. The different startup scenarios are defined as follows: Hot start up Less than 8 hours offline Cold start up Greater than 72 hours offline TABLE 6-3 BACT Startup/Shutdown Emissions Event Duration (minutes) NO x (lb/event) CO (lb/event) VOC (lb/event) PM 10 (lb/event) SO 2 (lb/event) Hot Startup Cold Startup , Shutdown BACT Summary This section presents a minor source BACT overview for the regulated emission sources proposed for the KUC project. Table 6-4 summarizes the control technologies and emission levels chosen as a result of the BACT and LAER analyses, and review of RBLC emissions information for comparable combustion turbines operating in combined cycle. TABLE 6-4 BACT and LAER Analysis Pollutant Combined-cycle Combustion Turbines NO x Low NO x Burners and SCR (2.0 ppmvd at 15% O 2) CO VOC SO 2 PM 10 Oxidation Catalyst (2.0 ppmvd at 15% O 2) Oxidation Catalyst (2.0 ppmvd at 15% O 2) Pipeline-quality Natural Gas (0.6 grains of sulfur/100 scf) Pipeline-quality Natural Gas and Good Combustor Design (0.008 lb/mmbtu) IS SLC\KUC UPP NOI FINAL_V4.DOCX 6-13

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39 7.0 Greenhouse Gas Emissions Analysis 7.1 GHG Tailoring Rule On May 13, 2010, EPA issued a final rule that sets thresholds for GHG emissions that define when permits under the NSR-PSD and Title V operating permit programs are required for new and existing industrial facilities. Implementation of the tailoring rule will occur in the following steps: Step 1 (January 2, 2011 through June 30, 2011): Only sources currently subject to the PSD permitting program (i.e. those that are newly constructed or modified in a way that significantly increases emissions of a pollutant other than GHGs) would be subject to permitting requirements for their GHG emissions under PSD. For these projects, only GHG increases of 75,000 tpy or more of total GHG, on a CO 2e basis, would need to determine the BACT for their GHG emissions. Similarly, for the operating permit program, only sources currently subject to the program (i.e. newly constructed or existing major sources for a pollutant other than GHGs) would be subject to Title V requirements for GHGs. During this time, no sources would be subject to CAA permitting requirements due solely to GHG emissions. Step 2 (July 1, 2011 through June 30, 2013): In this phase, PSD permitting requirements will cover for the first-time new construction projects that emit GHG emissions of at least 100,000 tpy even if they do not exceed the permitting thresholds for any other pollutant. Modifications at existing facilities that increase GHG emissions by at least 75,000 tpy will be subject to permitting requirements, even if they do not significantly increase emissions of any other pollutant. In Step 2, operating permit requirements will, for the first time, apply to sources based on their GHG emissions even if they would not apply based on emissions of any other pollutant. Facilities that emit at least 100,000 tpy CO 2e will be subject to Title V permitting requirements. Step 3: In this final rule, EPA commits to undertake another rulemaking, to begin in 2011 and conclude no later than July 1, That action will comment on an additional step for phasing in GHG permitting and may discuss whether certain smaller sources can be permanently excluded from permitting. Because this project is a minor modification of a major source and will not be under construction in 2011, it falls into the Tailoring Rule in Step 2. The proposed modification will result in a synthetic minor increase in plantwide emissions of GHGs below the significant emissions increase threshold of 75,000 tons CO 2e and will therefore not be subject to PSD review for GHG emissions. 7.2 Netting Demonstration for GHG Emissions The increase in GHG emissions associated with Unit 5 is presented in Table 7-1. The emissions reductions from the shutdown of the Boilers 1, 2 and 3 that will be used to offset the emissions from Unit 5 are discussed next. IS SLC\KUC UPP NOI FINAL_V4.DOCX 7-1

40 UPP UNITS 1, 2, AND 3 REPOWERING: NOTICE OF INTENT APPLICATION TABLE 7-1 Potential Annual Emissions Unit 5 Pollutant Unit 5 PTE (tpy) CO 2e Emissions 935,401 To demonstrate that a planned physical change will not result in a significant net emissions increase at a source, the source must show that the emissions increase associated with that change, along with all other contemporaneous increases and decreases in actual emissions, will be less than the significant emission rates. As noted previously, the boilers associated with Units 1, 2, and 3 will be shut down prior to commencing operation of Unit 5 and will therefore result in a contemporaneous emission decrease of CO 2e. As discussed previously in Section 5, baseline actual emissions are established as 2 consecutive years that precede commencement of construction. The annual emissions for the 2 years from January 1, 2008, to December 31, 2009, will be used for establishing baseline actual emissions for CO 2e. Table 7-2 shows a CO 2e netting demonstration for current UPP power generation to the proposed power generation emissions. Baseline plantwide actual power generation CO 2e emissions are an average of 2008 and 2009 emissions and in part represent a contemporaneous emission decrease from the shutdown of Boilers 1, 2, and 3. Post-project CO 2e potential emissions are the plantwide past actual emissions plus 74,900 tons. The net change in plantwide GHG emissions is not a significant emissions increase under the Tailoring Rule and therefore the project will not become subject to PSD permitting requirements because of GHG emissions. Detailed emission calculations are provided in Appendix B. TABLE 7-2 GHG Netting Demonstration Past Actual Plantwide Emissions Pollutant (tpy) Future Plantwide PTE Emissions (tpy) Net Change in Emissions (tpy) Significant Increase Thresholds (tpy) Significant Emissions Increase? CO 2e 1,220,646 1,29,646 75,000 75,000 No 7.3 Proposed CO 2 e Plantwide Applicability Limit KUC is proposing a UPP power generation PAL of less than 1,295,646 tpy of CO 2e pursuant to 40 CFR (aa). The annual power generation CO 2e cap shall be calculated on a 12-month rolling total basis using actual monthly fuel burn data from the UPP and emission factors from 40 CFR 98 Mandatory Reporting Rule and consistent with this analysis. The calculation of CO 2e emissions will be performed using actual fuel burn data and the methods required by the Mandatory Reporting Rule. The results will be reported to EPA 7-2 IS SLC\KUC UPP NOI FINAL_V4.DOCX

41 UPP UNITS 1, 2, AND 3 REPOWERING: NOTICE OF INTENT APPLICATION under the Mandatory Reporting Rule and to UDAQ pursuant to the PAL established by the AO issued for this project. If there is a change in federal regulations or a court determines that GHG emissions are not subject to regulation under Title V or the CAA, than the proposed GHG emissions PAL would no longer be applicable at the UPP. IS SLC\KUC UPP NOI FINAL_V4.DOCX 7-3

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43 8.0 Noncriteria Pollutant Impacts Information regarding the project-related HAP emissions and release characteristics must be provided as part of a complete NOI. The following items are listed in UDAQ s Modeling Guidance: Estimated maximum emission rates (lb/hr) Type of pollutant release (i.e., vertically restricted or unrestricted) Maximum release duration (minutes per hour) Release height of the emission point(s) as measured from ground level Height of any adjacent building(s) that could cause downwash effects The shortest distance from each release point to the ambient air boundary The emission threshold value, as determined from the emission threshold factor multiplied by the threshold limit value for each HAP The potential HAP impacts from the proposed expansion have been evaluated. The proposed combustion turbine would be vertically unrestricted releases. Emissions from the units will be continuous, and the closest approach of the ambient boundary is approximately 220 meters. Information regarding HAP emissions associated with the project are provided in Appendix B. Emission threshold values were calculated for each HAP following the methodology described in UDAQ modeling guidelines to determine which HAPs should be modeled. All but one HAP was below the emissions threshold value. Modeling was conducted for formaldehyde, for which emissions exceeded the emission threshold value. The HAP modeling procedures are described in the following section. The modeling demonstrated that ambient concentrations will be less than the toxic screening level for formaldehyde. 8.1 Model Selection The EPA-approved AERMOD dispersion modeling system was used to evaluate applicable HAP air quality impacts. The latest generation of EPA s dispersion model is AERMOD (Version 09292), which is recommended for predicting impacts in the near-field from industrial point sources as well as area and volume sources. AERMOD was used with regulatory default options as recommended in the EPA Guideline on Air Quality Models. The following supporting preprocessors for AERMOD were also used: BPIP-Prime (Version 04274) AERMET (Version 06341) AERMAP (Version 09040) The technical options selected for AERMOD include the following: Regulatory default control options Receptor elevations and controlling hill heights obtained from AERMAP output IS SLC\KUC UPP NOI FINAL_V4.DOCX 8-1

44 UPP UNITS 1, 2, AND 3 REPOWERING: NOTICE OF INTENT APPLICATION The proposed combustion turbine was modeled as point sources within AERMOD. Emission rates and other source parameters were determined from the manufacturer s data or EPA-established emission factors. Table 8-1 summarizes the source parameters used in AERMOD. TABLE 8-1 Source Parameters Parameter Value Units Stack Height 185 feet Stack Temperature 245 F Stack Diameter 21 feet Exhaust Exit Velocity 64 feet per second Formaldehyde Emissions Rate 1.24 lb/hr Easting 405, meters NAD83 Northing 4,507, meters NAD83 NOTE: NAD83 = North American Datum Receptors The base modeling receptor grid for AERMOD modeling consisted of receptors that were placed at the ambient air boundary and Cartesian-grid receptors that were placed beyond the boundary at spacing that increases with distance from the origin. The property boundary was used as the ambient air boundary. Figure 8-1 shows the base AERMOD receptor grid for UPP. Boundary receptors were placed at 50-meter intervals. Beyond the property boundary, receptor spacing was as follows: 100-meter spacing from property boundary to 1 kilometer 250-meter spacing from beyond 1 to 5 kilometers from the origin 500-meter spacing from beyond 5 to 10 kilometers In addition to the receptor grid described previously, a rail line passing through the property had receptors spaced at 50 meters. All receptors and source locations are in Universal Transverse Mercator (UTM) NAD83, Zone 12 coordinate system. Terrain in the vicinity of the project was accounted for by assigning base elevations and controlling hill heights to each receptor. National Elevation Dataset (NED) files from the United Stated Geological Survey were used to determine receptor elevations. AERMAP (Version 06341) was used to calculate the receptor elevations and the controlling hill heights. A sufficient AERMAP domain and NED file selection was identified to encompass the 10 percent slope calculation recommended by EPA to calculate the controlling hill heights in AERMAP. 8-2 IS SLC\KUC UPP NOI FINAL_V4.DOCX

45 UPP UNITS 1, 2, AND 3 REPOWERING: NOTICE OF INTENT APPLICATION FIGURE 8-1 KUC UPP Receptor Grid IS SLC\KUC UPP NOI FINAL_V4.DOCX 8-3