Sutherland Generating Station Unit 4 Prevention of Significant Deterioration Air Permit Application Prepared for: Interstate Power and Light Cedar Rapids, Iowa Prepared by: Black & Veatch Corporation Overland Park, Kansas October 2007 Black & Veatch Project No. 145491 Black & Veatch File No. 32.2010 Interstate Power and Light Sutherland Unit 4 Air Permit Application Table of Contents Table of Contents Acronym List ................................................................................................................AL-1 1.0 Introduction.......................................................................................................... 1-1 2.0 Project Characterization....................................................................................... 2-1 2.1 Project Location ....................................................................................... 2-1 2.2 Project Description................................................................................... 2-2 2.2.1 Existing Sutherland Generating Station .................................... 2-2 2.2.2 SGS Unit 4 Project Description................................................. 2-2 2.3 Project Emissions................................................................................... 2-10 2.4 Federal and State Air Quality Requirements ......................................... 2-11 2.4.1 New Source Review Applicability .......................................... 2-11 2.4.2 New Source Performance Standards ....................................... 2-15 2.4.3 National Emission Standards for Hazardous Air Pollutants ................................................................................. 2-16 2.4.4 Title V Operating Permit ......................................................... 2-18 2.4.5 Compliance Assurance Monitoring......................................... 2-18 2.4.6 Chemical Accident Prevention ................................................ 2-18 2.4.7 Title IV Acid Rain Permit Program......................................... 2-19 2.4.8 Other Iowa State Requirements............................................... 2-20 2.4.9 Emission Standards for Contaminants..................................... 2-20 2.4.10 Provisions for Air Quality Emissions Trading Programs........ 2-20 2.4.11 Green House Gases (GHG) ..................................................... 2-22 3.0 Best Available Control Technology..................................................................... 3-1 3.1 BACT Methodology ................................................................................ 3-1 3.2 Summary of the BACT Determination .................................................... 3-2 4.0 Air Dispersion Modeling Protocol and Impact Analysis..................................... 4-1 4.1 Ambient Air Quality Impact Results ....................................................... 4-1 4.2 Additional Impacts Analysis.................................................................... 4-4 Appendix A Appendix B Appendix C Appendix D IDNR Application Forms PSD Application Checklist Fuel Analyses System Descriptions 102607-145491 TC-1 Interstate Power and Light Sutherland Unit 4 Air Permit Application Table of Contents Table of Contents (Continued) Appendix E Appendix F Appendix G Appendix H Appendix I Appendix J Flow Diagrams and Site Drawings Equipment Performance Data Emission Calculations BACT Analysis Air Dispersion Modeling Protocol and Electronic Modeling Files Site Evaluation Study – Coal Technology Assessment Tables Table 2-1 Table 2-2 Table 3-1 Table 3-2 Table 4-1 Table 4-2 Maximum Hourly Emission Rates and Project PTE.............................. 2-12 Comparison of Potential Annual Emissions from the Project to the PSD Significant Emission Rates ...................................................... 2-13 BACT Determination Summary ............................................................... 3-3 Material Handling Particulate BACT Determinations............................. 3-6 Comparison of the Project’s Maximum Modeled Impacts with the PSD Class II Modeling Significance and Monitoring de minimis Levels....................................................................................................... 4-2 Comparison of the Ancillary Equipment’s Maximum Modeled Impacts with the Short-Term NAAQS .................................................... 4-3 Figures Figure 2-1 Figure 2-2 Overview of Project Location.................................................................. 2-1 SGS Unit 4 Proposed Air Quality Control Systems ................................ 2-6 102607-145491 TC-2 Interstate Power and Light Sutherland Unit 4 Air Permit Application Acronym List Acronym List ACI AQIA amsl BACT bhp bhph Btu CAA CAIR CAM CAMR CEMS CO DC Circuit DESP EGU EP FGD GHG H2S H2SO4 HF Hg IAC ID IDNR IPL km kW lb LMDCT LNB/OFA m3 MACT MBtu 102607-145491 Activated Carbon Injection Air Quality Impact Analysis Above Mean Sea Level Best Available Control Technology Brake Horsepower Brake Horsepower Hour British Thermal Unit Clean Air Act Clean Air Interstate Rule Compliance Assurance Monitoring Clean Air Mercury Rule Continuous Emissions Monitoring System Carbon Monoxide District of Columbia Circuit Dry Electrostatic Precipitator Electric Generating Units Emission Point Flue Gas Desulfurization Green House Gases Hydrogen Sulfide Sulfuric Acid Hydrofluoric Acid Mercury Iowa Administrative Code Induced Draft Iowa Department of Natural Resources Interstate Power and Light Kilometers Kilowatt Pound Linear Mechanical Draft Cooling Tower Low NOx Boiler/Overfire Air Cubic Meters Maximum Achievable Control Technology Million British Thermal Unit AL-1 Interstate Power and Light Sutherland Unit 4 Air Permit Application MW NAAQS NESHAPS NO2 NOx NSPS NSR PAC PM/PM10 PRB PSD PSEU PTE RICE RMP SCPC SCR SGS SIP SO2 tpy μg USEPA VOC 102607-145491 Acronym List Megawatt National Ambient Air Quality Standards National Emission Standards for Hazardous Air Pollutants Nitrogen Dioxide Nitrogen Oxides New Source Performance Standard New Source Review Powdered Activated Carbon Particulate Matter/Particulate Matter Less than 10 Microns Powder River Basin Prevention of Significant Deterioration Pollutant Specific Emission Unit Potential to Emit Reciprocating Internal Combustion Engines Risk Management Plan Supercritical Pulverized Coal Selective Catalytic Reduction Sutherland Generating Station State Implementation Plan Sulfur Dioxide Tons per Year Microgram United States Environmental Protection Agency Volatile Organic Compound AL-2 Interstate Power and Light Sutherland Unit 4 Air Permit Application 1.0 1.0 Introduction Introduction Interstate Power and Light (IPL) is proposing to construct and operate a new 649 megawatt (MW net) supercritical pulverized coal (SCPC) fired boiler (Unit 4) at its existing Sutherland Generating Station (SGS) located in Marshalltown, Iowa. The proposed SGS Unit 4 and supporting ancillary equipment will join the existing coal fired boilers (Units 1, 2, and 3) and six fuel oil fired combustion turbine generating units at the SGS. Pursuant to the requirements of Iowa Administrative Code (IAC) [567], Chapter 33 and 40 CFR Part 52.21, IPL is hereby submitting this Prevention of Significant Deterioration (PSD) air permit application for the construction and initial operation of SGS Unit 4 and associated equipment. The applicable air permit application forms and PSD application checklist are included in Appendices A and B, respectively. In addition to the new SGS Unit 4 boiler, the Project will include a new gas fired auxiliary boiler; emergency diesel generator; diesel fire pump and booster pump engines; gate station natural gas heater; a 16 cell linear mechanical draft cooling tower (LMDCT); and various material handling and storage systems associated with the storage, conveyance, and use of fuel, combustion byproducts, and reagents. New coal unloading, storage, and conveyance systems will not only supply SGS Unit 4, but will be designed to service the existing coal fired units as well. This design will allow the existing coal unloading, storage, and reclaim systems to be retired when SGS Unit 4 becomes operational. Apart from the retirement of the aforementioned existing coal handling equipment, no other modifications to the existing generating units and permitted air emissions sources are proposed as part of this Project, and are not considered to be subject to PSD review as part of this air permit application. The Project, which is designed to provide electricity to meet the increasing energy requirements in the region (a detailed project description is provided in Section 2.2), is scheduled to begin commercial operation in 2013. SGS Unit 4 will be designed to burn a wide range of fuel supplies including Powder River Basin (PRB) sub-bituminous and Eastern and Western bituminous coals and blends thereof, as well as potential inclusion of biomass fuel. For the purposes of this application, two coal fuel types have been utilized to represent and conservatively bracket the proposed range of coal fuel characteristics for this Project. The representative coal fuel types are summarized below. A detailed ultimate fuel analysis of each representative coal fuel, as well as the performance and alternative coal fuels, is contained in Appendix C. • Rawhide Mine--PRB coal with a typical sulfur content of 0.33 percent or 0.794 lb SO2/MBtu. • Greater Belleville (Illinois Basin) Mine--Bituminous coal with a typical sulfur content of 3.11 percent or 5.75 lb SO2/MBtu. 102607-145491 1-1 Interstate Power and Light Sutherland Unit 4 Air Permit Application 1.0 Introduction From a regulatory basis, the Project will be considered a major modification under the New Source Review (NSR) regulations and will be subject to the PSD preconstruction air permitting program. The purpose of this air permit application is to provide the necessary preliminary design information to describe and characterize the proposed Project and demonstrate its compliance with the applicable PSD air construction permit standards and regulations. In addition to this introduction, this air permit application package provides the following analyses and supporting information as a basis for the Iowa Department of Natural Resources (IDNR) to grant an air construction permit for the Project: • Project Characterization (Section 2.0). • Federal and State Air Quality Requirements (Section 2.4). • Best Available Control Technology (Section 3.0). • Air Dispersion Modeling Protocol and Impact Analysis (Section 4.0). 102607-145491 1-2 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 2.0 Project Characterization Project Characterization This section characterizes the proposed Project, including a description of the Project’s location, facility and equipment, emissions, and regulatory applicability. 2.1 Project Location The Project will be located at IPL’s existing SGS, on the east side of Marshalltown, Iowa, within Marshall County. The specific location of the Project is illustrated on Figure 2-1. The SGS is situated along the southern side of an east-west reach of the Iowa River near Marshalltown. The terrain encompassing the proposed site consists mostly of agricultural flat land within the floodplain, with some gently rolling hills located to the north and east. Areas surrounding the site are generally used for farming and residential purposes near the City of Marshalltown. Project Location IOWA Project Location Base Map Source: www.topozone.com USGS 7.5 Minute Quadrangle: Le Grand, IA Figure 2-1 Overview of Project Location 102607-145491 2-1 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 Project Characterization Grade elevation of the main structures of the Project will be approximately 863 feet above mean sea level (amsl). The Project’s stack height will be approximately 601 feet above grade, resulting in a stack-top elevation of 1,464 feet amsl. The nearest Class I area is the Hercules Glades Wilderness Area located approximately 590 km south of the Sutherland facility. Given the distant proximity of the nearest Class I area, an analysis of the impact to Class I areas is not proposed for this Project. 2.2 Project Description 2.2.1 Existing Sutherland Generating Station The SGS currently has the capability to provide approximately 308 MW of power by utilizing three coal fired and six fuel oil fired units. Units 1 and 2 are dry bottom pulverized coal fired boilers with low NOx burners. Each unit has a rated capacity of 444 MBtu/h and is designed for approximately 32 MW of electrical generation. The units are permitted to combust coal, petroleum coke, and natural gas. Units 1 and 2 have been in operation since 1954 and 1955, respectively. Unit 3 is a cyclone furnace boiler permitted to combust coal, petroleum coke, and natural gas. It was installed in 1961 and has a rated capacity of 868 MBtu/h and is designed for approximately 82 MW of electrical output. Additionally, the SGS has six 1978 vintage simple cycle combustion turbines (operated in pairs), each with a rated capacity of 402 MBtu/h (approximately 54 MW each), permitted to burn fuel oil. Apart from the retirement of the existing coal unloading, storage, and reclaim systems when SGS Unit 4 becomes operational, no other modifications to SGS’s existing emission sources are proposed as part of this Project. 2.2.2 SGS Unit 4 Project Description The proposed Project will provide additional generating capacity to provide electric energy to the transmission grid at Marshalltown, Iowa. The specific objective of the electric generating unit is to provide reliable base loaded coal fired energy. To achieve the objective of reliable generation, the Project is designed to burn a wide range of fuel supplies from a combustion and environmental control perspective. The primary coal supply is intended to be subbituminous coal from the Powder River Basin in the states of Wyoming and Montana. It is anticipated that this supply of coal will, during certain time periods, not be adequate to supply all of the low sulfur coal supply needed to fire IPL’s current fleet of coal fired units. During these supply inadequacies, the Project will switch, as needed, to alternate coal supplies that are available in the market place at that time. IPL envisions that these supplies will be from other Western and Midwestern 102607-145491 2-2 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 Project Characterization mines producing subbituminous and bituminous coals. From a sulfur content and other coal parameters perspective, Illinois Basin coal was identified to establish the Air Quality System and boiler design which in turn will provide the necessary system flexibility to utilize a wide range of coal supplies. To summarize, the intent of the Project is to utilize a wide range of bituminous and subbituminous coals to produce electric energy at Marshalltown, Iowa. This section describes and explains the major components of the Project, including the Unit 4 boiler; auxiliary boiler; gate station natural gas heater; emergency diesel generator; diesel fire pump and booster pump engines; cooling tower; and various material handling and storage systems associated with the storage, conveyance, and use of fuel, combustion byproducts, and reagents. In addition to the descriptions provide herein, more detailed engineering system descriptions, process flow diagrams, and site drawings are provided in Appendices D and E to further assist in characterizing the Project and its many components. The emission point (EP) identification numbers are included in parentheses following the equipment title of each piece of equipment. For reference and consistency, the EP identification numbers are used throughout this application, including the IDNR application forms, site arrangement, and emission calculation spreadsheets, to reference the Project’s proposed emission sources. As depicted in the overall site arrangement included in Appendix E, SGS Unit 4 and its supporting equipment (including an onsite coal combustion byproducts storage area) will be located to the south and southwest of the existing units at the SGS. While application for the construction of the landfill will be made under separate cover, the material handling activities associated with operation of the landfill (truck hauling, material dumping, maintenance, etc.) have been accounted for in this application. SGS Unit 4 SCPC Boiler (EP-248) SGS Unit 4 will be a 649 MW (net) SCPC boiler with a maximum design heat input of 6,326 MBtu/h. The SCPC technology offers superior boiler efficiency over convention subcritical boilers due to the increased steam pressure. More detailed information regarding the advantages of SCPC technology is included in Appendix J, Site Evaluation Study - Coal Technology Assessment. The boiler will be designed to burn a wide range of fuel supplies including PRB, Eastern, and Western bituminous coals and blends thereof, as well as potential inclusion of biomass fuel. For purposes of this permit application, the biomass blends is limited to 5 percent of the overall fuel input on a heat content basis. From the technical review performed to date, no negative impact to overall emissions was identified that could be associated with the use of biomass as a fuel. 102607-145491 2-3 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 Project Characterization Coal will be delivered to the site by rail car, where it will be unloaded, conveyed, and stacked out in a new coal storage yard. The coal will be reclaimed and transferred via conveyors to five new Unit 4 coal storage silos. Coal mills (called pulverizers) will crush the coal to reduce it to the size required for efficient combustion. Pressurized air will transport the pulverized coal from the pulverizers to the boiler’s burners. At the burners, the coal will be mixed with additional air, and the mixture will be ignited. The burners will be specially designed to produce low levels of NOx and promote efficient combustion. The coal and air mixture will be burned in the area of the boiler called the furnace. The furnace combustion process will produce steam, which is generated in the boiler by heating water. A boiler can be thought of as a large box that contains a burning coal/air mixture, with the walls of the box consisting of a large number of tubes, through which water and steam flow. Within the various sections of the boiler tubes, the water, which is delivered to the boiler inlet, will be heated and converted to steam at the pressure and temperature required for admission into the steam turbine. The steam turbine generator will then generate electricity. Before exiting to the atmosphere, the flue gas will go through a series of air quality control devices designed to remove air contaminants from the exhaust gas. These devices, including a selective catalytic reduction (SCR) system, fabric filter, and wet flue gas desulfurization (FGD) system are explained in detail in Section 3.0 (Best Available Control Technology [BACT] analysis) and are described below as a brief overview. An SCR system will be the first of these air quality control devices and will use ammonia in the presence of a catalyst to control the levels of NOx in the flue gas. The SCR system reduces NOx by injecting ammonia into the exhaust gas upstream of a catalyst bed, which converts NOx into inert nitrogen and water before leaving the stack. The ammonia used in the SCR will be either urea or aqueous ammonia (less than 19 percent concentration). The exhaust gas stream from the SCR will pass through the air heater and then to a dry electrostatic precipitator (DESP). The DESP will be installed for the purpose of beneficial reuse of fly ash and is not intended as the primary particulate control device. The DESP will collect fly ash that can be used as an ingredient in commercial concrete or reused by other industries (such as cement manufacturers). Fly ash that is reused will not require disposal space in the onsite byproduct storage area. An ESP is essentially a large enclosure placed in the ductwork between the air heater and the induced draft (ID) fan that contains a series of charged electrodes and parallel steel plates spaced approximately 12 to 16 inches apart. The ESP negatively charges the electrodes and positively charges the plates to create a voltage differential. 102607-145491 2-4 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 Project Characterization As the particulate-laden flue gas passes between the plates and the electrodes, the ash particles become negatively charged. The particles then migrate to the positively charged plate, where the ash accumulates. At periodic intervals, rapping of the plates removes the accumulated ash from the ESP, causing the accumulated ash to be collected in a hopper for either disposal or beneficial reuse. The exhaust gas stream from the DESP will next be ducted to a fabric filter baghouse dust collector. The fabric filter uses fabric bags as filters to collect particulate. The particulate-laden flue gas enters a fabric filter baghouse compartment and passes through a layer of particulate and filter bags. The collected particulate forms a cake on the bag, which enhances the bag’s filtering efficiency. The pressure drop across the bags increases as the thickness of the dust cake increases. At a predetermined pressure drop set point, the filtering bags are cleaned, dislodging a large portion of the dust cake for collection and disposal. Mercury emissions will be controlled by a combination of fuel blending, co-benefit control from post-combustion air quality control equipment, and activated carbon injection (ACI) upstream of the fabric filter to meet NSPS Subpart Da mercury emission limits. Activated carbon adheres to the mercury, allowing it to be captured and removed by the fabric filter system. Exhaust gas will exit the fabric filter to an FGD system. The FGD system uses either a lime or limestone reagent in a “shower-like” or “bath-like” flue gas contact process to scrub SO2 from the exhaust stream. Finally, the cleaned-up flue gas will exhaust to the atmosphere through a new chimney constructed for SGS Unit 4. A block flow diagram of the proposed air quality control systems is presented on Figure 2-2. While SGS Unit 4 is being proposed as a base load unit and being permitted for unlimited annual operation, the unit will be required to shut down and start up periodically, depending on load requirements and maintenance. The boiler will be designed to initially start up on natural gas until the load on the boiler reaches approximately 10 percent, after which coal will be introduced into the boiler in combination with the startup fuel for stabilization, until the boiler reaches approximately 25 percent of load. Auxiliary Boiler (EP-249) The Project will include a new auxiliary steam boiler to be used during startup of the main boilers at the SGS, during periods when the main boilers are offline, and to supply steam for onsite building heat and services. The auxiliary boiler fuel source will be natural gas and its maximum heat input will be limited to 270 MBtu/h. The auxiliary boiler is expected to operate no more than 2,000 hours per year. 102607-145491 2-5 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 Project Characterization Ammonia Sorbent Silo Economizer Steam Generator SCR Air Heater Fabric Filter Dry ESP AC Silo Bottom Ash Fly Ash FGD ID Fans Fly Ash Silo (Saleable) Stack Hydro cyclones Lime stone Silo Fly Ash Silo (Waste) Ball Mill Vacuum Filters Reagent Slurry Tank Reclaim Water Tank Gypsum Figure 2-2 SGS Unit 4 Proposed Air Quality Control Systems 102607-145491 2-6 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 Project Characterization Gate Station Heater (EP-297) Natural gas will be used during startup for both the new and existing boilers at the SGS and will be the primary fuel for the new auxiliary boiler. The natural gas supply to the SGS will arrive via a high-pressure natural gas pipeline. As the natural gas is extracted from the high-pressure pipeline, a reduction in pressure will naturally cool the gas to a temperature that is too low to be combusted in the boilers. As such, a natural gas fired gate station heater will be used to reheat the natural gas back to a usable temperature. The gate station heater will have a maximum heat input limit of 3 MBtu/h and designed for continuous operation. Emergency Generator (EP-250) In the event of a loss of normal auxiliary power, AC power will be supplied by a new 2,000 brake horsepower (bhp), 2,000 kilowatt (kW), No. 2 distillate fuel oil fired emergency generator. The emergency generator will be periodically tested for approximately 1 to 2 hours per week (typical) to confirm its ready-to-start condition. The emergency generator is expected to operate no more than 100 hours per year for normal testing and maintenance. Fire Pump and Booster Fire Pump Engines (EP-251 and 252) Pressurized fire water will be supplied by a new fire pump engine and fire booster pump engine rated at 575 bhp and 149 bhp, respectively. These engines will burn No. 2 distillate fuel oil. Similar to the emergency generator, the fire pump engines will be periodically tested for approximately 1 to 2 hours per week (typical) to confirm their ready-to-start condition. The fire pump engines are expected to operate no more than 100 hours per year (each) for normal testing and maintenance. Cooling Tower (EP-253) The Project will utilize a new 16 cell LMDCT to dissipate waste heat from the boiler’s steam cycle. The basic principle behind all cooling towers is to cool water using ambient air. Circulating cooling water will remove heat from the steam, causing it to condense. The heated circulating cooling water is transported to the cooling tower to dissipate the heat into the atmosphere. The circulating water is sprayed into the cooling tower as a coarse mist that cascades down a fill material. As the circulating water falls, air contacts the water, allowing a transfer of heat from the water to the cooler atmospheric air. The cooled circulating water is then collected in the cooling tower basin, where it is pumped from the cooling tower back to the condenser water boxes, repeating the process. 102607-145491 2-7 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 Project Characterization During the cooling process, small water droplets, known as cooling tower drift, escape to the atmosphere through the cooling tower exhaust. To minimize this effect, the cooling tower will be equipped with drift eliminators to minimize the escaping water droplets. Material Handling – Coal (EP-254 through 279) The existing material handling equipment for coal unloading, stockout, and reclaim will be not be used for the operation of SGS Unit 4. Instead, a new coal unloading, stockout, and reclaim system will be installed, replacing the existing one, to accommodate the operation of SGS Unit 4 and existing Units 1 through 3. The coal will be supplied by rail to the facility where is will be unloaded and sent to the coal yard storage area via new stockout conveyors. The coal yard will consist of active and inactive piles. Coal will be initially unloaded at a new rail car unloading building and stocked out to the active pile areas via a stacker reclaimer system, and as necessary, pushed to an inactive pile via bulldozers for long-term storage based on the facility’s coal needs. Coal will be reclaimed via the stacker reclaimer, which will drop the coal onto a new reclaim conveyor for transfer to either the coal blending area or directly to the crusher house. At the crusher house, the coal will be reduced in size and transferred to the SGS Unit 4 coal storage silos. Coal for the existing units will be reclaimed via a new underground reclaim system and transferred via conveyor to an existing coal yard transfer tower near Units 1 through 3. From that point, existing coal delivery equipment will continue to be utilized to supply the coal to existing Units 1 through 3. The existing facility’s coal unloading, stockout, and reclaim systems will be retired when SGS Unit 4 becomes operational. As further described in the BACT analysis (Section 3.0), dust collectors, water suppression, telescopic chutes, and partial or full enclosures will be utilized to control point and fugitive dust emissions from the coal material handling systems. Material Handling – Limestone (EP-280 through 285) Limestone will be delivered to the plant either by rail car or truck for use in SGS Unit 4’s wet FGD scrubber system. Limestone will be unloaded at a new limestone unloading building and stocked out to an active pile storage area via a conveyor system, and then as necessary, pushed to an inactive pile via bulldozers for long-term storage based on the facility’s usage. Limestone will be reclaimed via an underground reclaim system and conveyed to two limestone storage silos. From the storage silos, limestone will be fed to a ball mill and processed to a slurry before for being sent to the wet FGD system. 102607-145491 2-8 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 Project Characterization As further described in the BACT analysis (Section 3.0), dust collectors, water suppression, telescopic chutes, and partial or full enclosures will be utilized to control point and fugitive dust emissions from the limestone material handling systems. Material Handling – Fly Ash (EP-286 through 290) The fly ash handling system will remove fly ash waste collected from the economizer, air heater, SCR, and the fabric filter ash hoppers for disposal, as well as from the DESP ash hoppers for beneficial reuse as previously described. The system will transfer fly ash material from the individual collection hoppers to either a saleable or nonsaleable fly ash storage silo. The saleable ash can also be placed in a new winter ash storage building. Saleable fly ash will either be loaded into closed ash hauling trucks and rail cars and transported offsite for beneficial reuse, or conditioned and loaded into dump trucks for placement in the onsite byproducts storage area. Saleable fly ash stored in the winter storage building can be reclaimed via an underground reclaim system and loaded into closed ash hauling trucks. The non-saleable fly ash will be conditioned and loaded into dump trucks for disposal in the onsite byproducts storage area. As further described in the BACT analysis (Section 3.0), dust collectors, water suppression, telescopic chutes, and partial or full enclosures will be utilized to control point and fugitive dust emissions from the fly ash material handling systems. Material Handling – Bottom Ash The bottom ash material handling system will remove bottom ash from the steam generator furnace and collect coal pulverizer rejects via a submerged scrapper conveyor. The bottom ash will then be conveyed up a dewatering slope and discharged into a threesided, ground level, outdoor concrete storage bunker. From the bunker, the bottom ash will be loaded into ash dump trucks for offsite sales or transported directly to the onsite byproducts storage area. The bottom ash takes the form of a wet solid material (20 to 30 percent moisture content), and while dewatered, remains moist during all handling, conveyance, storage, and disposal operations. As such, the bottom ash material handling system is not a source of fugitive dust, other than that associated with the truck transportation haul road. Material Handling – Wet FGD Waste The wet FGD waste handling system will remove wet FGD scrubber waste (also known as gypsum) from the scrubber system. Twin vacuum belt filters will remove excess water, and the moist material will then be conveyed to a storage building. From 102607-145491 2-9 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 Project Characterization the storage building, the gypsum will be loaded into trucks and either transported offsite for beneficial reuse as wall board or disposed of onsite in the byproduct storage area. The wet FGD scrubber waste takes the form of a wet solid material (10 to 15 percent moisture content), and while dewatered, remains moist during all handling, conveyance, storage, and disposal operations. As such, the wet FGD scrubber waste material handling system is not a source of fugitive dust, other than that associated with the truck transportation haul road. Material Handling – Other – PAC, Sorbent, Lime, and Biomass (EP-291 through 296) The transportation and handling of various materials associated with bulk material storage, material delivery, and material disposal within the site boundaries or offsite will result in particulate emissions. These include, for example, truck deliveries (onsite or offsite, as applicable) of limestone, ash, FGD solids, coal, ammonia, powdered activated carbon (PAC), lime, and sorbent materials, as well as bulk material storage piles and storage pile maintenance. The following is contained in a summary of various other material handling activities included in this application as part of the Project: 2.3 • Haul roads for material deliveries and disposal. • Active and inactive coal storage piles. • Active and inactive limestone storage piles. • Material storage silos. • Saleable fly ash winter storage pile. • Front-end loader/bulldozing activities for loading/unloading materials and pile maintenance. • Biomass fuel material handling. Project Emissions The Project’s controlled emissions are presented in Table 2-1, including the maximum hourly and annual potential to emit (PTE) emissions associated with following proposed new sources as previously described. • SGS Unit 4, 649 MW (net) SCPC boiler. • One Auxiliary Boiler, 270 MBtu/h Maximum Heat Input, Natural Gas Fired. • One Gate Station Heater, 3 MBtu/h Maximum Heat Input, Natrual Gas Fired. • One Emergency Generator, 2,000 bhp, Diesel Fuel Fired. 102607-145491 2-10 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 Project Characterization • One Fire Pump Engine, 575 bhp, Diesel Fuel Fired. • One Fire Booster Pump Engine, 149 bhp, Diesel Fuel Fired. • 16 Cell LMDCT. • Coal Material Handling Equipment. • Fly Ash, Bottom Ash, and Wet FGD Scrubber Waste Material Handling Equipment. • PAC, Lime, Sorbent Material Handling, and All Haul Road Transportation. The basis, performance data, assumptions, and calculations used to estimate the Project’s emissions presented in Table 2-1 are contained in Appendices F and G. In summary, the emissions are based on worst case fuel and 100 percent capacity factor assumptions for the main boiler and material handling emission estimates, using controlled boiler emission estimates and United States Environmental Protection Agency (USEPA) AP-42 material handling emission factors. Ancillary equipment, such as the auxiliary boiler, emergency generator, fire pumps, and gate station heater, are based on representative manufacturers’ data and USEPA AP-42 emission factor estimates, as well as the maximum proposed annual hours of operation of the equipment. In Table 2-2, the Project’s aggregate annual PTE is presented and compared to the applicable PSD significant emission rates to determine which of the Project’s criteria pollutants are subject to PSD review, as further discussed in Section 2.4. 2.4 Federal and State Air Quality Requirements Air quality permitting in Iowa is under the jurisdiction of the IDNR. The USEPA has given the IDNR authority to implement and enforce the federal Clean Air Act (CAA) provisions and state air regulations under its approved State Implementation Plan (SIP). The following subsections discuss the applicable federal and state air quality programs, regulations, and standards. 2.4.1 New Source Review Applicability The federal CAA NSR provisions are implemented for new major stationary sources and major modifications under two programs: the PSD program outlined in 40 CFR 51 and 52.21, and the Nonattainment NSR program outlined in 40 CFR 51 and 52. The project site is in an attainment or unclassifiable area with respect to all pollutants. As such, the PSD program will apply to the Project, as administered by the state of Iowa under Chapter 33 of Section 567 of the Iowa Administrative Code (IAC 567-Chapter 33). 102607-145491 2-11 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 Project Characterization Table 2-1 Maximum Hourly Emission Rates and Project PTE Unit 4 PC Boiler Emissions(a,c) (lb/h) Auxiliary Steam Boiler Emissions (lb/h) Emergency Generator Emissions (lb/h) Gate Station Heater (lb/h) Fire Pump Engine (lb/h) Fire Booster Pump Engine (lb/h) Project PTE(b) (tpy) NOx 316.3 9.94 20.94 0.14 6.21 1.71 1,398 PM/PM10 113.9 1.88 0.12 0.02 0.10 0.06 517 SO2 506.1 0.16 0.49 0.002 0.20 0.07 2,217 H2SO4 25.3 0.25 0.74 0.003 0.31 0.10 111 CO 759.1 19.88 1.72 0.14 0.95 0.11 3,346 VOCs 21.5 1.34 0.87 0.02 0.37 0.12 95.7 0.000001 0.00004 0.00001 0.51 0.001 0.0004 4.80 Pollutant Lead Fluorides (e) 0.115 1.1 (d) 0.0001 0 0.00009 (g) 0.003 (g) (f) 0 (g) H2S 0(g) 0(g) 0(g) 0(g) 0(g) 0(g) 0(g) Total Reduced Sulfur 0(g) 0(g) 0(g) 0(g) 0(g) 0(g) 0(g) (a) Based on engineering design for two coal fuels, for a unit load of 100 percent of maximum capacity. Project controlled PTE based on 8,760 hours of operation per year for Unit 4 boiler; 2,000 hours of operation per year for the auxiliary boiler and 100 hours of operation per year for the emergency generator and fire pump and fire pump engines, and includes PM10 emissions from the material handling sources, cooling tower, and haul roads. (c) Based on a maximum boiler heat input of 6,326 MBtu/hr. (d) Based on the fluoride portion of the hydrofluoric acid (HF) emissions. (e) Lead based on fuel analysis. (f) Estimated based on AP-42 emission factor. (g) Emissions are insignificant and assumed to be zero. (b) Note: Detailed calculations are contained in Appendix G. 102607-145491 2-12 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 Project Characterization Table 2-2 Comparison of Potential Annual Emissions from the Project to the PSD Significant Emission Rates Total Project Potential Annual Emissions(a) (tons/year) PSD Significant Emission Rate (tons/year) PSD Review Required? (Yes/No) 1,398 40 Yes 517 25/15 Yes 2,217 40 Yes 111 7 Yes 3,346 100 Yes 95.7 40 Yes 0.51 0.6 No Fluorides 4.80 3 Yes H2S 0(e) 10 No (e) 10 No Pollutant NOx PM/PM10(b) SO2 H2SO4 CO VOCs Lead (c) (d) Total Reduced Sulfur 0 (a) Total Project Potential Annual Emissions are from Table 2-1. PM/PM10 includes the material handling equipment, cooling tower, and haul roads. (c) Lead based on controlled AP-42 emission factor. (d) Based on the fluoride portion of the HF emissions. (e) Emissions are insignificant and assumed to be zero. (b) Note: Detailed emission calculations are contained in Appendix G. 102607-145491 2-13 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 Project Characterization The PSD regulations are designed to ensure that the air quality in existing attainment areas does not significantly deteriorate or exceed the national ambient air quality standards (NAAQS), while providing a margin for future industrial and commercial growth. PSD regulations apply to major stationary sources and major modifications at existing major sources undergoing construction in areas designated as attainment or unclassifiable. The primary provisions of the PSD regulations require that major modifications and new major stationary sources be carefully reviewed prior to construction to ensure compliance with the NAAQS, the applicable PSD air quality increments, and the requirements to apply BACT to minimize the emissions of air pollutants. A major stationary source is defined as any one of the listed major source categories which emits, or has the PTE, 100 tpy or more of any regulated pollutant, or 250 tpy or more of any regulated pollutant if the facility is not one of the listed major source categories. Because the SGS is one of the major source categories (i.e., fossil fuel fired boilers with greater than 250 MBtu/h heat input), and has a PTE of greater than 100 tpy for at least one regulated pollutant, it is classified as a major stationary source. As the Project will be located at an existing major stationary source, PSD review is required for all pollutants for which the PTE is greater than the PSD significant emission rates. As shown in Table 2-2, the estimated potential emissions of NOx, SO2, CO, PM/PM10, VOC, H2SO4, and fluorides resulting from the Project exceed their respective PSD significant emission rates. Therefore, the Project’s emissions of those criteria pollutants are subject to PSD review. Pending final rules related to the implementation of NSR for PM2.5, the USEPA (in an October 1997 memorandum), has authorized the use of PM10 as a surrogate for PM2.5. This application incorporates USEPA’s PM2.5 NSR guidance. The PSD review includes a BACT analysis, air quality impact analysis (AQIA), and an assessment of the Project’s total impact on general residential and commercial growth, soils and vegetation, and visibility. These analyses are included in Sections 3.0 and 4.0 of this application, respectively. Based on comments received from IDNR during the September 24, 2007 preapplication meeting, IPL understands that PSD air construction permits typically expire in 36 months from issuance. As this Project’s construction schedule is estimated to take 45 to 48 months, IPL hereby requests a 48 month PSD air construction permit expiration date. 102607-145491 2-14 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 Project Characterization 2.4.2 New Source Performance Standards Standards of Performance for New Stationary Sources are contained in 40 CFR Part 60 and adopted by reference in IAC 567-23. These standards are commonly referred to as new source performance standards (NSPS). The following NSPSs and their associated emission limitations are applicable to the proposed Project. 2.4.2.1 NSPS Subpart Da – Standards of Performance for Electric Utility Steam Generating Units for Which Construction is Commenced After September 18, 1978. As an electric utility steam generating unit with greater than 250 MBtu/h heat input, the Project’s 648 MW (net) coal fired boiler will be subject to NSPS Subpart Da. NSPS Subpart Da includes new source emission limitations for certain NSR/PSD pollutants, including SO2, NOx, and PM/PM10, as well as Hg. The applicable NSPS Subpart Da emission limitations for the coal-fired boiler are as follows: • SO2: 1.4 lb/MWh (gross energy output) or 95 percent removal rate. • NOx: 1.0 lb/MWh (gross energy output) • PM/PM10: 0.14 lb/MWh (gross energy output) or 0.015 lb/MBtu • Hg: − 66 x 10−6 lb/MWh (gross energy output) when firing subbituminous coal. − 20 x 10−6 lb/MWh (gross energy output) when firing bituminous coal. − Equation 1 of §60.45Da(a)(5)(i) for a blend of coals. Installation of BACT controls on the new boiler will ensure compliance with the requirements of this regulation. 2.4.2.2 NSPS Subpart Db – Standards of Performance for IndustrialCommercial-Institutional Steam Generating Units. As a steam generating unit with greater than 100 MBtu/h, the Project’s 270 MBtu/h natural gas fired auxiliary boiler will be subject to NSPS Subpart Db. NSPS Subpart Db includes new source emission limitations for certain NSR/PSD pollutants including NOx, SO2, and PM/PM10. For the natural gas fired boiler, the only applicable emission limit is 0.20 lb/MBtu of NOx (as NO2). Compliance with NOx BACT will ensure compliance with the NSPS requirement. Other requirements under NSPS Subpart Db include keeping records of the fuel usage and the annual capacity factor. 2.4.2.3 NSPS Subpart IIII – Standards of Performance for Stationary Compression Ignition Internal Combustion Engines. The Project’s emergency diesel generator and the two emergency fire pumps will be subject to the manufacturer’s certification requirements of compliance to NSPS Subpart IIII. The rule provides various emission standards based on the engine’s classification, use, manufacture date, and 102607-145491 2-15 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 Project Characterization engine size. The applicable standards associated with the emergency generator will be dependent on the engine model year. Therefore, the exact emission standards applicable to the emergency black start engine cannot be identified until the engine is purchased. Similarly, the fire pump engines will need to meet the emission requirements listed in Table 4 of this regulation. Beginning with engines manufactured in model year 2007 (emergency engines) and 2008 (fire pump engines), the onus of this rule falls on the manufacturer of these engines as they are required to manufacture engines that comply with the rule. The requirement of this rule for owners and operators of these units is that they purchase certified engines. IPL will purchase certified engines that will meet the appropriate emission limits. 2.4.2.4 NSPS Subpart Y – Standards of Performance for Coal Preparation Plants. The coal handling system is subject to the NSPS requirements for coal preparation plants, 40 CFR 60, Subpart Y, Standards of Performance for Coal Preparation Plants, because it is an applicable facility as defined under Subpart Y. The coal processing and conveying equipment and coal storage systems, except for open storage piles, are subject to a 20 percent opacity standard in accordance with 40 CFR 60.252(c). Implementation of BACT controls on the material handling processes will ensure compliance with this limitation. 2.4.2.5 NSPS Subpart OOO – Standards of Performance for Nonmetallic Mineral Processing Plants. A wet FGD system will be installed to control emissions of SO2 from the new boiler. Wet FGD systems use limestone slurry for desulfurization and, therefore, require limestone handling, transfer, and storage to ensure proper operation. The slurry is created from limestone which is delivered to the site via pneumatic delivery truck or railcar. The limestone storage, transfer, and grinding operations will be subject to NSPS Subpart OOO. NSPS Subpart OOO includes new source limitations for PM/PM10. The applicable NSPS Subpart OOO emission limitation for the limestone handling operation is to not exceed stack opacity of 7 percent opacity. Implementation of BACT controls on the material handling processes will ensure compliance with this limitation. 2.4.3 National Emission Standards for Hazardous Air Pollutants National Emission Standards for Hazardous Air Pollutants (NESHAPS) are contained in 40 CFR Part 63 and adopted by reference in IAC 567-23 and are emissions standards set by the USEPA for particular source categories. These categories require the maximum degree of emission reduction of certain HAPs that the EPA determines to be achievable, which is known as the Maximum Achievable Control Technology (MACT). 102607-145491 2-16 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 Project Characterization In fact, these standards are commonly referred to as the MACT standards. The following MACT standards are applicable to the proposed Project. 2.4.3.1 NESHAP Subpart DDDDD – Industrial, Commercial, and Institutional Boilers and Process Heaters. The Project’s 270 MBtu/h auxiliary boiler would have been an affected source under the Industrial Boiler MACT, which was promulgated on September 13, 2004. The auxiliary boiler, based on its heat input rating and capacity factor, would have been considered a new large gas fuel boiler under this MACT. On June 8, 2007, the United States Court of Appeals for the District of Columbia Circuit (DC Circuit) vacated the Boiler MACT in its entirety. Subsequently, this ruling was mandated by the Court on July 30, 2007, which means that there is currently no Industrial Boiler MACT standard in place. A resolution to this issue may include a MACT 112(g) or 112(j) analysis of the auxiliary boiler. Since the outcome of the Boiler MACT vacatur is not clear, IPL will await further direction from the USEPA and IDNR on this issue. 2.4.3.2 NESHAP Subpart ZZZZ – Stationary Reciprocating Internal Combustion Engines. Currently, the Stationary Reciprocating Internal Combustion Engines (RICE) MACT is applicable to stationary RICE greater than 500 bhp located at a major HAP source (e.g., the SGS). The Project’s emergency diesel generator and the main fire water pump will be greater than the 500 bhp applicability threshold. However, a new emergency stationary RICE located at a major HAP source is subject only to the initial notification requirements of 40 CFR 63.6645(d). Since the purpose of the emergency diesel generator will be for emergency situations when the normal source of power is not available to the facility, and the fire pump will be used during a fire to pump water, these engines will be considered as “emergency” stationary RICE and, therefore, subject only to the initial notification requirements of the RICE MACT. 2.4.3.3 NESHAP Subpart Q – Industrial Process Cooling Towers. This rule’s standard prohibits the use of chromium-based water treatment chemicals in industrial process cooling towers. The Project will not use chromium-based water treatment chemicals. 2.4.3.4 Coal and Oil Fired Electric Utility Steam Generating Units. On March 15, 2005, the USEPA signed the final rule titled, “Revision of December 2000 Regulatory Finding on the Emissions of Hazardous Air Pollutants From Electric Utility Steam Generating Units and the Removal of Coal- and Oil-fired Electric Utility Steam Generating Units from the Section 112(c) List.” In this rule, the USEPA determined that it was not appropriate or necessary to regulate coal and oil fired utility units under Section 112 of the CAA, and thus, removed those utility units from the section list of source categories. The USEPA effectively concluded that utility HAP emissions remaining after the implementation of other requirements of the CAA (e.g., CAMR) do 102607-145491 2-17 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 Project Characterization not cause hazards to public health that would warrant regulation under Section 112. As such, the SGS Unit 4 boiler is not required to perform a case-by-case MACT analysis. 2.4.4 Title V Operating Permit 40 CFR Part 70, Title V of the CAA established an air quality operating permit program that provides a central point for tracking all applicable air quality requirements for every source required to obtain a permit. Each state was also required to establish a Title V Operating Permit Program. IAC 567-Chapter 22.101, Applicability of Title V Operating Permit Requirements, establishes such a program. IPL will follow IAC 567Chapter 22.105a, Timely Application, which requires owners or operators of subject facilities to submit a Title V modification application within 3 months after initial startup of the new emission units. 2.4.5 Compliance Assurance Monitoring The USEPA established criteria that defines what monitoring should be conducted by a source owner or operator to provide a reasonable assurance of compliance with emission limits and standards, to certify compliance under the Title V Operating Permit Program. A compliance assurance monitoring (CAM) plan, in accordance with 40 CFR, Part 64, is a required element of the Title V permit, if such a plan applies. CAM applies to each pollutant specific emission unit (PSEU) that meets the following three conditions: • Is subject to an emission limitation or standard, and • Uses a control device to achieve compliance, and • Has pre-control emissions that exceed or are equivalent to the major source threshold. Pre-controlled emissions of PM10 and H2SO4 mist from the Project will be above their respective major source thresholds and will be subject to an emission limitation. Additionally, these emissions will be controlled by add-on control devices. Emissions of SO2 and NOx are regulated under the acid rain rule and can be excluded from the CAM rule. CAM will be addressed in the application for the Title V modification discussed above. 2.4.6 Chemical Accident Prevention 40 CFR Part 68, Accidental Release Prevention Provisions, under CAA Section 112(r), Prevention of Accidental Releases, establishes a general duty for owners and operators of stationary sources who produce, process, handle, or store any of a number of regulated substances, to prevent and mitigate accidental releases of these substances by 102607-145491 2-18 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 Project Characterization preparing detailed risk assessments and implementing a number of safety procedures through the preparation of a risk management plan (RMP). The specific requirements of the RMP for affected facilities are established in 40 CFR Part 68, Accidental Release Prevention Provisions. These regulations require the owner or operator of an affected source to prepare and implement an RMP to detect and prevent or minimize accidental releases of regulated substances, and to provide a prompt emergency response to any such release to protect human health and the environment. Affected facilities are those stationary sources that store, use, or handle any of 140 listed hazardous chemicals or flammable/explosive substances in amounts greater than the listed threshold quantities. This list of regulated substances includes commonly stored liquid phases of gases such as ammonia, which the SGS may store at quantities near or above the threshold levels. Ammonia would be used in conjunction with the SCR for NOx control. The RMP is generally composed of three sections, including a hazard assessment, a prevention program, and an emergency release response program. For affected facilities, submittal of the comprehensive RMP is required by the later of the following dates: • Three years after the date when a regulated substance is listed. • The date on which a regulated substance is first present above the threshold quantity at the facility. The Project’s SCR will use aqueous ammonia at less than 20 percent concentration. As such, no RMP will be required for the Project’s use of ammonia. 2.4.7 Title IV Acid Rain Permit Program Title IV of the CAA imposes stringent requirements on electrical utilities and is enforced through the administration of the Title IV Acid Rain Permit Program, which is designed to achieve reductions in emissions of SO2 and NOx. The centerpiece of the Title IV program is the establishment of an SO2 emissions allowance and trading program. The Title IV requirements are applicable to “affected” units, and affected units are then classified as Phase I (1995 to 1999) or Phase II (2000 to present). The Project will qualify as a Phase II acid rain new affected unit, subject to the following general requirements: • Duty to apply for an Acid Rain Permit: Acid rain permit applications for new units are due 24 months before the unit commences operation. An Acid Rain Permit application will be submitted accordingly, in the applicable time frame. 102607-145491 2-19 Interstate Power and Light Sutherland Unit 4 Air Permit Application • 2.0 Project Characterization Duty to obtain allowances: Emission allowances will be obtained as required by the acid rain provisions. • Installation, operation, and certification of Continuous Emissions Monitoring Systems (CEMs): CEMs will be installed as required by the acid rain provisions. In addition to the above requirements, the contents of the Acid Rain Permit will be incorporated into the modified Title V Operating Permit discussed previously. The acid rain requirements are incorporated in IAC 567-22.125. 2.4.8 Other Iowa State Requirements As mentioned earlier, the IDNR has permitting and review authority for all air quality projects in Iowa through the USEPA-approved SIP. Additionally, IDNR has promulgated regulations for new and modified air pollutant sources, which are published in IAC Section 567-Chapters 20 through 34. Several of these regulations have already been addressed earlier, since they incorporate federal regulations by reference. Other applicable state regulations not previously discussed are presented below. 2.4.9 Emission Standards for Contaminants IAC 567-23.3(2)(c), Fugitive Dust, stipulates that no person shall cause, suffer, or allow any material to be handled, processed, transported, or stored; a building or its appurtenances to be constructed, altered, repaired, or demolished; or a road to be used without taking reasonable precautions to prevent particulate matter from becoming airborne and to prevent visible fugitive dust at the property line. Fugitive dust will be produced from the Project’s material handling, storage, conveying, and hauling systems. IPL will comply with this regulation by applying water or other suitable chemicals on roads, materials stockpiles, and other surfaces that can create airborne dusts. Wherever applicable, IPL will install and use enclosures, fans, and fabric filters to enclose and vent the handling of dusty materials, or use water sprays or other measures to suppress fugitive dust emissions. 2.4.10 Provisions for Air Quality Emissions Trading Programs IAC 567-34 implements the provisions for certain federal air emissions trading programs to control emissions of specific pollutants. Two such programs that are applicable to the Project are discussed below. 2.4.10.1 Clean Air Interstate Rule (CAIR). On May 12, 2005, the USEPA promulgated the CAIR to address interstate transport of SO2 and NOx emissions from eastern and midwestern states, including Iowa, which were found to contribute to 102607-145491 2-20 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 Project Characterization unhealthy levels of fine particles and ozone in downwind states. Although Iowa is currently in attainment for all NAAQS, it is included in the CAIR provisions because the USEPA found that Iowa’s emissions contribute to downwind nonattainment of air quality standards. As such, Iowa is required to meet the USEPA-prescribed emission targets in two phases. The first phase begins in 2009, while the second phase begins in 2015. The federal rule provided two options by which affected states could adopt the CAIR: 1) adopt the USEPA’s “model” rules that require electric generating units (EGUs) to participate in an interstate cap and trade program, or 2) establish emissions controls and emission caps for one or more industry sectors. In May 2005, the IDNR convened a workgroup to assist with rulemaking activities related to the adoption of the CAIR. The majority of the workgroup members recommended that the IDNR adopt the USEPA’s cap and trade program for regulating emissions from EGUs. Upon reviewing the CAIR provisions, considering the recommendations from all workgroup members and all public comments received during the comment period, IDNR adopted the USEPA’s cap and trade program for implementing the CAIR. Under the CAIR’s cap and trade approach, the USEPA allocates emissions allowance budgets to the state for NOx emissions. CAIR SO2 allowances are allocated to affected EGUs from the current allowances under the existing Acid Rain program. The state is responsible for allocating the initial NOx allowances to CAIR-affected facilities. Each allowance is equal to one ton of emissions. Upon initial allocation of NOx and SO2 allowances, EGUs can then trade them through a USEPA-managed trading program. Market forces determine the trade currency (allowance) values. At the end of each year, each affected EGU must hold one allowance for each ton of SO2 or NOx emitted. 2.4.10.2 Clean Air Mercury Rule. On May 18, 2005, the USEPA promulgated the CAMR to address mercury emissions. The CAMR rule permanently caps and reduces the nationwide level of mercury emissions from coal fired power plants. When fully implemented, it is estimated that the CAMR will reduce utility mercury emissions in 48 states to 15 tons annually, a 70 percent reduction from 2002 levels. As previously described in Section 2.4.2.1, CAMR also includes a NSPS for coal fired EGUs constructed after January 30, 2004. Affected new sources will need to meet a stringent emission standard for mercury and conduct emissions testing and continuous emissions monitoring. The first phase of the CAMR, set to occur in 2010, will place a nationwide, 38 ton cap on mercury emissions. The second phase of the CAMR will place a nationwide, 15 ton cap on mercury emissions, which will occur in 2018. Under the CAMR, each state is provided with an annual emissions cap for mercury. States must meet the required targets by either 1) adopting USEPA’s “model” rules that will require affected 102607-145491 2-21 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 Project Characterization coal fired EGUs to participate in a USEPA-administered interstate cap and trade program, or 2) establish source-by-source controls to achieve the USEPA-prescribed mercury cap. In May 2005, the IDNR convened a workgroup to assist with rulemaking activities related to the adoption of the CAMR. The majority of the workgroup members recommended that the IDNR adopt the USEPA’s cap and trade program for regulating mercury emissions from coal fired EGUs. Upon reviewing the CAMR provisions, considering the recommendations from all workgroup members and all public comments received during the comment period, the IDNR adopted the USEPA’s cap and trade program for implementing the CAMR. Under the CAMR’s cap and trade emissions trading program, each ounce of mercury emitted annually from an affected EGU will require one mercury allowance. The mercury allowances will be traded on a USEPA-administered open market, which will establish the trade currency (allowance) value. 2.4.11 Green House Gases (GHG) In early 2007, the Iowa Senate File 485 amended Iowa Code Section 455B.131 and required the IDNR to include estimates of emissions of some greenhouse gases in its construction permitting and emissions inventory programs. This bill also instructed the IDNR to develop a GHG inventorying method by January 1, 2008, and create a voluntary greenhouse gas registry by January 1, 2009, to track and credit companies in Iowa that reduce their emissions of greenhouse gases or that provide increased energy efficiency. On July 5, 2007, Iowa joined the Climate Registry, which is a multistate and tribe collaboration aimed at developing and managing a common greenhouse gas emissions reporting system. The IDNR is currently drafting rules that pertain to the voluntary Climate Registry and mandatory GHG inventory. It is expected that the draft rules will establish a mechanism to coordinate the information obtained in the greenhouse gas inventory with the Climate Registry, so regulated entities do not have to report the same information twice. The IDNR is also requiring all construction permit applications filed after July 2, 2007, to include potential greenhouse gas emissions for the project. The IDNR has published the appropriate GHG form and emissions estimation guidance. IPL has included the GHG form in Appendix A of this application package and estimated GHG emissions from all combustion sources that will be installed as part of the Project. 102607-145491 2-22 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.0 3.0 Best Available Control Technology Best Available Control Technology As discussed in Section 2.4, the Project is classified as a major modification to an existing major source. Based on the Project’s calculated PTE emissions increase (Table 2-2), the Project is subject to a BACT review for SO2, NOx, CO, PM/PM10, VOC, H2SO4, and fluorides. This section presents a summary of the BACT analysis methodology and the emissions control determinations for the Project’s affected equipment. The complete regulatory BACT analysis is included as Appendix H of this application. 3.1 BACT Methodology A BACT analysis was conducted for the Project’s 648 MW (net) SCPC boiler (SGS Unit 4); auxiliary steam boiler; gate station heater; emergency generator; fire pump and fire booster pump engines; cooling tower; and material handling systems for coal, limestone, ash, FGD waste, and reagent. As required under the NSR/PSD regulations, the BACT analysis employed the USEPA’s recommended top-down, five-step analysis process to determine the appropriate BACT emission limitations for Project. In summary, the BACT analysis was conducted in the following manner: • Step 1: Identify All Control Technologies • Step 2: Eliminate Technically Infeasible Options • Step 3: Rank Remaining Control Technologies by Effectiveness • Step 4: Evaluate Most Effective Controls and Document Results • Step 5: Select BACT As the aforementioned BACT methodology suggests, 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 (i.e., 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 considerations. BACT cannot be determined to be less stringent than the emissions limits established by an applicable NSPS for the affected air emission source. 102607-145491 3-1 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.2 3.0 Best Available Control Technology Summary of the BACT Determination Tables 3-1 and 3-2 present a summary of the BACT emission limit determinations, control equipment, and proposed averaging period for the Project. Table 3-1 summarizes the BACT results for Project, with the exception of the material handling sources, which are presented in Table 3-2. 102607-145491 3-2 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.0 Best Available Control Technology Table 3-1 BACT Determination Summary Emission Unit: 649 MW (net) SCPC Boiler (Steam Capacity Rating 4,389,000 lb/h) Pollutant Control Technology Emission Basis Avg. Period Testing Method SO2 Wet FGD 0.06 lb/MBtu or 98 percent removal (whichever occurs first) with 0.08 lb/MBtu upper limit. 30 day CEMS NOx LNB/OFA and SCR 0.05 lb/MBtu 30 day CEMS PM/PM10 Fabric Filter 0.012 lb/MBtu (filterable) 3 hour test runs (average) USEPA Method 5B 0.018 lb/MBtu (total) 3 hour test runs (average) USEPA Method 5B + 202 with condensable artifact modification Visible Emissions (Opacity) Fabric Filter 10% 6-minute average COMS CO Good Combustion Controls 0.12 lb/MBtu 8 hour CEMS VOC Good Combustion Controls 0.0034 lb/MBtu 3 hour test runs (average) USEPA Method 18 H2SO4 Sorbent Injection/Fabric Filter 0.004 lb/MBtu 3 hour test runs (average) Controlled Condensate Test Method Fluorides Wet FGD 0.0002 lb/MBtu 3 hour test runs (average) USEPA Method 13B or USEPA Method 26A Emission Unit: Auxiliary Steam Boiler (270 MBtu/h) Pollutant Control Technology Emission Basis Avg. Period Testing Method SO2 Natural Gas Firing 0.0006 lb/MBtu NA Fuel Recordkeeping NOx Good Combustion Controls 0.037 lb/MBtu 3 hour test runs (average) USEPA Method 7E PM/PM10 Natural Gas Firing 0.007 lb/MBtu NA Fuel Recordkeeping CO Good Combustion Controls 0.074 lb/MBtu NA Fuel Recordkeeping VOC Good Combustion Controls 0.005 lb/MBtu NA Fuel Recordkeeping H2SO4 Natural Gas Firing 0.0009 lb/MBtu NA Fuel Recordkeeping 102607-145491 3-3 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.0 Best Available Control Technology Table 3-1 (Continued) BACT Determination Summary Emission Unit: Emergency Generator (2,000 kW) Pollutant Control Technology Emission Basis SO2 Low Sulfur Distillate Fuel Oil < 0.05% Sulfur Fuel Oil NOx Good Combustion Controls 6.47 g/bhph PM/PM10 Low Sulfur Distillate Fuel Oil 0.08 g/bhph CO Good Combustion Controls 0.53 g/bhph VOC Good Combustion Controls 0.27 g/bhph H2SO4 Low Sulfur Distillate Fuel Oil < 0.05 % Sulfur Fuel Oil Emission Unit: Emergency Fire Pump (575 bhp) Pollutant Control Technology Emission Basis SO2 Low Sulfur Distillate Fuel Oil < 0.05% Sulfur Fuel Oil NOx Good Combustion Controls 4.9 g/bhph PM/PM10 Low Sulfur Distillate Fuel Oil 0.08 g/bhph CO Good Combustion Controls 0.75 g/bhph VOC Good Combustion Controls 0.29 g/bhph H2SO4 Low Sulfur Distillate Fuel Oil < 0.05% Sulfur Fuel Oil Emission Unit: Emergency Fire Booster Pump (149 bhp) Pollutant Control Technology Emission Basis SO2 Low Sulfur Distillate Fuel Oil < 0.05% Sulfur Fuel Oil NOx Good Combustion Controls 5.20 g/bhph PM/PM10 Low Sulfur Distillate Fuel Oil 0.19 g/bhph CO Good Combustion Controls 0.33 g/bhph VOC Good Combustion Controls 0.36 g/bhph H2SO4 Low Sulfur Distillate Fuel Oil < 0.05% Sulfur Fuel Oil Emission Unit: Cooling Tower Pollutant Control Technology Emission Basis PM/PM10 Drift Eliminators 0.0005% drift rate Gate Station Gas Heater (3 MBtu/hr) Pollutant Control Technology Emission Basis SO2 Natural Gas Firing 0.0006 lb/MBtu NOx Good Combustion Controls 0.046 lb/MBtu PM/PM10 Natural Gas Firing 0.0074 lb/MBtu CO Good Combustion Controls 0.046 lb/MBtu VOC Good Combustion Controls 0.0054 lb/MBtu H2SO4 Natural Gas Firing 0.0009 lb/MBtu 102607-145491 3-4 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.0 Best Available Control Technology Table 3-1 (Continued) BACT Determination Summary Emission Unit: Material Handling Systems for the Conveyance of Coal, Biomass, Ash, and Reagent Pollutant Emission Source Control Technology PM/PM10 Coal Handling Refer to Table 3-2 Limestone Handling Refer to Table 3-2 Fly Ash Handling Refer to Table 3-2 FGD Waste Handling Refer to Table 3-2 Bottom Ash Handling Refer to Table 3-2 Biomass Handling Refer to Table 3-2 Other Material Handling Refer to Table 3-2 CEMS = Continuous Emissions Monitoring System. FGD = Flue Gas Desulfurization. g/bhph = Grams per Brake Horsepower Hour. LNB/OFA = Low NOx Burner/Overfire Air. MBtu = Million British Thermal Unit. SCR = Selective Catalytic Reduction. 30 day = 30 day rolling average 102607-145491 3-5 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.0 Best Available Control Technology Table 3-2 Material Handling Particulate BACT Determinations System Emission Source BACT Control Technology Determination Rotary Car Dumper (DPR-1) Coal Unloading 100% building enclosure Dust collection system (0.01 gr/dscf) 100% belt enclosure and dust collection system (0.01 gr/dscf) 100% transfer tower enclosure (TT-1) and dust collection system (0.01 gr/dscf) 100% belt enclosure Telescopic chute and spray ring (CHE-1) 100% belt enclosure Belt Conveyor (BC-1) Coal Receiving Transfer Tower (TT-1) Belt Conveyor (BC-2) Emergency Stockout Belt Conveyor (BC-3) Emergency Stockout Reclaim Belt Conveyor (BC-4) Stacker/Reclaimer Conveyor Stack/Reclaimer (SR-1) Transfer Tower (TT-2) Coal Handling Belt Conveyor (BC-5A) Existing Units Reclaim Transfer Tower (TT-3) Belt Conveyor (BC-5B) Existing Units Feed Truck Loadout Belt Conveyor (BC-6) Pile Stockout Belt Conveyor (BC-7) Pile Stockout Belt Conveyor (BC-8) Pile Reclaim Belt Conveyor (BC-9) Pile Reclaim Belt Conveyors (BC-10 and 11) Crusher Feed Crusher House (CH-1) Belt Conveyors (BC-12 and 13) Plant Feed (SGS Unit 4) 102607-145491 Partial belt enclosure Dust suppression 100% transfer tower enclosure (TT-2) and dust collection system (0.01 gr/dscf) 100% belt enclosure and dust collection system (0.01 gr/dscf) 100% transfer tower enclosure (TT-3) and dust collection system (0.01 gr/dscf) 100% belt enclosure 100% building enclosure Dust collection system (0.01 gr/dscf) Loadout chute 100% belt enclosure Telescopic chute and spray ring (CHE-2) 100% belt enclosure Telescopic chute and spray ring (CHE-3) 100% belt enclosure and dust collection system (0.01 gr/dscf) 100% belt enclosure and dust collection system (0.01 gr/dscf) 100% belt enclosure 100% crusher building enclosure (CH-1) Dust collection system (0.01 gr/dscf) 100% belt enclosure 3-6 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.0 Best Available Control Technology Table 3-2 (Continued) Material Handling Particulate BACT Determinations System Coal Handling (Continued) Emission Source BACT Control Technology Determination Transfer Tower (TT-4) 100% transfer tower enclosure (TT-4) and dust collection system (0.01 gr/dscf) 100% belt enclosure 100% boiler house enclosure and dust collection system (0.01 gr/dscf) Belt Conveyors (BC-14 and 15) Tripper Conveyors Railcar/Truck Bottom Dumper Limestone Unloading Belt Conveyor (CVY-1) Limestone Receiving/Stock Out Limestone Handling Belt Conveyor (CVY-2) Limestone Reclaim Belt Conveyor (CVY-3) Distribution Conveyor Two Limestone Storage Silos Fly Ash Handling Saleable Fly Ash Storage Silo Saleable Fly Ash Separators Combination Railcar and Truck Loader (from saleable fly ash storage silo) Saleable Fly Ash Winter Storage Building 100% building enclosure Dust collection system (0.005 gr/dscf) 100% belt enclosure and dust collection system (0.005 gr/dscf) Telescopic chute (CHE-1) and dust suppression (DS-2) 75% storage building enclosure 100% belt enclosure 100% belt enclosure and dust collection system (0.005 gr/dscf) Bin vent fabric filter Bin vent fabric filter Exhaust vent fabric filter Telescopic chute Truck washdown facility 100% storage building enclosure Dust collection system (0.01 gr/dscf) Telescopic chute Saleable Fly Ash Truck Loader (from winter storage building) Waste Fly Ash Storage Silo Bin vent fabric filter Waste Fly Ash Separators Exhaust vent fabric filter Truck Loader (from waste fly ash storage silo) Telescopic chute FGD Waste Handling Wet Solids Material No fugitive or point source emissions Bottom Ash Handling Wet Solids Material No fugitive or point source emissions Biomass Handling Bale Conveyor No fugitive or point source emissions Hammermill No fugitive or point source emissions Eliminator Ginder Dust collection system (0.01 gr/dscf) Tube Conveyor Dust collection system (0.01 gr/dscf) Surge Bin w/rotary air lock Dust collection system (0.01 gr/dscf) 102607-145491 3-7 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.0 Best Available Control Technology Table 3-2 (Continued) Material Handling Particulate BACT Determinations System Emission Source BACT Control Technology Determination Haul Roads – Material Delivery and Disposal Paved roads Road surface cleaning Wet dust suppression Wet dust suppression and chemical surfactant Pile best management practices Crusting agent Wet dust suppression and chemical surfactant 75% storage building enclosure 100% storage building enclosure Dust collection system (0.01 gr/dscf) Limited operation Wet dust suppression Active Coal Storage Piles Other Material Handling Inactive Coal Storage Piles Limestone Storage Pile Saleable Fly Ash Winter Storage Pile Front End Loader/Dozer Note: Detailed material handling process flow diagrams identifying the material handling systems, emission sources, and particulate BACT control equipment are included in Appendix E of the air permit application. 102607-145491 3-8 Interstate Power and Light Sutherland Unit 4 Air Permit Application 4.0 4.0 Air Dispersion Modeling Protocol and Impact Analysis Air Dispersion Modeling Protocol and Impact Analysis This section contains a summary of the air dispersion modeling protocol and the results of the ambient air quality impact analysis (AQIA) air dispersion modeling for the proposed Project. The AQIA was conducted in accordance with USEPA’s Guideline on Air Quality Models (incorporated as Appendix W of 40 CFR 51) and IDNR’s Air Dispersion Modeling Guidelines for PSD Projects, as well as a pre-application meeting held with the IDNR and USEPA Region VII on February 7, 2007. The complete air dispersion modeling methodology and AQIA is included as Appendix I of this application. 4.1 Ambient Air Quality Impact Results The AERMOD air dispersion model was used to analyze the air quality impact resulting from the proposed Project. As fully described in Appendix I, multiple operating scenarios based on fuel type, operating load, and worst case/conservative emission source assumptions were analyzed in AERMOD to determine the Project’s maximum model predicted ground level concentration for each regulated pollutant subject to PSD review. The results of the air dispersion modeling are presented in Table 4-1 and compared to the respective PSD modeling significance and de minimis ambient monitoring levels. The impacts presented in Table 4-1 conservatively have all sources operating simultaneously at their maximum design rates (exceptions are the emergency diesel generator and two emergency diesel fire pumps which, on a short-term basis, will not be operated when the rest of the facility is in operation, except for testing and maintenance purposes). Annually, however, these additional emissions sources were included in the modeling of the full facility. As the results in Table 4-1 indicate, the Project’s model-predicted air quality impacts are less than the modeling significance and de minimis ambient monitoring concentrations, indicting that the Project is not subject to additional cumulative source air dispersion modeling analysis or pre-construction ambient monitoring requirements, respectively, as part of the PSD review process. 102607-145491 4-1 Interstate Power and Light Sutherland Unit 4 Air Permit Application 4.0 Air Dispersion Modeling Protocol and Impact Analysis Table 4-1 Comparison of the Project’s Maximum Modeled Impacts with the PSD Class II Modeling Significance and Monitoring de minimis Levels Operation Typical Operation(2) Pollutant Averaging Period AERMOD 1st High Maximum Impact(1) (μg/m3) NOx Annual 0.59 1 14 SO2 Annual 0.39 1 -- 24 hour 4.85 5 13 3 hour 15.41 25 -- Annual 0.77 1 -- 24 hour 4.92 5 10 8 hour 19.19 500 575 1 hour 49.12 2,000 -- 24 hour 0.01 -- 0.25 PM10 CO Fluorides PSD Class II Modeling Significance Level (μg/m3) PSD Class II Monitoring de minimis Level (μg/m3) (1) Represents the first high maximum model-predicted, ground level impact from the 5 year meteorological data set used. (2) On a short-term basis, typical operation includes the continuous and simultaneous operation of the proposed Unit 4 pulverized coal boiler, auxiliary boiler, natural gas fired heater, cooling tower, coal, limestone, ash, gypsum, and biomass material handling processes; truck deliveries; and byproduct and waste removals. It does not include the operation of the emergency diesel generator and two emergency diesel fire pumps, which, as allowed by IDNR, were modeled separately and compared to the short-term NAAQS (the results of which are presented in Table 4-2). On an annual basis, in addition to continuous and simultaneous operation of the sources listed immediately above, the modeling includes the auxiliary boiler operating for 2,000 hours per year. 102607-145491 4-2 Interstate Power and Light Sutherland Unit 4 Air Permit Application 4.0 Air Dispersion Modeling Protocol and Impact Analysis Additionally, as allowed under IDNR rules, the Project’s ancillary equipment, including the auxiliary boiler, emergency diesel generator, and two emergency diesel fire pumps, were included in a separate AERMOD air dispersion modeling analysis to assess their compliance with the applicable short-term NAAQS. As shown in Table 4-2, the modeling results for this scenario are all below the applicable NAAQS. It is important to note that the auxiliary boiler was conservatively included in both the short-term NAAQS analysis presented in Table 4-2, as well as the full facility modeling presented in Table 4-1, since it may operate both when the rest of the facility is not in operation (i.e., with the ancillary equipment) and when SGS Unit 4 is in operation. Table 4-2 Comparison of the Ancillary Equipment’s Maximum Modeled Impacts with the Short-Term NAAQS Operation Ancillary Operation(2) Pollutant Averaging Period AERMOD 1st High Maximum Impact(1) (μg/m3) SO2 24 hour 4.10 20 24.10 365 3 hour 19.80 20 39.80 -- PM10 24 hour 1.58 45 46.58 150 CO 8 hour 43.02 0 43.02 10,000 1 hour 96.82 0 96.82 40,000 Background Concentration Value (μg/m3)(3) Total (μg/m3) NAAQS (μg/m3) (1) Represents the first high maximum model-predicted, ground level impact from the 5 year meteorological data set used. (2) Ancillary equipment includes the unlimited short-term operation of the auxiliary boiler, emergency diesel generator, and two emergency diesel fire pumps for the full extent of the averaging period of concern. It is important to note that the auxiliary boiler was conservatively included in both the shortterm NAAQS analysis presented in this table, as well as the full facility modeling presented in Table 4-1, since it may operate both when the rest of the facility is not in operation and when SGS Unit 4 is in operation. (3) Taken from Table 4, Statewide Default Background Values of the IDNR’s Air Dispersion Modeling Guidelines for PSD Project (Version 010605), and updated to include the most recent background value for PM10 24 hour averaging period, as received in correspondence with IDNR staff. 102607-145491 4-3 Interstate Power and Light Sutherland Unit 4 Air Permit Application 4.2 4.0 Air Dispersion Modeling Protocol and Impact Analysis Additional Impacts Analysis In addition to the AQIA presented in the previous section, the PSD air quality regulations require the preparation of an analysis of additional impacts that may result from the proposed Project. The additional impact analysis considers the Project’s potential impairment to visibility, soils, and vegetation, as well as projected air quality impacts that may occur as the result of general commercial, residential, industrial, and other growth associated with the Project. While the complete report of the Project’s additional impact analysis is contained in Appendix I, a summary of the results concludes that the Project will have a minimal or insignificant impact to these resources. Additionally, because the distance to the nearest Class I area is approximately 510 km from the SGS, a regional haze visibility impairment analysis is not proposed or required for this Project. 102607-145491 4-4 Interstate Power and Light Sutherland Unit 4 Air Permit Application Appendix A Appendix A IDNR Application Forms 102607-145491 A-1 APPENDIX A Application Forms: Emission Units Legend Emission Unit (EU) Name Unit 4 Main Boiler Auxiliary Boiler Emergency Diesel Generator Diesel Fire Pump Diesel Booster Fire Pump Linear Mechanical Draft Cooling Tower Coal Material Handling Rotary Car Dumper Building (a) Unload from railcars to Hopper HPR-1 at rotary car dumper. Rotary Railcar Dump Vault Transfer from Hopper HPR-1 to to Belt Feeder BF-1. Transfer from Hopper HPR-1 to to Belt Feeder BF-2. Transfer from Belt Feeder BF-1 to Belt Conveyor BC-1. Transfer from Belt Feeder BF-2 to Belt Conveyor BC-1. Transfer Tower TT-1 Transfer from Belt Conveyor BC-1 to Belt Conveyor BC-4. Coal Stockout Pile No. 1 (Emergency) Transfer from Belt Conveyor BC-2 to Coal Stockout Pile No. 1 Transfer from Reclaim Hopper RH-1 to Belt feeder BF-3 North and South Coal Piles (Coal Stockout Pile No. 2) Transfer from Belt Conveyor BC-4 to SR-1 Boom Conveyor/Belt Conveyor BC-4 Transfer from SR-1 Boom Conveyor to Stockout Pile 2 Transfer Tower TT-2 Transfer from Belt Conveyor BC-4 to Belt Conveyor BC-6. Transfer from Belt Conveyor BC-4 to Belt Conveyor BC-7. Transfer from Belt Conveyor BC-8 to Belt Conveyor BC-10. Transfer from Belt Conveyor BC-8 to Belt Conveyor BC-11. Transfer from Belt Conveyor BC-9 to Belt Conveyor BC-10. Transfer from Belt Conveyor BC-9 to Belt Conveyor BC-11. Transfer from Belt Conveyor BC-4 to Belt Conveyor BC-10. Transfer from Belt Conveyor BC-4 to Belt Conveyor BC-11. Coal Stockout Pile No. 3 Transfer from Belt Conveyor BC-6 to Coal Stockout Pile No. 3 Pile 3 Vault Transfer from Reclaim Hopper RH-2 to Belt Feeder BF-4. Transfer from Belt Feeder BF-4 to Belt Conveyor BC-8. Coal Stockout Pile No. 4 Transfer from belt Conveyor BC-7 to Coal Stockout Pile No. 4 Pile 4 Vault Transfer from Reclaim Hopper RH-3 to Belt Feeder BF-5. Transfer from Belt Feeder BF-5 to Belt Conveyor BC-9. Associated Emission Point No. 248 249 250a, 250b 251 252 253a through p 254 through 279 EU No. 248 249 250 251 252 253 254 254a, 254b 255a 255b 255c 255d 255 255 255 255 256b 273 257 258 274, 275 256 273 257 258 274, 275 259a/b 260a/b and 261 a-d 259 260, 261 262a 262b 262c 262d 262e 262f 262g 262h 276 263 262 262 262 262 262 262 262 262 276 263 264a 264b 277 265 264 264 277 265 266a 266b 266 266 Emission Unit (EU) Name Crusher House CH-1 Transfer from Belt Conveyor BC-10 to Crusher Surge Bin SB-1 Transfer from Belt Conveyor BC-11 to Crusher Surge Bin SB-1 Transfer from surge bin SB-1 to Belt Feeder BF-6. Transfer from surge bin SB-1 to Belt Feeder BF-7. Crusher CR-1. Crusher CR-2. Transfer from Belt Feeder BF-6 through Crusher CR-1 to Belt Conveyor BC-13. Transfer from Belt Feeder BF-7 through Crusher CR-2 to Belt Conveyor BC-12. Transfer Tower TT-4 Transfer from Belt Conveyor BC-12 to Tripper Conveyors BC-1 Transfer from Belt Conveyor BC-12 to Tripper Conveyors BCTransfer from Belt Conveyor BC-13 to Tripper Conveyors BC-1 Transfer from Belt Conveyor BC-13 to Tripper Conveyors BCTransfer from Belt Conveyor BC-14 to Coal Silos. Transfer from Belt Conveyor BC-15 to Coal Silos. Pile 2 Vault Transfer from Reclaim Hopper RH-4 to BF-8. Transfer from Belt Feeder BF-8 to Belt Conveyor BC-5A. Transfer from Reclaim Hopper RH-5 to BF-9. Transfer from Belt Feeder BF-9 to Belt Conveyor BC-5A. Transfer Tower TT-3 Transfer from Belt Conveyor BC-5A to Belt Conveyor BC-5B. Existing Transfer Tower Transfer from Belt Conveyor BC-5B to Hopper HPR-2 Truck Loadout Enclosure Transfer from the Hopper HPR-2 to future truck load out Northgate Haul Road Westgate Haul Road Limestone Material Handling Railcar/Truck Unloading Building (a) Unload from railcars to hopper at unloader. Railcar/Truck Unloading Vault Transfer from Hopper HPR-1 to Belt Feeder FDR-1. Transfer from Hopper HPR-1 to Belt Feeder FDR-2. Transfer from Belt Feeder FDR-1 to Belt Conveyor CVY-1. Transfer from Belt Feeder FDR-2 to Belt Conveyor CVY-1. Limestone Building Storage-Limestone Active Pile Transfer from receiving conveyor CVY-1 to Limestone Building Storage Pile Vault Transfer from Hopper HPR-2 to Belt Feeder FDR-3. Transfer from Hopper HPR-3 to Belt Feeder FDR-4. Transfer from Belt Feeder FDR-3 to Belt Conveyor CVY-2. Transfer from Belt Feeder FDR-4 to Belt Conveyor CVY-2. EU No. Associated Emission Point No. 267a 267b 267c 267d 267e 267f 267 267 267 267 267 267 267g 267 267h 267 268a 268b 268c 268d 268e 268f 268 268 268 268 268 268 269a 269b 269c 269d 269 269 269 269 270 270 271 271 272 278 279 272 278 279 280 through 285 280 280a, 280b 281a 281b 281c 281d 282 281 281 281 281 282b 282 282a 283a 283b 283c 283d 283 283 283 283 Emission Unit (EU) Name Limestone Silo 1 Transfer from Belt Conveyor CVY-2 to Limestone Silo 1. Limestone Silo 2 Transfer from Belt Conveyor CVY-2 to Belt Conveyor CVY-3. Transfer from Belt Conveyor CVY-3 to Limestone Silo 2. Saleable Flyash Handling and Storage Pneumatic Conveyor Blower Exhaust Pneumatic Conveyor Blower Exhaust Ash Silo bin vent fan Ash storage building Vent Fan Ash storage building Vent Fan Waste Flyash Handling and Storage Pneumatic Conveyor Blower Exhaust Pneumatic Conveyor Blower Exhaust Ash silo bin vent fan Material Handling - Others PAC Transfer to Silo Sorbent Transfer to Day Silo Sorbent Transfer to Long Term Silo Transfer of Lime Biomass Material Handling Biomass Building (Line 1) Biomass Building (Line 2) Gate Station Heater (3 MBtu/hour) EU No. Associated Emission Point No. 284 284 285a 285b 286 286 287 288 288 289 289 290 291 292 293 294 295 296 297 285 285 286 through 288 286a 286b 287 288a 288b 289-290 289a 289b 290 291 292 293 294 295-296 295 296 297 EU5 ATTN: Application Log in AIR QUALITY BUREAU 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 AIR CONSTRUCTION PERMIT APPLICATION Form EU5: Boiler Information Please see instruction on reverse side EXEMPTION According to 567 Iowa Administrative Code Chapter 22.1(2)a, an indirect fired combustion source that uses only Natural Gas or LPG and has a heating capacity of less than 10 MMBTU/hr is exempted from the provisions of construction permits. According to 567 Iowa Administrative Code Chapter 22.1(2)b, an indirect fired combustion source that uses coal, fuel oil or untreated wood, seeds, pellets, other vegetable matter and has a heating capacity of less than 1 MMBTU/hr is exempted from the provisions of construction permits. Company Name: IPL-Sutherland Generating Station Unit 4 BOILER (EMISSION UNIT) DESCRIPTION AND SPECIFICATIONS New Unit Unpermitted Existing Unit (1) Boiler ID Number: EU-248 Modification to an unit with Permit #: (2) Rated Capacity (MMBTU/hr heat input): 6,326 (PRB-1) (3) Construction Date: November 2008 (4) Manufacturer: TBD (5) Model: TBD (6) Date of Modification (if applicable): N/A (8) Control Device (if any): CE248 A, B, C, D and E - SCR/PAC/FF/WFGD (7) Serial Number (if available): and sorbent injection FUEL DESCRIPTION AND SPECIFICATIONS (9) Fuel Type Natural Gas (cf/hr) Fuel Oil (# ) (gal/hr) (10) Full Load Consumption Rate (11) Sulfur Content wt% Coal type: PRB (lb/hr) Coal type: IL (lb/hr) Other Fuels Solid Biomass (lb/hr) 762,157 572,084 44,000 0.33 3.11 <0.1 None None Up to 5% of heat input from biomass (12) Requested Limit OPERATING LIMITS & SCHEDULE (13) Imposed Operating Limits (hours/year, or gallons fuel/year, etc.): None (14) Operating Schedule (hours/day, months/year, etc.): 24 hours/day, 12 months/year and 8,760 hours/year STACK/VENT (EMISSION POINT) SPECIFICATIONS (15) Stack/Vent ID: EP-248 (17) Stack Height (feet) from the Ground: 601 (18) Stack Height (feet) above the Building (If Applicable): (20) Distance (feet) from the Property Line: 1,476 (21) Rated Flow Rate ( 1,940,460 (PRB-1) acfm For Assistance 1-877-AIR-IOWA scfm): (16) Stack Opening Size: circular, diameter (inches) is: 316.56 other, size (inches x inches) is: (19) Discharge Style: V (Vertical, without rain cap or with unobstructing rain cap) VR (Vertical, with obstructing rain cap) H (Horizontal discharge) D (Downward discharge; for example, a goose neck stack) EXHAUST INFORMATION (22) Moisture Content % (if known): 6 (PRB-1) (23) Exit Temperature (°F) 130 (1-877-247-4692) Revised 11/2006 EU5 ATTN: Application Log in AIR QUALITY BUREAU 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 AIR CONSTRUCTION PERMIT APPLICATION Form EU5: Boiler Information Please see instruction on reverse side EXEMPTION According to 567 Iowa Administrative Code Chapter 22.1(2)a, an indirect fired combustion source that uses only Natural Gas or LPG and has a heating capacity of less than 10 MMBTU/hr is exempted from the provisions of construction permits. According to 567 Iowa Administrative Code Chapter 22.1(2)b, an indirect fired combustion source that uses coal, fuel oil or untreated wood, seeds, pellets, other vegetable matter and has a heating capacity of less than 1 MMBTU/hr is exempted from the provisions of construction permits. Company Name: IPL-Sutherland Generating Station Unit 4 BOILER (EMISSION UNIT) DESCRIPTION AND SPECIFICATIONS New Unit Unpermitted Existing Unit (1) Boiler ID Number: EU-249 Modification to an unit with Permit #: (2) Rated Capacity (MMBTU/hr heat input): 268.64 (3) Construction Date: November 2008 (4) Manufacturer: TBD (5) Model: TBD (6) Date of Modification (if applicable): N/A (8) Control Device (if any): (7) Serial Number (if available): TBD FUEL DESCRIPTION AND SPECIFICATIONS (9) Fuel Type Natural Gas (cf/hr) (10) Full Load Consumption Rate (11) Sulfur Content wt% Fuel Oil (# ) (gal/hr) Coal type: (lb/hr) Coal type: (lb/hr) Other Fuels (lb/hr) 263,115 N/A (12) Requested Limit N/A None OPERATING LIMITS & SCHEDULE (13) Imposed Operating Limits (hours/year, or gallons fuel/year, etc.): 527 million cubic feet per year of natural gas combustion. This operational limit is based on 2,000 hours per year of natural gas combustion at the maximum rated design heat input for the auxiliary boiler. (14) Operating Schedule (hours/day, months/year, etc.): 24 hours/day, 12 months/year and up to 527 million cubic feet per year of natural gas usage STACK/VENT (EMISSION POINT) SPECIFICATIONS (15) Stack/Vent ID: (16) Stack Opening Size: EP-249 circular, diameter (inches) is: 60 (17) Stack Height (feet) from the Ground: other, size (inches x inches) is: 285 (18) Stack Height (feet) (19) Discharge Style: above the Building (If Applicable): V (Vertical, without rain cap or with unobstructing rain cap) 11 VR (Vertical, with obstructing rain cap) (20) Distance (feet) from the Property Line: H (Horizontal discharge) 1,115 D (Downward discharge; for example, a goose neck stack) (21) Rated Flow Rate ( 51,850 acfm For Assistance 1-877-AIR-IOWA scfm): EXHAUST INFORMATION (22) Moisture Content % (if known): (23) Exit Temperature (°F) 650 (1-877-247-4692) Revised 11/2006 ATTN: Application Log in AIR QUALITY BUREAU 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 AIR CONSTRUCTION PERMIT APPLICATION Form EU1: Industrial Engine Information Please see instruction on reverse side EXEMPTION According to 567 Iowa Administrative Code Chapter 22.1(2)r, an internal combustion engine with a brake horsepower rating of less than 400 is exempted from the provisions of construction permits. Company Name: IPL - Sutherland Generating Station Unit 4 ENGINE (EMISSION UNIT) DESCRIPTION AND SPECIFICATIONS New Unit Unpermitted Existing Unit (1) Use of Engine: Normal Operation Modification to an unit with Permit #: Emergency Back-up (2) Engine ID Number: EU-250 (3) Rated Power: 2,937 bhp (5) Manufacturer: (6) Manufacture Date: TBD 2,000 KW (4) Construction Date: November 2008 (7) Model Year & Model Number: TBD (8) Engine Order Date: Fire Pump TBD (9) Control Device (if any): (10) Displacement per cylinder (L): TBD TBD (11) Engine Ignition Type: Spark Ignition (12) Engine Burn Type: Compression 2SLB 2SRB (13) Date of Modification (if applicable): 4SRB FUEL DESCRIPTION AND SPECIFICATIONS (14) Fuel Type Diesel Fuel (# ) (gal/hr) (15) Full Load Consumption Rate 138 (16) Actual Consumption Rate TBD (17) Sulfur Content wt% 0.05 Gasoline Fuel (gal/hr) N/A Natural Gas (cf/hr) Other Fuels (unit: ) N/A OPERATING LIMITS (18) Requested Operating Limits (hours/year, or gallons fuel/year, etc.): 100 hours/year STACK/VENT (EMISSION POINT) SPECIFICATIONS (19) Stack/Vent ID: EP-250a and EP-250b (21) Stack Height (feet) from the Ground: 10 (22) Stack Height (feet) above the Building (If Applicable): (24) Distance (feet) from the Property Line: 1,886 (25) Rated Flow Rate ( acfm scfm): 14,920 (total from two stacks) (20) Stack Opening Size: circular, diameter (inches) is: 8 other, size (inches x inches) is: Single Stack Dual Stack (23) Discharge Style: V (Vertical, without rain cap or with unobstructing rain cap) VR (Vertical, with obstructing rain cap) H (Horizontal discharge) D (Downward discharge; for example, a goose neck stack) I (Inside-Vent inside building) EXHAUST INFORMATION (26) Moisture Content % (if known): (27) Exit Temperature (°F) 761 ATTN: Application Log in AIR QUALITY BUREAU 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 AIR CONSTRUCTION PERMIT APPLICATION Form EU1: Industrial Engine Information Please see instruction on reverse side EXEMPTION According to 567 Iowa Administrative Code Chapter 22.1(2)r, an internal combustion engine with a brake horsepower rating of less than 400 is exempted from the provisions of construction permits. Company Name: IPL - Sutherland Generating Station Unit 4 ENGINE (EMISSION UNIT) DESCRIPTION AND SPECIFICATIONS New Unit Unpermitted Existing Unit (1) Use of Engine: Normal Operation Modification to an unit with Permit #: Emergency Back-up (2) Engine ID Number: EU-251 (3) Rated Power: 575 bhp (5) Manufacturer: (6) Manufacture Date: TBD (4) Construction Date: November 2008 KW (7) Model Year & Model Number: TBD (8) Engine Order Date: Fire Pump TBD (9) Control Device (if any): (10) Displacement per cylinder (L): TBD TBD (11) Engine Ignition Type: Spark Ignition (12) Engine Burn Type: Compression 2SLB 2SRB (13) Date of Modification (if applicable): 4SRB FUEL DESCRIPTION AND SPECIFICATIONS (14) Diesel Fuel (# ) (gal/hr) Fuel Type (15) Full Load Consumption Rate 29 (16) Actual Consumption Rate TBD (17) Sulfur Content wt% 0.05 Gasoline Fuel (gal/hr) N/A Natural Gas (cf/hr) Other Fuels (unit: ) N/A OPERATING LIMITS (18) Requested Operating Limits (hours/year, or gallons fuel/year, etc.): 100 hours/year STACK/VENT (EMISSION POINT) SPECIFICATIONS (19) Stack/Vent ID: EP-251 (21) Stack Height (feet) from the Ground: 12 (22) Stack Height (feet) above the Building (If Applicable): (24) Distance (feet) from the Property Line: 2,100 (25) Rated Flow Rate ( 2,904 acfm scfm): (20) Stack Opening Size: circular, diameter (inches) is: 6 other, size (inches x inches) is: Single Stack Dual Stack (23) Discharge Style: V (Vertical, without rain cap or with unobstructing rain cap) VR (Vertical, with obstructing rain cap) H (Horizontal discharge) D (Downward discharge; for example, a goose neck stack) I (Inside-Vent inside building) EXHAUST INFORMATION (26) Moisture Content % (if known): (27) Exit Temperature (°F) 918 ATTN: Application Log in AIR QUALITY BUREAU 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 AIR CONSTRUCTION PERMIT APPLICATION Form EU1: Industrial Engine Information Please see instruction on reverse side EXEMPTION According to 567 Iowa Administrative Code Chapter 22.1(2)r, an internal combustion engine with a brake horsepower rating of less than 400 is exempted from the provisions of construction permits. Company Name: IPL - Sutherland Generating Station Unit 4 ENGINE (EMISSION UNIT) DESCRIPTION AND SPECIFICATIONS New Unit Unpermitted Existing Unit (1) Use of Engine: Normal Operation Modification to an unit with Permit #: Emergency Back-up (2) Engine ID Number: EU-252 (3) Rated Power: 149 bhp (5) Manufacturer: (6) Manufacture Date: TBD KW (4) Construction Date: November 2008 (7) Model Year & Model Number: TBD (8) Engine Order Date: Fire Pump: Booster Fire Pump TBD (9) Control Device (if any): (10) Displacement per cylinder (L): TBD TBD (11) Engine Ignition Type: Spark Ignition (12) Engine Burn Type: Compression 2SLB 2SRB (13) Date of Modification (if applicable): 4SRB FUEL DESCRIPTION AND SPECIFICATIONS (14) Diesel Fuel (# ) (gal/hr) Fuel Type (15) Full Load Consumption Rate 9.5 (16) Actual Consumption Rate TBD (17) Sulfur Content wt% 0.05 Gasoline Fuel (gal/hr) N/A Natural Gas (cf/hr) Other Fuels (unit: ) N/A OPERATING LIMITS (18) Requested Operating Limits (hours/year, or gallons fuel/year, etc.): 100 hours/year STACK/VENT (EMISSION POINT) SPECIFICATIONS (19) Stack/Vent ID: EP-252 (21) Stack Height (feet) from the Ground: 12 (22) Stack Height (feet) above the Building (If Applicable): (24) Distance (feet) from the Property Line: 2,142 (25) Rated Flow Rate ( 790 acfm scfm): (20) Stack Opening Size: circular, diameter (inches) is: 5 other, size (inches x inches) is: Single Stack Dual Stack (23) Discharge Style: V (Vertical, without rain cap or with unobstructing rain cap) VR (Vertical, with obstructing rain cap) H (Horizontal discharge) D (Downward discharge; for example, a goose neck stack) I (Inside-Vent inside building) EXHAUST INFORMATION (26) Moisture Content % (if known): (27) Exit Temperature (°F) 1,044 AIR QUALITY BUREAU ATTN: Application Log in IOWA DNR Air Construction Permit Application 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EU4: Cooling Tower Information Please see instructions on the reverse side Company Name: IPL-Sutherland Generating Station Unit 4 COOLING TOWER IDENTIFICATION AND DESCRIPTION Tower 1 Tower 2 Tower 3 (1) Emission Unit Name Mechanical Draft Cooling Tower (2) Emission Unit ID Number EU-253 (3) Stack/Vent ID Number EP-253 (a thru p) (4) Tower Type N, U, M N, U, M N, U, M (N: New, U: Unpermitted, M: Modification) (5) Current Permit Number (6) Tower Construction Date November 2008 (7) Tower Manufacturer TBD (8) Tower Model Number TBD (9) Number of Cells in Tower 16 (2 x 8) (10) Tower Maximum Water Flow Rate 301,000 gallons per minute (11) Measured TDS Content (if known) 2,261 ppm (12) Do You Use Additives in the Water No Yes No Yes No Yes If Yes, Provide MSDS Sheets for Each (TBD) Additive CONTROL EQUIPMENT INFORMATION (13) Control Equipment No Yes No Yes No Yes (14) Control Equipment ID Number CE253 (15) Control Equipment Efficiency 0.0005% drift STACK/VENT INFORMATION (16) Cell Height from the Ground (ft) 53 (17) Distance from Property Line (ft) (18) Cell Stack Size (in Dia. or in.X in.) 360 (19) Stack Discharge Style Vertical (20) Cell Rated Air Flow Rate 1,477,500 ( acfm scfm) (21) Total Rated Air Flow Rate 23,640,000 ( acfm scfm) 104 (22) Exhaust Exit Temperature (°F) OPERATING SCHEDULE (23) Actual Operation (hours per year) TBD (24) Maximum Operation (hours per year) 8,760 REQUEST FOR PERMIT LIMITATIONS (25) Are you requesting any permit limits? No Yes. If yes, write down all that apply Tower Operation Hour Limits: TDS Limits (ppm): Material Usage Limits: Other: Served Tower 1 Tower 2 Rationale for Requesting the Limit(s): For Assistance 1-877-AIR IOWA (1-877-247-4692) Revised 11/2006 Tower 4 N, U, M No Yes No Yes EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point-Rail Car Unloading to Hopper (Rotary Railcar Dumper Building) 2) EU ID Number: EU-254 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-254a and EP-254b Previous Permit # is: 4,000 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-254a/b, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Hopper to Belt Feeder BF-1 2) EU ID Number: EU-255a 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-255 Previous Permit # is: 2,000 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-255, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Hopper to Belt Feeder BF-2 2) EU ID Number: EU-255b 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-255 Previous Permit # is: 2,000 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-255, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Feeder BF-1 to Belt Conveyor BC-1 2) EU ID Number: EU-255c 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-255 Previous Permit # is: 2,000 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-255, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Feeder BF-2 to Belt Conveyor BC-1 2) EU ID Number: EU-255d 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-255 Previous Permit # is: 2,000 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-255, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Conveyor BC-1 to Belt Conveyor BC-2 (Transfer Tower TT-1) 2) EU ID Number: EU-256a 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-256 Previous Permit # is: 4,000 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-256, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Conveyor BC-1 to Belt Conveyor BC-4 (Transfer Tower TT-1) 2) EU ID Number: EU-256b 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-256 Previous Permit # is: 4,000 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-256, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Conveyor BC-3 to Belt Conveyor BC-4 (Transfer Tower TT-1) 2) EU ID Number: EU-256c 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-256 Previous Permit # is: 1,200 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-256, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Conveyor BC-2 to Coal Stockout Pile No. 1 2) EU ID Number: EU-257 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-257 Previous Permit # is: 4,000 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? CE-257, Telescopic chute and wet suppression EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) No If Yes, Control Equipment name/ID are: Yes 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Reclaim Hopper RH-1 to Belt Feeder BF-3 2) EU ID Number: EU-258a 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-258 Previous Permit # is: 1,200 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-258, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Feeder BF-3 to Belt Conveyor BC-3 2) EU ID Number: EU-258b 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-258 Previous Permit # is: 1,200 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-258, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Elevated Tripper to Stacking Boom Conveyor 2) EU ID Number: EU-259a 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-259 Previous Permit # is: 4,000 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-259, wet suppression EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Elevated Tripper to Belt Conveyor BC-4 2) EU ID Number: EU-259b 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-259 Previous Permit # is: 4,000 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-259, wet suppression EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Stacking Boom Conveyor to Coal Pile No. 2 (North) 2) EU ID Number: EU-260a 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-260 Previous Permit # is: 4,000 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-260, wet suppression EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Stacking Boom Conveyor to Coal Pile No. 2 (South) 2) EU ID Number: EU-260b 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-260 Previous Permit # is: 4,000 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-260, wet suppression EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Stacker Reclaimer to Stacking Boom Conveyor (North Coal Pile) 2) EU ID Number: EU-261a 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-261 Previous Permit # is: 2,400 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-261, wet suppression EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Stacking Boom Conveyor to Belt Conveyor BC-4 (North Coal Pile) 2) EU ID Number: EU-261b 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-261 Previous Permit # is: 2,400 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-261, wet suppression EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Stacker Reclaimer to Stacking Boom Conveyor (South Coal Pile) 2) EU ID Number: EU-261c 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-261 Previous Permit # is: 2,400 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-261, wet suppression EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Stacking Boom Conveyor to Belt Conveyor BC-4 (South Coal Pile) 2) EU ID Number: EU-261d 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-261 Previous Permit # is: 2,400 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-261, wet suppression EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Conveyor BC-4 to Belt Conveyor BC-6 (Transfer Tower-2 (TT-2)) 2) EU ID Number: EU-262a 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-262 Previous Permit # is: 4,000 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-262, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Conveyor BC-4 to Belt Conveyor BC-7 (TT-2) 2) EU ID Number: EU-262b 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-262 Previous Permit # is: 4,000 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-262, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 AIR CONSTRUCTION PERMIT APPLICATION Form EU: Emission Unit Information Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Conveyor BC-8 to Belt Conveyor BC-10 (TT-2) 2) EU ID Number: EU-262c 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-262 Previous Permit # is: 1,200 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-262, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Conveyor BC-8 to Belt Conveyor BC-11 (TT-2) 2) EU ID Number: EU-262d 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-262 Previous Permit # is: 1,200 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-262, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Conveyor BC-9 to Belt Conveyor BC-10 (TT-2) 2) EU ID Number: EU-262e 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-262 Previous Permit # is: 1,200 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-262, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Conveyor BC-9 to Belt Conveyor BC-11 (TT-2) 2) EU ID Number: EU-262f 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-262 Previous Permit # is: 1,200 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-262, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Conveyor BC-4 to Belt Conveyor BC-10 (TT-2) 2) EU ID Number: EU-262g 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-262 Previous Permit # is: 1,200 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-262, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Conveyor BC-4 to Belt Conveyor BC-10 (TT-2) 2) EU ID Number: EU-262h 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-262 Previous Permit # is: 1,200 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-262, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Conveyor BC-6 to Coal Stockout Pile No. 3 2) EU ID Number: EU-263 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-263 Previous Permit # is: 4,000 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? CE-263, Telescopic chute and wet suppression EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) No If Yes, Control Equipment name/ID are: Yes 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Reclaim Hopper RH-2 to Belt Feeder BF-4 2) EU ID Number: EU-264a 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-264 Previous Permit # is: 2,400 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-264, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Feeder BF-4 to Belt Conveyor BC-8 2) EU ID Number: EU-264b 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-264 Previous Permit # is: 2,400 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-264, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Conveyor BC-7 to Coal Stockout Pile No. 4 2) EU ID Number: EU-265 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-265 Previous Permit # is: 4,000 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? CE-265, Telescopic chute and wet suppression EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) No If Yes, Control Equipment name/ID are: Yes 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. 4 For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Reclaim Hopper RH-3 to Belt Feeder BF-5 2) EU ID Number: EU-266a 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-266 Previous Permit # is: 1,200 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-266, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Feeder BF-5 to Belt Conveyor BC-9 2) EU ID Number: EU-266b 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-266 Previous Permit # is: 1,200 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-266, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Conveyor BC-10 to Crusher Surge Bin SB-1 (Crusher House-1 (CH-1)) 2) EU ID Number: EU-267a 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-267 Previous Permit # is: 1,200 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-267, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Conveyor BC-11 to Crusher Surge Bin SB-1 (CH-1) 2) EU ID Number: EU-267b 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-267 Previous Permit # is: 1,200 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-267, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Crusher Surge Bin SB-1 to Belt Feeder BF-6 (CH-1) 2) EU ID Number: EU-267c 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-267 Previous Permit # is: 1,200 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-267, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Crusher Surge Bin SB-1 to Belt Feeder BF-7 (CH-1) 2) EU ID Number: EU-267d 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-267 Previous Permit # is: 1,200 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-267, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Crusher-1 (CH-1) 2) EU ID Number: EU-267e 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-267 Previous Permit # is: 1,200 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-267, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Crusher-2 (CH-1) 2) EU ID Number: EU-267f 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-267 Previous Permit # is: 1,200 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-267, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Feeder BF-6 to Belt Conveyor BC-13 through Coal Crusher CR-1 (CH-1) 2) EU ID Number: EU-267g 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-267 Previous Permit # is: 1,200 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-267, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Feeder BF-7 to Belt Conveyor BC-12 through Coal Crusher CR-2 (CH-1) 2) EU ID Number: EU-267h 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-267 Previous Permit # is: 1,200 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-267, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Conveyor BC-12 to Belt Conveyor BC-14 (Transfer Tower-4 (TT-4)) 2) EU ID Number: EU-268a 3) EU Type: New Source Unpermitted Existing Source 4) Manufacturer: TBD 5) Model: TBD 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-268 Previous Permit # is: 1,200 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-268, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Conveyor BC-12 to Belt Conveyor BC-15 (TT-4) 2) EU ID Number: EU-268b 3) EU Type: New Source Unpermitted Existing Source 4) Manufacturer: TBD 5) Model: TBD 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-268 Previous Permit # is: 1,200 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-268, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Conveyor BC-13 to Belt Conveyor BC-14 (TT-4) 2) EU ID Number: EU-268c 3) EU Type: New Source Unpermitted Existing Source 4) Manufacturer: TBD 5) Model: TBD 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-268 Previous Permit # is: 1,200 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-268, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Conveyor BC-13 to Belt Conveyor BC-15 (TT-4) 2) EU ID Number: EU-268d 3) EU Type: New Source Unpermitted Existing Source 4) Manufacturer: TBD 5) Model: TBD 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-268 Previous Permit # is: 1,200 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-268, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Conveyor BC-14 to Coal Silos and Silo Storage (Unit No. 4 Boiler House) 2) EU ID Number: EU-268e 3) EU Type: New Source Unpermitted Existing Source 4) Manufacturer: TBD 5) Model: TBD 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-268 Previous Permit # is: 1,200 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-268, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Conveyor BC-15 to Coal Silos and Silo Storage (Unit No. 4 Boiler House) 2) EU ID Number: EU-268f 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-268 Previous Permit # is: 1,200 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-268, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 AIR CONSTRUCTION PERMIT APPLICATION Form EU: Emission Unit Information Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Reclaim Hopper RH-4 to Belt Feeder BF-8 2) EU ID Number: EU-269a 3) EU Type: New Source Unpermitted Existing Source 4) Manufacturer: TBD 5) Model: TBD 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-269 Previous Permit # is: 400 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-269, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Feeder BF-8 to Belt Conveyor BC-5A 2) EU ID Number: EU-269b 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-269 Previous Permit # is: 400 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-269, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Reclaim Hopper RH-5 to Belt Feeder BF-9 2) EU ID Number: EU-269c 3) EU Type: New Source Unpermitted Existing Source 4) Manufacturer: TBD 5) Model: TBD 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-269 Previous Permit # is: 400 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-269, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Feeder BF-9 to Belt Conveyor BC-5A 2) EU ID Number: EU-269d 3) EU Type: New Source Unpermitted Existing Source 4) Manufacturer: TBD 5) Model: TBD 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-269 Previous Permit # is: 400 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-269, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Conveyor BC-5A to Belt Conveyor BC-5B (Transfer Tower (TT-3)) 2) EU ID Number: EU-270 3) EU Type: New Source Unpermitted Existing Source 4) Manufacturer: TBD 5) Model: TBD 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-270 Previous Permit # is: 400 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-270, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Belt Conveyor BC-5B to Surge Hopper HPR-2 (Existing Transfer Tower) 2) EU ID Number: EU-271 3) EU Type: New Source Unpermitted Existing Source 4) Manufacturer: TBD 5) Model: TBD 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-271 Previous Permit # is: 400 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-271, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Transfer Point- Surge Hopper HPR-2 to Future Truck Loadout (Existing Transfer Tower) 2) EU ID Number: EU-272 3) EU Type: New Source Unpermitted Existing Source 4) Manufacturer: TBD 5) Model: TBD 6a) Maximum Nameplate Capacity: 6b) EP-272 EP ID Number: Modification to a Permitted Source Previous Permit # is: 200 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-272, Yes Chute/Enclosure/Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Emergency Coal Stockout Pile No. 1 (Fugitive) 2) EU ID Number: EU-273 3) EU Type: 4) Manufacturer: N/A 5) Model: N/A New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-273 Previous Permit # is: Exposed Surface Area: 0.85 Acres Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-273, Water Cannon/Surfactant Spray EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation Only Utilized During Emergency REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Stockout Pile No. 2-North (Fugitive) 2) EU ID Number: EU-274 3) EU Type: 4) Manufacturer: N/A 5) Model: N/A New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-274 Previous Permit # is: Exposed Surface Area: 5.82 Acres Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-274, Water Cannon, Surfactant Spray and Berm Yes EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? Operation Hour Limits: No Yes If Yes, check below and write down all that apply Bulldozing limited to not more than 8 hours per day on this pile Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 Air Quality Impacts PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Stockout Pile No. 2-South (Fugitive) 2) EU ID Number: EU-275 3) EU Type: 4) Manufacturer: N/A 5) Model: N/A New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-275 Previous Permit # is: Exposed Surface Area: 6.68 Acres Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-275, Water Cannon, Surfactant Spray and Berm Yes EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? Operation Hour Limits: No Yes If Yes, check below and write down all that apply Bulldozing limited to not more than 8 hours per day on this pile Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 Air Quality Impacts PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Stockout Pile No. 3 (Fugitive) 2) EU ID Number: EU-276 3) EU Type: 4) Manufacturer: N/A 5) Model: N/A New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-276 Previous Permit # is: Exposed Surface Area: 0.85 Acres Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-276, Water Cannon, Surfactant Spray EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? Operation Hour Limits: No Yes If Yes, check below and write down all that apply Bulldozing limited to not more than 8 hours per day on this pile Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 Air Quality Impacts PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Coal Stockout Pile No. 4 (Fugitive) 2) EU ID Number: EU-277 3) EU Type: 4) Manufacturer: N/A 5) Model: N/A New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-277 Previous Permit # is: Exposed Surface Area: 0.85 Acres Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-277, Water Cannon, Surfactant Spray EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? Operation Hour Limits: No Yes If Yes, check below and write down all that apply Bulldozing limited to not more than 8 hours per day on this pile Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 Air Quality Impacts PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: North Gate Haul Road (Fugitive) 2) EU ID Number: EU-278 3) EU Type: 4) Manufacturer: N/A 5) Model: N/A New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-278 Previous Permit # is: Haul Road Length: 0.48 miles (one way) Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-278, Paving and Speed Reduction EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: West Gate Haul Road (Fugitive) 2) EU ID Number: EU-279 3) EU Type: 4) Manufacturer: N/A 5) Model: N/A New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-279 Previous Permit # is: Haul Road Length: 0.86 miles (one way) Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No Yes If Yes, Control Equipment name/ID are: CE-279, Paving and Speed Reduction EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Limestone Transfer Point- Railcar/Truck Unloading to Hopper HPR-1 (Limestone Dumper Area) 2) EU ID Number: EU-280 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-280a and EP 280b Previous Permit # is: 600 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-280a/b, Yes Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Limestone Transfer Point- Hopper HPR-1 to Belt Feeder FDR-1 2) EU ID Number: EU-281a 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP-281 EP ID Number: Modification to a Permitted Source Previous Permit # is: 450 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-281, Yes Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EU: Emission Unit Information Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Limestone Transfer Point- Hopper HPR-1 to Belt Feeder FDR-2 2) EU ID Number: EU-281b 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP-281 EP ID Number: Modification to a Permitted Source Previous Permit # is: 450 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-281, Yes Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Limestone Transfer Point- Belt Feeder FDR-1 to Receiving Conveyor CVY-1 2) EU ID Number: EU-281c 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP-281 EP ID Number: Modification to a Permitted Source Previous Permit # is: 450 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-281, Yes Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Limestone Transfer Point- Belt Feeder FDR-2 to Receiving Conveyor CVY-1 2) EU ID Number: EU-281d 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP-281 EP ID Number: Modification to a Permitted Source Previous Permit # is: 450 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-281, Yes Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Limestone Transfer Point- Receiving Conveyor CVY-1 to Limestone Building Storage 2) EU ID Number: EU-282 3) EU Type: New Source Unpermitted Existing Source 4) Manufacturer: TBD 5) Model: TBD 6a) Maximum Nameplate Capacity: 6b) EP-282a and b (pile) EP ID Number: Modification to a Permitted Source Previous Permit # is: 600 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-282, Yes Telescopic Chute, Wet Suppression and Partial Enclosure EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Limestone Transfer Point- Vibrating Drawdown Hopper HPR-2 to Belt Feeder FDR-3 2) EU ID Number: EU-283a 3) EU Type: New Source Unpermitted Existing Source 4) Manufacturer: TBD 5) Model: TBD 6a) Maximum Nameplate Capacity: 6b) EP-283 EP ID Number: Modification to a Permitted Source Previous Permit # is: 400 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-283, Yes Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Limestone Transfer Point- Vibrating Drawdown Hopper HPR-3 to Belt Feeder FDR-4 2) EU ID Number: EU-283b 3) EU Type: New Source Unpermitted Existing Source 4) Manufacturer: TBD 5) Model: TBD 6a) Maximum Nameplate Capacity: 6b) EP-283 EP ID Number: Modification to a Permitted Source Previous Permit # is: 400 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-283, Yes Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Limestone Transfer Point- Belt Feeder FDR-3 to Reclaim Conveyor CVY-2 2) EU ID Number: EU-283c 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP-283 EP ID Number: Modification to a Permitted Source Previous Permit # is: 400 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-283, Yes Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Limestone Transfer Point- Belt Feeder FDR-4 to Reclaim Conveyor CVY-2 2) EU ID Number: EU-283d 3) EU Type: New Source Unpermitted Existing Source 4) Manufacturer: TBD 5) Model: TBD 6a) Maximum Nameplate Capacity: 6b) EP-283 EP ID Number: Modification to a Permitted Source Previous Permit # is: 400 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-283, Yes Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Limestone Transfer Point- Reclaim Conveyor CVY-2 to Limestone Silo No. 1 and Silo Storage 2) EU ID Number: EU-284 3) EU Type: New Source Unpermitted Existing Source 4) Manufacturer: TBD 5) Model: TBD 6a) Maximum Nameplate Capacity: 6b) EP-284 EP ID Number: Modification to a Permitted Source Previous Permit # is: 400 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-284, Yes Bin Vent Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Limestone Transfer Point- Reclaim Conveyor CVY-2 to Distribution Conveyor CVY-3 2) EU ID Number: EU-285a 3) EU Type: New Source Unpermitted Existing Source 4) Manufacturer: TBD 5) Model: TBD 6a) Maximum Nameplate Capacity: 6b) EP-285 EP ID Number: Modification to a Permitted Source Previous Permit # is: 400 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-285, Yes Bin Vent Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Limestone Transfer Point- Distribution Conveyor CVY-3 to Limestone Silo No. 2 and Silo Storage 2) EU ID Number: EU-285b 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP-285 EP ID Number: Modification to a Permitted Source Previous Permit # is: 400 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-285, Yes Bin Vent Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Saleable Fly Ash Transfer Point- Pneumatic Conveyor System Exhaust (Mechanical Exhaust) 2) EU ID Number: EU-286 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP-286a and EP 286b EP ID Number: Modification to a Permitted Source Previous Permit # is: 1.31 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-286 Yes a/b, Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Saleable Fly Ash Silo and Loading Operations 2) EU ID Number: EU-287 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP-287 EP ID Number: Modification to a Permitted Source Previous Permit # is: 1.31 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-287, Yes Bin Vent Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Saleable Fly Ash Storage Building 2) EU ID Number: EU-288 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-288a and EP-288b Previous Permit # is: 20.87 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-288a/b, Yes Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Waste Fly Ash Transfer Point- Pneumatic Conveyor System Exhaust (Mechanical Exhaust) 2) EU ID Number: EU-289 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP ID Number: Modification to a Permitted Source EP-289a and EP-289b Previous Permit # is: 1.31 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-289a/b, Yes Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Waste Fly Ash Silo and Loading Operations 2) EU ID Number: EU-290 3) EU Type: New Source Unpermitted Existing Source 4) Manufacturer: TBD 5) Model: TBD 6a) Maximum Nameplate Capacity: 6b) EP-290 EP ID Number: Modification to a Permitted Source Previous Permit # is: 20.87 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-290, Yes Bin Vent Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR CONSTRUCTION PERMIT APPLICATION AIR QUALITY BUREAU ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: PAC Silo- Transfer and Storage 2) EU ID Number: EU-291 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP-291 EP ID Number: Modification to a Permitted Source Previous Permit # is: 40 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-291, Yes Bin Vent Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Transfer of Sorbent to Day Silo and Silo Storage 2) EU ID Number: EU-292 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP-292 EP ID Number: Modification to a Permitted Source Previous Permit # is: 40 tons/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-292, Yes Bin Vent Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Transfer of Sorbent to Long Term Storage Silo and Silo Storage 2) EU ID Number: EU-293 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP-293 EP ID Number: Modification to a Permitted Source Previous Permit # is: 1 ton/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-293, Yes Bin Vent Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Lime Transfer to Lime Silo and Silo Storage for Water Treatment Process 2) EU ID Number: EU-294 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) EP-294 EP ID Number: Modification to a Permitted Source Previous Permit # is: 0.5 ton/hour Maximum Process Design Capacity (if different than 6a) 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-294, Yes Bin Vent Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Biomass Material Handling Operations –Line 1 2) EU ID Number: EU-295 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) Maximum Process Design Capacity (if different than 6a) EP-295 EP ID Number: Modification to a Permitted Source Previous Permit # is: 25 ton/hour 22 tons per hour 7) Date of Construction: November 2008 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-295, Yes Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in Form EU: Emission Unit Information 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instruction on reverse side IPL-Sutherland Generating Station Unit 4 Company Name: EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION 1) Emission Unit (EU) Name: Biomass Material Handling Operations –Line 2 2) EU ID Number: EU-296 3) EU Type: 4) Manufacturer: TBD 5) Model: TBD New Source Unpermitted Existing Source 6a) Maximum Nameplate Capacity: 6b) Maximum Process Design Capacity (if different than 6a) EP-296 EP ID Number: Modification to a Permitted Source Previous Permit # is: 25 ton/hour 22 tons per hour 7) Date of Construction: TBD 8) Date of Modification (if applicable) N/A 9) Is this a Controlled Emission Unit? No If Yes, Control Equipment name/ID are: CE-296, Yes Fabric Filter EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other) 10) Actual Operation TBD 11) Maximum Operation 8,760 hours/year REQUESTED LIMITS 12) Are you requesting any permit limits? No Yes If Yes, check below and write down all that apply Operation Hour Limits: Production Limits: Material Usage Limits Limits Based on Stack Testing Please attach all relevant stack testing summary reports Other: Rationale for Requesting the Limit(s): 13 PROCESS DESCRIPTION Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit. Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is insufficient, attach a separate sheet labeled EU-11A. Please see technical support document for description of this emission unit. The process flow drawings and material handling emission calculations are located in Appendix D and Appendix G of the Application Package, respectively. For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EU ATTN: Application Log in AIR QUALITY BUREAU 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 AIR CONSTRUCTION PERMIT APPLICATION Form EU5: Boiler Information Please see instruction on reverse side EXEMPTION According to 567 Iowa Administrative Code Chapter 22.1(2)a, an indirect fired combustion source that uses only Natural Gas or LPG and has a heating capacity of less than 10 MMBTU/hr is exempted from the provisions of construction permits. According to 567 Iowa Administrative Code Chapter 22.1(2)b, an indirect fired combustion source that uses coal, fuel oil or untreated wood, seeds, pellets, other vegetable matter and has a heating capacity of less than 1 MMBTU/hr is exempted from the provisions of construction permits. Company Name: IPL-Sutherland Generating Station Unit 4 BOILER (EMISSION UNIT) DESCRIPTION AND SPECIFICATIONS New Unit Unpermitted Existing Unit (1) Boiler ID Number: EU-297 Modification to an unit with Permit #: (2) Rated Capacity (MMBTU/hr heat input): 3 MMBTU/hr Gate Station Heater (3) Construction Date: November 2008 (4) Manufacturer: TBD (5) Model: TBD (6) Date of Modification (if applicable): N/A (8) Control Device (if any): (7) Serial Number (if available): TBD FUEL DESCRIPTION AND SPECIFICATIONS (9) Fuel Type Natural Gas Fuel Oil (# ) (cf/hr) (10) Full Load Consumption Rate (11) Sulfur Content wt% (gal/hr) Coal type: (lb/hr) Coal type: (lb/hr) Other Fuels (lb/hr) 2,941 N/A (12) Requested Limit N/A None OPERATING LIMITS & SCHEDULE (13) Imposed Operating Limits (hours/year, or gallons fuel/year, etc.): None (14) Operating Schedule (hours/day, months/year, etc.): 24 hours/day, 12 months/year STACK/VENT (EMISSION POINT) SPECIFICATIONS (15) Stack/Vent ID: EP-297 (17) Stack Height (feet) from the Ground: 20 (18) Stack Height (feet) above the Building (If Applicable): (16) Stack Opening Size: circular, diameter (inches) is: 15 other, size (inches x inches) is: (19) Discharge Style: V (Vertical, without rain cap or with unobstructing rain cap) VR (Vertical, with obstructing rain cap) H (Horizontal discharge) D (Downward discharge; for example, a goose neck stack) (20) Distance (feet) from the Property Line: 367 (21) Rated Flow Rate ( 1,429 acfm scfm): EXHAUST INFORMATION (22) Moisture Content % (if known): For Assistance 1-877AIR IOWA (1-877-247-4692) (23) Exit Temperature (°F) 700 DNR Form 542-3190-05 Revised 11/2006 EU EMISSION POINT FORMS For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-05 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-254a 2) Stack Opening size: circular, diameter (inches) 78 other size (inches x inches) 3) Height from ground (feet): 18 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 75,657 SCFM: 10) Does this emission point have control equipment? No Yes; If yes, provide control ID: CE-254a Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-254a EP-254b CE254a FF CE254b FF EU 254 Rotary Car Dumper For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-254b 2) Stack Opening size: circular, diameter (inches) 78 other size (inches x inches) 3) Height from ground (feet): 18 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 75,657 SCFM: 10) Does this emission point have control equipment? No Yes; If yes, provide control ID: CE-254b Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-254a EP-254b CE254a FF CE254b FF EU 254 Rotary Car Dumper For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-255 2) Stack Opening size: circular, diameter (inches) 42 other size (inches x inches) 3) Height from ground (feet): 12 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 7,500 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-255 Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-255 CE255 FF EU 255 a through d Rotary Car Dumper Area For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-256 2) Stack Opening size: circular, diameter (inches) 42 other size (inches x inches) 3) Height from ground (feet): 55 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 7,500 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-256 Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-256 CE256 FF EU 256 a through c Transfer Tower TT-1 For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-258 2) Stack Opening size: circular, diameter (inches) 42 other size (inches x inches) 3) Height from ground (feet): 55 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 7,500 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-258 Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-258 CE258 FF EU 258 a and b Emergency Coal Pile Reclaim For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-262 2) Stack Opening size: circular, diameter (inches) 42 other size (inches x inches) 3) Height from ground (feet): 65 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 7,500 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-262 Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-262 CE262 FF EU 262 a through h Transfer Tower TT-2 For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-264 2) Stack Opening size: circular, diameter (inches) 42 other size (inches x inches) 3) Height from ground (feet): 12 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 6,927 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-264 Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-264 CE264 FF EU 264 a and b Reclaim from Coal Pile No. 3 For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID: EP-266 2) Stack Opening size: circular, diameter (inches) 42 other size (inches x inches) 3) Height from ground (feet): 12 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 7,500 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-266 Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-266 CE266 FF EU 266 a and b Reclaim from Coal Pile No. 4 For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-267 2) Stack Opening size: circular, diameter (inches) 48 other size (inches x inches) 3) Height from ground (feet): 125 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 30,159 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-267 Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-267 CE267 FF EU 267 a through h Crusher House CH-1 For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-268 2) Stack Opening size: circular, diameter (inches) 63.6 other size (inches x inches) 3) Height from ground (feet): 190 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 52,948 SCFM: 10) Does this emission point have control equipment? No Yes; If yes, provide control ID: CE-268 Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-268 CE268 FF EU 268 a through f Transfer Tower TT-4 and Boiler House For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-269 2) Stack Opening size: circular, diameter (inches) 42 other size (inches x inches) 3) Height from ground (feet): 12 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 7,500 SCFM: 10) Does this emission point have control equipment? No Yes; If yes, provide control ID: CE-269 Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-269 CE269 FF EU 269 a through d Reclaim from Coal Pile 2 (North) For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-270 2) Stack Opening size: circular, diameter (inches) 42 other size (inches x inches) 3) Height from ground (feet): 35 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 7,500 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-270 Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-270 CE270 FF EU 270 Transfer Tower TT-3 For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-271 2) Stack Opening size: circular, diameter (inches) 42 other size (inches x inches) 3) Height from ground (feet): 65 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 7,500 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-271 Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-271 CE271 FF EU 271 Existing Transfer Tower For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-272 2) Stack Opening size: circular, diameter (inches) 30 other size (inches x inches) 3) Height from ground (feet): 50 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 12,000 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-272 Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-272 CE272 FF EU 272 Future Truck Loadout For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-280a 2) Stack Opening size: circular, diameter (inches) 78 other size (inches x inches) 3) Height from ground (feet): 18 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 75,657 SCFM: 10) Does this emission point have control equipment? No Yes; If yes, provide control ID: CE-280a Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-280a EP-280b CE280a FF CE280b FF EU 280 Limestone Rail Car Dumper For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-280b 2) Stack Opening size: circular, diameter (inches) 78 other size (inches x inches) 3) Height from ground (feet): 18 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 75,657 SCFM: 10) Does this emission point have control equipment? No Yes; If yes, provide control ID: CE-280b Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-280a EP-280b CE280a FF CE280b FF EU 280 Limestone Rail Car Dumper For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-281 2) Stack Opening size: circular, diameter (inches) 42 other size (inches x inches) 3) Height from ground (feet): 12 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 7,500 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-281 Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-281 CE281 FF EU 281 a through d Limestone Transfer For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-283 2) Stack Opening size: circular, diameter (inches) 42 other size (inches x inches) 3) Height from ground (feet): 23 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 7,500 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-283 Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-283 CE283 FF EU 283 a through d Reclaim from Limestone Storage Pile For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-284 2) Stack Opening size: circular, diameter (inches) 12 other size (inches x inches) 3) Height from ground (feet): 125 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 1,650 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-284 Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-284 CE284 Bin Vent EU 284 Limestone Silo-1 For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-285 2) Stack Opening size: circular, diameter (inches) 12 other size (inches x inches) 3) Height from ground (feet): 125 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 1,650 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-285 Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-285 CE285 Bin Vent EU 285 a and b Limestone Silo-2 For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-286a 2) Stack Opening size: circular, diameter (inches) 15 other size (inches x inches) 3) Height from ground (feet): 50 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 3,681 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-286 Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-286a EP-286b CE286a FF CE286b FF EU 286 Saleable Fly Ash Transfer For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-286b 2) Stack Opening size: circular, diameter (inches) 15 other size (inches x inches) 3) Height from ground (feet): 50 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 3,681 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-286 b Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-286a EP-286b CE286a FF CE286b FF EU 286 Saleable Fly Ash Transfer For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-287 2) Stack Opening size: circular, diameter (inches) 13.20 other size (inches x inches) 3) Height from ground (feet): 105 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 1,995 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-287 Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-287 CE287 Bin Vent EU 287 Saleable Fly Ash Silo For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-288a 2) Stack Opening size: circular, diameter (inches) 42 other size (inches x inches) 3) Height from ground (feet): 23 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 20,204 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-288a Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-288a EP-288b CE288a FF CE288b FF EU 288 Saleable Fly Ash Storage Building For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-288b 2) Stack Opening size: circular, diameter (inches) 42 other size (inches x inches) 3) Height from ground (feet): 23 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 20,204 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-288b Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-288a EP-288b CE288a FF CE288b FF EU 288 Saleable Fly Ash Storage Building For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-289a 2) Stack Opening size: circular, diameter (inches) 9.6 other size (inches x inches) 3) Height from ground (feet): 50 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 1,500 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-289a Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-289a EP-289b CE289a FF CE289b FF EU 289 Waste Fly Ash Transfer For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-289b 2) Stack Opening size: circular, diameter (inches) 9.6 other size (inches x inches) 3) Height from ground (feet): 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 1,500 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-289b Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-289a EP-289b CE289a FF CE289b FF EU 289 Waste Fly Ash Transfer For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-290 2) Stack Opening size: circular, diameter (inches) 13.2 other size (inches x inches) 3) Height from ground (feet): 105 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 2,000 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-290 Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-290 CE290 Bin Vent EU 290 Waste Flyash Storage Silo For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-291 2) Stack Opening size: circular, diameter (inches) 39.37 other size (inches x inches) 3) Height from ground (feet): 115 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 1.66 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-291 Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-290 CE290 Bin Vent EU 290 PAC Silo For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-292 2) Stack Opening size: circular, diameter (inches) 39.37 other size (inches x inches) 3) Height from ground (feet): 115 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 1.66 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-292 Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-292 CE292 Bin Vent EU 292 Sorbent Day Storage Silo For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-293 2) Stack Opening size: circular, diameter (inches) 39.37 other size (inches x inches) 3) Height from ground (feet): 280 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 1.66 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-293 Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-293 CE293 Bin Vent EU 293 Sorbent Long Term Storage Silo For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-294 2) Stack Opening size: circular, diameter (inches) 39.37 other size (inches x inches) 3) Height from ground (feet): 77 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 1.66 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-294 Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-294 CE294 Bin Vent EU 294 Lime Silo For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-295 2) Stack Opening size: circular, diameter (inches) 30 other size (inches x inches) 3) Height from ground (feet): 50 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 24,800 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-295 Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-295 CE295 FF EU 295 Biomass Material Handling Line -1 For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EP Stack/Vent Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) EP Number ID:EP-296 2) Stack Opening size: circular, diameter (inches) 30 other size (inches x inches) 3) Height from ground (feet): 50 4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical Support Document 5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document Vertical (without rain cap or with unobstructing rain cap) VR (Vertical, with obstruction rain cap) 6) Discharge Style (check one) D (Downward discharge; for example, a goose neck stack) H (Horizontal discharge) I (Inside-Vent inside building) Exhaust Information 7) Moisture Content % (if known): 9) Rated Flow Rate: 8) Exit Temperature (Fahrenheit): 47.4 °F ACFM: 24,800 10) Does this emission point have control equipment? SCFM: No Yes; If yes, provide control ID: CE-296 Air Emissions Pathway Diagram 11) Air Emissions Pathway Diagram (see examples on reverse-side) EP-296 CE296 FF EU 296 Biomass Material Handling Line -2 For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 EP CONTROL EQUIPMENT FORMS For Assistance 1-877AIR IOWA (1-877-247-4692) DNR Form 542-3190-13 Revised 11/2006 CE IOWA DNR Air Construction Permit Application AIR QUALITY BUREAU ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form CE Control Equipment Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-248A 2) Emission Point(s) ID: EP-248 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Description: Selective Catalytic Reduction (SCR) 6) Date of Construction: November 2008 7) Date of Modification: N/A 8) Capture Hood involved: Yes No 9) Capture Hood Efficiency (percentage): N/A 10) Date of Hood Installation: N/A 12) 11) Date of Hood Modification (if any): N/A Pollutant Controlled PM PM10 VOC SO2 Control Efficiency NOx CO Other( See BACT Analysis 13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. For Assistance 1-877AIR IOWA (1-877-247-4692) Revised 11/2006 ) AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form CE Control Equipment Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: N/A (See Below) 2) Emission Point(s) ID: EP-248 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Description: Dry Electrostatic Precipitator (DESP) 6) Date of Construction: November 2008 7) Date of Modification: N/A 8) Capture Hood involved: Yes No 9) Capture Hood Efficiency (percentage): N/A 10) Date of Hood Installation: N/A 12) 11) Date of Hood Modification (if any): N/A Pollutant Controlled PM PM10 VOC SO2 NOx CO Other( ) Control Efficiency 13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. The DESP is used on an as-needed basis for scavenging saleable flyash and is not considered as BACT. Compared to a full scale ESP designed for primary particulate control, the proposed scavenging DESP is a much undersized unit that is designed only to operate as process equipment to segregate fly ash for beneficial reuse. The installation of the scavenging DESP does not fall under any BACT requirement, since it will not be used for primary control or emissions compliance. Please refer to the BACT analysis in Appendix H of the Application Package. AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form CE Control Equipment Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-248B 2) Emission Point(s) ID: EP-248 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Description: Powdered Activated Carbon (PAC) Injection 6) Date of Construction: November 2008 7) Date of Modification: N/A 8) Capture Hood involved: Yes No 9) Capture Hood Efficiency (percentage): N/A 10) Date of Hood Installation: N/A 12) Pollutant Controlled PM Control Efficiency 11) Date of Hood Modification (if any): N/A PM10 VOC SO2 NOx CO Other(Hg) See Below 13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Mercury reduction will be achieved as a co-benefit of BACT. Any additional reductions needed will be obtained by PAC injection. Please refer to the BACT analysis in Appendix H of the Application Package. CE1 AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-248C 2) Emission Point(s) ID: EP-248 3) Manufacturer: TBD 5) Control Equipment Type: 4) Model Number: TBD Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: N/A 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): N/A 16) Pollutant Controlled PM Control Efficiency PM10 See BACT Analysis Other( ) See BACT Analysis 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. For Assistance 1-877AIR IOWA (1-877-247-4692) Revised 11/2006 AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form CE3 Control Equipment Information for Wet Scrubbers Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station 1) CE Number ID: CE-248D 2) Emission Point(s) ID: EP-248 3) Manufacturer: TBD 5) Type of Scrubber : 4) Model Number: TBD Packed Bed Spray Chamber Venturi Other 6) Total Liquor Flow Rate (gallons per minute) : TBD 7) Recycled Liquor Flow Rate (gallons per minute) : TBD 8) Normal Liquor pH : TBD 9) Pressure drop across Scrubber (in H2O): TBD 10) Date of Construction: November 2008 11) Date of Modification: N/A 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): N/A 16) Pollutant Controlled PM PM10 Control Efficiency VOC Other(SO2) See BACT Analysis 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form CE Control Equipment Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-248E 2) Emission Point(s) ID: EP-248 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Description: Sorbent Injection for SO3 control. 6) Date of Construction: November 2008 7) Date of Modification: N/A 8) Capture Hood involved: Yes No 9) Capture Hood Efficiency (percentage): N/A 10) Date of Hood Installation: N/A 12) Pollutant Controlled PM Control Efficiency 11) Date of Hood Modification (if any): N/A PM10 VOC SO2 NOx CO Other(SO3) See BACT Analysis 13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Sorbent will be injected after the air heater. Please refer to the BACT analysis in Appendix H of the Application Package. CE1 AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-254a 2) Emission Point(s) ID: EP-254a 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency Other( PM10 99.9% ) 99.9% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. For Assistance 1-877AIR IOWA (1-877-247-4692) Revised 11/2006 AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-254b 2) Emission Point(s) ID: EP-254b 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency Other( PM10 99.9% ) 99.9% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-255 2) Emission Point(s) ID: EP-255 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency Other( PM10 99.9% ) 99.9% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-256 2) Emission Point(s) ID: EP-256 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency Other( PM10 99.9% ) 99.9% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form CE Control Equipment Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-257 2) Emission Point(s) ID: EP-257 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Description: Telescopic Chute and Wet Suppression 6) Date of Construction: November 2008 7) Date of Modification: TBD 8) Capture Hood involved: Yes No 9) Capture Hood Efficiency (percentage): N/A 10) Date of Hood Installation: N/A 11) Date of Hood Modification (if any): 12) Pollutant Controlled PM Control Efficiency PM10 95% VOC SO2 NOx CO Other( 95% 13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. ) AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-258 2) Emission Point(s) ID: EP-258 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency Other( PM10 99.9% ) 99.9% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form CE Control Equipment Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-259 2) Emission Point(s) ID: EP-259 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Description: Telescopic Chute and Wet Suppression 6) Date of Construction: November 2008 7) Date of Modification: TBD 8) Capture Hood involved: Yes No 9) Capture Hood Efficiency (percentage): N/A 10) Date of Hood Installation: N/A 11) Date of Hood Modification (if any): 12) Pollutant Controlled PM Control Efficiency PM10 95% VOC SO2 NOx CO Other( 95% 13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. ) AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form CE Control Equipment Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-260 2) Emission Point(s) ID: EP-260 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Description: Wet Suppression 6) Date of Construction: November 2008 7) Date of Modification: TBD 8) Capture Hood involved: Yes No 9) Capture Hood Efficiency (percentage): N/A 10) Date of Hood Installation: N/A 11) Date of Hood Modification (if any): 12) Pollutant Controlled PM Control Efficiency PM10 95% VOC SO2 NOx CO Other( 95% 13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. ) AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form CE Control Equipment Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-261 2) Emission Point(s) ID: EP-261 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Description: Wet Suppression 6) Date of Construction: November 2008 7) Date of Modification: TBD 8) Capture Hood involved: Yes No 9) Capture Hood Efficiency (percentage): N/A 10) Date of Hood Installation: N/A 11) Date of Hood Modification (if any): 12) Pollutant Controlled PM Control Efficiency PM10 95% VOC SO2 NOx CO Other( 95% 13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. ) AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-262 2) Emission Point(s) ID: EP-262 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency Other( PM10 99.9% ) 99.9% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form CE Control Equipment Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-263 2) Emission Point(s) ID: EP-263 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Description: Telescopic Chute and Wet Suppression 6) Date of Construction: November 2008 7) Date of Modification: TBD 8) Capture Hood involved: Yes No 9) Capture Hood Efficiency (percentage): N/A 10) Date of Hood Installation: N/A 11) Date of Hood Modification (if any): 12) Pollutant Controlled PM Control Efficiency PM10 95% VOC SO2 NOx CO Other( 95% 13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. ) AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-264 2) Emission Point(s) ID: EP-264 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency Other( PM10 99.9% ) 99.9% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form CE Control Equipment Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-265 2) Emission Point(s) ID: EP-265 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Description: Telescopic Chute and Wet Suppression 6) Date of Construction: November 2008 7) Date of Modification: TBD 8) Capture Hood involved: Yes No 9) Capture Hood Efficiency (percentage): N/A 10) Date of Hood Installation: N/A 11) Date of Hood Modification (if any): 12) Pollutant Controlled PM Control Efficiency PM10 95% VOC SO2 NOx CO Other( 95% 13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. ) AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-266 2) Emission Point(s) ID: EP-266 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency Other( PM10 99.9% ) 99.9% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-267 2) Emission Point(s) ID: EP-267 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency Other( PM10 99.9% ) 99.9% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-268 2) Emission Point(s) ID: EP-268 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency Other( PM10 99.9% ) 99.9% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-269 2) Emission Point(s) ID: EP-269 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency Other( PM10 99.9% ) 99.9% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-270 2) Emission Point(s) ID: EP-270 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency Other( PM10 99.9% ) 99.9% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-271 2) Emission Point(s) ID: EP-271 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency Other( PM10 99.9% ) 99.9% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-272 2) Emission Point(s) ID: EP-272 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency Other( PM10 99.9% ) 99.9% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form CE Control Equipment Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-273 2) Emission Point(s) ID: EP-273 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Description: Water Cannon/Surfactant Spray 6) Date of Construction: November 2008 7) Date of Modification: TBD 8) Capture Hood involved: Yes No 9) Capture Hood Efficiency (percentage): N/A 10) Date of Hood Installation: N/A 11) Date of Hood Modification (if any): 12) Pollutant Controlled PM Control Efficiency PM10 90% VOC SO2 NOx CO Other( 90% 13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. ) AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form CE Control Equipment Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-274 2) Emission Point(s) ID: EP-274 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Description: Water Cannon/Surfactant Spray/Berm 6) Date of Construction: November 2008 7) Date of Modification: TBD 8) Capture Hood involved: Yes No 9) Capture Hood Efficiency (percentage): N/A 10) Date of Hood Installation: N/A 11) Date of Hood Modification (if any): 12) Pollutant Controlled PM Control Efficiency PM10 95% VOC SO2 NOx CO Other( 95% 13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. ) AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form CE Control Equipment Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-275 2) Emission Point(s) ID: EP-275 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Description: Water Cannon/Surfactant Spray/Berm 6) Date of Construction: November 2008 7) Date of Modification: TBD 8) Capture Hood involved: Yes No 9) Capture Hood Efficiency (percentage): N/A 10) Date of Hood Installation: N/A 11) Date of Hood Modification (if any): 12) Pollutant Controlled PM Control Efficiency PM10 95% VOC SO2 NOx CO Other( 95% 13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. ) AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form CE Control Equipment Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-276 2) Emission Point(s) ID: EP-276 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Description: Water Cannon/Surfactant Spray 6) Date of Construction: November 2008 7) Date of Modification: TBD 8) Capture Hood involved: Yes No 9) Capture Hood Efficiency (percentage): N/A 10) Date of Hood Installation: N/A 11) Date of Hood Modification (if any): 12) Pollutant Controlled PM Control Efficiency PM10 90% VOC SO2 NOx CO Other( 90% 13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. ) AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form CE Control Equipment Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-277 2) Emission Point(s) ID: EP-277 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Description: Water Cannon/Surfactant Spray 6) Date of Construction: November 2008 7) Date of Modification: TBD 8) Capture Hood involved: Yes No 9) Capture Hood Efficiency (percentage): N/A 10) Date of Hood Installation: N/A 11) Date of Hood Modification (if any): 12) Pollutant Controlled PM Control Efficiency PM10 90% VOC SO2 NOx CO Other( 90% 13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. ) AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form CE Control Equipment Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-278 2) Emission Point(s) ID: EP-278 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Description: Paving and Speed Reduction 6) Date of Construction: November 2008 7) Date of Modification: TBD 8) Capture Hood involved: Yes No 9) Capture Hood Efficiency (percentage): N/A 10) Date of Hood Installation: N/A 11) Date of Hood Modification (if any): 12) Pollutant Controlled PM Control Efficiency PM10 95% VOC SO2 NOx CO Other( 95% 13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. ) AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form CE Control Equipment Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-279 2) Emission Point(s) ID: EP-279 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Description: Paving and Speed Reduction 6) Date of Construction: November 2008 7) Date of Modification: TBD 8) Capture Hood involved: Yes No 9) Capture Hood Efficiency (percentage): N/A 10) Date of Hood Installation: N/A 11) Date of Hood Modification (if any): 12) Pollutant Controlled PM Control Efficiency PM10 95% VOC SO2 NOx CO Other( 95% 13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. ) AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-280a 2) Emission Point(s) ID: EP-280a 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency Other( PM10 99.9% ) 99.9% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-280b 2) Emission Point(s) ID: EP-280b 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency Other( PM10 99.9% ) 99.9% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-281 2) Emission Point(s) ID: EP-281 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency Other( PM10 99.9% ) 99.9% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form CE Control Equipment Information Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-282 2) Emission Point(s) ID: EP-282 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Description: Telescopic Chute/Wet Suppression/Partial Enclosure 6) Date of Construction: November 2008 7) Date of Modification: TBD 8) Capture Hood involved: Yes No 9) Capture Hood Efficiency (percentage): N/A 10) Date of Hood Installation: N/A 11) Date of Hood Modification (if any): 12) Pollutant Controlled PM Control Efficiency PM10 95% VOC SO2 NOx CO Other( 95% 13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. ) AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-283 2) Emission Point(s) ID: EP-283 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency Other( PM10 99.9% ) 99.9% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-284 2) Emission Point(s) ID: EP-284 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency Other( PM10 99% ) 99% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-285 2) Emission Point(s) ID: EP-285 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency Other( PM10 99% ) 99% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-286a 2) Emission Point(s) ID: EP-286a 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency Other( PM10 99.9% ) 99.9% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-286b 2) Emission Point(s) ID: EP-286b 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency PM10 99.9% Other( 99.9% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. ) AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-287 2) Emission Point(s) ID: EP-287 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency PM10 99% Other( 99% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. ) AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-288a 2) Emission Point(s) ID: EP-288a 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency Other( PM10 99.9% ) 99.9% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-288b 2) Emission Point(s) ID: EP-288b 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency Other( PM10 99.9% ) 99.9% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-289a 2) Emission Point(s) ID: EP-289a 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency PM10 99.9% Other( 99.9% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. ) AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-289b 2) Emission Point(s) ID: EP-289b 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency PM10 99.9% Other( 99.9% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. ) AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-290 2) Emission Point(s) ID: EP-290 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency PM10 99% Other( 99% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. ) AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-291 2) Emission Point(s) ID: EP-291 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency PM10 99% Other( 99% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. ) AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-292 2) Emission Point(s) ID: EP-292 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency PM10 99% Other( 99% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. ) AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-293 2) Emission Point(s) ID: EP-293 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency PM10 99% Other( 99% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. ) AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-294 2) Emission Point(s) ID: EP-294 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency PM10 99% Other( 99% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. ) AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-295 2) Emission Point(s) ID: EP-295 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency Other( PM10 99.9% ) 99.9% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in Form CE1 Control Equipment Information for Fabric Filter Equipment 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Please see instructions on the reverse side Company Name IPL-Sutherland Generating Station Unit 4 1) CE Number ID: CE-296 2) Emission Point(s) ID: EP-296 3) Manufacturer: TBD 4) Model Number: TBD 5) Control Equipment Type: Baghouse Cartridge Filters Bin vent Filters Other 6) Material filter media made of: TBD 7) Total Filter Face area of control device (ft2): TBD 8) Pressure drop across Filter (in H2O): TBD 9) Bag cleaning method : Pulse Jet Shaking Reverse Air Other 10) Date of Construction: November 2008 11) Date of Modification: TBD 12) Capture Hood involved: Yes No 13) Capture Hood Efficiency (percentage): N/A 14) Date of Hood Installation: N/A 15) Date of Hood Modification (if any): 16) Pollutant Controlled PM Control Efficiency Other( PM10 99.9% ) 99.9% 17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design specifications and performance data to support the above mentioned control efficiency. Please refer to the BACT analysis in Appendix H of the Application Package. AIR QUALITY BUREAU Application Log in Desk 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 1) Company Name: AIR CONSTRUCTION PERMIT APPLICATION Form EC: Emission Calculations Please see instructions on reverse side IPL-Sutherland Generating Station Unit 4 2) Emission Point (Stack/Vent) Number: EP-248 through EP-296 3) Emission Calculation (Please see instructions for proper way to calculate). This calculation is based on (check all that apply): Emission Factors Mass Balance Testing Data Other: Calculations: Please refer to Appendix G of the Technical Support Document for detailed emission calculations for all emission points. 5) POTENTIAL EMISSIONS: SUMMARY OF EMISSIONS FROM THIS EMISSION POINT Pollutant PM PM10 PM2.5 SO2 NOx VOC CO Lead Single HAP Total HAPs Concentration, Unit: lbs/hr tons/year For Assistance 1-877 AIRIOWA (1-877-247-4692) (DNR Form 542-3190-16) Revised 11/2006 EI AIR QUALITY BUREAU ATTN: Application Log in IOWA DNR Air Construction Permit Application 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Form EI Facility Emission Inventory Please see instructions on the reverse side Company Name: IPL-Sutherland Generating Station PSD Classification: Major Minor Unknown STACK/VENT EMISSIONS SUMMARY (1) EP ID (2) EU ID (3) Source Description (4) (5) Construction Date Permit Number PM (6) Potential or Permitted Emission Rate (tons/yr) PM10 SO2 NOx VOC CO Lead HAP THAP Please Refer to Appendices G and I of the Technical Support Document for a Summary of Emission Points, Emission Units and Associated Potential Emission Rates (7) Total Stack Emissions Fugitive Emission Summary (8) Source ID: (9) Total Fugitive Emissions (10) Total Plant Emissions (DNR Form 542-3190-55) For Assistance 1-877 Air Iowa (1-877-247-4692) Revised 10/2005 MI2 AIR QUALITY BUREAU ATTN: Application Log In 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Company Name: AIR CONSTRUCTION PERMIT APPLICATION FORM MI-2: Modeling Information (Emission Source Characteristics) Please see instructions on reverse side IPL-Sutherland Generating Station Unit 4 TABLE 1. SUMMARY OF EXISTING STACK/VENT EMISSION SOURCES (1) (2) (3) (4) (5) (6) (7) (8) Emission Point ID Number Stack Height Stack Size Exhaust Temperature Discharge Style Exhaust Flow Rate Operating Hours Air Pollutant Emission Rate (lbs/hr) (estimated actual emission rate) (inches) (ºF) (feet) PM10 (acfm) NOx SO2 CO Lead Please Refer to Appendix I, Table 2 of the Technical Support Document for the Information Requested in this Form. TABLE 2. SUMMARY OF EXISTING FUGITIVE EMISSION SOURCES (PSD PROJECTS ONLY) (9) (10) Source ID Source Description Number For Assistance 1-877-AIR-IOWA (11) (12) Dimensions (feet) Air Pollutant Emission Rate (lbs/hr) (estimated actual emission rate) (Length x Width x Height) PM10 NOx SO2 CO Lead (1-877-247-4692) (DNR Form 542-3190-56) Revised 10/2006 AIR QUALITY BUREAU AIR CONSTRUCTION PERMIT APPLICATION ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 FEDERAL REGULATION APPLICABILITY Please see instructions on the reverse side Company Name: IPL-Sutherland Generating Station Unit 4 APPLICABILITY DETERMINATION 1) Will this project be subject to 1990 CAA Section 112(g) (Case-by-Case MACT) NO YES* DON’T KNOW * If YES then applicant must submit an application for a case-by-case MACT determination [IAC 567 22-1(3)”b” (8)] 2) Will this project be subject to a New Source Performance Standard? (40 CFR part 60) NO YES* DON’T KNOW *If YES please identify sub-part __Da, Y, OOO__________________________________ 3) Will this project be subject to a MACT (Maximum Achievable Control Technology) Regulation? (40 CFR part 63) NO YES* DON’T KNOW *If YES please identify sub-part ___DDDDD (Vacated), ZZZZ______________________ THIS ONLY APPLIES IF THE PROJECT EMITS A HAZARDOUS AIR POLLUTANT – SEE TABLE A FOR LIST 4) 5) 6) Will this project be subject to a NESHAP (National Emission Standards for Hazardous Air Pollutants) Regulation? (40 CFR part 61) Will this project be subject to PSD (Prevention of Significant Deterioration) ? (40 CFR section 52.21) NO YES* DON’T KNOW *If YES please identify sub-part ________________________________________ NO YES NO YES* DON’T KNOW DON’T KNOW Was netting done for this project to avoid PSD? *If YES please attach netting calculations IF YOU ARE UNSURE HOW TO ANSWER ANY OF THESE QUESTIONS CALL 1-877 AIR IOWA Federal Regulations Applicability Form Instructions This form is designed to provide the review engineer information regarding applicable federal regulations. This project may be subject to a federal regulation. These regulations have also been adopted by the state of Iowa in IAC 567 23.1(1), 23.1(2), 23.1(3), 23.1(4) and 23.1(5). 1) The 112(g) provision is a transitional measure to ensure that facilities protect the public from hazardous air pollutants until EPA issues MACT standards that apply to the facilities. If this project is already subject to a MACT regulation it will not be subject to the provisions of 112 (g). 2) New Source Performance Standards are Federal Regulations that apply to a wide range of sources of criteria air pollutants. To locate the rule go to http://www.access.gpo.gov/nara/cfr/waisidx_01/40cfr60_01.html MACT regulations apply to sources of hazardous air pollutants. See Table A for a list of hazardous air pollutants. To locate the rule - go to: 3) www.epa.gov/ttn/atw/mactfnl.html. 4) NESHAP regulations apply to sources of the following pollutants: beryllium, mercury, vinyl chloride, radionuclides, benzene, asbestos and arsenic. To locate the rule - go to www.access.gpo.gov/nara/cfr/waisidx_02/40cfr61_02.html 5) If you are a PSD major source and the net emissions increase from this project exceeds significance levels (as defined by 40 CFR 52.21) this project will be subject to PSD regulations. Please contact DNR prior to AIR QUALITY BUREAU IOWA DNR Air Construction Permit Application ATTN: Application Log in 7900 Hickman Rd., Suite 1 Urbandale, IA 50322 Company Name: Form GHG: Project Greenhouse Gas Emission Inventory Please see instructions on the reverse side Please attach a copy of your calculations showing how the potential GHG emissions were calculated to this form IPL-Sutherland Generating Station Unit 4 Plant Number: 64-01-012 EMISSIONS SUMMARY (1) EP ID (2) EU ID (3) Source Description CO2 (tpy) (4) Potential Emission Rate CH4 (tpy) N2O (tpy) SF6 (lb/yr) 248 248 Unit 4 Boiler 5.74E+06 6.79E+02 9.70E+01 249 248 Auxiliary Boiler 3.13E+04 3.49E+00 5.37E-02 250 250 Emergency Diesel Engine 1.52E+02 4.58E-03 1.53E-03 251 251 Emergency Fire Pump (Main) 3.17E+01 9.57E-04 3.19E-04 252 252 Emergency Fire Pump (Booster) 1.04E+01 3.14E-04 1.05E-05 297 297 Gate Station Heater 1.53E+03 1.71E-01 2.63E-03 253 253 Linear Mechanical Draft Cooling Tower 0.00 0.00 0.00 254-279 254-279 Coal Material Handling 0.00 0.00 0.00 280-285 280-285 Limestone Material Handling 0.00 0.00 0.00 286-288 286-288 Saleable Flyash Handling and Storage 0.00 0.00 0.00 289-290 289-290 Waste Flyash Handling and Storage 0.00 0.00 0.00 291-294 291-294 Material Handling - Others 0.00 0.00 0.00 295-296 295-296 Biomass Material Handling 0.00 0.00 0.00 5.78E+06 6.83E+02 97.04 (5) Total Project Emissions HFCs (lb/yr) PFCs (lb/yr) Interstate Power and Light Sutherland Unit 4 Air Permit Application Attachment 1 Coal and Limestone Handling Dust Collection Systems Dust Collectors: The coal & limestone handling systems will be provided with dry type dust collection systems to reduce the amount of fugitive dust allowed to escape into the atmosphere, from the coal & limestone handling transfer points. The dust collectors will be provided at the following locations. Coal handling system: • Rail Car Unloading building and hoppers • Crusher House building • Mill Bunker building Limestone handling system: • Rail Car Unloading building and hoppers The function of the dust collectors will be to filter the dust-laden air collected at the various pick-up points and provide immediate storage for the dust particles removed from the air streams. The dust collectors will be induced draft, top access fabric filter type units enclosed in stiffened steel plate housings. Filter cleaning will be by cyclic impulse air jet reverse flow into the bags. The subcomponents of the collectors will include the unit housing and hopper, filter bags, filter support cages, cleaning air distribution valve and manifold, collector access, and all associated electrical and control devices. Each individual dust collector system will be bounded by the inlet and outlet dust stream ductwork, the bag cleaning mechanism supply air pipe or duct, rotary vane valve, and the support structure as applicable. The unfiltered air entrance will be baffled to distribute air evenly to the filter media and to reduce the velocity of the incoming air so that larger dust particles may precipitate directly to the bottom hoppers. The collector housings will be all welded airtight and watertight, fabricated from not less than 12 gauge steel plate, and stiffened to withstand the specified differential air pressure acting on the housing as well as any other live loadings specified. Access stairs and platforms will be provided to all areas of the structure where frequent and convenient access is necessary. Cage type ladders are used for access to remote areas. Hand railings and kick plates will be provided on all open platforms and along stairways and walkways. 082907-145491 1 Interstate Power and Light Sutherland Unit 4 Air Permit Application Attachment 1 For coal handling system units, the collector housings will be equipped with internal fire protection sprinkler headers. The filter bags will be flame proofed and grounded to dissipate static electric charges. Filter bags will have their shape maintained by bag cages. Attachment of the open ends of bags will be by snap rings or an equally acceptable method and will be secured to prevent side movement of the cages. The dust collection hoppers will be constructed with a smooth transition from the main section to the pyramidal or troughed type bottom sections. Each dust collector hopper will be equipped with dust level alarm units. The alarms will utilize an admittance probe detector with solid-state logic. A typical coal dust collection system is shown in Figure 1. A cutaway section of a typical dust collector is shown in Figure 2. Figure 1 Dust Collection System 082907-145491 2 Interstate Power and Light Sutherland Unit 4 Air Permit Application Attachment 1 Clean Air Dirty Air Bag Filters Figure 2 Cutaway Section of a Dust Collector Bin Vent Filters 082907-145491 3 Interstate Power and Light Sutherland Unit 4 Air Permit Application Attachment 1 The limestone handling system will be provided with Bin vent filters on top of the limestone storage silos, to reduce the amount of fugitive dust allowed to escape into the atmosphere. The Bin vent filters will be typically pulse jet bag-house type, and will be sized at the proper air to cloth ratio, based on the system requirement. The Bin vent filters will be provided at the following locations in the limestone handling system. • Top of each limestone storage silo Similar to the dust collectors described above, the Bin vent filters will be used to separate the fine fugitive dust generated during filling of the silos. Typically, they will be pulseclean, bag, or pleated fabric type, furnishing one bin vent for each storage silo. A centrifugal fan provided at the outlet end of the vent filter will create a slight vacuum at the flanged inlet of the bin vent filter. Dust laden air will enter the unit and passes through the filter bags, leaving dust on the bag exterior. Filtered air is exhausted to the atmosphere through the exhaust fan. An electric timer actuates valves in sequence, which releases compressed air through venturi tubes. Shock waves formed in the venture, travel downward and release caked dust from the bag exterior, discharging the collected dust back to the silos. The bin vent filter components will include, filter housing, penthouse, inlet, outlet, filter media, cage for each fabric filter bag in the vent filter, pulse clean venturi nozzles, exhaust fan etc. Each bin bent will be furnished with a dedicated programmable logic controller to initiate and control the pulse cleaning sequencing. Cleaning will be automatically initiated on a preset high differential pressure across the filter media. Pulse duration and delay between rows will be preset by the factory and field adjustable. Typical bin vent filters mounted on top of silos are shown in Figure 3. A sectional elevation of a typical bin vent filter with air flow is shown in Figure 4. 082907-145491 4 Interstate Power and Light Sutherland Unit 4 Air Permit Application Attachment 1 Figure 3 Bin Vent Filters on the silos 082907-145491 5 Interstate Power and Light Sutherland Unit 4 Air Permit Application Attachment 1 Figure 4 Sectional Elevation of Bin Vent Filter 082907-145491 6 Interstate Power and Light Sutherland Unit 4 Air Permit Application Appendix B Appendix B PSD Application Checklist 102607-145491 B-1 PSD APPLICATION CHECKLIST (Review and submit with each PSD application) I. Pre-Application Submittal Requirements Initial call made to Department to schedule Pre-Application Meeting and discuss application requirements (A pre-application meeting was held on Feb. 7, 2007 in IDNR's offices.) Dispersion modeling protocol was submitted to the Department (Modeling protocols were submitted for IDNR's comment and review on April 11, 2007 and May 9, 2007.) Dispersion Modeling Protocol accepted by Department (NA) Pre-construction monitoring was submitted to the Department Pre-construction monitoring accepted by Department Request made to waive pre-construction monitoring, if applicable (Pre-construction monitoring may only be waived if predicted concentrations are below the applicable monitoring de minimus levels) (NA) Determined if any support facilities and/or facilities under common control are associated with the facility where project is proposed Documentation to support decision was provided PSD Pre-Application Meeting with Department Representatives (80 percent Pre-application meeting held September 24, 2007 in IDNR's offices) II. Required Application Forms Fill out all application forms as directed by the individual form instructions FI: Facility Information Form FI signed by responsible official EU, EU1, or EU3: Emission Unit Information (one form required for each emission unit) Include all new and modified emission units. Remember to include ancillary units, such as emergency generators and fire pumps, blackstart engines, cooling towers, painting and solvent cleaning, VOC storage containers, storage piles, material handling, haul roads, etc. CS: Control Equipment and Stack/Vent Information (one form required for each emission point or indoor venting emission unit) EC: Emission Calculations (one form required for each emission point or indoor venting emission unit) PSD Application Checklist Page 1 of 4 EI: Facility Emission Inventory (includes all emissions from fugitive sources, exempt units, indoor venting emission units and new and/or modified emissions units within the previous five years) MI-1: Modeling Information Plot Plan MI-2: Modeling Information Emission Point Characteristics (include all emissions from fugitive sources, exempt units, indoor venting units and new and modified emissions units) FRA: Federal Regulation Applicability Include a list of all the emission units in this project subject to New Source Performance Standards (NSPS) or National Emission Standards for Hazardous Air Pollutants (NESHAP) with the appropriate Subpart labeled. III. Emission Increases for the Project All associated emission increases were included in the calculated net emissions increases for each pollutant including emission increases due to: (NA) Debottlenecked emission units (NA) Increased utilization of emission units Fugitive emissions (NA) All emission increases at any support facilities and/or facilities under common control were included in the project’s net emissions increase Documentation supporting emission calculations (e.g. engineering estimates, stack test results, etc.) were included with the application Check the pollutants that have a “significant” net emission increase, for this project: Pollutant “Significant” Net Emission Increase Particulate matter (PM) > 24.4 tpy PM10 > 14.4 tpy Sulfur dioxide (SO2) > 39.4 tpy Nitrogen oxides (NOX) > 39.4 tpy Ozone (Volatile organic compounds (VOC)) > 39.4 tpy Carbon Monoxide (CO) > 99.4 tpy Lead (elemental) > 0.54 tpy Fluorides > 2.4 tpy PSD Application Checklist Page 2 of 4 Sulfuric acid mist > 6.4 tpy Total reduced sulfur compounds (including H2S) > 9.4 tpy CFC’s 11, 12, 113, 114, 115 > 0 tpy Halons 1211, 1301, 2402 > 0 tpy Municipal Waste Combustor (MWC) acid gases > 39.4 tpy MWC metals > 14.4 tpy MWC Organics > 3.44 x 10-6 tpy Other pollutants regulated under the CAA (§52.21(b)(23)(ii)) > 0 tpy Opacity – Visible Emissions IV. BACT Analysis A “top-down” BACT analysis was performed for each new or modified emission unit that is a source of a pollutant that has a “significant” net emission increase. Submitted documentation supporting BACT analysis V. Dispersion Modeling Analysis (NA) Potential ozone plumes were evaluated for projects with VOC emissions over 100 tons per year. Determined if modeled concentrations of any PSD pollutant were above the applicable modeling significance level (MSL).(Modeling results are less than the applicable MSLs.) (NA) If yes, full impact analyses were conducted to evaluate compliance with the NAAQS and PSD Increment values. (NA) Documentation for the source inventories used for NAAQS and PSD increment in the full impact analyses was provided. Electronic files associated with all applicable modeling analyses (including modeling significance levels and full impact analyses) on appropriate media (i.e. floppy, CD or diskette). PSD Application Checklist Page 3 of 4 VI. Additional Impacts Analysis (NA) A Class I visibility impacts analysis was completed. (NA) Potential impacts on endangered or sensitive species located in Class I areas that may be affected by the proposed project were evaluated if applicable, and all necessary documentation is included with the application. A Class II visibility impacts analysis was completed. A hard copy of the VISCREEN output is included with the application. VISCREEN input and output files are provided on appropriate media (i.e. CD or diskette). Impacts on soils and vegetation were considered, including impacts of NOx over short-term periods and the combined impact of NOx in conjunction with SO2. An air quality analysis for associated growth from the proposed project was conducted, if applicable, and all necessary documentation is included with the application VII. Proposed Permit Conditions Is the facility proposing any of the following permit conditions: Emission limits (including applicable averaging periods) Test methods Compliance demonstration methods Monitoring requirements for all averaging periods Recordkeeping requirements for all averaging periods VIII. Miscellaneous Submitted four copies of the entire application (five copies of the entire application are necessary if the facility is locating in Linn or Polk County) PSD Application Checklist Page 4 of 4 Interstate Power and Light Sutherland Unit 4 Air Permit Application Appendix C Appendix C Fuel Analyses 102607-145491 C-1 Sub-Bituminous Design Range Coal Coal Analysis Specification Basis: Parameter As Received Proximate Analysis (%) Moisture Ash Volatile Matter Fixed Carbon Btu MAF Btu Sulfur As Received Ultimate Analysis (%) Carbon Hydrogen Nitrogen Chlorine Sulfur Ash Oxygen Moisture Heating Value (BTU/lbm) As received Dry MAF BTU Sulfur Forms Pyritic Sulfate Organic Total Equilibrium Moisture Hardgrove Grindability at Moisture Water Soluble Alakalies Water Soluble Na2O Water Soluble K2O Ash Fusion Temperatures (°F) (Reducing Atmosphere) Initial Deformation (ID) Softening Temperature (Spherical) Softening Temperature (Hemispherical) Fluid Temperature (0.0625 in.) Ash Fusion Temperatures (°F) (Oxidizing Atmosphere) Initial Deformation (ID) Softening Temperature (Spherical) Softening Temperature (Hemispherical) Fluid Temperature (0.0625 in.) Powder River Basin Performance Coal Peabody Caballo 2006-2010 Smith Seam 8,400 BTU Powder River Basin Design Coal- BTU Rawhide Smith Seam 8,100 BTU Powder River Basin Wyoming High S Jacobs Ranch Upper Wyodak Seam High Sulfur Typical Minimum Maximum Typical Minimum Maximum Typical Minimum Maximum 29.8 4.8 31.5 33.8 8,500 13,005 0.35 28.90 4.40 29.70 32.30 8,300 31.10 5.80 32.50 35.70 8,600 30.00 4.60 29.10 32.30 8,100 32.20 6.00 31.50 34.70 8,500 28.32 8 33.54 34.13 9,024 0.42 0.24 0.50 26.94 6.8 32.5 32.89 8,800 13,280 0.88 25.56 5.6 31.46 31.65 8,576 0.29 30.50 4.90 30.40 34.20 8,300 12,984 0.33 0.66 1.1 49.35 3.44 0.70 <0.01 0.35 4.84 11.51 29.80 48.85 3.13 0.64 0.00 0.31 4.62 10.52 28.90 49.40 3.72 0.76 0.01 0.40 5.51 12.26 31.10 48.58 3.34 0.63 0.00 0.33 4.93 11.66 30.50 47.60 3.08 0.63 0.00 0.25 4.69 10.71 30.00 48.14 3.39 0.75 0.02 0.49 5.63 12.41 32.20 51.26 3.89 0.8 <.01 0.88 6.8 9.44 26.94 49.38 3.63 0.6 53.14 4.15 1 0.66 5.6 8.74 25.56 1.1 8 10.14 28.32 8500 8,300 8,600 8,300 12,029 12,948 8100 8500 8,576 9,024 11040 13010 8,800 12,044 13,280 0.18 0.02 0.68 0.88 0.08 0 0.42 0.66 0.28 0.04 0.94 1.1 56 21.64 49 13 64 30 0.07 <.01 0.43 0.50 28.3 62 28.5 27.3 29.7 52 72 0.065 0.003 0.09 <0.01 0.39 0.48 29.1 0.075 0.006 0.071 0.005 2,100 2,070 2,190 2,170 2,065 2,305 2128 2086 2170 2,110 2,080 2,200 2,180 2,075 2,315 2170 2120 2220 2,120 2,090 2,210 2,190 2,085 2,325 2191 2111 2271 2,130 2,100 2,220 2,200 2,095 2,335 2269 2185 2353 2,180 2,135 2,255 2,210 2,105 2,305 2228 2186 2270 2,190 2,145 2,265 2,220 2,120 2,315 2247 2197 2297 2,200 2,155 2,275 2,230 2,125 2,325 2263 2183 2343 2,210 2,165 2,285 2,240 2,135 2,335 2338 2254 2422 1 of 4 Coal Analysis Specification Basis: Ash Mineral Analysis (%) Silica -- SiO2 Alumina -- Al2O3 Titania -- TiO2 Ferric Oxide -- Fe2O3 Calcium Oxide -- CaO Magnesium Oxide-- MgO Potassium Oxide -- K2O Sodium Oxide -- Na2O Phosphorous Pentoxide -P2O5 Sulfur Trioxide -- SO3 Strontium -- SrO Barium Oxide -- BaO Manganese Oxide- MnO2 Undetermined Miscellaneous Alkalies as NA2O, d.c.b Base / Acid ratio Silica Value Slag Viscosity (T250) lbs Ash/MMBTU lbs sulfur/MMBTU lbs Alkali as Na2O/MMBTU lbs H2O/MMBTU Free Swelling Index Mercury, Hg (ppm) Dry Whole Coal Basis Trace Analyis (Dry Whole Coal Basis) Trace Element Summary Antimony Arsenic Barium Beryllium Boron Bromine Cadmium Chlorine Chromium Cobalt Copper Fluorine Lead Lithium Manganese Mercury Molybdenum Nickel Selenium Silver Strontium Thallium Tin Vanadium Zinc Zirconium Powder River Basin Performance Coal Peabody Caballo 2006-2010 Smith Seam 8,400 BTU Powder River Basin Design Coal- BTU Rawhide Smith Seam 8,100 BTU Powder River Basin Wyoming High S Jacobs Ranch Upper Wyodak Seam High Sulfur 31.5 16 1.3 5.3 23.5 4.5 0.3 1.7 29.0 15.6 1.2 5.1 20.8 4.2 0.2 1.4 37.0 18.0 1.6 6.2 26.8 5.0 0.4 2.4 31.20 13.90 1.10 6.30 24.30 6.10 0.20 1.70 27.00 11.80 0.80 4.80 21.80 4.70 0.10 1.00 35.00 15.80 1.30 7.80 28.00 8.70 0.30 2.00 27.74 15.9 1.13 9.28 18.83 3.35 0.31 0.96 22.2 13.58 0.83 7.98 15.09 2.51 0.11 0.62 33.28 18.22 1.43 10.58 22.57 4.19 0.51 1.3 1.0 13.7 0.4 0.7 0.1 0 0.2 9.0 0.2 0.4 <0.1 1.1 15.7 0.6 0.8 0.2 0.5 13.6 0.4 0.7 0.4 10 0.2 0.4 1 16 0.6 0.8 0.89 17.85 0.27 0.43 0.13 2.91 0.45 14.13 1.33 21.57 0 6.33 0.00 0.72 0.84 46.29 2220 5.9 0.79 2078 7.73 2.00 0.1 3,506 0.0 0.0945 0.074 0.09 0.09 2135 5.7 0.82 <1 1 289 0.2 40 <20 <0.2 <501 5 3 13 56 3 2 21 0.09 <2 4 <1 <0.2 218 <1 <1 15 7 11 0.73 2015 2141 1.64 2.36 0.5 5.1 376 0.4 0.21 1.1 207 0.3 0.79 9.1 545 0.6 10 0.29 147 7 4 17 26.1 3.4 3 30 0.14 7 0.09 47 4 2.5 9 15.5 1.6 1 0 0.07 14 0.5 247 10 5.4 25 36.7 5.2 4 80 0.2 14 2 0.13 7 1.1 0.09 21 3 0.16 0.2 0 0.4 26 32 0 15 9 37 56 0 1 1 1 1 0.2 2 380 0.3 50 20 0.05 240 4 1.5 9 27.6 2 2.84 21 0.09 0.18 0.7 300 0.1 40 10 0.02 120 2 0.8 4 17 1 0 12 0.02 0.65 5 480 0.5 60 30 0.07 400 8 5.1 14 34.9 4 6.08 45 0.12 5 1.2 2 0.4 10 2 270 200 380 12 11 Page 2 of 4 0.14 7 3 20 20 Bituminous Design Range Coal Coal Analysis Specification Basis: Parameter As Received Proximate Analysis (%) Moisture Ash Volatile Matter Fixed Carbon Btu MAF Btu Sulfur As Received Ultimate Analysis (%) Carbon Hydrogen Nitrogen Chlorine Sulfur Ash Oxygen Moisture Heating Value (BTU/lbm) As received Dry MAF BTU Sulfur Forms Pyritic Sulfate Organic Total Equilibrium Moisture Hardgrove Grindability at Moisture Water Soluble Alakalies Water Soluble Na2O Water Soluble K2O Ash Fusion Temperatures (°F) (Reducing Atmosphere) Initial Deformation (ID) Softening Temperature (Spherical) Softening Temperature (Hemispherical) Fluid Temperature (0.0625 in.) Ash Fusion Temperatures (°F) (Oxidizing Atmosphere) Initial Deformation (ID) Softening Temperature (Spherical) Softening Temperature (Hemispherical) Fluid Temperature (0.0625 in.) Illinois Basin Alternate Illinois Basin Coal Peabody Gateway Typical Illinois No. 6 11,000 BTU Typical Minimum Maximum Illinois Basin Illinois Basin Greater Belleville U. G. Illinois Basin no. 6 10, 800 BTU Typical Minimum Maximum 13.5 8.6 35.5 42.4 11,004 14,119 2.84 14.2 9.5 34.7 41.6 10,800 14,158 3.11 12.5 7.6 32.1 38.7 16.4 11.6 37.2 44.1 2.50 4.00 61.76 4.33 1.12 0.10 2.84 8.56 7.79 13.5 60.06 4.2 1.12 0.10 3.11 9.52 6.93 14.2 58.98 3.76 0.7 0.04 2.54 7.7 6.13 12.5 60.94 4.68 1.34 0.21 3.93 11.12 9.78 16.4 11,004 12,721 14,119 10,800 10,400 11,100 0.97 0.01 2.30 3.28 10.3 52 4.0 1.12 0.05 2.45 3.62 0.53 <0.01 1.6 1.79 0.10 3.2 53 28.5 48 28.5 58 28.5 0.094 0.005 0.94 0.005 0.04 <0.1 0.12 0.01 14,158 1,960 2,095 2,170 2,280 2,070 2,080 2,090 2,100 2,190 2,200 2,210 2,220 2020 2110 2185 2315 1920 1980 2030 2170 2160 2265 2350 2525 2,340 2,400 2,445 2,500 2,135 2,145 2,155 2,165 2,255 2,265 2,275 2,285 2325 2375 2420 2510 2200 2250 2300 2370 2450 2530 2565 2695 49.6 19.3 0.9 16.3 5.2 1 2.1 1.2 0.2 4.2 <0.1 <0.1 <0.1 43.2 16.4 0.6 13.2 2.6 0.6 1.5 0.6 0.1 2.6 <0.1 <0.1 <0.1 55.4 22.2 1.2 22.1 7.2 1.3 2.5 1.5 0.3 8.4 0.1 0.1 0.1 Ash Mineral Analysis (%) Silica -- SiO2 Alumina -- Al2O3 Titania -- TiO2 Ferric Oxide -- Fe2O3 Calcium Oxide -- CaO Magnesium Oxide -- MgO Potassium Oxide -- K2O Sodium Oxide -- Na2O Phosphorous Pentoxide -- P2O5 Sulfur Trioxide -- SO3 Strontium -- SrO Barium Oxide -- BaO Manganese Oxide- MnO2 Undetermined 51.4 19.7 1 16.3 4.2 1.0 2.2 1.3 0.2 2.6 <0.1 0.1 <0.1 0 Page 3 of 4 Coal Analysis Specification Basis: Illinois Basin Alternate Illinois Basin Coal Peabody Gateway Typical Illinois No. 6 11,000 BTU Illinois Basin Illinois Basin Greater Belleville U. G. Illinois Basin no. 6 10, 800 BTU Miscellaneous Alkalies as NA2O, d.c.b Base / Acid ratio Silica Value Slag Viscosity (T250) lbs Ash/MMBTU lbs SO2/MMBTU lbs Alkali as Na2O/MMBTU lbs H2O/MMBTU Free Swelling Index Mercury, Hg (ppm)Dry Whole Coal Basis Trace Analysis (Dry Whole Coal Basis) Antimony Arsenic Barium Beryllium Boron Bromine Cadmium Chlorine Chromium Cobalt Copper Fluorine Lead Lithium Manganese Mercury Molybdenum Nickel Selenium Silver Strontium Thallium Tin Vanadium Zinc Zirconium 0.27 0.35 70.51 2475 7.8 5.157 0.1 1,226.83 0.0 0.09 0.2 0.37 68.79 2450 7.73 5.75 0.074 <1 2 32 1 159 36 0.4 1100 20 3 8 102 2 7 22 0.06 6 11 1.9 0.1 17 <1 <1 32 40 15 <0.1 2 50 1.2 150 22 0.5 759 25 2 10 99 6 7 39 0.07 8 14 2 <0.2 25 <0.1 <0.1 32 67 15 0.16 0.27 62 2290 0.39 0.5 76 2634 4.80 7.20 0.14 Source: Illinois GS Belleville Basin Illinois Basin Nos. 6 Seam Dry Whole Coal Basis-ppm Note: The characteristics of all coals to be burned in the new generating unit will be generally consistent with the fuel quality limits presented in Appendix C and used in the preparation of this application. Page 4 of 4 Interstate Power and Light Sutherland Unit 4 Air Permit Application Appendix D Appendix D System Descriptions System Description Contents • • • • • • • • • • • • • • • 102607-145491 Major Systems Location - Overview Drawing Steam Generator Steam Turbine Generator Auxiliary Boiler Coal Handling System Fly Ash Handling FGD Solids Biomass Handling Bottom Ash Chimney Emergency Generation Fencing and Security Gate Station Heater Limestone Handling System Site and Equipment Fire Protection D-1 Interstate Power and Light Sutherland Unit 4 Air Permit Application 1.0 System Description 1.1 System Identification – Steam Generator 1.2 Function The Steam Generator System provides for the heat transfer of heat released during the combustion of the fuel to the feedwater and steam. This heat transfer produces main steam at a supercritical pressure and 1080 oF temperature required by the high-pressure turbine. Heat transfer also takes place in the reheater to increase the temperature of the cold reheat steam to that required by the intermediate-pressure turbine. The Steam Generator will receive a coal-air mixture from the pulverizers in the Combustion Air System, fuel gas from the Ignitor Fuel System, combustion air from the Combustion Air System, feedwater from the Boiler Feed System, and cold reheat steam from the Cold Reheat System, and combustion air from the Combustion Air System. The Steam Generator will be a field erected top supported pulverized coal, once-through supercritical, variable pressure, balanced draft, spiral or straight furnace tube orientation with single reheat. 1.3 Process Description The Pulverized Coal Steam Generator System consists of the following major equipment and components: EQUIPMENT QUANTITY/REDUNDANCY Boiler and Auxiliaries One 100% capacity system • Furnace wall system • Vertical / Spiral tube • Superheater, Reheater • SA231 - T11, T22, T91, or T347 • Attemperators • Superheater, Reheater • Economizer • Plain tube in line • Steam Separator and Startup System • By Contractor • Boiler Casing, Refractory and Insulation • 120 F max insul surface temperature • Windbox • By Contractor • Burners • Low NOx • Secondary air ports, dampers and drives • By Contractor • Scanners • By Contractor • Igniters • By Contractor • Sootblowers • Steam type 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application EQUIPMENT QUANTITY/REDUNDANCY • Furnace high pressure water wash system • Total coverage, including pumps and piping. • Regenerative Air Preheater • By Contractor • Overfire Air Ports • Separated OFA • Safety/Relief Valves • Overpressure protect per Code • Boiler structure and enclosure • Galvanized structural steel for boiler, auxiliary bay, and coal silo bay(s) • Variable Speed Centrifugal type FD fans with VFD motors • 2 x 50% per boiler • • 2 x 50% per boiler Single Speed Centrifugal type PA fans • FD fan and PA fan secondary air preheat coils • Steam coils sized to provide minimum CEAT – by Contractor • Air and gas ductwork • • Vertical Type Coal pulverizers • 5 pulverizers sized for no more that 80% of maximum capacity at MCR Unit load point. By Contractor • 4 + 1 spare = 5 • Pulverizer Inerting system • By Contractor • Gravimetric Coal feeders • One per pulverizer • Pulverized coal piping • Carbon steel pipe with hard facing as required on wear sections • Natural Gas Startup System • By Contractor • Chemical cleaning provisions • Connections for portable equipment • Burner management system • By Contractor • Valves and accessories • By Contractor • Test connections • • Structural Steel and Enclosures • SCR, SCR catalyst, ammonia vaporization system and related ducting • Ductwork, breeching, expansion joints, piping supports, electrical controls and instruments, motors, lube systems and accessories 082907-145491 Facilitate boiler testing Interstate Power and Light Sutherland Unit 4 Air Permit Application Combustion of pulverized coal fuel with air described in the Combustion Air System releases radiant and convective heat energy in the steam generator furnace. The Steam Generator System also receives feedwater from the boiler feed pumps described in the Boiler Feed System, and cold reheat steam from the high-pressure turbine exhaust as described in the Cold Reheat Steam System. The steam generator will use these sources to produce steam at the required operating conditions for main steam flow to the highpressure turbine and for hot reheat steam flow to the intermediate-pressure turbine. Boiler feedwater enters the economizer section of the steam generator, located at the bottom of the convection pass heat recovery area, and will flow up to the economizer outlet header. Exhaust gas will flow across the economizer tubes in a direction opposite to the feedwater flow. The furnace section of the steam generator will be a gastight construction of welded membrane carbon steel tubes. The furnace tubes will be arranged in a spiral pattern to minimize localized hot spots and minimize thermal stresses. The furnace tube construction is dependent on the manufacturer’s specific design. The furnace will consist of a combustion zone that is to be conservatively sized in order to minimize slagging, fouling, and erosion risks based on the design coals. The steam generator will consist of feedwater and steam cooled furnace walls, convection pass walls, convection pass screen tubes, primary superheat tubes, finishing secondary superheater tubes, reheater tube sections and steam separator and water collector vessels. The bottom of the furnace will slope down and toward the center of the furnace from the water walls to form a long sloping ash discharge interface leading into the bottom ash drag chain conveyor. The steam temperature leaving the final superheater will be controlled with firing rate and feedwater flow control. Attemporators may also be used for emergency control. The attemporator spray water will be supplied from the Boiler Feed System. The main steam temperature will be maintained at 1080 °F from 75% load to rated load. The boiler water circulation pump (if required and provided by the manufacturer) is used during startup to maintain a minimum circulation in the boiler wall tubes cooled by feedwater and steam. The reheater section of the steam generator will consist of horizontal tube banks with a vertical tube section outlet. Steam from the Cold Reheat System enters the reheater inlet header section at the bottom of the path and then flows upward in the horizontal section of reheater tubes as a counter flow to the gas stream. Reheated steam leaves through the outlet header located above the furnace roof panel tubes. One method of reheat steam temperature control will include two parallel gas paths with dampers located at the outlet of the economizer sections installed in each path. One path will contain the primary superheater and the other path will contain the reheater. The reheater outlet temperature will normally be controlled by adjustment of the dampers located at the outlet of the economizer section. The balance of the flue gas flow will be directed through the superheater path. To maintain the reheater outlet steam temperature, the percentage of gas flow over the reheater will be increased with a decrease in load. 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application Another method of steam temperature control is the use of tilting burners in the furnace to move the burner flames higher or lower in the furnace that enable greater or less heat transfer from the flue gas to the furnace walls before the gas enters the convection pass area of the steam generator. The method of reheater steam temperature control will be determined by the design of the selected manufacturer. In either case, spray attemporators are to be provided for fast desuperheating response for any temperature excursions as part of the steam temperature controls. The steam generator will be top supported with thermal growth downward. Connections to the steam generator will be designed to accommodate this expansion without excessive stress. 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application 1.0 System Description 1.1 System Identification – Steam Turbine Generator 1.2 Function The cylindrical rotor machine converts rotational energy to electricity with proven reliability and efficiency in a large number of units operating at comparable conditions. 1.3 Process Description The Steam Turbine Generator System includes the following major equipment and components: • Stator core and stator winding. • Hydrogen gas cooler. • Temperature detectors. • Rotor and rotor coils. • Hydrogen gas system. • Shaft seal oil system. • Static excitation system and power system stabilizer. • Generator neutral grounding. The generator will be completely enclosed and, in operation, use hydrogen gas as the cooling medium. The ventilation system, including the fans and gas coolers, will be selfcontained and completely enclosed to prevent dirt and moisture from entering into the generator. The stator and rotor windings will be directly cooled by hydrogen. The generator casing will be substantially cylindrical in shape and of welded gastight construction. The outer end shields at either end of the casing will also be of gastight construction and support the generator bearings and shaft seals. The rotor shaft will pass through the outer end shield out of the generator, and shaft seal devices are provided to prevent hydrogen gas leakage. The generator will be designed to be able to operate at 5% over and under voltage at rated kVA output. The generator will be rated to carry the maximum turbine output continuously at a leading power factor of 0.95 through lagging power factor of 0.85 at constant kVA output. The generator winding will be wye connected and suitable for operation with the neutral resistance grounded through a distribution transformer. Phase terminals will be brought out separately. 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application The stator and rotor winding insulation will be a Class F insulation system with class B temperature rise. The stator core will be supported by spring plates in the stator frame to isolate the core from vibration. The generator will be designed for continuous operation and constructed to withstand a sudden change in load and three-phase short circuit. Various kinds of supervising and controlling instruments will be provided for keeping the generator in satisfactory operation. 1.3.1 Stator Core and Stator Winding The stator core will be built up of segmental insulated punchings of low loss silicon steel sheets. The punchings will be assembled in an interleaved manner on rib bar and axial ventilation holes provided to cool the stator core by hydrogen. The stator winding will be formed by insulated bars assembled in the stator slots, and connected to the phase belts by bus rings. The stator bars will be composed of insulated conductors arranged in the form of transposed rectangular bars. This transposition avoids eddy current losses under load conditions. The ground insulation system will be epoxyresin impregnation under vacuum system and classified as Class F insulation. The stator winding will be star connected. All six terminals will be brought out of the machine and will be available for external connections. Either end of the winding will be designed for use as a neutral bus or for use as the main generator power leads. The generator neutral connection rating in amperes will be the same as the generator line terminal rating and will be based on the maximum MVA rating of the generator operating at minimum allowable generator terminal voltage. The main power lead terminal bushings will be spaced to permit connection to the generator terminal conductor system. Connection to the generator terminal conductor system to the generator high voltage line bushings will be accomplished using bolted connection to spade type flanges. Flexible connections will be used where appropriate to allow thermal expansion and to avoid transmittal of vibration to other equipment. Current transformers will be installed on the generator line and neutral bushings in quantities required to provide relay protection, metering, and control functions. Sufficiently high accuracy class CTs will be chosen to avoid saturation and false signals. The generator neutral will be high resistance grounded via a neutral grounding transformer and resistor assembly. The assembly will include a sheet metal steel indoor cubicle, a neutral grounding transformer, and a neutral grounding resistor. The resistance value will be chosen so that the resistor kW dissipation during a phase-to-ground fault is equal to or greater than the generator and generator terminal equipment system charging kVA. In general, the phase-to-ground primary current range should be limited to 4 to 10 amperes, thereby minimizing damage to the main generator windings if a fault occurs. Current through the neutral grounding system or voltage across the resistor will be used to detect a ground fault within the generator or on the generator bus or other connected 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application equipment. The transformer and resistor will be sized to withstand resulting fault current for 30 seconds. The generator stator frame will be provided with four grounding pads located diametrically opposite at four corners of the structure, each with threaded holes and associated bolts for attachment of the station grounding conductors. 1.3.2 Hydrogen Gas Cooling A hydrogen gas cooler will be used to cool the hydrogen gas. It will be composed of a set of water boxes, a bundle of finned tubes set in the tube sheets, and a supporting frame. Hydrogen gas in the generator will be carried into the hydrogen gas cooler by a fan on the generator rotor. Hydrogen gas will flow over the surfaces of the cooling tubes, liberating its heat to the water running inside the cooling tubes. The tube material will be copper nickel or approved equal. During normal operation, the hydrogen gas pressure in the generator casing will be automatically maintained at the rated gas pressure by the gas pressure regulator. When the generator casing is to be filled with hydrogen gas, the air inside the casing will initially be purged by carbon-dioxide gas through the purge line and, then, this carbondioxide will be replaced by hydrogen, so as to avoid the formation of an explosive hydrogen and air mixture in the generator casing. During these procedures, the purged gas or air will be vented to the atmosphere through the vent pipe. To monitor the system, instruments such as the machine gas purity meter, the machine gas pressure gauge, etc. will be provided on the hydrogen control panel and rack. Hydrogen gas purity will be measured and the system will be designed to scavenge a small amount of hydrogen to allow makeup to maintain required purity. Gas dewpoint will be monitored continuously. A hydrogen seal oil system will be provided. Oil seal glands will be provided at the generator shaft to prevent loss of gas or air infiltration, and oil drains from the generator bearings will be designed to prevent hydrogen from reaching the oil reservoir. The seal oil system will be capable of regulating the oil pressure above the hydrogen pressure to maintain a tight seal even under hydrogen pressure changes. The system will be designed for detraining air and/or hydrogen from the oil for each cycle it passes through the seals. Generator bearing lube oil will be used as the seal oil, eliminating any concern about mixing of two different oil systems. The Supplier will be responsible for demonstrating the integrity of the hydrogen seal oil system to show that leakage rates are within guaranteed tolerances. 1.3.3 Temperature Detectors Several resistance temperature detectors (RTDs) will be located between coils in each phase of the stator windings to measure the temperature of the windings. Other resistance temperature detectors will be located to measure the temperature of cooling hydrogen gas entering and exiting the hydrogen gas cooler. In addition, several RTDs 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application will be located to measure the temperature of the hydrogen gas leaving the stator winding. 1.3.4 Rotor and Rotor Coils The rotor will be machined from a single alloy steel forging. Prior to machining, extensive tests will be made to assure that the forging meets the required specifications for physical and metallurgical properties. Longitudinal slots, machined radially in the body, will contain the rotor coils. The rotor coils will be held in the slots against centrifugal force by wedges. These wedges will be fitted and driven into dovetail openings machined in the rotor slots. The rotor fan, which is provided for the ventilation of the generator, will be multi-stage axial flow type. The fan will be assembled near the ends of the rotor. The collector rings, which are provided for supplying excitation current to the rotor coils from the static excitation system, will be shrunk on the rotor shaft end. The rotor coils will consist of rectangular copper bars formed into coils. Several coils will be assembled around each pole to form the winding. The individual turns of the coils will be insulated from each other by insulation sheet. The coils will be insulated from the rotor body by the slot cells made from glass/Nomex-laminated epoxy-resin. A molded insulation ring will be provided between the coils and retaining rings, and insulating space blocks will be provided in the end windings to support the coils. The retaining rings restrict the movement of the coils caused by thermal deformation and centrifugal force, and will be made from high mechanical strength, non-magnetic alloy steel. 1.3.5 Static Excitation System and Power System Stabilizer A potential-source controlled rectifier excitation system will be provided, which has high performance, reliability, and response. Self excitation of the generator will be provided by a static excitation system using a thyristor rectifier that converts the AC voltage from the generator terminals through the excitation transformer into DC voltage. The Automatic Voltage Regulator will be a continuously acting, micro-processor based AVR, utilizing modern electrical technology. The voltage regulator will control the output voltage of a thyristor rectifier that consists of rectifiers with the resulting dc power supplied to the generator field. The excitation power will be taken from the generator terminal voltage through the excitation transformer except during initial excitation. A power system stabilizer will be provided in accordance with the requirements of the governing authorities. The Supplier will be responsible for initial setup (including any and all calculations necessary to support proposed settings and all onsite commissioning and tuning activities related to the power system stabilizer. The power system stabilizer function will provide a stabilization signal output to the AVR to suppress active power disturbances. Excitation Control Panel (Automatic Voltage Regulator; AVR). The excitation control system will have two master controllers that constitute a duplicated-redundant AVR system and one system controller. During normal operation, the whole excitation 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application control function will be subject to automatic control. A Standby AVR system, with continuous follow-up for a bumpless switch-over (in case of a failure in the operating AVR system), will also be provided. The manual excitation control function will also be provided. Thyristor Rectifier Cubicle. The thyristor rectifier will consist of 3-phase full-wave thyristor bridges, equipped with 6 thyristors. A fuse will be connected in series to each thyristor. Fans may be used to cool the thyristor tray (thyristor element) of the rectifier with forced air. Cooling fans, if used, will be set in 2-system configuration. Normally, only one fan system will be used for cooling, however operation will switch to the other fan if the normal fan motor fails. Field Circuit Breaker Cubicle. The field discharge circuit will be made of an AC breaker in an AC circuit and discharge circuit connected to a discharge resistor (linear resistor) and discharge thyristor in a DC circuit. The over voltage suppression will be made of a ZNR absorber (varistor) and CR absorber in an AC/DC circuit of a thyristor rectifier bridge. Excitation Monitoring. The excitation monitoring circuit will monitor the performance of the excitation system. In case of a failure, an automatic change-over to the stand-by channel or the shut-down of the excitation system will be initiated. The major functions are the following: • Measuring of generator terminal voltage (VT-failure). • Measuring of field current. • Monitoring of the operational condition. 1.3.6 Generator Protection The following protection functions will be provided, as a minimum, for the generator excitation system: • Overexcitation protection will be provided to prevent excessive, sustained ceiling excitation voltage from increasing damage to either the excitation equipment or the generator. This protection will consist of the following as a minimum: o Overexcitation trip to trip the machine if excessive excitation remains for a predetermined time, both in automatic and in manual operation. o An adjustable limiting device which will automatically prevent operation above the rated generator overexcitation capability. • A volts/hertz regulator will be furnished to provide a continuously acting limit to the maximum volts/hertz. The volts/hertz will act only in the automatic regulator. 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application • Automatic and continuous ground detection equipment will be provided to detect grounds in the generator field. Facilities will be provided to permit inservice tests of the ground detection system at any time. Ground detection will be relayed via a contact for remote annunciation in the main control room. • Underexcitation protection will be provided so that the synchronous machine voltage regulator will be limited by means of an adjustable limiting device which will automatically prevent operation below the rated generator capability for underexcitation operation. • A voltage unbalance detector circuit will be provided. Loss of regulator sensing voltage will transfer the regulator from automatic to manual. Remote annunciation will be provided in the main control room for loss of metering and regulating voltage transformer signals. Redundant multifunction protective relays will be used to provide the protective functions. Industry standards will be followed regarding the selection of protective functions, as well as calculation of the settings to be used. 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application 1.0 System Description 1.1 System Identification – Auxiliary Boiler 1.2 Function The Auxiliary Boiler provides auxiliary steam during startup and normal operation for the following: 1.3 • Heating steam for the deaerator during startup. • Shaft sealing steam for main steam turbine during startup and low load. • Steam for building HVAC heating (including tie to existing Units 1, 2, & 3). • Boiler air preheat coils. • Steam for pulverizer inerting system. • Steam for other auxiliaries (including tie to existing Units 1, 2, & 3). Process Description The auxiliary boiler will be natural gas fired and transfer heat to auxiliary boiler feedwater to produce saturated steam. The natural gas fuel system shall be capable of operating the boiler throughout its entire load range of ambient conditions with a limited maximum heat input of 270 MBtu/h. The auxiliary boiler will provide 200,000 lb/hr of 250 psia saturated steam to the auxiliary steam header. The auxiliary boiler is expected to operate no more than 2,000 hours per year. The auxiliary boiler stack will discharge to the atmosphere at the specified elevation. 082907-145491 Interstate Power & Light Company Sutherland Unit 4 Air Permit Application 1.0 System Description 1.1 System Identification – Coal Handling System 1.2 Function The function of the Coal Handling System will be to receive and unload coal delivered by rail cars, provide a means to stock out and store the coal in active and reserve storage piles, provide the means to reclaim, blend, crush the coal to the desired size, and supply the coal to the Unit 4 silos to satisfy plant usage requirements. The coal handling system will also be sized to serve existing Units 1, 2, and 3 by providing a separate stockout facility to store coal unloaded by the Unit 4 unloading facility and to provide a separate reclaim facility to reclaim coal designated for Units 1, 2, and 3. 1.3 Process Description Drawing 145491-1CHU-S2100 is the process flow diagram of the Coal Handling System. 1.3.1 System Operation. The new coal handling system at the Sutherland Plant will supply coal to the existing Units 1, 2 and 3 as well as the new Unit 4. The system will be designed to accommodate simultaneous car unloading, stacking and silo fill operations to Units 4 and be configured to provide sufficient redundancy for nonoperating equipment. Coal will be delivered to the power plant by unit train consisting of approximately 150 cars. Each of the rail cars will carry approximately 120 tons of coal. The coal received in the plant will be unloaded by a rotary car dumper at a rate of 4,000 TPH. The rotary car dumper will be equipped with a rail car positioner, hopper, grizzly and traveling hammermill for the breaking of oversize and frozen coal. The unloaded coal will be collected by the hopper and withdrawn by two belt feeders BF-1 and BF-2. Dust Collection System (DC) will control dust in the dumper building above the unloading hopper. The coal will be transferred from the feeders to unloading conveyor BC-1 which will take it to Transfer Tower TT-1. Belt conveyor BC-1 will be equipped with the as-received sampling system SMP-1 and 1/4 % accuracy belt scale BS-1. The discharge of conveyor BC-1 will be equipped with inline Magnetic Separator MS-1. At Transfer Tower TT-1, the coal would be directed to Belt Conveyor BC-4 which feeds Stacker/Reclaimer SR-1. Under normal operating conditions the unloaded coal will be stacked out by Stacker/Reclaimer SR-1 at 4,000 TPH. During reclaiming the boom conveyor of Stacker/Reclaimer SR-1 will be reversed to support a reclaim capacity of either 1,200 080307-145491 Interstate Power & Light Company Sutherland Unit 4 Air Permit Application TPH or 2400 TPH onto Conveyor Belt BC-4. The discharge point at the top of Stacker/Reclaimer SR-1 will be equipped with a motorized flow splitting gate, enabling the operator to split the material flow of 4,000 TPH into two separate streams, one stream would be sent directly to crushing and silo fill and the second stream going to stockout. In case of a Stacker/Reclaimer SR-1 failure, the unloaded coal will be stacked out at 4000 TPH by emergency stacking conveyor BC-2, equipped with telescopic chute CHE-1 onto a 13,300 ton capacity emergency pile. Depending on operating requirements, the coal from the emergency pile may be bulldozed directly into the yard storage or to the reclaim hopper RH-1, equipped with a variable frequency drive belt feeder BF-3 at a rate of 0 – 1200 TPH, and fed onto reclaim Conveyor BC-3 for stacking by SR-1 or sent directly to the plant as required. Belt Conveyor BC-3 will be 48” 1200 TPH and will be equipped with Belt Scale BS-2. The discharge of Conveyor BC-3 will be equipped with inline Magnetic Separator MS-2. Coal for existing Units 1, 2 and 3 will be fed from reclaim hoppers RH-4 and RH-5 with 400 TPH Belt Feeders BF-8 and BF-9 onto Belt Conveyor BC-5A, 30” 400 TPH. Belt Conveyor BC-5A will be equipped with Belt Scale BS-7. Belt Conveyor BC-5A will discharge onto Belt Conveyor BC-5B, 30” 400 TPH at the new Transfer Tower 3. Conveyor BC-5B will deliver coal to a new hopper, HPR-2, located over the existing hopper in the existing coal handling system for Units 1, 2, and 3. The new hopper will have a working capacity of 200 tons, be equipped with a cutoff gate, and feed the existing hopper. The new hopper, HPR-2, will also be provided with a side discharge chute that will be equipped with a cutoff gate. The side discharge chute and gate could be used to load coal trucks in the future. Should coal trucks be loaded in the future, an enclosed structure and dust control would be provided for loading operations. At the discharge point of Belt Conveyor BC-4, the coal will be directed through a 3-way flow diverting flop gate to allow the coal to be sent directly to the Crushers and Unit Silo Fill when SR-1 is reclaiming at 1200 or 2400 TPH, or onto Belt Conveyor BC-6 or Belt Conveyor BC-7 at a maximum rate of 4000 TPH and stock piled for blending during reclaiming operations. A flow splitter gate would located below one leg of the 3-way flop gate to allow a 2400 TPH flow to be split to feed Belt Conveyors BC-10 and BC-11, 1200 TPH each. Coal directed onto Belt Conveyor BC-6 will be stockpiled using Telescopic Chute CHE-2 and reclaimed through under pile Reclaim Hopper RH-2 equipped with Variable Frequency Drive Belt Feeder BF-4 at a rate from 0-2400 TPH onto reclaim Belt Conveyor BC-8, 60” 2400 TPH. Belt Conveyor BC-8 will be equipped with Belt Scale BS-3 to facilitate proportioning for blending operations. Belt Conveyor BC-8 will discharge into a flow splitting gate to allow a 2400 TPH flow to be split into two 1200 TPH flows and be directed to both Belt Conveyors BC-10 and BC-11 simultaneously for the crushing and unit silo fill operations. 080307-145491 Interstate Power & Light Company Sutherland Unit 4 Air Permit Application Coal directed onto Belt Conveyor BC-7 will be stockpiled using Telescopic Chute CHE-3 and reclaimed through under pile Reclaim Hopper RH-3 equipped with Variable Frequency Drive Belt Feeder BF-5 at a rate from 0-1200 TPH onto reclaim Belt Conveyor BC-9, 48” 1200 TPH. Belt Conveyor BC-9 will be equipped with Belt Scale BS-4 to facilitate proportioning for blending operations. Belt Conveyor BC-9 will discharge into a flow splitting gate to provide blending capability with coal from either BC-4 or BC-8. Belt Conveyors BC-10 and BC-11 will each be 48”, 1200 TPH and will feed coal to the Crusher Surge Bin SB-1 located inside the Crusher House, CH-1. Each of these conveyors will be equipped with Belt Scales BS-5 and BS-6. The discharge of these conveyors will be equipped with inline Magnetic Separators, MS-3 and MS-4. The surge bin will have two outlets, each equipped with a rack & pinion slide gate. Coal will be discharged from the crusher surge bin outlets using Variable Frequency Drive Belt Feeders BF-6 and BF-7, which will feed 1200 TPH Ring Granulator Crushers (2 x 100%), CR-1 and CR-2 respectively. The crusher house will contain a Dust Collection System (DC). Plant Conveyors BC-12 and BC-13 will each be 48”, 1200 TPH and will deliver crushed coal from Crusher House CH-1 to Transfer Tower TT-4. These two conveyors will each be equipped with metal detectors, Metal Detector MD-1 on Belt Conveyor BC-12 and Metal Detector MD-2 on Belt Conveyor BC-13. Belt Conveyors BC-12 and BC-13 will be equipped with swing arm as-fired sample cutters SMP-2 and SMP-3 which will collect the coal samples from the belt and send them to the modular sampling system house located at ground elevation. The discharge chutework of Conveyors BC-12 and BC-13 will be provided with motorized flop gates to provide complete cross-over redundancy to feed either of the two Tripper Conveyors BC-14 and BC-15. Tripper Conveyors BC-14 and BC-15 will each be 48”, 1200 TPH and will each deliver coal to a traveling tripper, Conveyor BC-14 to Traveling Tripper TRP-1 and Conveyor BC-15 to Traveling Tripper TRP-2. Each traveling tripper will be equipped with a single discharge chute and will deliver coal to any selected plant silo. Dust Collection System (DC) will provide dust control in Transfer Tower TT-4 and the coal silos. 1.3.2 Equipment Description. Train Positioner. The train positioner will be at the exit end of the dumper and capable of automatically positioning a train of 150 cars each weighing 286,000 lbs. to 315,000 lbs., and four (4) locomotives. The positioner will incorporate all necessary safety devices to prevent damage to the train and/or positioner in event of a power failure or emergency. 080307-145491 Interstate Power & Light Company Sutherland Unit 4 Air Permit Application The positioner will be equipped with a hydraulic cable tensioning device. The unit train will be under the control of the positioner arm or wheel chocks at all times. The positioner will incorporate entry truck type chocks to insure immobilization of the train during the offloading of the rotary coupled train. A set of exit hook and pawl chocks will be provided and used in conjunction with the entry chocks, to hold empty cars during the offloading of unit-rain and random cars. Rotary Railcar Dumper. The rotary car dumper will consist of a rotating cradle of suitable size and structural rigidity resting on a double set of trunnion wheels mounted on foundations. The dumper will be driven by an electromechanically driven system proven suitable for the type of services and duty specified. The dumper will include a movable platen, stationary spill girder and gravity setting mechanical car clamp system. The dumper will be designed for unit car unloading. The car dumper will consist of the following components: Drive Mechanism, Rack & Pinion. The rotation of the dumper will be accomplished by a single motor connected through a flexible coupling to speed reducer unit. The low speed output shafts of the speed reducer will be flange coupled to line shafts, which will then be coupled to the pinion strands compete with drive rack gears located on each end ring. Rotating Cradle. The rotating cradle will be a structural steel frame incorporating two end rings and supported on a total of eight wheels, four under each end ring. The rotating part of the dumper will consist of a rigid structure, capable of withstanding as an integrated unit, all forces resulting from its function of inverting railcars. Platen. The platen will be a structural steel table carrying car rails and supported on rollers. The connection of the platen to the rotating cradle will be such that the platen will be suitably supported and guided in the event the cradle is rotated when there is no car in the dumper. Bucket Wheel Stacker/Reclaimer. The bucket wheel stacker/reclaimer will be rail mounted hinged bascule, single counterbalanced slewing/luffing boom, cell-less bucket wheel type stacker/reclaimers with retractable trailer including an elevating conveyor, capable of both automatic and manual stacking to and reclaiming from double stockpiles located at both sides of its rail track. The following are the major components of the bucket wheel stacker/reclaimer. 080307-145491 Interstate Power & Light Company Sutherland Unit 4 Air Permit Application Fixed Gantry. The fixed gantry will have a travel mechanism with flanged wheels 50 % of which will be driven by electric motors and gear reducers. The slewing mechanism will be mounted on the fixed gantry structure, incorporating large-diameter anti-friction bearing with ring gear including its drive mechanism and slewing ring locking assembly. Slewing drives will be variable frequency drives. Rotating Structure. The rotating structure will be mounted on the slewing ring (bearing) enabling the entire structure to rotate. The rotating structure will support boom with associated boom conveyor, operators cab, bucket wheel and the counterweight boom. The entire boom assembly will be hinge mounted on the rotating structure and can be raised and lowered with hydraulic lift mechanism mounted on the rotating structure. Belt Conveyors. The conveyor subcomponents include the conveyor belt, idlers, pulleys, take-ups, bearings, belt cleaners, drives, motors, drive base-plates, walkways, stringers, supports, head and tail frames, foundations, and all other appurtenances necessary for each of the individual conveyors. The elevated portion of all conveyors between structures, except for Conveyors BC-5A and BC-5B, will be supported by enclosed box type trusses with solid floors. A walkway on one side of the conveyors will be furnished for single conveyors. One walkway will be provided for dual conveyors less than 48-inches in width. Three walkways will be provided for dual conveyors 48-inches wide and greater. The conveyor trusses will be suitable for use with a washdown system. Telescopic Chute. A telescopic chute will be provided at the discharge end of the stock out conveyors to control dust emissions during stock piling of the coal. The telescopic chute will consist of steel fabricated concentric tubular sections telescoping into each other as required for stock piling of coal into a conical pile. The telescoping sections of the chute will be lifted or lowered by a motorized winch. Belt Feeders. The function of the belt feeders will be to receive coal from the hoppers located above the feeders and feed to the belt conveyors located below the feeders at a fixed or variable rate. Coal Crushers. The coal crushers will be ring granulator type crushers which will be able to produce 1200 TPH of 1-1/4 inch product while receiving raw coal of 3 x 0 inches. The crushers will have a rugged heavy-duty dust-tight frame of welded or cast steel construction. All internal wear parts will be made of manufacturer’s recommended steel and will be replaceable. The main shaft will be manufacturer’s recommended steel and will be equipped with heavy-duty roller antifriction bearings arranged for grease lubrication. The crushers will be equipped with externally adjustable devices to permit control of product size and to compensate for wear. Traveling Trippers. Traveling trippers will be of the motor driven, self-propelled, reversible, automatic and manually positioned type, designed to straddle the tripper belt conveyors and travel over the in-plant storage/ mill silos to any desired discharge 080307-145491 Interstate Power & Light Company Sutherland Unit 4 Air Permit Application position. Each tripper will be rated for the conveyor capacity it serves. The tripper machine will be equipped with single discharge chute for discharging the coal. The tensioned over-the-chute sealing belt systems will be furnished to seal the bunker slot openings. Metal Detectors. The metal detectors will be of the electronic type which will continuously monitor the conveyor belts for tramp metals. The metal detectors will be designed to detect all types of tramp metal, whether ferrous, nonferrous, magnetic, or nonmagnetic, from the entire width of the material being conveyed on the conveyor belt. Magnetic Separators. The magnetic separator will be the overhead, manual cleaning suspended type or self-cleaning, belted in-line, type. The magnetic separator will be housed completely inside dust covers. The self cleaning magnetic separator will be positioned above and forward of the conveyor head pulley. The magnet will be sloped towards a tramp iron chute. The tramp iron chute will transport tramp iron to a collection box at grade. Belt Scales. The primary function of the belt scale will be for feed rate control and material inventory monitoring. The belt scales will be the 3 or 4-idler precision digital electronic type with solid-state circuitry and built-in, self-testing devices. The scales will also be provided with test weights for self calibration. Each belt scale will use an environmentally sealed, temperature-compensated, load-sensing device and weigh bridge. The scales will weigh and totalize to a value within either 1/4 % or 1/2 % of the test load at flow rates between 25% and 100% of the scale system’s calibrated capacity. 080307-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application 1.0 System Description 1.1 System Identification – Fly Ash Handling 1.2 Function The Fly Ash Handling system is comprised of two separate systems. The Saleable Fly Ash Handling System removes fly ash from the ESP hoppers and transfers it to a saleable fly ash storage silo or a winter fly ash storage building via a continuously operating pneumatic vacuum and vacuum/pressure conveying system. The Waste Fly Ash Handling System removes fly ash from the fabric filter hoppers, air heater hoppers, SCR hoppers, and economizer hoppers and transfers it via a continuously operating pneumatic vacuum conveying system to a fly ash waste storage silo. The hopper fluidizing system for the fabric filter is not covered in this system definition. The saleable fly ash silo will be equipped with a silo bottom aeration system and fluidized outlet hopper. Fly ash from the saleable storage silo will be loaded into closed ash hauling trucks or railcars or conditioned and loaded into open dump trucks for placement in a landfill, via a dry telescoping spout. A combination truck or rail scale capable of weighing both carriers will be provided for the saleable fly ash silo. The fly ash waste storage silo will be equipped with a silo bottom aeration system and fluidized outlet hopper. Fly ash from the waste storage silo will be conditioned and loaded into open dump trucks for placement in a landfill. The fly ash waste silo will also be equipped with a dry telescoping spout for loading into closed ash hauling trucks. The winter fly ash storage building will be equipped with a pressurized conveying system to convey ash from the ESP vacuum filter/separator hopper to the building. A network of pressure conveying line branches will be provided to distribute saleable ash within the building. To recover the ash from the building, a recovery air gravity conveyor system will be provided to promote ash flow into a below grade recovery hopper. The recovery air gravity conveyor system will work in conjunction with a front end loader. A mechanical conveying system will transfer ash from the recovery hopper to a truck load-out system. A truck scale will be provided for the winter storage building truck load-out system. Dust collection and ash return equipment will be included to keep the building under negative pressure. 1.3 Process Description 1.3.1 Saleable Fly Ash Conveying System 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application The Saleable Fly Ash Handling System will service all unit ESP hoppers, one saleable fly ash storage silo and one fly ash winter storage building as shown in process flow diagram M2022A. Each collection point in the fly ash handling system will be tied into a pneumatic vacuum conveying system via ash intake valves arranged in a straight branch line off the main conveying lines. The conveying system will sequentially remove fly ash from the ESP hoppers and transfer the material to either the saleable fly ash storage silo or the winter storage building via a pressure conveying system. Each ESP hopper will be equipped with a manual hopper isolation valve and an automatic material intake valve. The automatic material intake valve isolates the hopper being emptied and provides a controlled flow of ash into the conveyor line. Each valve will be arranged for air-electric operation and will include replaceable, abrasion resistant components. Two vacuum filter/separators (2 X 100%) located on top of the saleable fly ash storage silo will receive and transfer the material to the saleable fly ash storage silo via a double dump airlock valves. A third vacuum filter/separator (1 x 100%) located at ground level next to the winter storage building will receive and transfer the ash into the winter storage building via a pressure pneumatic conveying system for future recovery into dry ash trucks. Each vacuum filter/separator on the saleable fly ash silo will consist of a continuous operating filter section with filter bags, pulse jet filter bag cleaning system, integral surge hopper and double dump airlock valve assembly for discharge into the silo. The vacuum filter/separator for the winter fly ash storage building will consist of a continuous operating filter section with filter bags, pulse jet filter bag cleaning system, integral surge hopper and a pressure airlock pneumatic conveyor to convey the ash to the winter storage building. Inside the building, a pressure conveying line will be provided with branches to direct the ash to various areas of the building. Each branch will be equipped with an automatic isolation valve. A dust detector will be furnished to detect broken filter bags and prevent intrusion of ash into the exhausters. Air intake heaters will be provided at the intake end of the ESP conveying line branches. Automatic vacuum breaker valves will also be furnished on the mechanical exhauster piping of each vacuum filter/separator. Two (2 X 100%) mechanical exhausters will be furnished for the vacuum conveying system. Each exhauster will be designed to supply motive air to convey the ash at the specified rate. One (1 X 100%) pressure blower will be furnished for the pressure conveying system to the winter storage building. The pressure blower will be designed to supply motive air to convey the ash at the specified rate. Two pneumatic conveying lines will convey material from the ESP branch lines to each filter/separator. The two conveying lines will be capable of transporting ash to the saleable fly ash storage silo or to the winter storage building pressure conveying/distribution system. One conveying line will be provided to convey material from the pressure airlock to the winter storage building including a distribution system with automatic valves to direct ash to various areas of the building. 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application Branch segregating knife gate valves will be furnished on each branch line in the pneumatic conveying system. These valves will be of the automatic, abrasion resistant knife gate type, actuated by air cylinder operators. The conveying lines will be designed to maintain the air velocity above the material saltation velocity, minimize bends and provide adequate access for clearing out lines. The system will be able to start and stop conveying with ash in the conveying pipelines. All piping, elbows, laterals, and other fittings used on vacuum conveying pipelines will have minimum hardness ratings designed for ash conveying service. The saleable fly ash storage silo will be designed to receive and temporarily store saleable fly ash from the conveying system. The silo will have pass through access for ash discharge to railcars and trucks. The capacity of the silo will allow for up to four days of material storage based on the unit running at MCR conditions while burning worst case fuel. The saleable fly ash storage silo will be equipped with a fluidizing system to promote ash discharge during unloading. The silo will also include a bin vent filter, material level sensors and equipment access. The silo will be equipped with a dry fly ash load out station. This station will consist of discharge valves, telescopic chute assembly, vent fan, vent return valve, vent piping and pendant control. A combination truck or rail scale will be provided below the silo. 1.3.2 Waste Fly Ash Conveying System The Waste Fly Ash Handling System will service all unit fabric filter hoppers, all air heater hoppers, all SCR hoppers, all economizer hoppers and one fly ash waste storage silo as shown in process flow diagram M2022C. Each collection point in the waste fly ash handling system will be tied into a pneumatic vacuum conveying system via ash intake valves arranged in a straight branch line off the main conveying lines. The conveying system will sequentially remove fly ash from the hoppers and transfer the material to the fly ash waste storage silo. Each hopper will be equipped with a manual hopper isolation valve and an automatic material intake valve. The automatic material intake valve isolates the hopper being emptied and provides a controlled flow of ash into the conveyor line. Each valve will be arranged for air-electric operation and will include replaceable, abrasion resistant components. Two vacuum filter/separators (2 X 100%) located on top of the fly ash waste storage silo will receive and transfer the material to the fly ash waste storage silo via a double dump airlock valves. Each vacuum filter/separator on the fly ash waste silo will consist of a continuous operating filter section with filter bags, pulse jet filter bag cleaning system, integral surge hopper and double dump airlock valve assembly for discharge into the silo. A dust detector will be furnished to detect broken filter bags and prevent intrusion of ash into the exhausters. 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application Air intake heaters will be provided at the intake end of each fabric filter conveying line branch. Automatic vacuum breaker valves will also be furnished on the mechanical exhauster piping of each vacuum filter/separator. Two (2 X 100%) mechanical exhausters will be furnished for the vacuum conveying system. Each exhauster will be designed to supply motive air to convey the ash at the specified rate. Two pneumatic conveying lines will convey material from the fabric filter branch lines to each filter/separator. Each row of fabric filter hoppers will have an independent conveying line. The two conveying lines will be capable of transporting ash to the fly ash waste storage silo. Pneumatic conveying lines will convey material from the air heater hoppers, SCR hoppers and economizer hoppers to each filter/separator. These conveying lines will tie into the conveying lines from the fabric filter. Branch segregating knife gate valves will be furnished on each branch line in the pneumatic conveying system. These valves will be of the automatic, abrasion resistant knife gate type, actuated by air cylinder operators. The conveying lines will be designed to maintain the air velocity above the material saltation velocity, minimize bends and provide adequate access for clearing out lines. The system will be able to start and stop conveying with ash in the conveying pipelines. All piping, elbows, laterals, and other fittings used on vacuum conveying pipelines will have minimum hardness ratings designed for ash conveying service. The fly ash waste storage silo will be designed to receive and temporarily store fly ash from the conveying system. The silo will have pass through access for ash discharge to trucks. The capacity of the silo will allow for up to four days of material storage based on the unit running at MCR conditions while burning worst case fuel. The fly ash waste storage silo will be equipped with a fluidizing system to promote ash discharge during unloading. The silo will also include a bin vent filter, material level sensors and equipment access. Ash conditioning pugmills (2 x 100%) will be provided as the primary means of ash unloading from the fly ash storage silo. Flow control valves will be provided to meter the ash and water into the pugmill. The silo will also be equipped with a dry fly ash load out station. This station will consist of discharge valves, telescopic chute assembly, vent fan, vent return valve, vent piping and pendant control. 1.3.3 Saleable Fly Ash Storage Silo, Fluidizing System and Discharge System A saleable fly ash storage silo will be supplied to receive and temporarily store saleable fly ash from the vacuum conveying system. The capacity of the silo will allow for up to 4 days of saleable ash storage, including allowances for angle of repose and freeboard clearance, based on the unit running at MCR conditions while burning worst case fuel. 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application The roof of the silo will be equipped with two filter/separators, a bin vent filter, a material level transmitter and material high level switches. A pressure/vacuum relief assembly, along with a roof manway access hatch will also be included on the roof. The silo will be arranged with parallel truck or railcar pass-through access and will include platforms at both the roof elevation and the unloading floor elevation. A single jib crane will be provided atop the silo. The silo will be of a flat-bottom design utilizing a floor fluidizing system to promote ash flow toward the silo discharge hopper(s) during unloading. The silo fluidizing system will consist of a network of floor fluidizer diffuser assemblies. The area of fluidizing coverage will be no less than 12 percent of the entire silo floor area. Fluidizing blowers (one operating, one standby), air heaters, piping, valves and flow control accessories will be furnished for the silo. Ash conditioning equipment will be provided as the primary means of ash unloading at the silo. Two ash conditioning pugmills (one operating, one standby) will be provided on the enclosed unloading floor under the silo. Manual and air cylinder operated valves will be provided to isolate the unloading equipment from the silo. An ash metering device (either automatic valve with positioner and feedback loop or rotary vane feeder) will control the flow of fly ash into the pugmill. A pressure regulating valve and flow meter will control the flow of water into the pug mill. To accommodate fly ash sales, the fly ash silo will be equipped with a dry load out station which consists of a telescopic chute assembly, silo isolation valve, automatic valve, vent fan, vent return valve, piping and a pendant control. The silo will also have pass through access with a combination truck or rail scale for weighed ash discharge to railcars or trucks. The silo unloading operation will be automated to the maximum practical extent. Local control stations will be provided to allow for the activation and control of the truck filling operation by the truck driver, including minor adjustments to ash/water feed rates. The truck loading area beneath the silo will be equipped with wash down facilities. Truck wash down water will drain to a local saleable fly ash silo drainage sump. Water collected in the saleable fly ash silo drain sump will be periodically pumped to the waste water collection pond by one of two full capacity sump pumps (one operating, one standby). 1.3.4 Fly Ash Waste Storage Silo, Fluidizing System and Discharge System A fly ash waste storage silo will be supplied to receive and temporarily store fly ash from the vacuum conveying system. The capacity of the silo will allow for up to 4 days of ash storage, including allowances for angle of repose and freeboard clearance, based on the unit running at MCR conditions while burning worst case fuel. 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application The roof of the silo will be equipped with two filter/separators, a bin vent filter, a material level transmitter and material high level switches. A pressure/vacuum relief assembly, along with a roof manway access hatch will also be included on the roof. The silo will be arranged with parallel truck pass-through access and will include platforms at both the roof elevation and the unloading floor elevation. A single jib crane will be provided atop the silo. The silo will be of a flat-bottom design utilizing a floor fluidizing system to promote ash flow toward the silo discharge hopper(s) during unloading. The silo fluidizing system will consist of a network of floor fluidizer diffuser assemblies. The area of fluidizing coverage will be no less than 12 percent of the entire silo floor area. Fluidizing blowers (one operating, one standby), air heaters, piping, valves and flow control accessories will be furnished for the silo. Ash conditioning equipment will be provided as the primary means of ash unloading at the waste silo. Two ash conditioning pugmills (one operating, one standby) will be provided on the enclosed unloading floor under the silo. Manual and air cylinder operated valves will be provided to isolate the unloading equipment from the silo. An ash metering device (either automatic valve with positioner and feedback loop or rotary vane feeder) will control the flow of fly ash into the pugmill. A pressure regulating valve and flow meter will control the flow of water into the pug mill. The fly ash waste silo will also be equipped with a dry load out station which consists of a telescopic chute assembly, silo isolation valve, automatic valve, vent fan, vent return valve, piping and a pendant control. The waste silo unloading operations (both dry and conditioned fly ash) will be automated to the maximum practical extent. Local control stations will be provided to allow for the activation and control of the truck filling operation by the truck driver, including minor adjustments to ash/water feed rates. The truck loading area beneath the silo will be equipped with wash down facilities. Truck wash down water will drain to a local fly ash waste silo drainage sump. Water collected in the fly ash waste silo drain sump will be periodically pumped to the waste water collection pond by one of two full capacity sump pumps (one operating, one standby). 1.3.5 Fly Ash Winter Storage Building, Fluidizing System and Load-out System A winter storage building will be supplied to receive and temporarily store saleable fly ash from the ESP vacuum/pressure conveying system. The fly ash storage capacity of the building will be 30,000 tons. The building will be constructed of a concrete base, concrete partial wall, structural steel frame, steel wall panels and steel roof panel 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application sections. Access and platforms will be provided for maintenance of equipment inside the building. Access doors for front end loading equipment will be provided. To fill the building, one vacuum filter/separator located at ground level will receive ash from the ESP hoppers and discharge it through a pressure airlock into a pressure conveying line with multiple branches to distribute the ash within the building. Each branch will be equipped with an automatic isolation valve. Two dust collectors with ID fans will be provided to pull dust laden air from inside the building and exhaust the filtered air to atmosphere. The dust collector will maintain the building under a slight negative pressure. A rotary airlock and screw conveyor will be provided at the discharge of the dust collector hopper to convey accumulated dust back into the building. To remove the ash from the building an air gravity conveyor will be supplied at floor level to promote ash flow into an ash recovery hopper in conjunction with a front end loader. Ash collected in the recovery hopper will be conveyed by screw conveyor to the truck load-out area. The screw conveyor will discharge into a bucket elevator which will convey the material up into a dry load out station positioned over a truck drive-through. The load-out station consists of a telescopic chute assembly, automatic isolation valve, vent return valve, piping to the building dust collector system and a pendant control. A truck scale for the truck load-out system will also be provided. 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application 1.0 System Description 1.1 System Identification – FGD Solids 1.2 Function This document provides basic function and description for the solids material handling of the flue gas desulfurization (FGD) addition. The function of the Flue Gas Desulfurization (FGD) Solids System is to collect and dewater the solids produced within the Flue Gas Desulfurization System, and transport the dewatered solids to an enclosed storage building or an emergency stock pile. The quality of FGD solids produced will be of “wallboard” grade gypsum. 1.3 Process Description There will be two 100 percent FGD Solids System trains housed in a common building. The dewatered FGD solids will be discharged from the vacuum filters onto one of the two FGD solids product conveyors GC-1A or 1B through motorized diverter gates. Conveyor GC-1A will transfer the FGD solids to a transfer conveyor GC-2. The transfer conveyor GC-2 will transfer the solids to an elevated shuttle belt conveyor GC-3, located inside the solids storage building. The shuttle conveyor will prepare a series of conical or elongated piles of solids inside the building. Finally the FGD solids from the storage building as well as the emergency stock pile will be loaded onto trucks by mobile equipment (by others). In order to prevent fine solids from accumulating in the FGD recycle tanks, a small flow stream will be taken from the hydrocyclone classifier overflow to be blown down to a local drain sump that will be equipped with an agitator to keep the solids in suspension and to be removed later using sump pumps that will transfer the sump water to the Wastewater Collection and Treatment System. Classifiers will be capable of being backflushed or serviced on line to remove any pluggage that occurs. 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application 1.0 System Description 1.1 System Identification – Biomass Handling 1.2 Function The biomass handling system will provide the necessary functions to receive, process and convey the processed biomass to the boiler. The design and process described herein are based on the principles and extensive operating experience derived from the biomass fuel operations at IPL’s Ottumwa Generating Station. 1.3 Process Description The biomass fuel is harvested into “bales,” which are of approximate dimensions of 3 ft by 3 ft by 8 ft (which weigh approximately 700 pounds) or 3 ft by 4 ft by 8 ft (which weigh approximately 1,000 pounds). The bales will be delivered to the site on flatbed trailers with 54 (3 ft by 3 ft by 8 ft) bales or 36 (3 ft by 4 ft by 8 ft) bales on each trailer. The bales will then be unloaded with a forklift and piled in the storage building. The bales will be picked up with the forklift and placed on a conveyor. The binding twine will automatically be cut and retrieved from the bale prior to the bale feeding into the “debaler,” a hammermill, which will mill the biomass before sending it through a sizing screen. After passing through the screen, the biomass will be collected and conveyed to the “eliminator”, an attrition mill configured to reduce the biomass to the selected size for pneumatic conveying to the boiler. Prior to the biomass reaching the attrition mill, a magnetic belt traversing the feed conveyor, will collect all foreign metal objects captured during the baling process. A baghouse and separator will pull the biomass material from the eliminator grinder, where the heavy material will drop down a surge bin, and the lighter material will move into the baghouse for collection. The biomass material will then be removed from the baghouse through the tube conveyor to storage surge bins for pneumatic transport to the boiler. All of the equipment downstream of the eliminator grinder will be kept at a slight negative pressure for dust control. 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application 1.0 System Description 1.1 System Identification – Bottom Ash 1.2 Function The Bottom Ash System collects and removes bottom ash from the bottom of the steam generator furnace. The system also collects coal pulverizer (pyrites) rejects. All are gathered in the upper trough of the Submerged Scraper Conveyor (SSC) and conveyed to a three walled ash storage bunker for periodic truck transport to a landfill. 1.3 Process Description A mechanical system for collection, removal, dewatering and transport of bottom ash will be provided. The system will also provide for the removal and transport of DeNOX ash, economizer ash, coal pulverizer rejects and storage bunker drain effluent. Boiler seal plates, which extend below the SSC upper trough water level, will provide a pressure seal for the boiler. Bottom ash produced in the steam generator furnace will fall into the water-filled upper trough of the SSC. DeNOX and Economizer ash will be transferred via dry drag chain conveyors to the SSC outside of the seal plates. Rejects from the coal pulverizers will be sluiced to the SSC outside of the seal plates. The collected ash and coal pulverizer rejects in the upper trough of the SSC will be conveyed up a dewatering slope and discharged into a three-sided concrete storage bunker located indoors at the ground level, from where it will be loaded directly into ash dump trucks for off-site sales or transport to a landfill. The Bottom Ash System will also be designed to remove coal pulverizer rejects which represent 1.0 percent, by weight of the as-fired coal. During normal operation of the steam generator, each rejects hopper will continuously receive material rejected from the coal pulverizer. Material will accumulate in each rejects hopper until transferred to the SSC. During the transfer process, each coal pulverizer rejects jet pump will be operated in sequence to sluice the rejects from its respective hopper through a common transport line to the SSC. The rejects will enter the SSC at an enclosed area of the conveyor trough outside of the steam generator seal plates or as required to prevent splashing of water onto the lower boiler tubes. Each rejects hopper will be a self-supported steel tank mounted near the coal pulverizer rejects outlet and will be provided with a jet pump for intermittent hydraulic transfer of the rejects to the SSC. The coal pulverizer rejects system will also be designed for hopper unloading following a mill trip. Sluice water for transporting coal pulverizer rejects will be supplied from two sluice water pumps. One primary pump and one standby pump will be provided. The sluice water pumps will supply the required flow and pressure to the jet pumps to transport the coal pulverizer rejects from the hoppers to the SSC. The sluice water pumps will take their suction from the upper trough of the SSC (outside the seal plates). 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application 1.0 System Description 1.1 System Identification – Chimney 1.2 Function The function of the Chimney is to discharge combustion gas to the atmosphere at a sufficient elevation to provide adequate diffusion as required by the air permit. 1.3 Description The Chimney shall consist of a reinforced concrete shell surrounding, protecting, and supporting a liner carrying flue gas for atmospheric dispersal. It consists of the following four components: • Foundation--Shall provide support and carry the loads to the subsurface. • Structural Shell--Shall provide support for the contained liner and systems and stability for the entire structure. • Access--Shall provide means of ingress and egress and allow for access to the contained systems through doors, service car, ladders, and platforms. • Drains and Plumbing--Shall provide wastewater drains at the base of the Chimney. The Chimney shall occupy the area at the south end of the power block downstream of the AQCS Scrubber Module. It shall be founded on a reinforced concrete foundation supported on piles. The gas path shall consist of a fiberglass reinforced plastic (RFP) liner extending from the inlet breeching connected to the ductwork downstream of the Scrubber Module to the chimney outlet. An expansion joint shall separate the upstream ductwork from the breeching penetrating the shell and liner. The base of the liner shall be elevated to match the ductwork elevation. Appurtenances shall be included to result in a complete gas dispersal system. The shell shall contain a construction opening (to be fitted with a motorized roll up door following construction) and a personnel door accessing the bottom of the chimney. Interior steel and grating platforms shall be provided near the midpoint and at the top of the chimney for access and operation of continuous emissions monitoring equipment and service of obstruction lighting. An equipment hoist shall be provided to move materials to the Monitoring Platform on the inside of the shell. A ladder, with required standoffs and safety climb apparatus, and a rack-and-pinion vertical lift service car, rated at 900 pound capacity operating at a minimum of 120 fpm, shall be provided on the shell interior for access to the platforms. The vertical lift service car shall include a manual lowering device for emergency operation. The Chimney shall be provided with aviation 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application obstruction lighting in accordance with FAA requirements mounted on swing-in doors for light maintenance from the interior platforms. An electrical area shall be provided at the base of the Chimney to contain the power and control system for the aviation lighting. The base of the liner shall contain a drain and a piping system leading to a drain in the Chimney foundation for removal of collected rainwater to the plant wastewater system. The liner shall contain an ash cleanout port at its base. Ventilation of the annulaus space shall be provided by louvers with bird screens. The final size, arrangement, and details of the Chimney shall be determined during the detailed design based on load requirements, equipment enclosure and access, and regulatory and permitting restrictions. 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application 1.0 System Description 1.1 System Identification – Emergency Generation 1.2 Function The Emergency Generation System shall provide power for essential loads following the loss of auxiliary power. The Emergency Diesel Generator (EDG) shall be supplied to provide emergency shutdown power at 480 volt ac upon the loss of normal 480 volt ac power. The EDG shall be connected to BOP/Essential Area Load Centers and provide a backup power feed to the essential 480 volt ac motor control center, from which it shall distribute power to loads such as the turbine turning gear, the turning gear oil pump, jacking oil pumps (if any), hydrogen seal oil pump, boiler fans oil pumps (if any), boiler feed pump, lubricating oil pumps, plant control room lighting, and stack obstruction lighting. The EDG backup operation shall be automatic. Upon loss of normal 480 volt ac power, the automation system shall automatically start the EDG, open the two main LC breakers and close the EDG and tie breakers. Transfer from EDG back to normal 480 volt ac power shall be closed transition. The EDG shall require an electric operated maintenance circuit breaker connected to a 480 volt load bank. The EDG shall be required to be tested periodically, and this electric breaker and load bank shall allow the starting and testing of the EDG off line without affecting the normal operation of BOP/Essential LCs 11 and 21. 1.3 Process Description The emergency diesel generator consists of a prime mover and generator. In the event of the loss of auxiliary power, ac power shall be supplied by the emergency generator. The emergency generator shall consist of a 480 volt, three-phase, 60 hertz generator driven by a direct coupled diesel engine. The emergency diesel generator shall be connected to a 480 volt secondary unit substation that shall feed the emergency motor control centers (MCCs) supplying power to selected unit and common emergency loads. The emergency diesel generator will be periodically tested to confirm its ready-to-start condition. It will be manually started, brought up to speed and voltage, synchronized onto a 480 volt bus, and loaded. Following completion of the test, the emergency generator will be unloaded and manually removed from service. The number of buses connected to the emergency diesel generator shall be limited. Equipment requiring standby generator power shall be connected to selected 480 volt 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application buses. Loads shall be limited to those designated “essential” and “emergency,” and connection of those loads shall be accomplished by closing a minimum number of 480 volt bus main breakers. The emergency diesel generator shall be provided with its own “Black Start” capability, but shall not be sized to provide this capability for the units. The emergency diesel generator shall be capable of being started, synchronized to the system, and loaded to its full rating without dependence on ac auxiliary power. The fuel governing system shall be capable of isochronal or droop type speed regulation. The generator design shall allow parallel operation for testing purposes. Bumpless transfer schemes shall be used when switching between isochronal and droop modes. Remote control for the emergency diesel generator shall be provided from the Main Control Room. The operator interface shall include indication and alarms for operator monitoring of relevant parameters and conditions, and operator controls for remotely synchronizing and operating the generator, and manually adjusting the fuel governor and voltage regulator. The emergency diesel generator equipment shall be mounted in a weather proof, sound attenuating enclosure on a double-walled fuel tank (belly tank). All transformers, motor starters, electrical equipment, and auxiliary equipment to locally operate the generator set shall be furnished and mounted within the confines of the steel base. All interconnecting piping and wiring for steel base mounted equipment shall be factory installed. Three 2hole grounding pads shall be furnished and factory installed: one bronze pad attached to the generator frame adjacent to the main lead terminal housing and two pads on each end of the generator skid frame. The muffler shall be on top of the enclosure. Stack height shall comply with permit. The emergency diesel generator shall be sized according to the continuous emergency load requirements and the motor starting requirements of the generating station during a shutdown. The emergency load shall consist of loads required for maintaining a soft shutdown of the generation unit’s turbine generator, steam generator, and scrubber. The emergency generator shall be sized so that the bus voltage does not drop below 90 percent when the largest motor is started with all other loads in operation. These emergency loads shall include, but not be limited to, the following: • 125 VDC system battery chargers. • Generator seal oil pumps. • Turbine bearing oil pumps. • Turbine turning gear. • Elevators. 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application • Obstruction lighting. • Emergency quench pumps. • Emergency lighting systems. • Control building. • DCS equipment rooms. The generator and exciter shall be designed and constructed in accordance with the following conditions: Design Condition Minimum net continuous rated capacity at 80 percent power factor 2,000 kW (standby rating) Location Outdoors; 40° C, maximum Rated voltage 480 wye Electrical output characteristics 3-phase, 3-wire, 60 hertz Generator speed, rpm 1,800 Type of excitation system Static “Black Start” capability Station auxiliary ac power not available for startup Neutral grounding resistor Rated 27.7 ohms, 600 volts nominal The armature and field windings shall be coated with a fungus resistant resin. The insulation system of the armature and field shall be Class F (155° C hot spot). Construction shall include damper windings and shall be of the salient-pole type. The specified exciter shall enable the generator to sustain 300 percent of rated full load current for 10 seconds during a fault condition. The diesel engine shall be suitable for standby service and sized to drive the emergency generator at rated output under the following design conditions: • 40° C maximum ambient cooling air through the radiator(s). • 50° C maximum ambient air temperature around the engine. • Elevation above sea level of approximately 860 feet. • Glycol in cooling system suitable for an ambient temperature of - 30° F (-34.4° C). 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application • Outdoor location. • The exhaust system of the diesel engine having a silencer or muffler as specified. • The fuel tank sized to provide sufficient fuel for 24 hours of continuous operation at the expected plant load. The base fuel tank shall be double walled satisfying the secondary containment requirements found in the Environmental Protection Administration 40 CFR 112.7(c). The tank shall have overfill prevention measures that include an overfill alarm and an automatic flow restrictor or flow shutoff. 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application 1.0 System Description 1.1 System Identification – Fencing and Security 1.2 Function The Fencing and Security System controls access into the site. The system shall also control access to the existing Unit 1, 2 & 3 while allowing free movement between the existing Units and Unit 4. 1.3 Description General Arrangement Drawing 145491-DS-1000 and Site Arrangement Drawing 145491DS-1001 show the proposed Fencing System layout. A new perimeter fence and motor-operated slide gates shall be provided around the site as indicated on General Arrangement Drawing 145491-DS-1000. A new fence and swing gates shall be provided around the switchyard as indicated on General Arrangement Drawing 145491-DS-1000 and Site Arrangement Drawing 145491-DS1001. Fencing and gates shall be composed of galvanized chain link mesh and posts and meet the appropriate material ASTM Standard Specifications. Fencing shall include top rail, bottom rail, bottom tension wire and three strands of barbed wire mounted on 45-degree extension arms. Chain link mesh shall be six feet tall. Slide gates shall be capable of remote operation and swing gates shall be manually operated. 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application 1.0 System Description 1.1 System Identification – Gate Station Heater 1.2 Function Natural gas will be used during start up for both the new and existing boilers at the SGS, and will be the primary fuel for the new auxiliary boiler. The natural gas supply to the SGS will arrive via a high pressure natural gas pipeline. As the natural gas is extracted from the high pressure pipeline across a pressure reducing control valve, the reduction in pressure will naturally cool the gas below the dew point temperature and to a temperature too low to be combusted in the boilers. As such, a natural gas fired gate station heater will be used to heat the natural gas upstream of the pressure reducing device to prevent the gas from dropping below the recommended operating temperature. The gate station heater will have a maximum heat input limit of 3 MBtu/h and designed for continuous operation. 1.3 Process Description The Gate Station Heater receives high pressure natural gas from a single interface point for the natural gas supply system provided by the Owner. The heater uses an indirect fired heating process and an intermediate heating fluid. In this process, natural gas is burned and the resulting hot combustion gases flow through fire tubes located inside the lower portion of a large pressure vessel where the heat is transferred to the water/ethylene glycol mixture surrounding the fire tubes. The combustion gases will be exhausted to a stack after exiting the end of the fire tubes. The surrounding fluid will then circulate up to the tubes carrying the natural gas to be heated. These tubes are located in the upper portion of the vessel and receive heat from the hot fluid circulating over the natural gas tubes. The cooled fluid will then flow back to the bottom of the vessel. The hot fuel gas is then reduced in pressure and regulated to 125 psig. Fuel gas is provided to the auxiliary boiler and to the steam generator ignitors. 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application 1.0 System Description 1.1 System Identification – Limestone Handling System 1.2 Function The function of the Limestone Handling System will be to receive bulk limestone by bottom dump hopper rail cars with an alternate by truck, to provide a means to stock out and store the limestone in an active storage pile, and to provide reclaim capacity to satisfy plant usage requirements. 1.3 Process Description 1.3.1 System Operation: Bulk limestone will be delivered by either bottom dump hopper rail cars or dump trucks and will be unloaded into the limestone unloading hopper, HPR-1. Belt feeders FDR-1 & 2 will receive limestone from unloading hopper outlets and transfer it to the receiving conveyor CVY-1 which will transfer the material at a rate of 600 TPH to the limestone pile through a telescopic chute CHE-1. The conical shaped pile will have a total capacity equivalent to 7-days use. The limestone pile will be enclosed by a covered steel structure to protect the limestone from the weather. The limestone will be reclaimed from this storage pile by two underground belt feeders located below the vibrating drawdown hoppers which will feed the same onto the reclaim conveyor CVY-2. The reclaim conveyor will transfer the limestone at a rate of 400 TPH to the distribution/silo fill conveyor CVY-3, which will be running on top of the two limestone silos of Unit 4. The reclaim conveyor will discharge the limestone into a twoway chute with motorized diverter gate, GAT-1. One leg of this chute will be used to fill the limestone silo 1 and the other leg will transfer the limestone to the distribution/silo fill conveyor CVY-3 to fill the silo 2 of Unit 4. The limestone reclaiming and silo fill system will operate as needed basis, to fill the limestone silos. During the operation of the limestone mills, a silo low level alarm will trigger either an automatic or an operator controlled start function of the reclaim and silo fill system. The operators will be able to regulate the speed of the belt feeders for both the stock out and reclaim conveyors with the help of in-line belt scales mounted on these conveyors. An in-line magnetic separator mounted at the head/discharge section of reclaim conveyor CVY-2 will be able to remove the harmful ferrous metal objects from the limestone flow before they reach the silos or the mills. Suitably designed dust control equipment will be installed at strategic locations of the system. The limestone dust control system will control the escape to atmosphere of dust 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application particles generated at the various transfer locations in the limestone handling system. The bottom dump rail/truck dump facility will be provided with an enclosure. A dry induced air fabric filter bag type dust collection system, DC-1 will be provided at the enclosure to control dust emissions during unloading railcars or trucks. The transfer chutes below the railcar/truck dump hopper and the reclaim hoppers will be provided with dry fog type dust suppression systems, DS-1 & 3 respectively. A spray type dust suppression system, DS-2, will be provided at the discharge of Telescopic Chute CHE-1. Two fabric filter bag type bin vent dust collectors BV-1 & 2 will be provided on top of each limestone silo for Unit 4. 1.3.2 Equipment Description: Belt Conveyors. The conveyor subcomponents include the conveyor belt, idlers, pulleys, take-ups, bearings, belt cleaners, drives, motors, drive base-plates, walkways, stringers, supports, head and tail frames, foundations, and all other appurtenances necessary for each of the individual conveyors. The elevated portion of all conveyors between structures will be supported by enclosed box type trusses with solid floors. A walkway on the one side of the conveyors will be furnished. The conveyor trusses will be suitable for use with a washdown system. Telescopic chute. A telescopic chute will be provided at the discharge end of the receiving/stock out conveyor CVY-1, to control dust emissions during stock piling of limestone. The telescopic chute will consist of steel fabricated concentric tubular sections telescoping into each other as required for stock piling of limestone into a conical pile. The telescoping sections of the chute will be lifted or lowered by a motorized winch. The telescopic chute will be rigidly supported from the outlet flange of the head chute of the stock out conveyor CVY-1. Belt Feeders. The function of the belt feeders will be to receive limestone from the hoppers located above the feeders and feed to the belt conveyors located below the feeders at a desired rate. Belt feeders FDR-1 & 2, will be equipped with variable speed drives, 20-degree picking table idlers, adjustable screw take up, and other components as appropriate. Magnetic Separator. The magnetic separator will be the overhead, self-cleaning, belted in-line, fluid-filled type. The magnetic separator will be housed completely inside dust covers. The magnetic separator will be mounted at the head chute of conveyor CVY-2. The magnetic separator will be positioned above and forward of the conveyor head pulley. The magnet will be sloped towards a tramp iron chute. The tramp iron chute will transport tramp iron to a collection box at grade. 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application Belt Scales. Conveyors CVY-1 & 2 will be provided with belt scales. The primary function of the belt scales is for feed rate control and material inventory monitoring. The belt scales will be the 3 or 4-idler precision digital electronic type with solid-state circuitry and built-in, self-testing devices. The scales will also be provided with test weights for self calibration. Each belt scale will use an environmentally sealed, temperature-compensated, load-sensing device and weigh bridge. The scales will weigh and totalize to a value within 1 to 2% of the test load at flow rates between 25% and 100% of the scale system’s calibrated capacity. Limestone Storage Building. The limestone storage building will completely enclose the conical shaped 7-day storage pile. The three sides of the building and the roof will be fully covered to prevent the escape of limestone dust and to protect the pile from weather. One side of the building will be open to provide access for mobile equipment and will be provided with a dust curtain. The storage building will be constructed from steel columns and beams and provided with girts, purlins and bracing. The roof and three sides will be of non-insulating metal panel construction. 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application 1.0 System Description 1.1 System Identification – Site and Equipment Fire Protection 1.2 Function The Site and Equipment Fire Protection System will convey water to fire hydrants, hose stations, fixed water suppression systems and provide independent fire detection systems, standpipe and fire hose stations, and portable fire extinguishers in the minimum combinations required to protect equipment, buildings, structures, and their contents in the event of fire. It is not the intent of this document to identify all of the necessary fire protection system, but rather to clarify the minimum requirements identified at the time of this writing. 1.3 Process Description The Site and Equipment Fire Protection System consists of the following major equipment and components: • Fire hydrants. • Hose stations. • Fixed water suppression systems. • Independent fire detection systems. • Main Fire Pumps (one electric and one diesel) and Pressure Maintenance Pump. • Fire Water Booster Pumps (one electric and one diesel) and Pressure Maintenance Pump • Portable fire extinguishers. • Piping, valves and accessories. • Backflow prevention as required by City. Water supply for the Site and Equipment Fire protection System will be from two (2) independent 24” sources supplied at interconnections to City Water mains. Underground water mains shall be arranged in a loop header system around the Steam Generation Building and boiler, leading to fire pumps serving the facility. See the Service Water System Description for requirements for re-routing the City water leading to the existing units to the north. 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application The fire protection systems and components will comply with applicable state laws, building and fire prevention codes, local ordinances, NFPA codes and standards based on industry standard practices and the Owner’s insurance consultant’s requirements. The EPC Contractor is to prepare a list of the proposed systems for the Owner and Owner’s insurance consultant’s review and approval. Systems anticipated include: • Coal Handling (conveyors, transfer houses, crusher building, railcar unloading, trippers, dust collectors). • Steam turbine operating floor, underfloor, and mezzanine. • Steam turbine bearings • Boiler feed pump turbines • Electrical equipment room detection (DCS, batteries, control room) • Administrative and warehouse areas • Transformer deluge systems • Cooling tower area hydrants (one per two cells) and dry-pipe protection system The fire protection systems will include the various types of fixed water suppression and detection systems for the areas and hazards identified as requiring fire suppression or detection. These systems operate in response to conditions such as excessive heat, temperature rate-of-rise, or visible and invisible products of combustion. Fire pumps shall be horizontal split-case, centrifugal type with UL-listed motor and accessories, including UL-listed and FM-approved pump controllers. For each pressure level, one pump will be electric motor drive while the second pump shall be diesel driven. Each set of two pumps will be furnished in a self contained enclosure at grade, complete with sprinklers, diesel fuel tanks, controllers, and with a fire rated wall between the two pumps. An electric motor driven pressure maintenance pump will be required for each pressure system. Systems will include fire pump flow test sections and fire department pumper connections. Portable fire extinguishers will be provided at all standpipe and fire hose stations in addition to other key locations. The extinguishing medium selected will be dependent on hazards encountered in the immediate area. Aboveground piping materials will be carbon steel with welded headers. Underground fire protection piping will be cement lined ductile iron or UL/FM approved HDPE. 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application Valves 2-1/2 inch and larger will be cast iron. Two inch and smaller valves will be bronze where located in copper piping or tubing, forged or cast carbon steel where located in carbon steel piping, and stainless steel where located in stainless steel piping or tubing. New fire hydrants will be of the dry barrel type (frostproof) to eliminate freezing and will be complete with connections and threads matching the existing plant and city fire department requirements. Each hydrant will have an underground isolation valve and valve box. All valves except drains, vents, gauge isolations, and booster pump sensing valves will be FM approved or UL listed indicating type. 082907-145491 Interstate Power and Light Sutherland Unit 4 Air Permit Application Appendix E Appendix E Flow Diagrams and Site Drawings 102607-145491 E-1 Interstate Power and Light Sutherland Unit 4 Air Permit Application Appendix F Appendix F Equipment Performance Data 102607-145491 F-1 Emissions Calculations - Stack Project Date Engineer Basis Composition of Gas Exiting Stack (lb/hr) Fuel Type: Case: Interstate Power and Light (IP&L) 17-Oct-07 William Stevenson Stack PRB - 1 M10- Run PRB-1 IL - 1 M10- Run IL-1 PRB - 2 M10- Run PRB-2 IL - 2 M10- Run IL-2 Oxygen Nitrogen Chlorine Carbon Dioxide Sulfur Dioxide Moisture 353,161 4,800,280 0 1,358,469 380 837,451 423,364 4,813,179 0 1,280,117 494 699,458 336,116 4,566,406 0 1,292,086 361 700,434 399,863 4,547,159 0 1,209,205 466 567,035 Total Flue Gas Flow Rate (lb/hr) 7,349,741 7,216,612 6,895,403 6,723,728 261,473 288,852 232,601 257,966 Oxygen Nitrogen Chlorine Carbon Dioxide Sulfur Dioxide Moisture 11,040 171,360 0 30,870 6 46,490 13,230 171,820 0 29,090 8 38,830 10,500 163,010 0 29,360 6 38,880 12,500 162,320 0 27,480 7 31,480 Total Flue Gas Flow Rate (moles/hr) 259,766 252,978 241,756 233,787 Stack Exit Conditions Fuel Type: Case: Fuel Burn Rate, MBtu/hr Fuel Higher Heating Value, Btu/lb Fuel Burn Rate, lb/hr Wet Molecular Weight, lb/mole Flue Gas Density, lb/cuft Total Gas Flow Rate, acfm Total Gas Flow Rate leaving A/H, acfm Temperature, F Pressure, in w.g. Stack Exit Velocity, ft/sec Stack Exit Area (ft2) Stack Diameter (feet) PRB - 1 M10- Run PRB-1 6,326 8,300 762,157 28.29 0.0631 1,940,460 2,392,341 130 0 59.2 546.63 26.38 IL - 1 M10- Run IL-1 6,169 10,800 571,210 28.53 0.0641 1,876,128 2,337,509 130 0 57.2 546.63 26.38 PRB - 2 M10- Run PRB-2 6,017 8,300 724,913 28.52 0.0641 1,793,722 2,202,160 130 0 54.7 546.63 26.38 IL - 2 M10- Run IL-2 5,828 10,800 539,605 28.76 0.0652 1,719,350 2,135,983 120 0 52.4 546.63 26.38 Nitrogen Oxide NOX Uncontrolled Emission Rate, lb/Mbtu 0.20 0.20 0.20 0.20 NOX Uncontrolled Emission Rate, ppmvw (actual O 2) 106 106 108 108 NOX Controlled Emission Rate, lb/MBtu 0.05 0.05 0.05 0.05 NOX Controlled Emissions, lb/hr 316.3 308.5 300.8 291.4 26 27 27 27 5,025 92.4% 380 35,493 98.6% 494 4,780 92.4% 361 33,529 98.6% 466 Moisture Added by wet FGD Composition of Gas Exiting Stack (moles/hr) NOX Controlled Emissions, ppmvw (actual O2) Sulfur Dioxide Uncontrolled SO 2 Emissions, lb/hr Scrubber Removal Efficiency, % Controlled SO 2 Emissions, lb/hr Controlled SO 2 Emissions, moles/hr 6 8 6 7 Controlled SO 2 Emissions, ppmw 23.1 31.6 24.8 29.9 Controlled SO 2 Emissons, lb/MBtu 0.06 0.08 0.06 0.08 Carbon Monoxide (CO) CO Emission Rate, lb/MBtu CO Emission Rate, lb/hr 0.12 759 0.12 740 0.12 722 0.12 699 Emissions Calculations - Stack Project Date Engineer Basis Fuel Type: Case: Sulfur Trioxide (SO3) Interstate Power and Light (IP&L) 17-Oct-07 William Stevenson Stack PRB - 1 M10- Run PRB-1 IL - 1 M10- Run IL-1 PRB - 2 M10- Run PRB-2 IL - 2 M10- Run IL-2 SO2 to SO3 Conversion Rate (Boiler and SCR Total), % 2.00 2.00 2.00 2.00 Uncontrolled SO 3 Emissions, lb/hr 125.5 886.8 119.4 837.7 Uncontrolled SO 3 Emissions, moles/hr 1.57 11.08 1.49 10.47 Uncontrolled SO 3 Emissions, ppmvw (actual O2) 6.0 43.8 6.2 44.8 153.8 1086.3 146.3 1026.2 Uncontrolled SO 3 Emissions as H2SO4, lb/hr Controlled SO 3 Emissions, lb/hr Controlled SO 3 Emissions, lb/MBtu Controlled SO 3 Emissions, as H2SO4 lb/hr Controlled SO 3 Emissions, as H2SO4 lb/MBtu Particulate (PM+PM10) Ash Content in Fuel, percent Unburned Carbon, lb/hr Uncontrolled Particulate Emissions, lb/hr Uncontrolled Particulate Emission Rate , lb/MBtu Uncontrolled Particulate, Emissions, gr/acf Controlled Particulate Emissions (Filterable), lb/hr Controlled Particulate Emission Rate (Filterable), lb/MBtu Controlled Particulate, Emissions (Filterable), gr/acf Controlled Particulate Emissions (Filterable + Condensible), lb/hr Controlled Particulate Emission Rate (Filterable + Condensible), lb/mmbtu Controlled Particulate, Emissions (Filterable + Condensible), gr/acf Volatile Organic Compounds (VOC) VOC Emission Rate, lb/MBtu VOC Emission Rate, lb/hr Mercury (Hg) Hg Emission Rate, lb/MW-hr Ammonia Slip (NH3) 20.7 20.1 19.6 19.0 0.0033 0.0033 0.0033 0.0033 25.3 24.7 24.1 23.3 0.0040 0.0040 0.0040 0.0040 4.93% 380 30,439 4.81 1.83 75.9 0.012 0.0046 113.9 0.018 0.0068 9.52% 370 43,874 7.11 2.73 74.0 0.012 0.0046 111.0 0.018 0.0069 4.93% 361 28,952 4.81 1.88 72.2 0.012 0.0047 108.3 0.018 0.0070 9.52% 350 41,446 7.11 2.81 69.9 0.012 0.0047 104.9 0.018 0.0071 0.0034 21.51 0.0034 20.97 0.0034 20.46 0.0034 19.81 6.6E-05 6.6E-05 6.6E-05 6.6E-05 Ammonia Slip, ppmvd (at 3% O2) Ammonia Slip, lb/hr Fluorides as HF HF Emission Rate, lb/Mbtu HF Emission Rate, lb/hr 2.00 7.3 2.00 7.3 2.00 6.9 2.00 6.9 0.0002 1.27 0.0002 1.23 0.0002 1.20 0.0002 1.17 Consumables Water (gpm) Limestone (lb/hr) Sorbent Injection (lb/hr)5 Powdered Activated Carbon -- PAC sorbent injection (lb/hr) Ammonia (Anhydrous) (lb/hr) Ammonia (Aqueous @ 19% NH 3) (lb/hr) 543 7,786 222 431 375 1,976 747 59,305 2,011 421 366 1,928 484 7,407 212 396 357 1,880 677 55,827 1,899 384 346 1,822 30,363 28,917 1,953 7,515 12,589 43,799 41,680 2,614 10,876 95,663 28,879 27,504 1,844 7,148 11,995 41,376 39,374 2,457 10,274 90,062 Waste Products Total Fly Ash Removed (lb/hr) Sellable Fly Ash (lb/hr) Non-sellable Fly Ash (lb/hr) Bottom Ash (lb/hr) Total Byproducts [gypsum] from FGD -- dry basis (lb/hr) Assumptions: 1. Fly Ash / Bottom Ash Split is 80/20. 2. Unit MW at Design Load is 649 MW Net References: 1. M-10 Run: IPL Base Load Coal Plant - M-10 Run PRB-1 by Kris Gamble, 5/18/07 2. M-10 Run: IPL Base Load Coal Plant - M-10 Run IL-1 by Kris Gamble, 5/18/07 3. M-10 Run: IPL Base Load Coal Plant - M-10 Run PRB-2 (Max fuel input at mean ambient temperature) by Kris Gamble, 7/31/2007 4. M-10 Run: IPL Base Load Coal Plant - M-10 Run IL-2 (Max fuel input at mean ambient temperature) by Kris Gamble, 7/31/2007 5. SOLVAY Chemicals, SOLVAir Select Application Guide (Sorbent Injection Rate) Notes: 1. Stack Exit Area and Stack Diameter was set by the PRB - Biomass Fuel case due to the fact that it had the greatest stack flow which drives the stack diameter. Emissions Calculations - Stack Project Date Engineer Basis Composition of Gas Exiting Stack (lb/hr) Fuel Type: Case: Interstate Power and Light (IP&L) 17-Oct-07 William Stevenson Stack PRB - 2 75% of Max. Heat Input PRB-2 IL - 2 75% of Max. Heat Input IL-2 PRB - 2 50% of Max. Heat Input PRB-2 IL - 2 50% of Max. Heat Input IL-2 Oxygen Nitrogen Chlorine Carbon Dioxide Sulfur Dioxide Moisture 292,251 3,690,683 0 1,018,760 285 557,461 362,083 3,757,638 0 960,128 370 459,511 255,388 2,661,283 0 679,246 190 374,026 288,811 2,662,403 0 640,154 247 312,105 Total Flue Gas Flow Rate (lb/hr) 5,559,440 5,539,730 3,970,133 3,903,720 187,991 213,141 126,349 146,793 Oxygen Nitrogen Chlorine Carbon Dioxide Sulfur Dioxide Moisture 9,130 131,750 0 23,150 4 30,940 11,320 134,140 0 21,820 6 25,510 7,980 95,000 0 15,430 3 20,760 9,030 95,040 0 14,550 4 17,320 Total Flue Gas Flow Rate (moles/hr) 194,974 192,796 139,173 135,944 Stack Exit Conditions Fuel Type: Case: Fuel Burn Rate, MBtu/hr Fuel Higher Heating Value, Btu/lb Fuel Burn Rate, lb/hr Wet Molecular Weight, lb/mole Flue Gas Density, lb/cuft Total Gas Flow Rate, acfm Total Gas Flow Rate leaving A/H, acfm Temperature, F Pressure, in w.g. Stack Exit Velocity, ft/sec Stack Exit Area (ft2) Stack Diameter (feet) PRB - 2 75% of Max. Heat Input PRB-2 4,744 8,300 571,566 28.51 0.0641 1,445,407 1,738,831 125 0 44.1 546.63 26.38 IL - 2 75% of Max. Heat Input IL-2 4,627 10,800 428,426 28.73 0.0652 1,416,164 1,725,456 120 0 43.2 546.63 26.38 PRB - 2 50% of Max. Heat Input PRB-2 3,163 8,300 381,084 28.53 0.0644 1,027,703 1,228,459 125 0 31.3 546.63 26.38 IL - 2 50% of Max. Heat Input IL-2 3,085 10,800 285,648 28.72 0.0653 996,132 1,211,621 120 0 30.4 546.63 26.38 Nitrogen Oxide NOX Uncontrolled Emission Rate, lb/MBtu 0.20 0.20 0.20 0.20 NOX Uncontrolled Emission Rate, ppmvw (actual O 2) 106 104 99 99 NOX Controlled Emission Rate, lb/MBtu 0.05 0.05 0.05 0.05 NOX Controlled Emissions, lb/hr 237.2 231.4 158.2 154.3 26 26 25 25 3,769 92.4% 285 26,621 98.6% 370 2,513 92.4% 190 17,749 98.6% 247 Moisture Added by wet FGD Composition of Gas Exiting Stack (moles/hr) NOX Controlled Emissions, ppmvw (actual O2) Sulfur Dioxide Uncontrolled SO 2 Emissions, lb/hr Scrubber Removal Efficiency, % Controlled SO 2 Emissions, lb/hr Controlled SO 2 Emissions, moles/hr 4 6 3 4 Controlled SO 2 Emissions, ppmw 20.5 31.1 21.6 29.4 Controlled SO 2 Emissons, lb/MBtu 0.06 0.08 0.06 0.08 Carbon Monoxide (CO) CO Emission Rate, lb/MBtu CO Emission Rate, lb/hr 0.12 569 0.12 555 0.12 380 0.12 370 Emissions Calculations - Stack Project Date Engineer Basis Fuel Type: Case: Sulfur Trioxide (SO3) Interstate Power and Light (IP&L) 17-Oct-07 William Stevenson Stack PRB - 2 75% of Max. Heat Input PRB-2 IL - 2 75% of Max. Heat Input IL-2 PRB - 2 50% of Max. Heat Input PRB-2 IL - 2 50% of Max. Heat Input IL-2 SO2 to SO3 Conversion Rate (Boiler and SCR Total), % 2.00 2.00 2.00 2.00 Uncontrolled SO 3 Emissions, lb/hr 94.2 665.1 62.8 443.4 Uncontrolled SO 3 Emissions, moles/hr 1.18 8.31 0.78 5.54 Uncontrolled SO 3 Emissions, ppmvw (actual O2) 6.0 43.1 5.6 40.8 115.4 814.8 76.9 543.2 Uncontrolled SO 3 Emissions as H2SO4, lb/hr Controlled SO 3 Emissions, lb/hr 15.5 15.1 10.3 10.1 0.0033 0.0033 0.0033 0.0033 Controlled SO 3 Emissions, as H2SO4 lb/hr 19.0 18.5 12.7 12.3 Controlled SO 3 Emissions, as H2SO4 lb/MBtu 0.004 0.004 0.004 0.004 4.93% 285 22,827 4.81 1.84 56.9 0.012 0.0046 85.4 0.018 0.0069 9.52% 278 32,907 7.11 2.71 55.5 0.012 0.0046 83.3 0.018 0.0069 4.93% 190 15,220 4.81 1.73 38.0 0.012 0.0043 56.9 0.018 0.0065 9.52% 185 21,940 7.11 2.57 37.0 0.012 0.0043 55.5 0.018 0.0065 0.0034 16.13 0.0034 15.73 0.0034 10.75 0.0034 10.49 6.6E-05 Controlled SO 3 Emissions, lb/Mbtu Particulate (PM+PM10) Ash Content in Fuel, percent Unburned Carbon, lb/hr Uncontrolled Particulate Emissions, lb/hr Uncontrolled Particulate Emission Rate , lb/mmbtu Uncontrolled Particulate, Emissions, gr/acf Controlled Particulate Emissions (Filterable), lb/hr Controlled Particulate Emission Rate (Filterable), lb/MBtu Controlled Particulate, Emissions (Filterable), gr/acf Controlled Particulate Emissions (Filterable + Condensible), lb/hr Controlled Particulate Emission Rate (Filterable + Condensible), lb/MBtu Controlled Particulate, Emissions (Filterable + Condensible), gr/acf Volatile Organic Compounds (VOC) VOC Emission Rate, lb/MBtu VOC Emission Rate, lb/hr Mercury (Hg) Hg Emission Rate, lb/MW-hr Ammonia Slip (NH3) 6.6E-05 6.6E-05 6.6E-05 Ammonia Slip, ppmvd (at 3% O2) Ammonia Slip, lb/hr Fluorides as HF HF Emission Rate, lb/MBtu HF Emission Rate, lb/hr 2.00 5.6 2.00 5.7 2.00 4.0 2.00 4.0 0.0002 0.95 0.0002 0.93 0.0002 0.63 0.0002 0.62 Consumables Water (gpm) Limestone (lb/hr) Sorbent Injection (lb/hr)5 Powdered Activated Carbon -- PAC sorbent injection (lb/hr) Ammonia (Aqueous @ 19% NH 3) (lb/hr) 391 5,840 167 313 1,483 554 44,480 1,508 311 1,447 263 3,894 111 221 990 379 29,657 1,005 218 966 22,770 21,686 1,454 5,636 9,452 32,851 31,261 1,956 8,157 71,797 15,182 14,459 982 3,757 6,301 21,903 20,843 1,315 5,439 47,835 Waste Products Total Fly Ash Removed (lb/hr) Sellable Fly Ash (lb/hr) Non-sellable Fly Ash (lb/hr) Bottom Ash (lb/hr) Total Byproducts [gypsum] from FGD -- dry basis (lb/hr) Assumptions: 1. Fly Ash / Bottom Ash Split is 80/20. 2. Unit MW at Design Load is 649 MW Net References: 1. M-10 Run: IPL Base Load Coal Plant: 75% of Maximum Heat Input - Mean Ambient PRB-2 by Kris Gamble, 5/18/07 2. M-10 Run: IPL Base Load Coal Plant: 75% of Maximum Heat Input - Mean Ambient IL-2 by Kris Gamble, 5/18/07 3. M-10 Run: IPL Base Load Coal Plant: 50% of Maximum Heat Input - Mean Ambient PRB-2 by Kris Gamble, 5/18/07 4. M-10 Run: IPL Base Load Coal Plant: 50% of Maximum Heat Input - Mean Ambient IL-2 by Kris Gamble, 5/18/07 5. SOLVAY Chemicals, SOLVAir Select Application Guide (Sorbent Injection Rate) Notes: 1. Stack Exit Area and Stack Diameter was set by the PRB - Biomass Fuel case due to the fact that it had the greatest stack flow which drives the stack diameter. Emissions Calculations - Stack Project Date Engineer Basis Composition of Gas Exiting Stack (lb/hr) Fuel Type: Case: Interstate Power and Light (IP&L) 17-Oct-07 William Stevenson Stack PRB - BM M10- Run PRB Coal - Biomass IL - BM M10- Run Illinois Coal - Biomass Oxygen Nitrogen Chlorine Carbon Dioxide Sulfur Dioxide Moisture 376,484 4,869,907 0 1,362,592 380 845,488 444,174 4,886,735 0 1,288,479 495 716,861 Total Flue Gas Flow Rate (lb/hr) 7,454,851 7,336,744 265,302 293,964 Oxygen Nitrogen Chlorine Carbon Dioxide Sulfur Dioxide Moisture 11,770 173,840 0 30,960 6 46,930 13,880 174,440 0 29,280 8 39,790 Total Flue Gas Flow Rate (moles/hr) 263,506 257,398 Moisture Added by wet FGD Composition of Gas Exiting Stack (moles/hr) Stack Exit Conditions Fuel Type: PRB - BM IL - BM M10- Run PRB Coal - Biomass 6,333 8,207 771,688 28.29 0.0631 1,967,862 2,427,142 130 0 60.0 M10- Run Illinois Coal - Biomass 6,187 10,488 589,902 28.50 0.0640 1,909,549 2,381,044 125 0 58.2 546.63 26.38 546.63 26.38 Nitrogen Oxide NOX Uncontrolled Emission Rate, lb/MBtu 0.20 0.20 NOX Uncontrolled Emission Rate, ppmvw (actual O 2) 105 105 NOX Controlled Emission Rate, lb/MBtu 0.05 0.05 NOX Controlled Emissions, lb/hr 316.7 309.3 Case: Fuel Burn Rate, MBtu/hr Fuel Higher Heating Value, Btu/lb Fuel Burn Rate, lb/hr Wet Molecular Weight, lb/mole Flue Gas Density, lb/cuft Total Gas Flow Rate, acfm Total Gas Flow Rate leaving A/H, acfm Temperature, F Pressure, in w.g. Stack Exit Velocity, ft/sec Stack Exit Area (ft 2) Stack Diameter (feet) NOX Controlled Emissions, ppmvw (actual O 2) Sulfur Dioxide Uncontrolled SO 2 Emissions, lb/hr Scrubber Removal Efficiency, % Controlled SO 2 Emissions, lb/hr Controlled SO 2 Emissions, moles/hr 26 26 4,873 92.2% 380 33,907 98.5% 495 6 8 Controlled SO 2 Emissions, ppmw 22.8 31.1 Controlled SO 2 Emissons, lb/MBtu 0.06 0.08 Carbon Monoxide (CO) CO Emission Rate, lb/MBtu CO Emission Rate, lb/hr 0.12 760 0.12 742 Emissions Calculations - Stack Project Date Engineer Basis Fuel Type: Case: Sulfur Trioxide (SO3) Interstate Power and Light (IP&L) 17-Oct-07 William Stevenson Stack PRB - BM M10- Run PRB Coal - Biomass IL - BM M10- Run Illinois Coal - Biomass SO2 to SO3 Conversion Rate (Boiler and SCR Total), % 2.00 2.00 Uncontrolled SO 3 Emissions, lb/hr 121.7 847.1 Uncontrolled SO 3 Emissions, moles/hr 1.52 10.58 Uncontrolled SO 3 Emissions, ppmvw (actual O 2) 5.8 41.1 149.1 1037.8 Uncontrolled SO 3 Emissions as H2SO4, lb/hr Controlled SO 3 Emissions, lb/hr Controlled SO 3 Emissions, lb/Mbtu 20.7 20.2 0.0033 0.0033 Controlled SO 3 Emissions, as H2SO4 lb/hr 25.3 24.7 Controlled SO 3 Emissions, as H2SO4 lb/MBtu 0.004 0.004 4.93% 380 30,785 4.86 1.83 76.0 0.012 0.0045 114.0 0.018 0.0068 9.16% 371 43,591 7.05 2.66 74.2 0.012 0.0045 111.4 0.018 0.0068 0.0034 21.53 0.0034 21.04 6.6E-05 6.6E-05 Particulate (PM+PM 10) Ash Content in Fuel, percent Unburned Carbon, lb/hr Uncontrolled Particulate Emissions, lb/hr Uncontrolled Particulate Emission Rate , lb/MBtu Uncontrolled Particulate, Emissions, gr/acf Controlled Particulate Emissions (Filterable), lb/hr Controlled Particulate Emission Rate (Filterable), lb/MBtu Controlled Particulate, Emissions (Filterable), gr/acf Controlled Particulate Emissions (Filterable + Condensible), lb/hr Controlled Particulate Emission Rate (Filterable + Condensible), lb/MBtu Controlled Particulate, Emissions (Filterable + Condensible), gr/acf Volatile Organic Compounds (VOC) VOC Emission Rate, lb/MBtu VOC Emission Rate, lb/hr Mercury (Hg) Hg Emission Rate, lb/MW-hr Ammonia Slip (NH3) Ammonia Slip, ppmvd (at 3% O 2) Ammonia Slip, lb/hr Fluorides as HF HF Emission Rate, lb/MBtu HF Emission Rate, lb/hr 2.00 7.4 2.00 7.4 0.0002 1.27 0.0002 1.24 Consumables Water (gpm) Limestone (lb/hr) 551 7,531 747 56,613 Sorbent Injection (lb/hr) 3 Powdered Activated Carbon -- PAC sorbent injection (lb/hr) Ammonia (Aqueous @ 19% NH 3) (lb/hr) 214 437 1,940 1,919 429 1,895 30,709 29,246 1,539 7,601 12,163 43,517 41,411 2,180 10,805 91,362 Waste Products Total Fly Ash Removed (lb/hr) Sellable Fly Ash (lb/hr) Non-sellable Fly Ash (lb/hr) Bottom Ash (lb/hr) Total Byproducts [gypsum] from FGD -- dry basis (lb/hr) Assumptions: 1. Fly Ash / Bottom Ash Split is 80/20. 2. Unit MW at Design Load is 649 MW Net References: 1. M-10 Run: IPL Base Load Coal Plant - M-10 Run; PRB Coal Case - Biomass, by Kris Gamble 5/25/07 2. M-10 Run: IPL Base Load Coal Plant - M-10 Run; Illinos Coal - Biomass, by Kris Gamble 5/25/07 3. SOLVAY Chemicals, SOLVAir Select Application Guide (Sorbent Injection Rate) Notes: 1. Stack Exit Area and Stack Diameter was set by the PRB - Biomass Fuel case due to the fact that it had the greatest stack flow which drives the stack diameter Coen Auxiliary Boiler, info from Locke Equipment, at flow 200,000 lb/hr and saturated pressure 250 psi (All values at 100% full load): Fuel Natural Gas Stack Gas Exit Temp Stack Gas Flow (exhaust density = .0765 lb/ft3) 650 °F 237,980 lb/hr =51,850 acfm Stack Exhaust Inside Diameter 5 ft Stack Height Above Ground 285 ft Stack Gas Emissions: NOx 0.037 lbm/MMBtu CO 0.074 lbm/MMBtu PM10 0.007 lbm/MMBtu VOC 0.005 lbm/MMBtu SOx 0.0006 lbm/MMBtu Heat Input 268,640,000 Btu/hr Dawn Equipment, Inc. 2.461 mm Btu/Hr design Heat absorbed to the process fluid (fuel gas) 3.007 mm Btu/hr burner heat release (LHV basis) Overall Heater Thermal Efficiency = 81.82%, LHV basis 1. Stack Gas Exit Temp (Design Loads and Fuels) Broach: 700 Deg F 2. Stack Gas Exit Vel (Design Loads and Fuels) Broach: 20 Feet per Second 3. Stack Gas Vol Flow (Design Loads and Fuels)(acfm) Broach: 2917 Lbs/hr – Mass Basis, or 1,429 ACFM @ 700 Deg F 4. Stack Exhaust Inside Diameter Broach: 1’-3” at stack tip 5. Stack Ht Above Ground Broach: 50 feet approx - for stack draft and safety reasons 6. Stack Gas Emissions (NOx, CO, PM10, SOx, VOC)(lb/h, lb/Mbtu @ Design Loads and Fuels) Broach: Typical Exhaust Emissions Limits = 30 ppm NOx, 50 ppm CO, & 0 SOx (not to exceed) Interstate Power and Light Sutherland Unit 4 Air Permit Application Appendix G Appendix G Emission Calculations 102607-145491 G-1 IPL Sutherland Unit 4 PSD Application Summary of Potential to Emit for Criteria Pollutants (Tons per year) CO Unit 4 Boiler Auxiliary Boiler Emergency Generator Fire Pump Fire Booster Pump Gate Station Heater Cooling Tower Material Handling Coal Transfers Wind Erosion Maintenance/Bulldozing Limestone Transfers Wind Erosion Maintenance/Bulldozing Miscellaneous Transfers Saleable Fly Ash Waste Fly Ash Biomass PAC Sorbent Lime Haul Roads Delivery TOTAL SER PSD Review Required? 3,324.95 19.88 1.72E-01 4.75E-02 5.50E-03 6.21E-01 --- NOx TSP PM10 1385.394 498.74184 498.74184 9.94 1.88 1.880 2.09E+00 0.012 0.012 3.11E-01 5.00E-03 5.00E-03 8.55E-02 3.05E-03 3.05E-03 6.12E-01 9.80E-02 9.80E-02 -11.545 11.545 -18.189 4.279 SO2 2216.6304 0.161 0.049 1.02E-02 3.35E-03 7.74E-03 --- Total Fluorides Reduced Sulfur 94.206792 0.5049354 0 110.83152 4.7969 0 1.343 1.32E-04 0.000 2.47E-01 0.00E+00 0.00 0.087 8.69E-06 0.000 7.45E-02 2.57E-04 0.00 1.83E-02 1.83E-06 0.00E+00 1.57E-02 5.41E-05 0.00E+00 5.99E-03 5.99E-07 0.00E+00 5.13E-03 1.77E-05 0.00E+00 7.09E-02 6.45E-06 0.00E+00 1.19E-02 0.00E+00 0.00E+00 ------------VOC Pb H2S H2SO4 ------------------ ------------------ 11.532 5.201 0.962 5.368 1.314 0.297 0.216 0.801 0.017 0.003 0.003 3.6E-05 0.005 0.005 6.2E-05 5.326 5.326 2.813 1.161 0.481 1.170 0.422 0.118 0.108 0.196 0.006 0.001 0.001 3.6E-05 0.002 0.002 2.3E-05 1.037 1.037 ------------------ ------------------ ------------------ ------------------ ------------------ ------------------ ------------------ 3,345.67 100 YES 1,398.44 40 YES 530.47 25 YES 516.56 15 YES 2,216.86 40 YES 95.73 40 YES 0.5051 0.6 NO 0.00 10 NO 111.19 7 YES 4.7972 3 YES 0.0000 10 NO IPL Sutherland Unit 4 Unit 4 Boiler Parameters Emissions Calculation Basis: Fuel Burn Rate Fuel Burn Rate Unit MW (net) Hours of Operations Number of Boilers 6,326 768,547 630 8,760 1 Table A1 Unit 4 Boiler Emissions Emission Pollutant Level (lb/mmBtu) mmBtu/hr lb/hr MW hr/yr [1] Mass Rate (lb/hr) PC Boiler PTE (tpy) CO NOx 0.12 0.05 759.1 316.3 [2] PM10 0.018 113.9 [2] 498.7 506.1 [2] 2,216.6 21.5 [2] 94.2 0.000018 0 0.115 0 [3] 0.505 0 0.004 25.3 [2] 110.8 1.1 0 [5a] 4.8 0 SO2 VOC Lead H2 S H2SO4 Fluorides Total Reduced Sulfur 0.08 0.0034 0.0002 0 [2] [4] [4] 3,324.9 1,385.4 Notes [ ]: 1. Based on boiler performance data at 100% of base load for PRB coal. 2. Performance data contained in Appendix F. 3. Based on fuel analysis. A 97.5% control efficiency was assumed. 4. Hydrogen sulfide and total reduced sulfur emissions are insignificant and assumed to be zero. All sulfur contained in the coal was assumed to be emitted as either SO2 or H2SO4. 5. Fluoride emissions with assumed 98% control efficiency. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 1 "External Combustion Sources", Section 1.1 "Bituminous and Subbituminous Coal Combustion". September 1998. a. Table 1.1-15 "Emission Factors for Hydrogen Chloride (HCl) and Hydrogen Fluoride (HF) from Coal Combustion". IPL Sutherland Unit 4 PSD Application Auxiliary Boiler Emissions Calculation and Stack Parameters Information Basis: Heat Input Heating Value Fuel Burn Rate Hours of Operation Stack Exit Conditions: Exhaust Flow Rate Exhaust Exit Velocity Exhaust Temperature Stack Diameter Stack Height 268.64 1,021 263,115 2,000 mmBtu/hr [1] Btu/scf[2] scf/hr hrs/yr 237,980 44.0116 650 60 285 lb/hr ft/sec °F in ft Table A2 Auxiliary Boiler Emissions Outlet Conditions [1] Pollutant lb/mmBtu 526 Mscf/yr 51,850 13.4147 616.4833 5 86.8680 acfm m/sec K ft m 1.5240 m Potential to Emit ton/yr Emission Rate g/sec lb/hr CO NOx 0.074 0.037 2.5047 1.2524 19.8794 9.9397 [1] PM/PM10 0.007 0.2369 1.8805 [1] 1.88 0.1612 [1] 0.16 1.3432 [1] 1.34 1.32E-04 0 SO2 VOC 0.0006 0.005 0.0203 0.1692 [1] 19.88 9.94 Lead H2 S 4.90E-07 0 1.66E-05 0 1.32E-04 0 [3] H2SO4 9.19E-04 3.11E-02 2.47E-01 [5] 2.47E-01 0 0 [4] 0 0 Fluorides Total Reduced Sulfur 0 0 0 0 [4] [4] Notes [ ]: 1. Vendor data - Coen boiler performance data. 2. Assumed IPL natural gas lower heating value of 1021 Btu/scf. 3. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 1 "External Combustion Sources", Section 1.4 "Natural Gas Combustion". July 1998. Table 1.4-2 "Emission Factors for Criteria Pollutants and Greenhouse Gases from Natural Gas Combustion". 4. Hydrogen sulfide, total reduced sulfur, and fluorides emissions are insignificant and assumed to be zero. 5. Assumed 100% conversion of SO2 to H2SO4. IPL Sutherland Unit 4 PSD Application Emergency Generator Parameters Emissions Calculation and Stack Parameters Information Basis: Power Rating Heat Input Heating Value Fuel Burn Rate Hours of Operation Stack Exit Conditions Number of Stacks Exhaust Flow Rate Exhaust Flow Rate Exhaust Exit Velocity Exhaust Temperature Stack Diameter Stack Height 2,937 19.32 140,000 138.00 100 [3] HP[1] mmBtu/hr Btu/gal[2] gal/hr[1] hrs/yr 13,800 gal/yr : 2 14,920.0 7,460.0 227.9608 761 10 10 # acfm (total) acfm (per stack) ft/sec °F in ft 69.4825 678.15 0.8333 3.0480 m/sec K ft m Table A3 Diesel Generator Emissions Outlet Pollutant Conditions [1] Emission Rate (per stack) g/hp-hr g/sec lb/hr 0.2540 m Potential to Emit (total) ton/yr CO NOx 0.26 3.23 0.2161 2.6378 1.7150 20.9350 [1] PM/PM10 0.02 0.0145 0.1150 [1] 1.15E-02 SO2 0.08 0.0613 0.48645 [3] 4.86E-02 0.8694 [4a] 8.69E-02 8.69E-05 0 [5a] 8.69E-06 0.00E+00 VOC 0.13 Lead H2S 1.34E-05 0 H2SO4 Fluorides Total Reduced Sulfur 0.12 0.0004 0 0.1095 1.10E-05 0 0.0939 0.0003 0 [1] [6] 1.72E-01 2.09E+00 0.7449 [7] 7.45E-02 2.57E-03 0 [5b] 2.57E-04 0.00E+00 [6] Notes [ ]: 1. Vendor data - Caterpillar Specification Sheet 2. Assumed fuel oil heating value of 140,000 Btu/gal. USEPA, AP-42, Fifth Edition, Vol. I. Appendix A "Miscellaneous Data and Conversion Factors". September 1985. 3. Low sulfur fuel oil, 0.05%(wt). 4. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 3 "Stationary Internal Combustion Sources", Section 3.4 "Large Stationary Diesel and All Stationary Dual-fuel Engines". October 1996. a. Table 3.4-1 "Gaseous Emission Factors for Large Stationary Diesel and All Stationary Dual-Fuel Engines". 5. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 1 "External Combustion Sources", Section 1.3 "Fuel Oil Combustion". September 1998. a. Table 1.3-10 "Emission Factors for Trace Elements from Distillate Fuel Oil Combustion Sources". b. Table 1.3-11 "Emission Factors for Metals from Uncontrolled No. 6 Fuel Oil Combustion". 6. Hydrogen sulfide and total reduced sulfur emissions are insignificant and assumed to be zero. 7. Assumed 100% conversion of SO 2 to H2SO4. IPL Sutherland Unit 4 PSD Application Fire Pump Parameters Emissions Calculation and Stack Parameters Information Basis: Power Rating Heat Input Heating Value Fuel Burn Rate Hours of Operation Stack Exit Conditions Exhaust Flow Rate Exhaust Exit Velocity Exhaust Temperature Stack Diameter Stack Height 575 4.06 140,000 29.00 100 BHP[1] mmBtu/hr Btu/gal[2] gal/hr[1] hrs/yr 2,900 gal/yr [1] : 2,904 246.4992 918 6 12 Table A4 Fire Pump Emissions Outlet [1] Pollutant Conditions g/bhp-hr acfm ft/sec °F in ft 75.1329 765.372222 0.5000 3.6576 m/sec K ft m Potential to Emit ton/yr Emission Rate g/sec lb/hr CO NOx 0.75 4.90 0.1197 0.7824 0.9500 6.2100 [1] PM/PM10 0.08 0.0126 0.1000 [1] 5.00E-03 0.20445 [3] 1.02E-02 0.3654 [4a] 1.83E-02 3.65E-05 0 [5a] 1.83E-06 0.00E+00 SO2 0.16 0.0258 [1] 4.75E-02 3.11E-01 VOC 0.29 0.0460 Lead H2S 2.88E-05 0 4.60E-06 0 0.25 0.0394 0.3131 [7] 1.57E-02 0.0009 0 0.0001 0 1.08E-03 0 [5b] 5.41E-05 0.00E+00 H2SO4 Fluorides Total Reduced Sulfur 0.1524 m [6] [6] Notes [ ]: 1. Vendor data for the Clarke UF70 2. Assumed fuel oil heating value of 140,000 Btu/gal. USEPA, AP-42, Fifth Edition, Vol. I. Appendix A "Miscellaneous Data and Conversion Factors". September 1985. 3. Low sulfur fuel oil, 0.05%(wt). 4. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 3 "Stationary Internal Combustion Sources", Section 3.4 "Large Stationary Diesel and All Stationary Dual-fuel Engines". October 1996. a. Table 3.4-1 "Gaseous Emission Factors for Large Stationary Diesel and All Stationary Dual-Fuel Engines". 5. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 1 "External Combustion Sources", Section 1.3 "Fuel Oil Combustion". September 1998. a. Table 1.3-10 "Emission Factors for Trace Elements from Distillate Fuel Oil Combustion Sources". b. Table 1.3-11 "Emission Factors for Metals from Uncontrolled No. 6 Fuel Oil Combustion". 6. Hydrogen sulfide and total reduced sulfur emissions are insignificant and assumed to be zero. 7. Assumed 100% conversion of SO2 to H2SO4. IPL Sutherland Unit 4 PSD Application Fire Booster Pump Parameters Emissions Calculation and Stack Parameters Information Basis: Power Rating Heat Input Heating Value Fuel Burn Rate Hours of Operation Stack Exit Conditions Exhaust Flow Rate Exhaust Exit Velocity Exhaust Temperature Stack Diameter Stack Height 149 1.33 140,000 9.50 100 BHP[1] mmBtu/hr Btu/gal[2] gal/hr[1] hrs/yr 790.0 96.5625 1044 5 12 acfm ft/sec °F in ft 950 gal/yr [1] : 29.4322 835.372222 0.4167 3.6576 m/sec K ft m Table A5 Fire Booster Pump Emissions Outlet [1] Emission Rate Pollutant Conditions g/sec lb/hr g/bhp-hr Potential to Emit ton/yr CO NOx 0.33 5.20 0.0139 0.2153 0.1100 1.7090 [1] PM/PM10 0.19 0.0077 0.0610 [1] 3.05E-03 0.067 [3] 3.35E-03 0.1197 [4a] 5.99E-03 1.20E-05 0 [5a] 5.99E-07 0.00E+00 0.1026 [7] 5.13E-03 3.54E-04 0 [5b] 1.77E-05 0.00E+00 SO2 0.20 0.0084 VOC 0.36 0.0151 Lead H2S 3.64E-05 0 1.51E-06 0 0.31 0.0129 H2SO4 Fluorides Total Reduced Sulfur 0.0011 0 4.46E-05 0 0.1270 m [1] [6] [6] 5.50E-03 8.55E-02 Notes [ ]: 1. Vendor data for the Clarke UFG8 2. Assumed fuel oil heating value of 140,000 Btu/gal. USEPA, AP-42, Fifth Edition, Vol. I. Appendix A "Miscellaneous Data and Conversion Factors". September 1985. 3. Low sulfur fuel oil, 0.05%(wt). 4. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 3 "Stationary Internal Combustion Sources", Section 3.4 "Large Stationary Diesel and All Stationary Dual-fuel Engines". October 1996. a. Table 3.4-1 "Gaseous Emission Factors for Large Stationary Diesel and All Stationary Dual-Fuel Engines". 5. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 1 "External Combustion Sources", Section 1.3 "Fuel Oil Combustion". September 1998. a. Table 1.3-10 "Emission Factors for Trace Elements from Distillate Fuel Oil Combustion Sources". b. Table 1.3-11 "Emission Factors for Metals from Uncontrolled No. 6 Fuel Oil Combustion". 6. Hydrogen sulfide and total reduced sulfur emissions are insignificant and assumed to be zero. 7. Assumed 100% conversion of SO2 to H2SO4. IPL Sutherland Unit 4 PSD Application Gate Station Heater Emissions Calculation and Stack Parameters Information Basis: Heat Input Heating Value Fuel Burn Rate Hours of Operation 3.007 1,021 2945.15 8,760 mmBtu/hr[1] Btu/scf [2] scf/hr hrs/yr Molecular Weights Carbon (C) Oxygen (O) Nitrogen (N) 12.0107 g/gmol 15.9994 g/gmol 14.0067 g/gmol Stack Exit Conditions: Exhaust Flow Rate Exhaust Exit Velocity Exhaust Temperature Stack Diameter Stack Height 2,917 19.4076 700 15 20 lb/hr ft/sec °F in ft 26 Mscf/yr 1,429 5.9154 644.2611 1.25 6.0960 acfm m/sec K ft m 0.3810 m Table A6 Gate Station Heater Emissions Outlet Conditions [1] lb/mmBtu ppmv Pollutant Molecular Weight g/gmol Potential to Emit ton/yr Emission Rate g/sec lb/hr CO NOx 0.0471 0.0465 50 30 28.01 46.01 1.79E-02 1.76E-02 0.1418 0.1397 [1] PM/PM10 0.0074 -- -- 2.82E-03 0.0224 [3] 0.10 SO2 0.0006 -- -- 2.23E-04 0.0018 [3] 0.01 0.0162 [3] 0.07 6.45E-06 0 VOC 0.0054 Lead 4.90E-07 H2S -H2SO4 9.00E-04 Fluorides Total Reduced Sulfur --- -- -- 2.04E-03 [1] 0.62 0.61 --- --- 1.86E-07 0 1.47E-06 0 [3] -- -- 3.41E-04 2.71E-03 [5] 1.19E-02 0.0000 0 [4] 0.00E+00 0 --- --- 0.00E+00 0 [4] [4] Notes [ ]: 1. Vendor data - G.C Broach Co. (Dawn) 2. Assumed IPL natural gas lower heating value of 1021 Btu/scf. 3. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 1 "External Combustion Sources", Section 1.3 "Natural Gas Combustion". July 1998. Table 1.4-2 "Emission Factors for Criteria Pollutants and Greenhouse Gases from Natural Gas Combustion". 4. Hydrogen sulfide, total reduced sulfur, and fluorides emissions are insignificant and assumed to be zero since EPA has not derived an emission factor for either pollutant. 5. Assumed 100% conversion of SO 2 to H2SO4. IPL Sutherland Unit 4 PSD Application Cooling Tower - Linear Mechanical Draft Cooling Tower Emissions Basis (per Tower): Cycled Water TDS Drift Rate Cell Diameter Stack Height Circulating Water Flow Exhaust Air Flow (per fan) Number of Cells (per tower) Number of Towers PM10/TSP Fraction PM2.5/PM10 Fraction 3,500 0.0005 30 53 301,000 1,477,500 16 1 ppmw % ft ft gpm cfm No. No. 1.000 dimensionless [1] 0.600 dimensionless [2a] Calculations: TSP Emission (lb/hr) = Circulating Water Flow Rate (gpm) x (Drift Rate(%)/100) x Density of Circulating Water (lb/gal) x TDS (ppmw) x 60 min/hr TSP Emission (tpy) = TSP Emission (lb/hr) x Operating Hours (hrs/yr) x 1 ton/2,000 lb PM10 Emission (lb/hr) = TSP Emission (lb/hr) x PM10/TSP Fraction PM10 Emission (tpy) = PM10 Emission (lb/hr) x Operating Hours (hrs/yr) x 1 ton/2,000 lb PM2.5 Emission (lb/hr) = PM10 Emission (lb/hr) x PM2.5/PM10 Fraction PM2.5 Emission (tpy) = PM2.5 Emission (lb/hr) x Operating Hours (hrs/yr) x 1 ton/2,000 lb Table A7 Cooling Tower Emissions Number Activity of Towers No. Cooling Tower - Mechanical 1 Draft Calculations (for modeling): Exit Velocity (per cell) Exit Temperature (dry bulb) Hours of Operation hr/yr Circulating Water Flow gpm Drift Rate % Density Circ Water lb/gal TDS ppmw 8,760 301,000 0.0005 8.34 3,500 34.8372 ft/sec = 104.0000 °F = 10.6184 m/sec 40.0000 °C = Potential Uncontrolled Emissions tpy TSP PM10 PM2.5 11.55 11.55 6.93 Control Method Control Efficiency % NA 0 313.1500 °K Table A8 Cooling Tower Modeling Parameters EP Number [3] 253a-p Activity Cooling Tower - Mechanical Draft Cells per Tower No. 16 Controlled Emissions (per cell) lb/hr TSP PM10 PM2.5 Controlled Emissions (per cell) g/sec TSP PM10 PM2.5 0.1647 0.0208 0.1647 0.0988 0.0208 0.0125 Notes [ ]: 1. Assumed all particulate emissions are less than 10 microns. 2. South Coast AQMD, Air Guidance Book "Methodology to Calculate Particulate Matter (PM) 2.5 and PM 2.5 Significance Thresholds". Final. October 2006. a. Table A "Updated CEIDARS Table with PM2.5 Fractions". 3. IDNR Air Quality Construction Permit Forms ID Number. Potential Controlled Emissions tpy TSP PM10 PM2.5 11.55 11.55 6.93 IPL Sutherland Unit 4 PSD Application Aggregate Transfers Enclosed Drop Emission Calculation Emission Factors: TSP [1] EF (transfer) 0.0030 EF (crushing) 0.0054 PM-10 [1] 0.0011 0.0024 PM-2.5 [2] 1.65E-04 lb/ton 3.60E-04 lb/ton Table A9 Enclosed Transfers: Potential to Emit Calculations EU Number EP [3] Max Number Transfer Description Max Transferred ton/hr Transferred ton/yr 2000 17,520,000 2000 17,520,000 2000 17,520,000 Potential Uncontrolled Emissions TSP ton/yr PM-10 ton/yr PM-2.5 ton/yr 26.2800 9.6360 1.4454 26.2800 9.6360 1.4454 26.2800 9.6360 1.4454 26.2800 9.6360 1.4454 105.1200 38.5440 5.7816 26.2800 9.6360 1.4454 Control Control Method Efficiency % Potential Controlled Emissions [4] Emission Rates Flow Modeling Parameters Discharge Discharge Exhaust Exhaust Exhaust TSP ton/yr PM-10 ton/yr PM-2.5 ton/yr TSP lb/hr PM-10 lb/hr PM-2.5 lb/hr Rate acfm Type [5] V/H Height ft Diameter ft Velocity [6] fps Temperature [7] °K 0.0263 0.0096 0.0014 6.00E-03 2.20E-03 3.30E-04 75,000 V 12 6.5 38 0 0.0263 0.0096 0.0014 0.0263 0.0096 0.0014 6.00E-03 2.20E-03 3.30E-04 75,000 V 12 6.5 38 0 0.0263 0.0096 0.0014 0.1051 0.0385 0.0058 2.40E-02 8.80E-03 1.32E-03 7,500 V 12 3.5 13 0 0.0263 0.0096 0.0014 1.20E-02 4.40E-03 6.60E-04 7,500 V 55 3.5 13 0 2.28E-02 8.36E-03 1.25E-03 7,500 V 65 3.5 13 0 7.20E-03 2.64E-03 3.96E-04 7,500 V 12 3.5 13 0 3.60E-03 1.32E-03 1.98E-04 7,500 V 12 3.5 13 0 3.46E-02 1.37E-02 2.05E-03 30,000 V 125 4.0 40 0 1.44E-02 5.28E-03 7.92E-04 53,000 V 190 5.3 40 0 4.80E-03 1.76E-03 2.64E-04 7,500 V 12 3.5 13 0 1.20E-03 4.40E-04 6.60E-05 7,500 V 35 3.5 13 0 1.20E-03 4.40E-04 6.60E-05 7,500 V 55 3.5 13 0 6.00E-04 2.20E-04 3.30E-05 12,000 V 65 2.5 40 0 Coal Rotary Car Dumper Building (a) Unload from railcars to Hopper HPR-1 at rotary car dumper. Dust Collector 99.90 Dust Collector 99.90 Dust Collector 99.90 254 254a 254 254b 255a 255 255b 255 Transfer from Hopper HPR-1 to to Belt Feeder BF-2. 2000 17,520,000 26.2800 9.6360 1.4454 Dust Collector 99.90 0.0263 0.0096 0.0014 255c 255 Transfer from Belt Feeder BF-1 to Belt Conveyor BC-1. 2000 17,520,000 26.2800 9.6360 1.4454 Dust Collector 99.90 0.0263 0.0096 0.0014 255d 255 Transfer from Belt Feeder BF-2 to Belt Conveyor BC-1. 2000 17,520,000 Dust Collector 99.90 Rotary Car Dumper Building (b) Unload from railcars to Hopper HPR-1 at rotary car dumper. Rotary Railcar Dump Vault Transfer from Hopper HPR-1 to to Belt Feeder BF-1. Transfer Tower TT-1 Transfer from Belt Conveyor BC-1 to Belt Conveyor BC-4. 256b 256 262a 262 Transfer from Belt Conveyor BC-4 to Belt Conveyor BC-6. 262 Transfer from Belt Conveyor BC-4 to Belt Conveyor BC-7. 26.2800 9.6360 1.4454 52.5600 19.2720 2.8908 52.5600 19.2720 2.8908 4000 35,040,000 99.8640 36.6168 5.4925 1333 11,680,000 17.5200 6.4240 17.5200 6.4240 Transfer Tower TT-2 0.0263 0.0096 0.0014 0.0526 0.0193 0.0029 0.0526 0.0193 0.0029 Dust Collector 99.90 0.0999 0.0366 0.0055 0.9636 Dust Collector 99.90 0.0175 0.0064 0.0010 0.9636 Dust Collector 99.90 0.0175 0.0064 0.0010 0.0005 1333 11,680,000 262g 262 Transfer from Belt Conveyor BC-4 to Belt Conveyor BC-10. 667 5,840,000 8.7600 3.2120 0.4818 Dust Collector 99.90 0.0088 0.0032 262h 262 Transfer from Belt Conveyor BC-4 to Belt Conveyor BC-11. 667 5,840,000 8.7600 3.2120 0.4818 Dust Collector 99.90 0.0088 0.0032 0.0005 262c 262 Transfer from Belt Conveyor BC-8 to Belt Conveyor BC-10. 1200 10,512,000 15.7680 5.7816 0.8672 Dust Collector 99.90 0.0158 0.0058 0.0009 262d 262 Transfer from Belt Conveyor BC-8 to Belt Conveyor BC-11. 1200 10,512,000 15.7680 5.7816 0.8672 Dust Collector 99.90 0.0158 0.0058 0.0009 262e 262 Transfer from Belt Conveyor BC-9 to Belt Conveyor BC-10. 600 5,256,000 7.8840 2.8908 0.4336 Dust Collector 99.90 0.0079 0.0029 0.0004 262f 262 Transfer from Belt Conveyor BC-9 to Belt Conveyor BC-11. 600 5,256,000 7.8840 2.8908 0.4336 Dust Collector 99.90 0.0079 0.0029 0.0004 63.0720 23.1264 3.4690 0.0631 0.0231 0.0035 31.5360 31.5360 11.5632 11.5632 1.7345 1.7345 0.0315 0.0315 0.0116 0.0116 0.0017 0.0017 31.5360 11.5632 1.7345 0.0315 0.0116 0.0017 15.7680 5.7816 0.0158 0.0058 0.0009 262b Pile 3 Vault 264a 264 264b 264 Transfer from Reclaim Hopper RH-2 to Belt Feeder BF-4. Transfer from Belt Feeder BF-4 to Belt Conveyor BC-8. 2400 2400 21,024,000 21,024,000 Transfer from Reclaim Hopper RH-3 to Belt Feeder BF-5. 1200 10,512,000 Transfer from Belt Feeder BF-5 to Belt Conveyor BC-9. 1200 10,512,000 15.7680 5.7816 0.8672 Dust Collector 99.90 0.0158 0.0058 0.0009 151.3728 59.9184 8.9878 0.1514 0.0599 0.0090 1200 10,512,000 15.7680 5.7816 0.8672 Dust Collector 99.90 0.0158 0.0058 0.0009 15.7680 5.7816 0.8672 Dust Collector 99.90 0.0158 0.0058 0.0009 0.0009 Pile 4 Vault 266a 266 266b 266 Crusher House CH-1 267a 267 Transfer from Belt Conveyor BC-10 to Crusher Surge Bin SB-1. 267 Transfer from Belt Conveyor BC-11 to Crusher Surge Bin SB-1. Dust Collector Dust Collector 99.90 99.90 0.8672 Dust Collector 99.90 1200 10,512,000 267c 267 Transfer from surge bin SB-1 to Belt Feeder BF-6. 1200 10,512,000 15.7680 5.7816 0.8672 Dust Collector 99.90 0.0158 0.0058 267d 267 Transfer from surge bin SB-1 to Belt Feeder BF-7. 1200 10,512,000 15.7680 5.7816 0.8672 Dust Collector 99.90 0.0158 0.0058 0.0009 267e 267 Crusher CR-1. 1200 10,512,000 28.3824 12.6144 1.8922 Dust Collector 99.90 0.0284 0.0126 0.0019 267b 267f 267 Crusher CR-2. 1200 10,512,000 28.3824 12.6144 1.8922 Dust Collector 99.90 0.0284 0.0126 0.0019 267g 267 Transfer from Belt Feeder BF-6 through Crusher CR-1 to Belt Conveyor BC-13. 1200 10,512,000 15.7680 5.7816 0.8672 Dust Collector 99.90 0.0158 0.0058 0.0009 267h 267 Transfer from Belt Feeder BF-7 through Crusher CR-2 to Belt Conveyor BC-12. 1200 10,512,000 15.7680 5.7816 0.8672 Dust Collector 99.90 0.0158 0.0058 0.0009 63.0720 23.1264 3.4690 0.0631 0.0231 0.0035 Transfer Tower TT-4 268a 268 Transfer from Belt Conveyor BC-12 to Tripper Conveyors BC-14. 600 5,256,000 7.8840 2.8908 0.4336 Dust Collector 99.90 0.0079 0.0029 0.0004 268b 268 Transfer from Belt Conveyor BC-12 to Tripper Conveyors BC-15. 600 5,256,000 7.8840 2.8908 0.4336 Dust Collector 99.90 0.0079 0.0029 0.0004 268c 268 Transfer from Belt Conveyor BC-13 to Tripper Conveyors BC-14. 600 5,256,000 7.8840 2.8908 0.4336 Dust Collector 99.90 0.0079 0.0029 0.0004 268d 268 Transfer from Belt Conveyor BC-13 to Tripper Conveyors BC-15. 600 5,256,000 7.8840 2.8908 0.4336 Dust Collector 99.90 0.0079 0.0029 0.0004 268e 268 Transfer from Belt Conveyor BC-14 to Coal Silos. 1200 10,512,000 15.7680 5.7816 0.8672 Dust Collector 99.90 0.0158 0.0058 0.0009 268f 268 Transfer from Belt Conveyor BC-15 to Coal Silos. 1200 10,512,000 Dust Collector 99.90 Pile 2 Vault 15.7680 5.7816 0.8672 21.0240 7.7088 1.1563 0.0158 0.0058 0.0009 0.0210 0.0077 0.0012 269a 269 Transfer from Reclaim Hopper RH-4 to BF-8. 400 3,504,000 5.2560 1.9272 0.2891 Dust Collector 99.90 0.0053 0.0019 0.0003 269b 269 Transfer from Belt Feeder BF-8 to Belt Conveyor BC-5A. 400 3,504,000 5.2560 1.9272 0.2891 Dust Collector 99.90 0.0053 0.0019 0.0003 269c 269 Transfer from Reclaim Hopper RH-5 to BF-9. 400 3,504,000 5.2560 1.9272 0.2891 Dust Collector 99.90 0.0053 0.0019 0.0003 269d 269 Transfer from Belt Feeder BF-9 to Belt Conveyor BC-5A. 400 3,504,000 5.2560 1.9272 0.2891 Dust Collector 99.90 0.0053 0.0019 0.0003 5.2560 1.9272 0.2891 0.0053 0.0019 0.0003 400 3,504,000 5.2560 1.9272 0.2891 Dust Collector 99.90 0.0053 0.0019 0.0003 Transfer Tower TT-3 270 270 Transfer from Belt Conveyor BC-5A to Belt Conveyor BC-5B. Existing Transfer Tower 271 271 272 272 Transfer from Belt Conveyor BC-5B to Hopper HPR-2 400 3,504,000 200 1,752,000 Truck Loadout Enclosure Transfer from the Hopper HPR-2 to future truck load out Total Uncontrolled Emissions 5.2560 1.9272 0.2891 5.2560 1.9272 0.2891 2.6280 0.9636 0.1445 2.6280 0.9636 0.1445 653.32 243.97 36.59 Dust Collector 99.90 Dust Collector 99.90 Total Controlled Emissions 0.0053 0.0019 0.0003 0.0053 0.0019 0.0003 0.0026 0.0010 0.0001 0.0026 0.0010 0.0001 0.65 0.24 0.04 Table A9 Enclosed Transfers: Potential to Emit Calculations EU EP Number [3] Number Transfer Description Max Max Transferred ton/hr Transferred ton/yr 600 5,256,000 600 5,256,000 Potential Uncontrolled Emissions TSP ton/yr PM-10 ton/yr PM-2.5 ton/yr 7.8840 2.8908 0.4336 7.8840 2.8908 0.4336 7.8840 2.8908 0.4336 7.8840 2.8908 0.4336 Control Control Method Efficiency [4] % Potential Controlled Emissions Emission Rates Flow Modeling Parameters Discharge Discharge Exhaust Exhaust Exhaust TSP ton/yr PM-10 ton/yr PM-2.5 ton/yr TSP lb/hr PM-10 lb/hr PM-2.5 lb/hr Rate acfm Type [5] V/H Height ft Diameter ft Velocity [6] fps Temperature [7] °K 0.0079 0.0029 0.0004 1.80E-03 6.60E-04 9.90E-05 75,000 V 35 6.5 38 0 0.0079 0.0029 0.0004 0.0079 0.0029 0.0004 1.80E-03 6.60E-04 9.90E-05 75,000 V 35 6.5 38 0 0.0079 0.0029 0.0004 5.40E-03 1.98E-03 2.97E-04 7,500 V 12 3.5 13 0 2.40E-03 8.80E-04 1.32E-04 7,500 V 12 3.5 13 0 1.20E-02 4.40E-03 6.60E-04 1,500 H 110 1 0.0033 0 2.40E-02 8.80E-03 1.32E-03 1,500 H 110 1 0.0033 0 3.93E-05 3.93E-05 3.93E-05 3.93E-05 6.25E-04 1.44E-05 1.44E-05 1.44E-05 1.44E-05 2.29E-04 2.16E-06 2.16E-06 2.16E-06 2.16E-06 3.44E-05 4,000 4,000 2,000 20,000 20,000 H H H H H 12 12 105 23 23 1.25 1.25 1.1 3.5 3.5 0.0033 0.0033 0.0033 0.0033 0.0033 0 0 0 0 0 3.93E-05 3.93E-05 6.25E-04 1.44E-05 1.44E-05 2.29E-04 2.16E-06 2.16E-06 3.44E-05 1,350 1,350 2,000 H H H 28 28 105 0.8 0.8 1.1 0.0033 0.0033 0.0033 0 0 0 1.20E-03 4.40E-04 6.60E-05 1,000 H 114.99 1.1 0.0033 0 1.20E-03 3.02E-05 4.40E-04 1.11E-05 6.60E-05 1.66E-06 5,000 5,000 H H 114.99 279.99 1.1 1.1 0.0033 0.0033 0 0 1.41E-05 5.17E-06 7.76E-07 5,000 H 77 1.1158 0.0033 0 Limestone Railcar/Truck Unloading Building (a) Unload from railcars to hopper at unloader. Dust Collector 99.90 Dust Collector 99.90 0.0237 0.0087 0.0013 0.3252 Dust Collector 99.90 0.0059 0.0022 0.0003 0.3252 Dust Collector 99.90 0.0059 0.0022 0.0003 0.0003 280 280a 280 280b 23.6520 8.6724 1.3009 281a 281 Transfer from Hopper HPR-1 to Belt Feeder FDR-1. 450 3,942,000 5.9130 2.1681 281b 281 Transfer from Hopper HPR-1 to Belt Feeder FDR-2. 450 3,942,000 5.9130 2.1681 Railcar/Truck Unloading Building (b) Unload from railcars to hopper at unloader. Railcar/Truck Unloading Vault 281c 281 Transfer from Belt Feeder FDR-1 to Belt Conveyor CVY-1. 450 3,942,000 5.9130 2.1681 0.3252 Dust Collector 99.90 0.0059 0.0022 281d 281 Transfer from Belt Feeder FDR-2 to Belt Conveyor CVY-1. 450 3,942,000 5.9130 2.1681 0.3252 Dust Collector 99.90 0.0059 0.0022 0.0003 10.5120 3.8544 0.5782 0.0105 0.0039 0.0006 Pile Vault 283a 283 Transfer from Hopper HPR-2 to Belt Feeder FDR-3. 200 1,752,000 2.6280 0.9636 0.1445 Dust Collector 99.90 0.0026 0.0010 0.0001 283b 283 Transfer from Hopper HPR-3 to Belt Feeder FDR-4. 200 1,752,000 2.6280 0.9636 0.1445 Dust Collector 99.90 0.0026 0.0010 0.0001 283c 283 Transfer from Belt Feeder FDR-3 to Belt Conveyor CVY-2. 200 1,752,000 2.6280 0.9636 0.1445 Dust Collector 99.90 0.0026 0.0010 0.0001 283d 283 Transfer from Belt Feeder FDR-4 to Belt Conveyor CVY-2. 200 1,752,000 2.6280 0.9636 0.1445 Dust Collector 99.90 0.0026 0.0010 0.0001 5.2560 1.9272 0.2891 0.0526 0.0193 0.0029 5.2560 1.9272 0.2891 0.0526 0.0193 0.0029 Silo 1 284 284 285a 285b 285 285 Transfer from Belt Conveyor CVY-2 to Limestone Silo 1. 400 3,504,000 10.5120 3.8544 0.5782 400 400 3,504,000 5.2560 1.9272 3,504,000 5.2560 65.70 Silo 2 Transfer from Belt Conveyor CVY-2 to Belt Conveyor CVY-3. Transfer from Belt Conveyor CVY-3 to Limestone Silo 2. Total Uncontrolled Emissions Saleable Fly Ash 286 286 287 288 288 286a 286b 287 288a 288b Pneumatic Conveyor Blower Exhaust Pneumatic Conveyor Blower Exhaust Ash Silo bin vent fan Ash storage building Vent Fan Ash storage building Vent Fan 1.31 1.31 1.31 1.31 20.84 11,476 11,476 11,476 11,476 182,558 Total Uncontrolled Emissions Waste Fly Ash 289 289 290 289a 289b 290 Pneumatic Conveyor Blower Exhaust Pneumatic Conveyor Blower Exhaust Ash silo bin vent fan 1.31 1.31 20.84 11,476 11,476 182,558 Total Uncontrolled Emissions PAC (Mercury) 291 291 Transfer to Silo 40 350,400 Total Uncontrolled Emissions Bin Vent 99.00 0.1051 0.0385 0.0058 0.2891 Bin Vent 99.00 0.0526 0.0193 0.0029 1.9272 0.2891 Bin Vent 99.00 0.0526 0.0193 0.0029 24.09 3.61 0.21 0.08 0.01 0.0172 0.0172 0.0172 0.0172 0.2738 0.0063 0.0063 0.0063 0.0063 0.1004 0.0009 0.0009 0.0009 0.0009 0.0151 1.72E-04 1.72E-04 1.72E-04 1.72E-04 2.74E-03 6.31E-05 6.31E-05 6.31E-05 6.31E-05 1.00E-03 9.47E-06 9.47E-06 9.47E-06 9.47E-06 1.51E-04 0.3427 0.1257 0.0188 3.43E-03 1.26E-03 1.88E-04 0.0172 0.0172 0.2738 0.0063 0.0063 0.1004 0.0009 0.0009 0.0151 1.72E-04 1.72E-04 2.74E-03 6.31E-05 6.31E-05 1.00E-03 9.47E-06 9.47E-06 1.51E-04 0.3083 0.1130 0.0170 3.08E-03 1.13E-03 1.70E-04 0.5256 0.1927 0.0289 5.26E-03 1.93E-03 2.89E-04 0.5256 0.1927 0.0289 5.26E-03 1.93E-03 2.89E-04 0.5256 0.0132 0.1927 0.0048 0.0289 0.0007 5.26E-03 1.32E-04 1.93E-03 4.84E-05 2.89E-04 7.27E-06 0.5388 0.1976 0.0296 5.39E-03 1.98E-03 2.96E-04 0.0062 0.0023 0.0003 6.18E-05 2.26E-05 3.40E-06 0.0062 0.0023 0.0003 6.18E-05 2.26E-05 3.40E-06 Total Controlled Emissions Bin Vent Bin Vent Bin Vent Bin Vent Bin Vent 99.00 99.00 99.00 99.00 99.00 Total Controlled Emissions Bin Vent Bin Vent Bin Vent 99.00 99.00 99.00 Total Controlled Emissions Bin Vent 99.00 Total Controlled Emissions Sorbent (H2SO4) 292 293 292 293 Transfer to Day Silo Transfer to Long Term Silo 40 1.01 350,400 8,808 Total Uncontrolled Emissions Lime (Water Treatment) 294 294 Transfer of Lime 0.47 4,117 Total Uncontrolled Emissions Bin Vent Bin Vent 99.00 99.00 Total Controlled Emissions Bin Vent 99.00 Total Controlled Emissions Notes [ ]: 1. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 11 "Mineral Products Industry", Section 11.19.2 "Crushed Stone Processing and Pulverized Mineral Processing". Table 11.19.2-2 "Emission Factors for Crushed Stone Processing Operations". August 2004. 2. Western Governors' Association Western Regional Air Partnership (WRAP). "Background Document for Revisions to Fine Fraction Ratios Used for AP-42 Fugitive Dust Emission Factors". Final. November 1, 2006. Prepared by Midwest Research Institute. It was assumed that the PM2.5/PM10 ratio of 0.15 recommended for the transfer of aggregate associated with conveyor transfer points subject to an open atmosphere is applicable to an enclosed conveyor transfer point. 3. IDNR Air Quality Construction Permit Forms ID Number. 4. Dust Collectors - Vendor Data Bin Vent - BACT 5. V - Vertical Discharge, H - Horizontal Discharge 6. For horizontal releases, the exhaust velocity was set to 0.001 m/s per the "AERMOD Implementation Guide", dated September 27, 2005. 7. Represents an ambient temperature release. IPL Sutherland Unit 4 PSD Application Biomass Transfers Grain Handling Emission Calculation Emission Factors: EF (debaler/chipper) EF (transfer) TSP [1] 0.0270 0.0140 PM-10 [1] 0.0270 0.0140 PM-2.5 [2] 4.05E-03 lb/hr 2.10E-03 lb/hr Table A10 Biomass Transfers: Potential to Emit Calculations EU Number Biomass 295 296 EP [3] Number of Number 295 296 Transfer Description Operations No. Biomass Building (Line 1) Potential Uncontrolled Emissions TSP ton/yr PM-10 ton/yr PM-2.5 ton/yr Control Control Method Efficiency % Potential Controlled Emissions [4] Exhaust Exhaust Exhaust PM-10 ton/yr PM-2.5 ton/yr TSP lb/hr PM-10 lb/hr PM-2.5 lb/hr Rate acfm Type [5] V/H Height ft Diameter ft Velocity fps Temperature [6] °K 4.14E-06 4.14E-06 6.21E-07 24,800 V 46.42 2.5 84.2036 0 4.14E-06 4.14E-06 6.21E-07 24,800 V 46.42 2.5 84.2036 0 0.3022 0.3022 0.0453 1.813E-05 1.813E-05 2.720E-06 1 0.1183 0.1183 0.0177 Cyclone & Baghouse 99.994 7.096E-06 7.096E-06 1.064E-06 Transfer 3 0.1840 0.1840 0.0276 Cyclone & Baghouse 99.994 1.104E-05 1.104E-05 1.656E-06 Biomass Building (Line 2) 0.3022 0.3022 0.0453 1.813E-05 1.813E-05 2.720E-06 Debaler/Chipper 1 0.1183 0.1183 0.0177 Cyclone & Baghouse 99.994 7.096E-06 7.096E-06 1.064E-06 Transfer 3 0.1840 0.1840 0.0276 Cyclone & Baghouse 99.994 1.104E-05 1.104E-05 1.656E-06 0.6044 0.6044 0.0907 3.63E-05 3.63E-05 5.44E-06 Total Uncontrolled Emissions Total Controlled Emissions Notes [ ]: 1. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 9 "Food and Agricultural Industries", Section 9.3.2 "Grain Harvesting". Table 9.3.2 "Emission Rates/Factors from Grain Harvesting". February 1980. Section 9.3.2 stated that the emission rates/factors in Table 9.3.2 were for particulate with a mean aerodynamic diameter of <7 micrometers, as such, all emissions were considered to be TSP and PM10. 2. Western Governors' Association Western Regional Air Partnership (WRAP). "Background Document for Revisions to Fine Fraction Ratios Used for AP-42 Fugitive Dust Emission Factors". Final. November 1, 2006. Prepared by Midwest Research Institute. It was assumed that the PM2.5/PM10 ratio of 0.15 recommended for the transfer of aggregate associated with conveyor transfer points subject to an open atmosphere is applicable to an enclosed conveyor transfer point. 3. IDNR Air Quality Construction Permit Forms ID Number. 4. Dust Collectors - Vendor Data Bin Vent - BACT 5. V - Vertical Discharge, H - Horizontal Discharge 6. Represents an ambient temperature release. Flow Modeling Parameters Discharge Discharge TSP ton/yr Debaler/Chipper Emission Rates IPL Sutherland Unit 4 PSD Application Aggregate Transfers Continuous Conveyor Drop (Open to Atmosphere) Emission Calculation Emission Factor (EF) Equation [1] EF = k(0.0032) (U/5)1.3/(M/2)1.4 Equation 1 [1] Where: EF = particulate emission factor (lb/ton) k = particle size multiplier (dimensionless) U = mean wind speed (mph) M = material moisture content (%) Calculated Emission Factors: TSP EF (lb/ton) 5.721E-04 7.326E-04 5.446E-03 PM-10 2.706E-04 3.465E-04 2.576E-03 0.74 0.35 0.053 10.0 10.5 8.8 2.1 PM-2.5 4.098E-05 5.247E-05 3.900E-04 for TSP for PM-10 for PM-2.5 [2] Avg PRB coal Avg ILL coal Limestone [3] [3] [1a] for PRB coal for ILL coal for limestone Table A11 Atmospheric Transfers: Potential to Emit Calculations EU Number EP Number [4] Transfer Description Max Max Potential Uncontrolled Emissions Control Transferred ton/hr Transferred ton/yr TSP ton/yr PM-10 ton/yr PM-2.5 ton/yr Control Method 4000 4000 4000 4000 35,040,000 35,040,000 35,040,000 35,040,000 12.8357 12.8357 10.0238 12.8357 6.0710 6.0710 4.7410 6.0710 0.9193 0.9193 0.7179 0.9193 Wet Suppression Wet Suppression Telescopic Chute/ Wet Suppression Telescopic Chute/ Wet Suppression 48.53 22.95 3.48 14.3114 6.7689 1.0250 14.3114 6.7689 1.0250 Potential Controlled Emissions Emission Rates Modeling Parameters Release Height PM-2.5 lb/hr ft Efficiency [5] % TSP ton/yr PM-10 ton/yr PM-2.5 ton/yr TSP lb/hr PM-10 lb/hr 95.00 95.00 98.75 98.75 0.6418 0.6418 0.1253 0.1604 0.3035 0.3035 0.0593 0.0759 0.0460 0.0460 0.0090 0.0115 1.47E-01 1.47E-01 2.86E-02 3.66E-02 6.93E-02 6.93E-02 1.35E-02 1.73E-02 1.05E-02 1.05E-02 2.05E-03 2.62E-03 1.57 0.74 0.11 0.0894 0.0423 0.0064 2.04E-02 9.66E-03 1.46E-03 0.09 0.04 0.01 Initial Sigma y ft Initial Sigma z ft 6 N/A N/A N/A 1.3944 N/A N/A N/A 2.7920 N/A N/A N/A N/A N/A N/A Coal 259a/b 260a/b and 26a-d [6] 263 [6] 265 [6] 259 260 263 265 Transfer from Belt Conveyor BC-4 to SR-1 Boom Conveyor/Belt Conveyor BC-4 Transfer from SR-1 Boom Conveyor to Stockout Pile 2-South Transfer from Belt Conveyor BC-6 to Coal Stockout Pile 3. Transfer from Belt Conveyor BC-7 to Coal Stockout Pile 4. Total Uncontrolled Emissions Total Controlled Emissions Limestone (Scrubber) [6] [6] Transfer from Receiving Conveyor CVY-1 to Storage Pile 600 5,256,000 Total Uncontrolled Emissions Telescopic Chute/ Wet Suppression/ Partial Enclosure Notes [ ]: 1. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 13 "Miscellaneous Sources", Section 13.2.4 "Aggregate Handling and Storage Piles". November 2006. a. Table 13.2.4-1 "Typical Silt and Moisture Contents of Materials at Various Industries". 2. U.S. Department of Commerce. "Local Climatological Data - Annual Summary with Comparative Data". Des Moines Surface Station (KDSM) [WBAN: 14933], Des Moines, IA. NCDC, NESDIS, NOAA. 2006. 3. Average moisture content for PRB and Illinois coal based on boiler performance data 4. IDNR Air Quality Construction Permit Forms ID Number. 5. Wet Suppression - An average of the control efficiency for TSP and PM10 emissions from conveyor transfer points. AP-42, Section 11.19.2 (Note [1])) Telescopic Chute - USEPA. "Stationary Source Control Techniques Document for Fine Particulate Matter". EPA Contract No. 68-D-98-026. Submitted by EC/R Incorporated. October, 1998. Bin Vent - BACT Partial Enclosure - Assumed control efficiency 6. Atmospheric transfer emission points included in coal pile summary as drops onto the pile, not as individual point sources. 99.38 Total Controlled Emissions IPL Sutherland Unit 4 PSD Application Conveyors Partially Covered Emission Calculation Emission Factors: [1] TSP 0.0034 EF PM-10 [1] 0.0002 PM-2.5 [2] 0.00003 lb/ton Basis: Emissions based on maximum rated capacity of conveyor. Table A12 Conveyors: EP Number [3] NA Modeling ID Number BC4-(1-80) Conveyor BC-4 Activity Max Transferred ton/hr ton/yr 4,000 35,040,000 Conveyor Length Width ft in 958 72 Total Uncontrolled Emissions (tons/yr) Potential to Emit Calculations Potential Uncontrolled Emissions TSP PM-10 PM-2.5 Control Method ton/yr ton/yr ton/yr 59.5680 3.5040 0.5256 59.57 3.50 0.53 Wet Supression Control Potential Controlled Emissions Number Efficiency [4a] TSP PM-10 PM-2.5 of Sources % ton/yr ton/yr ton/yr # 95% Total Controlled Emissions (tons/yr) 2.9784 0.1752 0.0263 2.98 0.18 0.03 80 Modeling Parameters Emission Rates (per source) Release TSP PM-10 PM-2.5 Height lb/hr lb/hr lb/hr ft 8.5000E-03 Notes [ ]: 1. USEPA, AP-42, Fourth Edition, Vol. I. Chapter 8 "Mineral Products Industry", Section 8.19.2 "Crushed Stone Processing". September 1985. a. Table 8.19.2-2 " Uncontrolled Particulate Emission Factors for Open Dust Sources at Crushed Stone Plants" 2. Western Governors' Association Western Regional Air Partnership (WRAP). "Background Document for Revisions to Fine Fraction Ratios Used for AP-42 Fugitive Dust Emission Factors". Final. November 1, 2006. Prepared by Midwest Research Institute. It was assumed that the PM2.5/PM10 ratio of 0.15 recommended for the transfer of aggregate associated with conveyor transfer points subject to an open atmosphere is applicable to an enclosed conveyor transfer point. 3. IDNR Air Quality Construction Permit Forms ID Number. 4. Texas Commission on Environmental Quality. Air Permit Division. "Rock Crushing Plants". Draft RG 058. February 2002. a. Table 7 "Controls". 5.0000E-04 7.5000E-05 1.5 Initial Sigma y ft Initial Sigma z ft Material Handled 5.5814 0.6977 Coal IPL Sutherland Unit 4 PSD Application Vehicle Traffic Paved Road Emissions Calculation Emission Factor (EF) Equation [1] EF = [k * (sL/2)^0.65 * (W/3)^1.5 - C] * (1-(P/(4*N))) Where: EF = particulate emission factor, lb/ton k = particle size multiplier = sL = surface silt loading, g/m 2 = W = average vehicle weight, tons = C = emission factor for 1980's vehicle fleet exhaust, brake & tire wear P = number of days per year with at least 0.01 in of precipitation N = number of days in the averaging period [1a] 0.082 for TSP 0.016 for PM-10 [1a] 0.0024 for PM-2.5 [1a] 0.6 Ubiquitous Baseline (ADT <500) [1c] see Table below 0.00047 for TSP & PM-10 [1b] 0.00036 for PM-2.5 [1b] [2] 111.8 365 Basis: Short Term emissions based on maximum usage/generation rates. Table A13 Vehicle Traffic Counts: North Gate Haul Road Truck Capacity Round Trips Empty Vehicle Weight Full Vehicle Weight One-way Distance Trucks per Day PRB1-100 IL1-100 4 29 1 1 1 1 1 1 14 21 1 2 4 6 Material Limestone Sorbent Powdered Activated Carbon Ammonia (Aqueous @ 19% NH3) Sellable Fly Ash Non-sellable Fly Ash Bottom Ash Total Byproducts (gypsum) 7 [3] Switch Grass Lime 24 1 [3] Coal Sales 24 82 [3] Total --> 25 16,060 11.75 36.75 0.4791 West Gate Haul Road Truck Capacity Round Trips Empty Truck Weight Full Truck Weight One-way Distance tons truck/year tons tons miles 25 29,930 11.75 36.75 0.8618 tons truck/year tons tons miles 1 126 Table A14 Vehicle Traffic: EP Number [4] Transport Activity Average Vehicle Weight tons TSP Emission Factor lbs/VMT PM-10 Emission Factor lbs/VMT PM-2.5 Emission Factor lbs/VMT Vehicle Mile Traveled VMT/yr Potential Uncontrolled Emissions Control Method TSP ton/yr PM-10 ton/yr PM-2.5 ton/yr Potential to Emit Calculations Potential Controlled Emissions Control TSP PM-10 PM-2.5 Efficiency [5] % ton/yr ton/yr ton/yr Number of Sources # TSP lb/hr Emission Rates (per volume source) PM-10 PM-10 lb/hr g/s PM-2.5 lb/hr Release Height [6] ft Initial Sigma y ft Initial Sigma z [7] ft 278 North Gate Haul Road 24.3 0.80 0.15 0.02 15,387.96 6.12 1.19 0.18 Water Flushing 80.00 1.22 0.24 0.035 52 5.3727E-03 1.0460E-03 1.3179E-04 1.5509E-04 3.4442 22.8896 10.6047 279 West Gate Haul Road 24.3 0.80 0.15 0.02 51,589.85 20.51 3.99 0.59 Water Flushing 80.00 4.10 0.80 0.118 93 1.0072E-02 1.9608E-03 2.4705E-04 2.9073E-04 3.4442 22.8896 10.6047 26.63 5.18 0.77 5.33 1.04 0.15 Total Uncontrolled Emissions (tons/yr) Total Controlled Emissions (tons/yr) Notes [ ]: 1. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 13 "Miscellaneous Sources", Section 13.2.1 "Paved Roads". November 2006 (Updated March 7, 2007). a. Table 13.2.1-1 "Particle Size Multipliers for Paved Road Equation" b. Table 13.2.1-2 "Emission Factor for 1980's Vehicle Fleet Exhaust, Brake Wear and Tire Wear" 2 c. Table 13.2.1-3 "Ubiquitous Silt Loading Default Values with Hot Spot Contributions from Anti-Skid Abrasives (g/m )" 2. U.S. Department of Commerce. "Local Climatological Data - Annual Summary with Comparative Data". Des Moines Surface Station (KDSM) [WBAN: 14933], Des Moines, IA. NCDC, NESDIS, NOAA. 2006. 3. A total of 64 trucks can be used in any combination of allotment for gypsum, switch grass, and coal sales. 4. IDNR Air Quality Construction Permit Forms ID Number. 5. Water flushing (80%) based on Ohio EPA RACM 1980 document. 6. Assumed a 285/75R24.5 tire. 7. Assumed a truck height of 22.8 ft. IPL Sutherland Unit 4 PSD Application Bulldozing Traffic Unpaved Road Emissions Calculation Emission Factor (EF) Equation [1] EF = k * (s/12)^a * (W/3)^b * ((365-p)/365) Where: EF = particulate emission factor, lb/ton k = particle size multiplier = a = constant = s = surface material silt content, % = b = constant = W = average vehicle weight, tons = p = number of days per year with at least 0.01 in of precipitation 4.9 for TSP 1.5 for PM-10 0.15 for PM-2.5 0.7 for TSP 0.9 for PM10 & PM2.5 2.2 for coal (as received) AP-42 13.2.4 3.9 limestone AP-42 13.2.4 0.45 for TSP, PM10, & PM2.5 see Table below [2] 111.8 Basis: Short Term emissions based on maximum usage/generation rates. Bulldozing Hours Average Speed Empty Vehicle Weight (FE Loader) Full Vehicle Weight (FE Loader) 8.00 4 50 50 hrs/day/pile mph tons tons Table A15 Vehicle Traffic: EP Number [3] Transport Activity Average Vehicle Weight tons TSP Emission Factor lbs/VMT PM-10 Emission Factor lbs/VMT PM-2.5 Emission Factor lbs/VMT Vehicle Mile Traveled VMT/yr Potential Uncontrolled Emissions Control Method TSP ton/yr PM-10 ton/yr PM-2.5 ton/yr Potential to Emit Calculations Potential Controlled Emissions Control TSP PM-10 PM-2.5 Efficiency [4] % ton/yr ton/yr ton/yr Number of Sources # TSP lb/hr Emission Rates (per volume source) PM-10 PM-10 lb/hr g/s PM-2.5 lb/hr Release Height ft Initial Sigma y [5] ft Initial Sigma z [6] ft [7] Coal Pile Bulldozing North Pile 50.0 3.68 0.80 0.08 11,680 21.47 4.68 0.47 Watering and Speed Reduction 95.00 1.07 0.23 0.023 47 5.2153E-03 1.1372E-03 1.4325E-04 1.1372E-04 24.0000 10.9767 5.0775 [7] Coal Pile Bulldozing South Pile 50.0 3.68 0.80 0.08 11,680 21.47 4.68 0.47 Watering and Speed Reduction 95.00 1.07 0.23 0.023 53 4.6249E-03 1.0084E-03 1.2703E-04 1.0084E-04 24.0000 10.9767 5.0775 [7] Coal Pile Bulldozing Blending Pile 3 50.0 3.68 0.80 0.08 11,680 21.47 4.68 0.47 Watering and Speed Reduction 95.00 1.07 0.23 0.023 8 3.0640E-02 6.6808E-03 8.4158E-04 6.6808E-04 40.5000 10.9767 5.0775 [7] Coal Pile Bulldozing Blending Pile 4 50.0 3.68 0.80 0.08 11,680 21.47 4.68 0.47 Watering and Speed Reduction 95.00 1.07 0.23 0.023 8 3.0640E-02 6.6808E-03 8.4158E-04 6.6808E-04 40.5000 10.9767 5.0775 [7] Coal Pile Bulldozing North Reclaim Pile 50.0 3.68 0.80 0.08 11,680 21.47 4.68 0.47 Watering and Speed Reduction 95.00 1.07 0.23 0.023 4 6.1280E-02 1.3362E-02 1.6832E-03 1.3362E-03 24.0000 10.9767 5.0775 Watering and Speed Reduction and Partial Enclosure 97.50 0.80 0.20 0.020 4 4.5744E-02 1.1184E-02 1.4089E-03 1.1184E-03 22.0000 10.9767 5.0775 6.17 1.37 0.14 [7] Limestone Pile Bulldozing 50.0 5.49 1.34 0.13 11,680 Total Uncontrolled Emissions (tons/yr) 32.06 7.84 0.78 139.42 31.25 3.12 Total Controlled Emissions (tons/yr) Notes [ ]: 1. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 13 "Miscellaneous Sources", Section 13.2.2 "Unpaved Roads". Table 13.2.2-1 "Typical Silt Content Values of Surface Material on Industrial Unpaved Roads". November 2006. 2. U.S. Department of Commerce. "Local Climatological Data - Annual Summary with Comparative Data". Des Moines Surface Station (KDSM) [WBAN: 14933], Des Moines, IA. NCDC, NESDIS, NOAA. 2006. 3. IDNR Air Quality Construction Permit Forms ID Number. 4. Watering (75%) based on EPA-450/3-88-008; 15 mph speed reduction (80%) based on Ohio EPA RACM 1980 document; partial enclosure (50%) is assumed. 5. Assumed bulldozer width of 11 ft 9.6 in (Caterpillar C9). 6. Assumed bulldozer height of 10 ft 11 in (Caterpillar C9). 7. Emissions due to bulldozing operations are included in the pile EP Number. IPL Sutherland Unit 4 PSD Application Coal Storage Piles Summary Emissions Summaries Table A16 Pile Summary EP Storage Pile Description Number [1] 274 Coal Storage Pile 2 - North Pile Height ft 40.00 Release Height ft 20.00 Init. Vert. Dimen. ft 9.30 [2] 40.00 20.00 9.30 194.00 [2] 73.00 36.50 16.98 [2] 194.00 [2] 73.00 36.50 16.98 92.00 [2] 92.00 [2] 36.00 18.00 8.37 100.00 [2] 100.00 [2] 40.00 20.00 9.30 Emission Rate lb/hr-ft2 g/s-m2 1.88E-07 2.55E-07 Equivalent Length Width ft ft 1095.00 [2] 188.00 4.80E-07 6.51E-07 1263.00 [2] 188.00 8.69E-07 1.18E-06 194.00 [2] 9.98E-07 1.35E-06 194.00 1.01E-05 1.37E-05 2.11E-07 2.86E-07 [2] - Conveyor Drop - Wind Erosion 275 Coal Storage Pile 2 - South - Conveyor Drop - Wind Erosion 276 Coal Storage Pile 3 - Conveyor Drop - Wind Erosion 277 Coal Storage Pile 4 - Conveyor Drop - Wind Erosion 282b Limestone Storage Pile 1 - Conveyor Drop - Wind Erosion 274 Small Active North Pile - Wind Erosion Notes [ ]: 1. IDNR Air Quality Construction Permit Forms ID Number. 2. From storage pile emission data table. IPL Sutherland Unit 4 PSD Application Coal Pile Erosion - Active Storage Wind Erosion Calculations Emission Factor (EF) Equation [1] 1.7*(s/1.5)*(f/15)*((365-p)/235) EF = Where: EF = particulate (TSP) emission factor, lb/ton s = material silt content, % f = percentage of time the unobstructed wind speed exceeds 12 mph p = number of days per year with at least 0.01 in of precipitation Calculated Emission Factors: PM-10 [1] PM-2.5 [5] TSP EF (transfer) 6.8773 3.4386 0.5158 lb/day/acre of surface EF (transfer) 12.1915 6.0958 0.9144 lb/day/acre of surface 2.2 3.9 38.4 111.8 % Coal % Limestone % days [2] [2] [3] [4] coal limestone Table A17 Active Coal Pile Wind Erosion Emissions: Potential to Emit Calculations EP Number [6] [8] [8] [8] [8] [8] [8] Activity Limestone Storage Pile Coal Storage Pile 2 -North Pile Coal Storage Pile 2 -South Pile Coal Storage Pile 3 Coal Storage Pile 4 Small North Pile Exposed Surface Area acre 0.19 5.41 6.24 0.85 0.85 0.29 Total Uncontrolled Emissions (tons/yr) Potential Uncontrolled Emissions TSP PM-10 PM-2.5 ton/yr ton/yr ton/yr 0.431 0.216 0.032 6.786 3.393 0.509 7.830 3.915 0.587 1.066 0.533 0.080 1.066 0.533 0.080 0.369 0.184 0.028 17.548 8.774 1.316 Control Method Partial Enclosure Water Cannon/Surfactant and Berm Water Cannon/Surfactant and Berm Water Cannon/Surfactant Water Cannon/Surfactant Water Cannon/Surfactant and Berm Control Efficiency [7] % 50 95 95 90 90 95 Total Controlled Emissions (tons/yr) Potential Controlled Emissions TSP PM-10 PM-2.5 ton/yr ton/yr ton/yr 0.216 0.108 0.016 0.339 0.170 0.025 0.391 0.196 0.029 0.107 0.053 0.008 0.107 0.053 0.008 0.018 0.009 0.001 1.178 0.589 Modeling Parameters Emission Rates Pile Height TSP PM-10 PM-2.5 lb/hr lb/hr lb/hr ft 0.049 0.025 0.004 36 0.077 0.039 0.006 40 0.089 0.045 0.007 40 0.024 0.012 0.002 73 0.024 0.012 0.002 73 0.004 0.002 0.000 73 0.088 Notes [ ]: 1. USEPA. "Fugitive Dust Background Document and Technical Information Document for Best Available Control Measures". EPA-450/2-92-004. September 1992. 2. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 13 "Miscellaneous Sources", Section 13.2.4 "Aggregate Handling and Storage Piles". November 2006. a. Table 13.2.4-1 "Typical Silt and Moisture Contents of Materials at Various Industries". 3. U.S. Department of Commerce. "International Station Meteorological Climate Summary Ver 4.0 CD-ROM". Des Moines Surface Station (KDSM) [WBAN: 14933], Des Moines, IA. National Climatic Data Center, NESDIS, NOAA. 1997. 4. U.S. Department of Commerce. "Local Climatological Data - Annual Summary with Comparative Data". Des Moines Surface Station (KDSM) [WBAN: 14933], Des Moines, IA. NCDC, NESDIS, NOAA. 2006. 5. Western Governors' Association Western Regional Air Partnership (WRAP). "Background Document for Revisions to Fine Fraction Ratios Used for AP-42 Fugitive Dust Emission Factors". Final. November 1, 2006. Prepared by Midwest Research Institute. It was assumed that the PM2.5/PM10 ratio of 0.15 recommended for the transfer of aggregate associated with conveyor transfer points subject to an open atmosphere is applicable general material handling operations. 6. IDNR Air Quality Construction Permit Forms ID Number. 7. Water cannon/surfactant (90%) based on Ohio EPA RACM 1980 document (average of chemical stabilization). Assumed berm control of 50%. 8. Emissions due to wind erosion are included in the pile EP Number. Release Init. Vert. Height Dimen. ft ft 18.0000 16.7442 20.0000 18.6047 20.0000 18.6047 36.5000 33.9535 36.5000 33.9535 36.5000 33.9535 IPL Sutherland Unit 4 PSD Application Coal Pile - Active Storage Equivalent Dimensions Calculation Coal Storage Pile 2- North Basis: Height = Length = Width = 40 ft 1095 ft 188 ft Coal Storage Pile 4 Basis: Height = Diameter = Radius = 73 ft 194 ft 97 ft Calculations: Calculations: Footprint Area of the Full Pile =L*W 2 Area = 205,860.00 ft Footprint Area of the Full Circle =π*r2 2 Area = 29,559.25 ft Coal Storage Pile 2- South Basis: Height = Length = Width = Limestone Storage Pile 1 Basis: Height = Diameter = Radius = 40 ft 1263 ft 188 ft 36 ft 92 ft 46 ft Calculations: Calculations: Footprint Area of the Full Pile =L*W 2 Area = 237,444.00 ft Footprint Area of the Full Circle =π*r2 2 Area = 6,647.61 ft Coal Storage Pile 3 Basis: Height = Diameter = Radius = Small Active North Pile Basis: Height = Length = Width = 73 ft 194 ft 97 ft 40 ft 100 ft 100 ft Calculations: Calculations: Footprint Area of the Full Circle =π*r2 2 Area = 29,559.25 ft Footprint Area of the Full Pile =L*W 2 Area = 10,000.00 ft IPL Sutherland Unit 4 PSD Application Coal Pile - Active Storage Surface Area Calculation Coal Storage Pile 2 North Basis: Coal Storage Pile 4 Basis: Height (H) = Overall Length (l) = Overall Width (w) = Angle of Repose (φ) = Radius (R) = Length (L) = Width (W) = 40 1095 188 38 51.20 992.60 85.60 ft ft ft ° ft ft ft Calculations: Surface Area of the Pile = π * R (r2 + h2)^0.5 + 2 * L (r2 + h2)^0.5 + 2 * W (r2 + h2)^0.5 + L * W 2 Surf. Area = 235,525.82 ft Coal Storage Pile 2 South Basis: Height (H) = Overall Length (l) = Overall Width (w) = Angle of Repose (φ) = Radius (R) = Length (L) = Width (W) = 40 1263 188 38 51.20 1160.60 85.60 ft ft ft ° ft ft ft Calculations: Surface Area of the Pile = π * R (r2 + h2)^0.5 + 2 * L (r2 + h2)^0.5 + 2 * W (r2 + h2)^0.5 + L * W 2 Surf. Area = 271,737.58 ft Coal Storage Pile 3 Basis: Height (H) = Base Radius (Rb) = 73 ft 97 ft Calculations: Surface Area of the Conical Pile = π * r (r2 + h2)^0.5 2 Surf. Area = 36,994.82 ft Height (H) = Base Radius (Rb) = 73 ft 97 ft Calculations: Surface Area of the Conical Pile = π * r (r2 + h2)^0.5 2 Surf. Area = 36,994.82 ft Limestone Storage Pile Basis: Height (H) = Base Radius (Rb) = 36 ft 46 ft Calculations: Surface Area of the Conical Pile = π * r (r2 + h2)^0.5 2 Surf. Area = 8,441.36 ft Small Active North Pile Basis: Height (H) = Length (L) = Width (W) = Height of Side (h) = 40 100 100 64.03 ft ft ft ft Calculations: Surface Area of the Pile = 4 * (0.5 * b * h) where b = base (L or W) 2 Surf. Area = 12,806.25 ft GHG Emissions Estimation from IPL Sutherland Generating Station Unit 4 Project Emission Unit Main Boiler Limestone Usage in Main Boiler Scrubber Aux Boiler @ 2000 hrs/yr Emergency Engine @ 52 hrs/yr Fire Pump @ 52 hrs per year Booster Fire Pump @ 52 hrs/yr Gate Station Heater MHDR Emission Factor Emissions (tpy) CO2 Units CH4 Units N2O Units CO2 CH4 N2O 6326 mmBtu/hr Utility Coal 206.19 lb/mmBtu 0.0245 lb/mmBtu 0.0035 lb/mmBtu 5.71E+06 6.79E+02 9.70E+01 29.697 tons/hr N/A 240 lb/ton N/A 3.12E+04 N/A 268.6 138.9 29 9.5 3 Units Fuel mmBtu/hr gal/hr gal/hr gal/hr mmBtu/hr NG Diesel Diesel Diesel NG 116.38 159.69 159.69 159.69 116.38 lb/mmBtu lb/mmBtu lb/mmBtu lb/mmBtu lb/mmBtu 0.013 0.00066 0.00066 0.00066 0.013 lb/mmBtu lb/gal lb/gal lb/gal lb/mmBtu 0.0002 0.00022 0.00022 0.00022 0.0002 lb/mmBtu lb/gal lb/gal lb/gal lb/mmBtu 3.13E+04 1.52E+02 3.17E+01 1.04E+01 1.53E+03 3.49E+00 4.58E-03 9.57E-04 3.14E-04 1.71E-01 5.37E-02 1.53E-03 3.19E-04 1.05E-04 2.63E-03 Total.(tpy) 5.78E+06 6.83E+02 9.704E+01 Interstate Power and Light Sutherland Unit 4 Air Permit Application Appendix H Appendix H BACT Analysis 102607-145491 H-1 BEST AVAILABLE CONTROL TECHNOLOGY ANALYSIS Prepared for Interstate Power and Light Sutherland Generating Station Unit 4 October 2007 PROJECT NO. 145491 Black & Veatch Corporation Overland Park, Kansas Interstate Power and Light Sutherland Unit 4 Air Permit Application Table of Contents Table of Contents Acronym List ................................................................................................................AL-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 ....................................... 2-5 2.2.1 Coal Fired Boiler ....................................................................... 2-7 2.2.2 Auxiliary Boiler....................................................................... 2-11 2.2.3 Emergency Generator.............................................................. 2-12 2.2.4 Emergency Fire Pumps............................................................ 2-13 2.2.5 Gate Station Gas Heater .......................................................... 2-14 3.0 Coal Fired Boiler SO2 BACT Analysis ............................................................... 3-1 3.1 Step 1--Identify All Control Technologies .............................................. 3-1 3.1.1 Coal Washing ............................................................................ 3-1 3.1.2 Wet Lime- and Limestone-Based FGD Processes .................... 3-2 3.1.3 Semi-Dry Lime-Based FGD Systems ....................................... 3-6 3.2 Step 2--Eliminate Technically Infeasible Options................................... 3-9 3.2.1 Coal Washing .......................................................................... 3-10 3.2.2 Wet Lime- and Limestone-Based FGD Processes .................. 3-10 3.2.3 Semi-Dry Lime-Based FGD Systems ..................................... 3-10 3.3 Step 3--Rank Remaining Control Technologies by Effectiveness ........ 3-13 3.4 Step 4--Evaluate Most Effective Controls and Document Results........ 3-18 3.4.1 Energy Evaluation of Alternatives .......................................... 3-18 3.4.2 Environmental Evaluation of Alternatives .............................. 3-18 3.4.3 Economic Evaluation of Alternatives...................................... 3-19 3.5 Step 5--Select SO2 BACT...................................................................... 3-20 4.0 Coal Fired Boiler NOx BACT Analysis............................................................... 4-1 4.1 Step 1--Identify All Control Technologies .............................................. 4-1 4.1.1 Selective Catalytic Reduction System....................................... 4-2 4.1.2 Selective Noncatalytic Reduction System................................. 4-3 4.2 Step 2--Eliminate Technically Infeasible Options................................... 4-4 4.3 Step 3--Rank Remaining Control Technologies by Effectiveness .......... 4-4 102607-145491 TC-1 Interstate Power and Light Sutherland Unit 4 Air Permit Application Table of Contents Table of Contents (Continued) 4.4 4.5 Step 4--Evaluate Most Effective Controls and Document Results.......... 4-7 4.4.1 Energy Evaluation of Alternatives ............................................ 4-8 4.4.2 Environmental Evaluation of Alternatives ................................ 4-8 4.4.3 Economic Evaluation of Alternatives........................................ 4-9 Step 5--Select NOx BACT ....................................................................... 4-9 5.0 Coal Fired Boiler PM/PM10 BACT Analysis ...................................................... 5-1 5.1 Step 1--Identify All Control Technologies .............................................. 5-1 5.1.1 Coal Washing ............................................................................ 5-1 5.1.2 Dry Electrostatic Precipitator Systems ...................................... 5-1 5.1.3 Fabric Filter Systems ................................................................. 5-3 5.1.4 Wet Electrostatic Precipitator.................................................... 5-4 5.2 Step 2--Eliminate Technically Infeasible Options................................... 5-5 5.3 Step 3--Rank Remaining Control Technologies by Effectiveness .......... 5-6 5.4 Step 4--Evaluate Most Effective Controls and Document Results.......... 5-9 5.4.1 Energy Evaluation of Alternatives .......................................... 5-10 5.4.2 Environmental Evaluation of Alternatives .............................. 5-10 5.4.3 Economic Evaluation of Alternatives...................................... 5-10 5.5 Step 5--Select PM/PM10 BACT ............................................................. 5-11 6.0 Coal Fired Boiler CO and VOC BACT Analysis ................................................ 6-1 6.1 Step 1--Identify All Control Technologies .............................................. 6-1 6.1.1 Good Combustion Controls....................................................... 6-1 6.1.2 Oxidation Catalysts ................................................................... 6-2 6.2 Step 2--Eliminate Technically Infeasible Options................................... 6-2 6.3 Step 3--Rank Remaining Control Technologies by Effectiveness .......... 6-3 6.4 Step 4--Evaluate Most Effective Controls and Document Results.......... 6-8 6.4.1 Energy Evaluation of Alternatives ............................................ 6-9 6.4.2 Environmental Evaluation of Alternatives ................................ 6-9 6.4.3 Economic Evaluation of Alternatives........................................ 6-9 6.5 Step 5--Select CO and VOC BACT......................................................... 6-9 7.0 Coal Fired Boiler Sulfuric Acid Mist BACT Analysis........................................ 7-1 7.1 Step 1--Identify All Control Technologies .............................................. 7-1 7.1.1 Wet and Semi-Dry Lime-Based FGD Systems ......................... 7-1 102607-145491 TC-2 Interstate Power and Light Sutherland Unit 4 Air Permit Application Table of Contents Table of Contents (Continued) 7.2 7.3 7.4 7.5 7.1.2 Wet Electrostatic Precipitator.................................................... 7-2 7.1.3 Sorbent Injection Systems ......................................................... 7-3 Step 2--Eliminate Technically Infeasible Options................................... 7-3 Step 3--Rank Remaining Control Technologies by Effectiveness .......... 7-4 Step 4--Evaluate Most Effective Controls and Document Results.......... 7-7 7.4.1 Energy Evaluation of Alternatives ............................................ 7-7 7.4.2 Environmental Evaluation of Alternatives ................................ 7-7 7.4.3 Economic Evaluation of Alternatives........................................ 7-7 Step 5--Select H2SO4 BACT.................................................................... 7-8 8.0 Coal Fired Boiler Fluorides BACT Analysis....................................................... 8-1 8.1 Step 1--Identify All Control Technologies .............................................. 8-1 8.2 Step 2--Eliminate Technically Infeasible Options................................... 8-1 8.3 Step 3--Rank Remaining Control Technologies by Effectiveness .......... 8-4 8.4 Step 4--Evaluate Most Effective Controls and Document Results.......... 8-6 8.4.1 Energy Evaluation of Alternatives ............................................ 8-7 8.4.2 Environmental Evaluation of Alternatives ................................ 8-7 8.4.3 Economic Evaluation of Alternatives........................................ 8-7 8.5 Step 5--Select Fluorides BACT ............................................................... 8-7 9.0 Auxiliary Boiler BACT Analysis......................................................................... 9-1 9.1 SO2 BACT Analysis ................................................................................ 9-1 9.1.1 Step 1--Identify All Control Technologies................................ 9-1 9.1.2 Step 2--Eliminate Technically Infeasible Options .................... 9-1 9.1.3 Step 3--Rank Remaining Control Technologies by Effectiveness.............................................................................. 9-1 9.1.4 Step 4--Evaluate Most Effective Controls and Document Results ....................................................................................... 9-2 9.1.5 Step 5--Select SO2 BACT ......................................................... 9-2 9.2 NOx BACT Analysis................................................................................ 9-2 9.2.1 Step 1--Identify All Control Technologies................................ 9-2 9.2.2 Step 2--Eliminate Technically Infeasible Options .................... 9-3 9.2.3 Step 3 -- Rank Remaining Control Technologies by Effectiveness.............................................................................. 9-3 9.2.4 Step 4--Evaluate Most Effective Controls and Document Results ....................................................................................... 9-3 9.2.5 Step 5--Select NOx BACT......................................................... 9-4 102607-145491 TC-3 Interstate Power and Light Sutherland Unit 4 Air Permit Application Table of Contents Table of Contents (Continued) 9.3 9.4 9.5 PM/PM10 BACT Analysis........................................................................ 9-4 9.3.1 Step 1--Identify All Control Technologies................................ 9-4 9.3.2 Step 2--Eliminate Technically Infeasible Options .................... 9-4 9.3.3 Step 3--Rank Remaining Control Technologies by Effectiveness.............................................................................. 9-5 9.3.4 Step 4--Evaluate Most Effective Controls and Document Results ....................................................................................... 9-5 9.3.5 Step 5--Select PM/PM10 BACT................................................. 9-6 CO BACT Analysis ................................................................................. 9-6 9.4.1 Step 1--Identify All Control Technologies................................ 9-6 9.4.2 Step 2--Eliminate Technically Infeasible Options .................... 9-6 9.4.3 Step 3--Rank Remaining Control Technologies by Effectiveness.............................................................................. 9-7 9.4.4 Step 4--Evaluate Most Effective Controls and Document Results ....................................................................................... 9-7 9.4.5 Step 5--Select CO BACT ........................................................ 9-10 VOC BACT Analysis ............................................................................ 9-10 9.5.1 Step 1--Identify All Control Technologies.............................. 9-10 9.5.2 Step 2--Eliminate Technically Infeasible Options .................. 9-12 9.5.3 Step 3--Rank Remaining Control Technologies by Effectiveness............................................................................ 9-12 9.5.4 Step 4--Evaluate Most Effective Controls and Document Results ..................................................................................... 9-12 9.5.5 Step 5--Select VOC BACT ..................................................... 9-13 10.0 Emergency Generator and Fire Pumps BACT Analysis.................................... 10-1 10.1 Select SO2 BACT................................................................................... 10-1 10.2 Select NOx BACT .................................................................................. 10-1 10.3 Select PM/PM10 BACT.......................................................................... 10-2 10.4 Select CO BACT.................................................................................... 10-3 10.5 Select VOC BACT................................................................................. 10-3 10.6 Select H2SO4 BACT............................................................................... 10-4 11.0 Gate Station Heater BACT Analysis ................................................................. 11-1 11.1 Select SO2 BACT................................................................................... 11-1 11.2 Select NOx BACT .................................................................................. 11-1 11.3 Select PM/PM10 BACT.......................................................................... 11-2 102607-145491 TC-4 Interstate Power and Light Sutherland Unit 4 Air Permit Application Table of Contents Table of Contents (Continued) 11.4 11.5 11.6 Select CO BACT.................................................................................... 11-3 Select VOC BACT................................................................................. 11-3 Select H2SO4 BACT............................................................................... 11-4 12.0 Cooling Tower BACT Analysis......................................................................... 12-1 12.1 Step 1--Identify All Control Technologies ............................................ 12-1 12.2 Step 2--Eliminate Technically Infeasible Options................................. 12-1 12.3 Step 3--Rank Remaining Control Technologies by Effectiveness ........ 12-1 12.4 Step 4--Evaluate Most Effective Controls and Document Results........ 12-2 12.4.1 Energy Evaluation of Alternatives .......................................... 12-2 12.4.2 Environmental Evaluation of Alternatives .............................. 12-2 12.4.3 Economic Evaluation of Alternatives...................................... 12-2 12.5 Step 5--Select BACT ............................................................................. 12-2 13.0 Material Handling Systems BACT Analysis ..................................................... 13-1 13.1 Coal Handling ........................................................................................ 13-1 13.2 Limestone Handling............................................................................... 13-3 13.3 Fly Ash Handling................................................................................... 13-4 13.4 Saleable Fly Ash Handling System........................................................ 13-4 13.5 Waste Ash Handling .............................................................................. 13-6 13.6 FGD Solids Handling............................................................................. 13-7 13.7 Bottom Ash Handling ............................................................................ 13-7 13.8 Biomass Handling.................................................................................. 13-8 13.9 Other Material Handling ........................................................................ 13-8 13.10 Step 1--Identify All Control Technologies ............................................ 13-9 13.11 Step 2--Eliminate Technically Infeasible Options................................. 13-9 13.12 Step 3--Rank Remaining Control Technologies by Effectiveness ........ 13-9 13.13 Step 4--Evaluate Most Effective Controls and Document Results...... 13-10 13.13.1 Energy Evaluation of Alternatives ........................................ 13-10 13.13.2 Environmental Evaluation of Alternatives ............................ 13-10 13.13.3 Economic Evaluation of Alternatives.................................... 13-10 13.14 Step 5--Select BACT ........................................................................... 13-10 Attachment A Attachment B Coal Fired Boiler Top-Down RBLC Clearinghouse Review Results.......................................................................................................1 Auxiliary Boiler Top-Down RBLC Clearinghouse Review Results.......................................................................................................1 102607-145491 TC-5 Interstate Power and Light Sutherland Unit 4 Air Permit Application Table of Contents Table of Contents (Continued) Tables Table 1-1 Table 2-1 Table 2-2 Table 2-3 Table 2-4 Table 2-5 Table 2-6 Table 2-7 Table 2-8 Table 2-9 Table 2-10 Table 2-11 Table 2-12 Table 2-13 Table 3-1 Table 3-2 Table 3-3 Table 3-4 Table 3-5 Table 4-1 Table 4-2 Table 4-3 Table 4-4 Table 5-1 Table 5-2 Table 5-3 Table 5-4 Table 5-5 Table 5-6 Table 5-7 Table 5-8 Table 6-1 Table 6-2 BACT Determination Summary ............................................................... 1-5 Main Boiler Design Basis ........................................................................ 2-7 Coal and Biomass Fuel Specifications..................................................... 2-8 Sulfur and Heating Value Fuel Variability for Worst-Case Greater Belleville (Illinois Basin) Coal ................................................... 2-9 Main Boiler Baseline Uncontrolled Emissions PRB Coal....................... 2-9 Main Boiler Baseline Uncontrolled Emissions Illinois Basin Coal....... 2-10 Auxiliary Boiler Design Basis ............................................................... 2-11 Auxiliary Boiler Baseline Emissions ..................................................... 2-11 Emergency Generator Design Basis ...................................................... 2-12 Emergency Generator Baseline Emissions ............................................ 2-12 Emergency Fire Pumps Design Basis .................................................... 2-13 Emergency Fire Pumps Baseline Emissions.......................................... 2-13 Gate Station Gas Heater Design Basis................................................... 2-14 Gate Station Gas Heater Baseline Emissions......................................... 2-14 Summary of Step 2--Eliminate Technically Infeasible Options ............ 3-11 Subbituminous Fuels SO2 Top-Down RBLC Clearinghouse Review Results....................................................................................... 3-14 Bituminous or Bituminous Blend of Fuels SO2 Top-Down RBLC Clearinghouse Review Results .............................................................. 3-15 Ranking of SO2 Control Technologies .................................................. 3-18 Main Boiler SO2 BACT Determination................................................. 3-20 Summary of Step 2--Eliminate Technically Infeasible Options .............. 4-4 NOx Top-Down RBLC Clearinghouse Review Results .......................... 4-5 Ranking of NOx Control Technologies.................................................... 4-7 Main Boiler NOx BACT Determination .................................................. 4-9 Summary of Step 2--Eliminate Technically Infeasible Options .............. 5-6 PM/PM10 Top-Down RBLC Clearinghouse Review Results .................. 5-8 Ranking of PM/PM10 Control Technologies.......................................... 5-10 Fabric Filter Engineering Analysis - Cost Analysis .............................. 5-12 DESP Engineering Analysis - Cost Analysis......................................... 5-13 Particulate Matter Top-Down BACT Summary .................................... 5-14 Main Boiler PM/PM10 BACT Determination ........................................ 5-15 Main Boiler Visible Emission (Opacity) BACT Determination............ 5-16 Summary of Step 2--Eliminate Technically Infeasible Options .............. 6-3 CO Top-Down RBLC Clearinghouse Review Results............................ 6-4 102607-145491 TC-6 Interstate Power and Light Sutherland Unit 4 Air Permit Application Table of Contents Table of Contents (Continued) Tables (Continued) Table 6-3 Table 6-4 Table 6-5 Table 7-1 Table 7-2 Table 7-3 Table 7-4 Table 7-5 Table 7-6 Table 7-7 Table 8-1 Table 8-2 Table 8-3 Table 8-4 Table 9-1 Table 9-2 Table 9-3 Table 13-1 VOC Top-Down RBLC Clearinghouse Review Results ......................... 6-7 Ranking of CO/VOC Control Technologies............................................ 6-9 Main Boiler CO/VOC BACT Determinations....................................... 6-10 Summary of Step 2--Eliminate Technically Infeasible Options .............. 7-4 H2SO4 Top-Down RBLC Clearinghouse Review Results....................... 7-5 Ranking of H2SO4 Control Technologies ................................................ 7-7 Wet ESP Equipment Engineering Analysis - Cost Analysis (WESP) .................................................................................................... 7-9 SO3 Sorbent Injection Equipment Engineering Analysis - Cost Analysis.................................................................................................. 7-10 Sulfuric Acid Mist Top-Down BACT Summary................................... 7-12 Main Boiler H2SO4 BACT Determination............................................. 7-12 Summary of Step 2--Eliminate Technically Infeasible Options .............. 8-3 Fluorides Top-Down RBLC Clearinghouse Review Results .................. 8-5 Ranking of HF Control Technologies...................................................... 8-6 Main Boiler HF BACT Determination .................................................... 8-8 Summary of Step 2--Eliminate Technically Infeasible Options .............. 9-7 Auxiliary Boiler Catalytic Oxidation System Equipment Engineering Analysis - Cost Analysis ..................................................... 9-9 Carbon Monoxide/Volatile Organic Compounds Top-Down BACT Summary .................................................................................... 9-11 Material Handling Particulate BACT Determinations......................... 13-11 102607-145491 TC-7 Interstate Power and Light Sutherland Unit 4 Air Permit Application Acronym List Acronym List AGR AQC BACT bhp bhph Btu Ca(OH)2 CaSO3 Advanced Gas Reburn Air Quality Control Best Available Control Technology Brake Horsepower Brake Horsepower Hour British Thermal Unit Calcium Hydroxide Calcium Hydroxide CaSO3•1/2H2O Calcium Sulfite Hemihydrate CaSO4•2H2O CAA CAMR CDS CEMS CFB CFR CO COMS DESP FGD FPL g/bhph H2S H2SO4 h/yr HAP HF Hg HHV IAC ID IGCC IPL Calcium Sulfate Dihydrate Clean Air Act Clean Air Mercury Rule Circulating Dry Scrubber Continuous Emissions Monitoring System Circulating Fluidized Bed Code of Federal Regulations Carbon Monoxide Continuous Opacity Monitoring System Dry Electrostatic Precipitator Flue Gas Desulfurization Florida Power and Light Company Grams per Brake Horsepower Hour Hydrogen Sulfide Sulfuric Acid Mist Hours per Year Hazardous Air Pollutant Hydrofluoric Acid Mercury Higher Heating Value Iowa Administrative Code Induced Draft Integrated Gasification Combined Cycle Interstate Power and Light 102607-145491 AL-1 Interstate Power and Light Sutherland Unit 4 Air Permit Application JBR KCP&L kW kWh LAER Lb/h L/G LIFAC LNB/OFA MACT MBtu MW NMHC NO2 NOx NSPS NSR OAQPS OEM Pb PC PM/PM10 PRB PSD RACT RBLC RICE SCPC SCR SDA SGS SNCR SO2 SO3 SSC tpy 102607-145491 Acronym List Jet Bubbling Reactor Kansas City Power & Light Kilowatt Kilowatt Hour Lowest Achievable Emission Rate Pound per Hour Liquid-To-Gas Limestone Injection into the Furnace and ReActivation of Calcium Low NOx Burner/Overfire Air Maximum Achievable Control Technology Million British Thermal Unit Megawatt Non-Methane Hydro Carbon Nitrogen Dioxide Nitrogen Oxides New Source Performance Standard New Source Review Office of Air Quality Planning And Standards Original Equipment Manufacturer Lead Pulverized Coal Particulate Matter/Particulate Matter Less than 10 Microns Powder River Basin Prevention of Significant Deterioration Reasonably Available Control Technology RACT/BACT/LAER Clearinghouse Reciprocating Internal Combustion Engine Supercritical Pulverized Coal Selective Catalytic Reduction Spray Dryer Absorber Sutherland Generating Station Selective Noncatalytic Reduction Sulfur Dioxide Sulfur Trioxide Submerged Scraper Conveyor Tons per Year AL-2 Interstate Power and Light Sutherland Unit 4 Air Permit Application TR USEPA VOC WESP 102607-145491 Acronym List Transformer Rectifier United States Environmental Protection Agency Volatile Organic Compound Wet Electrostatic Precipitator AL-3 Interstate Power and Light Sutherland Unit 4 Air Permit Application 1.0 1.0 Introduction and Executive Summary Introduction and Executive Summary Interstate Power and Light (IPL) proposes to construct a new electric generating facility (hereinafter referred to as the “Project”) at its existing Sutherland Generating Station (SGS) in Marshalltown, Iowa. The Project, SGS Unit 4, will consist of one 649 MW (megawatt) (net) supercritical pulverized coal (SCPC) fired boiler, an auxiliary steam boiler, an emergency generator, two diesel driven emergency fire pumps, a cooling tower, and material handling systems for the conveyance of coal, biomass, ash, and reagent. The Project is classified as a New Source Review/Prevention of Significant Deterioration (NSR/PSD) major modification to an existing major source, and as a result of the calculated emissions increases, is subject to a Best Available Control Technology (BACT) review for sulfur dioxide (SO2), nitrogen oxides (NOx), carbon monoxide (CO), particulate matter (PM)/PM10, volatile organic compounds (VOC), sulfuric acid mist (H2SO4), and fluoride, as previously discussed in Section 2.4 of the air permit application document. The Project is not subject to review for lead (Pb), hydrogen sulfide (H2S), or total reduced sulfur compounds. As required under the NSR/PSD regulations, the BACT analysis presented herein employed a “top-down,” five-step analysis process to determine the appropriate emission control technologies and emissions limitations for the Project. The BACT analysis was conducted for the main boiler, the auxiliary steam boiler, the emergency diesel fire pumps, the cooling tower, and the material handling systems related to the conveyance and storage of coal, biomass, ash, and reagent. The BACT analysis was conducted in accordance with the United States Environmental Protection Agency’s (USEPA’s) recommended methodology: • 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. • Step 5--Select BACT. Step 1--Identify All Control Technologies The first step in a “top-down” analysis is to identify all available control options for the emission unit in question. Identifying all the potential available control options consists of those air pollution control technologies or techniques with a practical potential for application to the emission unit and the regulated pollutant under evaluation. The potential available control technologies and techniques include lower emitting processes, practices, and post-combustion controls. Lower emitting practices can include fuel 102607-145491 1-1 Interstate Power and Light Sutherland Unit 4 Air Permit Application 1.0 Introduction and Executive Summary cleaning, treatment, or innovative fuel combustion techniques that are classified as precombustion controls. Post-combustion controls would be the various add-on controls for the pollutant being controlled. Step 2--Eliminate Technically Infeasible Options The second step of the “top-down” analysis is to identify the technical feasibility of the control options identified in Step 1, which are evaluated with respect to sourcespecific factors. A control option that is determined to be technically infeasible is eliminated. “Technically infeasible” is defined as a clearly documented case of a control option that has technical difficulties that would preclude the successful use of the control option because of physical, chemical, and engineering principles. After completion of this step, technically infeasible options are then eliminated from the BACT review process. In Step 2, the control option is identified as technically feasible. A “technically feasible” control option is defined as a control technology that has been installed and operated successfully at a similar type of source of comparable size under review (demonstrated). If the control option cannot be demonstrated, the analysis gets more involved. When determining if a control option has not been demonstrated, two key concepts need to be analyzed. The first concept, availability, is defined as technology that can be obtained through commercial channels or is otherwise available within the common sense meaning of the term. A technology that is being offered commercially by 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. 102607-145491 1-2 Interstate Power and Light Sutherland Unit 4 Air Permit Application 1.0 Introduction and Executive Summary 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: • Energy evaluation of alternatives. • Environmental evaluation of alternatives. • 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. Examples of non-air quality environmental impacts include polluted water discharge and solids or waste generation. The procedure for conducting this analysis should be based on a consideration of site-specific circumstances. The third and final impact analysis addresses the economic evaluation of alternatives. This analysis is performed to indicate the cost to purchase and operate the control technology. The capital and operating/annual cost is estimated based on the established design parameters. Information for the design parameters should be obtained from established sources that can be referenced. However, documented assumptions can be made in the absence of references for the design parameters. The estimated cost of control is represented as an annualized cost ($/year) and, with the estimated quantity of pollutant removed (tons/year), the cost-effectiveness ($/tons) of the control technology is determined. The cost-effectiveness describes the potential to achieve the required emissions reduction in the most economical way. The cost-effectiveness compares the potential technologies on an economical basis. Two types of cost-effectiveness are considered in a BACT analysis: average and incremental cost-effectiveness. Average cost-effectiveness is defined as the total annualized cost of control divided by the annual 102607-145491 1-3 Interstate Power and Light Sutherland Unit 4 Air Permit Application 1.0 Introduction and Executive Summary quantity of pollutant removed for each control technology. The incremental costeffectiveness is a comparison of the cost and performance level of a control technology to the next most stringent option. It has a unit of (dollars/incremental ton removed). The incremental cost-effectiveness is a good measure of viability when comparing technologies that have similar removal efficiencies. Step 5--Select BACT The highest ranked control technology that is not eliminated in Step 4 is proposed as BACT for the pollutant and emission unit under review. As summarized in Table 1-1, the aforementioned BACT analysis process resulted in the following control technology and emissions level determinations for the Project’s affected air emissions sources and pollutants. The ton per year emissions presented in Appendix G are proposed as BACT emission caps. 102607-145491 1-4 Interstate Power and Light Sutherland Unit 4 Air Permit Application 1.0 Introduction and Executive Summary Table 1-1 BACT Determination Summary Emission Unit: 649 MW (net) SCPC Boiler (Steam Capacity Rating 4,389,000 lb/h) Pollutant Control Technology Emission Basis Avg. Period Testing Method SO2 Wet FGD 0.06 lb/MBtu or 98 percent removal (whichever occurs first) with 0.08 lb/MBtu upper limit. 30 day CEMS NOx LNB/OFA and SCR 0.05 lb/MBtu 30 day CEMS PM/PM10 Fabric Filter 0.012 lb/MBtu (filterable) 3 hour test runs (average) USEPA Method 5B 0.018 lb/MBtu (total) 3 hour test runs (average) USEPA Method 5B + 202 with condensable artifact modification Visible Emissions (Opacity) Fabric Filter 10% 6-minute average COMS CO Good Combustion Controls 0.12 lb/MBtu 8 hour CEMS VOC Good Combustion Controls 0.0034 lb/MBtu 3 hour test runs (average) USEPA Method 18 H2SO4 Sorbent Injection/Fabric Filter 0.004 lb/MBtu 3 hour test runs (average) Controlled Condensate Test Method Fluorides Wet FGD 0.0002 lb/MBtu 3 hour test runs (average) USEPA Method 13B or USEPA Method 26A Emission Unit: Auxiliary Steam Boiler (270 MBtu/h) Pollutant Control Technology Emission Basis Avg. Period Testing Method SO2 Natural Gas Firing 0.0006 lb/MBtu NA Fuel Recordkeeping NOx Good Combustion Controls 0.037 lb/MBtu 3 hour test runs (average) USEPA Method 7E PM/PM10 Natural Gas Firing 0.007 lb/MBtu NA Fuel Recordkeeping CO Good Combustion Controls 0.074 lb/MBtu NA Fuel Recordkeeping VOC Good Combustion Controls 0.005 lb/MBtu NA Fuel Recordkeeping H2SO4 Natural Gas Firing 0.0009 lb/MBtu NA Fuel Recordkeeping 102607-145491 1-5 Interstate Power and Light Sutherland Unit 4 Air Permit Application 1.0 Introduction and Executive Summary Table 1-1 (Continued) BACT Determination Summary Emission Unit: Emergency Generator (2,000 kW) Pollutant Control Technology Emission Basis SO2 Low Sulfur Distillate Fuel Oil < 0.05% Sulfur Fuel Oil NOx Good Combustion Controls 6.47 g/bhph PM/PM10 Low Sulfur Distillate Fuel Oil 0.08 g/bhph CO Good Combustion Controls 0.53 g/bhph VOC Good Combustion Controls 0.27 g/bhph H2SO4 Low Sulfur Distillate Fuel Oil < 0.05 % Sulfur Fuel Oil Emission Unit: Emergency Fire Pump (575 bhp) Pollutant Control Technology Emission Basis SO2 Low Sulfur Distillate Fuel Oil < 0.05% Sulfur Fuel Oil NOx Good Combustion Controls 4.9 g/bhph PM/PM10 Low Sulfur Distillate Fuel Oil 0.08 g/bhph CO Good Combustion Controls 0.75 g/bhph VOC Good Combustion Controls 0.29 g/bhph H2SO4 Low Sulfur Distillate Fuel Oil < 0.05% Sulfur Fuel Oil Emission Unit: Emergency Fire Booster Pump (149 bhp) Pollutant Control Technology Emission Basis SO2 Low Sulfur Distillate Fuel Oil < 0.05% Sulfur Fuel Oil NOx Good Combustion Controls 5.20 g/bhph PM/PM10 Low Sulfur Distillate Fuel Oil 0.19 g/bhph CO Good Combustion Controls 0.33 g/bhph VOC Good Combustion Controls 0.36 g/bhph H2SO4 Low Sulfur Distillate Fuel Oil < 0.05% Sulfur Fuel Oil Emission Unit: Cooling Tower Pollutant Control Technology Emission Basis PM/PM10 Drift Eliminators 0.0005% drift rate Gate Station Gas Heater (3 MBtu/hr) Pollutant Control Technology Emission Basis SO2 Natural Gas Firing 0.0006 lb/MBtu NOx Good Combustion Controls 0.046 lb/MBtu PM/PM10 Natural Gas Firing 0.0074 lb/MBtu CO Good Combustion Controls 0.046 lb/MBtu VOC Good Combustion Controls 0.0054 lb/MBtu H2SO4 Natural Gas Firing 0.0009 lb/MBtu 102607-145491 1-6 Interstate Power and Light Sutherland Unit 4 Air Permit Application 1.0 Introduction and Executive Summary Table 1-1 (Continued) BACT Determination Summary Emission Unit: Material Handling Systems for the Conveyance of Coal, Biomass, Ash, and Reagent Pollutant Emission Source Control Technology PM/PM10 Coal Handling Refer to Table 13-1 Limestone Handling Refer to Table 13-1 Fly Ash Handling Refer to Table 13-1 FGD Waste Handling Refer to Table 13-1 Bottom Ash Handling Refer to Table 13-1 Biomass Handling Refer to Table 13-1 Other Material Handling Refer to Table 13-1 CEMS = Continuous Emissions Monitoring System. FGD = Flue Gas Desulfurization. g/bhph = Grams per Brake Horsepower Hour. LNB/OFA = Low NOx Burner/Overfire Air. MBtu = Million British Thermal Unit. SCR = Selective Catalytic Reduction. 30 day = 30 day rolling average 102607-145491 1-7 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 2.0 BACT Analysis Basis BACT Analysis Basis This section describes the basis of the BACT analysis, including the regulatory background, methodology and approach, and emission unit description and assumptions. 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 can be found in Iowa Administrative Code (IAC) [567] Chapter 22, which adopts by reference the federal definition of BACT in 40 CFR 52.21 as “An Emissions limitation (including a visible emission standard) based on the maximum degree of reduction for each pollutant subject to regulation under the Act which would be emitted from any proposed major stationary source or major modification which the Administrator, on a case-by-case basis, taking into account energy, environmental, and economic impacts and other costs, determines is achievable for such source or modification through application of production processes or available methods, systems, and techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for control of such pollutant. In no event shall the application of best available control technology result in emissions of any pollutant which would exceed the emissions allowed by any applicable standard under 40 CFR Parts 60 and 61. If the Administrator determines that technological or economic limitations on the application of measurement methodology to a particular emissions unit would make the imposition of an emissions standard infeasible, a design, equipment, work practice, operational standard, or combination thereof, may be prescribed instead to satisfy the requirement for the application of best available control technology. Such standard shall, to the degree possible, set forth the emissions reduction achievable by implementation of such design, equipment, work practice or operation, and shall provide for compliance by means which achieve equivalent results. 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 102607-145491 2-1 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 BACT Analysis Basis 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. 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: • USEPA’s RACT/BACT/LAER Clearinghouse (RBLC). • USEPA’s National Coal Fired Utility Projects Spreadsheet (July 2007). • Federal/State/Local new source review permits, permit applications, and associated inspection/test reports. • Technical journals, newsletters, and reports. • Information from air quality control (AQC) technology suppliers. • 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 Da – Standards of Performance for Electric Utility Steam Generating Units for Which Construction is Commenced After September 18, 1978. As an electric utility steam generating unit greater than 250 MBtu/h heat input, the Project’s main boiler will be subject to NSPS Subpart Da. NSPS Subpart Da includes new source emissions limitations for 102607-145491 2-2 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 BACT Analysis Basis certain NSR/PSD pollutants, including SO2, NOx, and PM/PM10. Applicable NSPS Subpart Da emissions limitations for the coal fired boiler are as follows: • SO2: 1.4 lb/MWh (gross energy output) or 95 percent removal rate. • NOx: 1.0 lb/MWh (gross energy output). • PM/PM10: 0.14 lb/MWh (gross energy output) or 0.015 lb/MBtu. • Opacity: Less than or equal to 20 percent opacity (6 minute average) except for one 6 minute period per hour of not more than 27 percent opacity. 2.1.1.2 NSPS Subpart Db – Standards of Performance for IndustrialCommercial-Institutional Steam Generating Units. As a steam generating unit greater than 100 MBtu/h, the Project’s 270 MBtu/h auxiliary boiler will be subject to NSPS Subpart Db. NSPS Subpart Db includes new source emissions limitations for certain NSR/PSD pollutants including NOx. Applicable NSPS Subpart Db emissions limitations for the natural gas fired auxiliary boiler are as follows: • NOx: 0.10 lb/MBtu. 2.1.1.3 Reciprocating Internal Combustion Engine MACT. The reciprocating internal combustion engine (RICE) Maximum Achievable Control Technology (MACT) can be found at 40 CFR 63 Subpart ZZZZ, National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines. Currently, the RICE MACT is applicable to stationary RICE at a major hazardous air pollutant (HAP) source. However, the RICE MACT does not apply to stationary RICE with a site rating of 500 brake horsepower (bhp) or less. Because the emergency fire booster pump is an approximately 149 bhp engine, it is not subject to the RICE MACT. The emergency fire pump and emergency generator engines will be greater than 500 bhp (575 and 2,919 bhp, respectively). However, new emergency stationary RICE units located at a major source of HAPs are subject only to the initial notification requirements of 40 CFR 63.6645(d). It is important to note that on June 12, 2006, the USEPA proposed revisions to the RICE MACT that would expand the applicability of the RICE MACT to stationary RICE of less than 500 bhp at a major HAP source and would include stationary RICE at area sources of HAPs. An area source of HAP emissions is a source that is not a major source of HAPs. If the June 12, 2006, proposed RICE MACT changes are finalized, the Project’s emergency fire booster pump will be an affected unit under the RICE MACT, regardless of whether the Project is a major source of HAPs. However, under the proposed changes to the RICE MACT, as with the existing RICE MACT, a new “emergency” stationary RICE is subject only to the initial notification requirements of the RICE MACT. Because the emergency generator, emergency fire pump, and emergency fire booster pump engines are all considered emergency stationary RICE units, if the 102607-145491 2-3 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 BACT Analysis Basis proposed RICE MACT changes are finalized, these engines will be subject only to the initial notification requirements. 2.1.1.4 NSPS Subpart IIII – Standards of Performance for Stationary Compression Ignition Internal Combustion Engines. The Project’s emergency generator, emergency fire pump, and emergency fire booster pump engines will be subject to the manufacturer’s certification requirements of compliance to NSPS Subpart IIII. The rule provides various emissions standards based on the engine’s use, manufacture date, and engine size. The applicable standards associated with the equipment will be dependent on the engine model year. Beginning with engines manufactured in model year 2007, the onus of this rule falls on the engine manufacturers, since they are required to manufacture engines that comply with the rule. The requirement of this rule for owners and operators of these engines is that they purchase certified engines. 2.1.1.5 NSPS Subpart Y – Standards of Performance for Coal Preparation Plants. The Project’s coal conveying, storage, transfer, loading, and processing operations will be subject to NSPS Subpart Y. NSPS Subpart Y includes new source limitations for PM/PM10. The applicable NSPS Subpart Y emissions limitation for the coal handling facility is as follows: • PM/PM10: 20 percent opacity. 2.1.1.6 NSPS Subpart OOO – Standards of Performance for Nonmetallic Mineral Processing Plants. The Project’s proposed wet FGD system uses a limebased slurry to control the emissions of SO2. The slurry is created from bulk limestone, which is delivered to the site via bottom dump hopper railcars or alternatively by delivery truck. A limestone slurry system will grind the limestone and mix it with water to be used as a reagent for the wet FGD SO2 emissions control system. Limestone is classified as a nonmetallic mineral requiring further processing at the facility, the types of which are covered by NSPS Subpart OOO. Therefore, the Project’s limestone handling, storage, transfer, and grinding operations will be subject to NSPS Subpart OOO. NSPS Subpart OOO includes new source limitations for PM/PM10. The applicable NSPS Subpart OOO emissions limitation is as follows: • PM/PM10: 7 percent opacity. 2.1.1.7 NSPS Subpart HHHH – Emission Guidelines and Compliance Times for Coal Fired Electric Steam Generating Units. This subpart establishes the model rule comprising general provisions and the designated representative, permitting, allowance, and monitoring provisions for the state mercury (Hg) Budget Trading Program, under Section 111 of the CAA known as the Clean Air Mercury Rule (CAMR), as a means of reducing national Hg emissions. Iowa has amended its air quality 102607-145491 2-4 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 BACT Analysis Basis regulations to adopt the federal CAMR rules, including the Hg trading and monitoring provisions. The SGS Unit 4 SCPC fired boiler will comply with the provisions of the CAMR cap-and-trade program by holding sufficient Hg allowances in an amount no less than its annual emissions of Hg. 2.2 Unit Operations and Baseline Emissions Basis Prior to initiating this air permitting process, IPL commissioned a technology assessment study to evaluate and compare alternative power generation processes for its portfolio planning. The generation alternatives considered by IPL include the following: • SCPC. • Circulating Fluidized Bed (CFB). • Integrated Gasification Combined Cycle (IGCC). Based on an analysis of the possible power generation alternatives (the results of which are documented in a report entitled Site Evaluation Study – Coal Technology Assessment (included as Appendix J of the air permit application package), IPL concluded that the appropriate project design alternative, commensurate with the forecasted load demand and fuel costs, would be a 649 MW (net) SCPC fired unit at the existing SGS. It is USEPA’s long-standing policy that the BACT analysis process does not require a redefinition or redesign of a project. See letter from S. Page, USEPA, to P. Plath (December 13, 2005). Therefore, based on USEPA’s policy, the BACT analysis will focus on pollution control technologies applicable to pulverized coal boiler technologies. IPL proposes applicable work practice standards, such as good air pollution control practices and proper operation and maintenance, and ton per year emission caps as BACT during startup, shutdown, and malfunctions. While SGS Unit 4 is proposed as a baseload unit and being permitted for unlimited annual operation, the unit will infrequently be required to shut down and start up depending on load requirements and system maintenance. The boiler will be designed to initially start up on clean emitting natural gas until the load on the boiler reaches approximately 10 percent, after which coal will be introduced into the boiler in combination with the startup fuel for stabilization, until the boiler reaches approximately 25 percent of load. 102607-145491 2-5 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 BACT Analysis Basis Startup of the boiler from cold conditions to full load is estimated to take between 8 and 12 hours. If the auxiliary boiler is used to maintain heat in the boiler, startup time is reduced. Natural gas fuel is used in the boiler ignitors to slowly increase boiler metal temperatures. Once boiler load has increased beyond the minimum capacity of one coal mill (approximately 4 to 6 hours into startup), a coal mill is started and the boiler is operated on both natural gas fuel and coal. Once stable operation on coal has been established on two mills (approximately 25 percent load, 8 to 10 hours into startup), the natural gas fuel is discontinued and boiler load is increased as necessary using primarily coal fuel. As additional coal mills are started, natural gas fuel is briefly (less than an hour) used in the appropriate individual boiler ignitors to ensure safe startup of the mill. The AQC equipment has differing startup requirements before it becomes fully effective. A fabric filter that controls PM/PM10 becomes effective instantaneous with the startup of the boiler. A wet FGD that controls SO2 becomes effective instantaneous with the startup of the boiler. An SCR that controls NOx does not become fully effective until the flue gas temperature after the economizer of the boiler reaches approximately 550º F to 600º F which is critical with the injection of ammonia. The SCR has an operating temperature range of approximately 600º F to 800º F in effectively controlling NOx. The temperature range needs to be closely adhered to in avoidance of damaging the catalyst or possible fouling of the air heater. The estimated time of the SCR to become fully effective is between 25 to 50 percent load (approximately 8 to 11 hours). As for CO and VOC control, good combustion controls are used. Good combustion controls begin to become effective at approximately 60 percent load when the boiler is tuned and it is achieving its steam temperature. The estimated time of good combustion controls is approximately 11 to 12 hours into startup. As a practical and regulatory matter, a BACT determination, in addition to having to be technically feasible as previously described, must be enforceable. For the purposes of a BACT determination for periods of startup, shutdown, and malfunction, an important consideration to be made is whether an emission limit is practicably enforceable as a BACT determination. Consideration of this issue relies heavily and primarily on whether emission measurements made during these transient events can be used to determine compliance with a specified emission limit. For coal fired boilers, emission tests cannot be conducted with any suitable degree of reliability during startup, shutdown, and malfunction in order to serve as a reliable method of demonstrating compliance with an expressed BACT emission limit. This is similar and consistent with the regulatory provisions of the NSPS, where the operations during periods of startup, shutdown, and malfunction are not considered representative conditions for the purpose of conducting compliance performance tests. In other words, the use of an emission limit to establish BACT compliance during startup, shutdown, and 102607-145491 2-6 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 BACT Analysis Basis malfunction is not considered practicably enforceable. However, the regulatory definition of BACT envisioned these types of circumstances and provided for the use of applicable work practice standards such as good air pollution control practices and proper operation and maintenance as a basis for measurable and practicably enforceable compliance elements in lieu of emission standards. The Project is proposed as a baseloaded electric generating facility and, for the purposes of this application, is designed to operate unrestricted for 8,760 hours per year. Ancillary air emissions sources, such as the auxiliary boiler, emergency generator, and emergency fire pumps, will operate infrequently and typically only when the coal fired boiler is not, or under emergency conditions. The following subsections characterize the unit size, fuel, operating scenario, and emissions assumptions that were collectively utilized as a basis for the BACT analysis. A more detailed Project description is provided in Section 2.2 of the Main Application. 2.2.1 Coal Fired Boiler Table 2-1 presents the BACT design basis for the Project’s coal fired boiler. Table 2-1 Main Boiler Design Basis(1) Size Maximum Heat Input Operating Hours Fuel Startup Fuel 649 MW (net) 6,326 MBtu/h(2) 8,760 h/yr Powder River Basin (PRB) or Illinois Basin Coals with Biomass Natural Gas (1) 100 percent load, average annual site conditions. Based upon firing PRB coal. (2) The Project will burn low sulfur PRB and Illinois Basin coals in SGS Unit 4’s boiler. The Project will have the capability of burning the PRB and Illinois Basin coal separately or as a blend of the two coals. Additionally, the Project will be capable of burning a blend of biomass (5 percent based on fuel heat input) with either PRB or Illinois Basin coal fuel or with a blend of the PRB/Illinois Basin coal. Table 2-2 presents the typical coal quality fuel specifications for the Rawhide Mine (PRB) coal, Greater Belleville (Illinois Basin) coal, and biomass fuel, which are considered representative of the fuels proposed for this Project, hereinafter, referred to as the Project’s coal fuel alternatives. 102607-145491 2-7 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 BACT Analysis Basis Table 2-2 Coal and Biomass Fuel Specifications Greater Belleville Illinois Basin Biomass 10,800 6,384 As Received As Received As Received Description Value Rawhide Mine PRB Higher Heating Value (HHV) Btu/lbm 8,300 Ultimate Analysis Basis Carbon % 48.58 60.06 41.15 Hydrogen % 3.34 4.20 4.30 Nitrogen % 0.62 1.12 0.48 Sulfur % 0.33 3.11 0.10 Chlorine % 0.00 0.10 0.12 Ash % 4.93 9.52 4.85 Moisture % 30.50 14.20 15.00 Oxygen (by difference) % 11.70 7.69 34.14 For the purposes of the SO2 BACT analysis and the SO2 control technology and emissions level determination, the Greater Belleville (Illinois Basin) coal fuel and its range of heating value and sulfur content are considered representative of the worst-case fuels proposed for this Project. Table 2-3 presents minimum, typical, and maximum sulfur content and heating values of the worst-case Greater Belleville (Illinois Basin) coal, along with the corresponding uncontrolled SO2 emissions rates. Using the design basis presented in Table 2-1 and the fuel specifications presented in Tables 2-2 and 2-3, the uncontrolled baseline emissions from the Project’s coal fired boiler are presented in Tables 2-4 and 2-5 for PRB and Illinois Basin coal, respectively. The uncontrolled emissions for the Project’s representative coal alternatives were analyzed to determine the worst-case scenario for each pollutant. The worst-case scenario for each pollutant is the basis for the BACT analysis. 102607-145491 2-8 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 BACT Analysis Basis Table 2-3 Sulfur and Heating Value Fuel Variability for Worst-Case Greater Belleville (Illinois Basin) Coal Fuel Variability Sulfur Content (percent by weight) Higher Heating Value (Btu/lb) Uncontrolled SO2 Emissions Rate (lb/MBtu) Minimum 2.50 10,400 4.81 Typical 3.11 10,800 5.76 Maximum 4.00 11,100 7.21 Table 2-4 Main Boiler Baseline Uncontrolled Emissions PRB Coal Pollutant Mass Rate (lb/h) Emissions Level (lb/MBtu) SO2 5,025 0.794 NOx 1,275 0.20 PM/PM10 (filterable) 30,439 4.81 CO 759 0.12 VOC 21.51 0.0034 H2SO4 153.8 0.0243 Fluorides 26.6 0.0042 Total emissions are based on typical, baseload fuel coal specifications for each pollutant at 6,326 MBtu/h. Items underlined represent the basis of the BACT analysis. 102607-145491 2-9 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 BACT Analysis Basis Table 2-5 Main Boiler Baseline Uncontrolled Emissions Illinois Basin Coal Pollutant Mass Rate (lb/h) Emissions Level (lb/MBtu) SO2 35,493 5.75 NOx 1,234 0.20 PM/PM10 (filterable) 43,874 7.11 CO 740 0.12 VOC 20.97 0.0034 H2SO4 1,086 0.176 Fluorides 56.75 0.0092 Total emissions are based on typical, baseload fuel coal specifications for each pollutant at 6,169 MBtu/h. Items underlined represent the basis of the BACT analysis. It should be noted that the unit is planning for an “as-needed” operating fly ashsegregating dry electrostatic precipitator (DESP) just downstream of the air heater and any proposed back-end BACT equipment (except for the SCR). Compared to a full-scale DESP designed for primary particulate control, the proposed scavenging DESP is a much undersized version, designed only to operate as process equipment to segregate fly ash for beneficial reuse. The installation of the as-needed DESP does not fall under any BACT requirement, since it will not be used for primary control or emissions compliance. Since the unit will not always operate the DESP, the particulate BACT analysis is based on the primary particulate control device discussed in Section 5.0 of this analysis. 102607-145491 2-10 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.2.2 2.0 BACT Analysis Basis Auxiliary Boiler Table 2-6 presents the BACT design basis for the Project’s auxiliary boiler. Table 2-6 Auxiliary Boiler Design Basis* Size Maximum Heat Input Operating Hours Fuel 200,000 lb-steam/h 270 MBtu/h 2,000 h/yr Natural gas *100 percent full load, average annual site conditions. Based on the design basis presented in Table 2-6, the baseline emissions from the Project’s auxiliary boiler are presented in Table 2-7. Table 2-7 Auxiliary Boiler Baseline Emissions* Pollutant Mass Rate (lb/h) Emissions Level (lb/MBtu) SO2 NOx PM/PM10 (filterable) CO VOC H2SO4 0.16 9.94 1.88 19.88 1.34 0.2 0.0006 0.037 0.007 0.074 0.005 0.0009 *Emissions based on manufacturer’s performance data and maximum fuel heat input. 102607-145491 2-11 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.2.3 2.0 BACT Analysis Basis Emergency Generator Table 2-8 presents the BACT design basis for the Project’s emergency generator. Table 2-8 Emergency Generator Design Basis Size 2,000 kW Maximum Horsepower 2,919 bhp Operating Hours 100 h/yr* Fuel Low sulfur distillate fuel oil (<0.05% sulfur) *Operated 1 to 2 hours weekly for testing and maintenance. Based on the design basis presented in Table 2-8, the baseline emissions from the Project’s emergency generator are presented in Table 2-9. Table 2-9 Emergency Generator Baseline Emissions* Pollutant Mass Rate (lb/h) Emission Level (g/bhph) SO2 0.49 0.15 NOx 20.94 6.47 PM/PM10 (filterable) 0.13 0.08 CO 1.72 0.53 VOC 0.87 0.27 H2SO4 0.74 0.23 *Emissions based on manufacturer’s performance data. VOC emissions based on a USEPA AP-42 air emissions factor. 102607-145491 2-12 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.0 BACT Analysis Basis 2.2.4 Emergency Fire Pumps Table 2-10 presents the BACT design basis for the Project’s emergency fire pump and emergency fire booster pump engines. Table 2-10 Emergency Fire Pumps Design Basis Unit Fire Pump Fire Booster Pump Maximum Horsepower 575 bhp 149 bhp Operating Hours 100 h/yr* 100 h/yr* Fuel Low sulfur distillate fuel oil (<0.05% sulfur) Low sulfur distillate fuel oil (<0.05% sulfur) *Operated 1 to 2 hours weekly for testing and maintenance. Based on the design basis presented in Table 2-10, the baseline emissions from the Project’s emergency fire pumps are presented in Table 2-11. Table 2-11 Emergency Fire Pumps Baseline Emissions(1) Unit Fire Pump Fire Booster Pump Mass Rate (lb/h) Emissions Level (g/bhph) Mass Rate (lb/h) Emissions Level (g/bhph) 0.20 0.16 0.11 0.20 NOx + NMHC 6.21 4.90 1.71 5.20 PM/PM10 (filterable) 0.10 0.08 0.06 0.19 CO 0.95 0.75 0.11 0.33 VOC 0.37 0.29 0.12 0.36 H2SO4 0.31 0.25 0.10 0.31 Pollutant SO2 (2) (1) Emissions based on manufacturer’s performance data. VOC emissions based on a USEPA AP-42 air emissions factor. (2) NMHC = Non-Methane Hydro Carbon. 102607-145491 2-13 Interstate Power and Light Sutherland Unit 4 Air Permit Application 2.2.5 2.0 BACT Analysis Basis Gate Station Gas Heater Table 2-12 presents the BACT design basis for the Project’s gate station gas heater. Table 2-12 Gate Station Gas Heater Design Basis* Maximum Heat Input 3.0 MBtu/h Operating Hours 8,760 h/yr Fuel Natural Gas *Full load operation, average annual site conditions. Based on the design basis presented in Table 2-12, the baseline emissions from the Project’s gate station gas heater are presented in Table 2-13. Table 2-13 Gate Station Gas Heater Baseline Emissions* Pollutant Mass Rate (lb/h) Emissions Level (lb/MBtu) SO2 0.002 0.0006 NOx 0.14 0.05 PM/PM10 (filterable) 0.02 0.007 CO 0.14 0.05 VOC 0.02 0.005 H2SO4 0.003 0.0009 *Emissions based on manufacturer’s performance data. PM/PM10, SO2, and VOC emissions based on USEPA AP-42 air emissions factors. 102607-145491 2-14 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.0 3.0 Coal Fired Boiler SO2 BACT Analysis Coal Fired Boiler SO2 BACT Analysis This section presents the top-down, five-step BACT process that was used to evaluate and determine the Project’s SO2 emissions limits for the main boiler. As this analysis will demonstrate, the proposed SO2 BACT limit for the Project’s main boiler is a emission limit of 0.06 lb/MBtu (based on a 30 day rolling average) or 98 percent SO2 removal (whichever occurs first) with a 0.08 lb/MBtu (based on a 30 day rolling average) upper limit. 3.1 Step 1--Identify All 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 SO2 emission limit that is being evaluated. There are several pre-combustion and post-combustion FGD processes that have demonstrated SO2 removal capabilities for use with of a pulverized coal fired boiler. Based on the various SO2 removal alternatives, lime and limestone wet scrubbers and lime semi-dry/dry scrubber systems are the most widely used FGD systems. In comparing the various FGD technologies and applications, both the controlled emissions limit and the percent of SO2 removed need to be considered. Depending on the coal sulfur content or SO2 loading, either of these performance criteria can represent the limiting factor for the performance that the technology can achieve. High SO2 loading may allow for higher removal efficiencies than lower sulfur fuels on a percentage basis, while lower sulfur fuels can achieve lower absolute emissions limits. The following subsections review the available pre-combustion and post-combustion SO2 control technologies. 3.1.1 Coal Washing Pre-combustion control technology can be considered a fuel cleaning or treatment method for reducing baseline SO2 emissions. One way of reducing SO2 emissions from a coal fired plant is to remove the sulfur from the coal prior to the combustion process. The basic theory of coal washing is that pure coal is lighter than rock or any impurities that are contained in the coal. Coal washing utilizes various techniques such as high speed coal washes or agitating liquids to produce a separation of impurities from the coal. As a part of this separation of impurities, pyritic sulfur will be separated from the coal product. Various reports have shown that the sulfur content in the coal is reduced from 30 to 50 percent. As the sulfur content (especially the pyritic sulfur) in the fuel decreases (e.g., 102607-145491 3-1 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.0 Coal Fired Boiler SO2 BACT Analysis Illinois Basin to PRB coals), the amount of potential sulfur removal also decreases. In addition, some of the carbon is removed with the sulfur containing underflow, which lowers the overall recovery of useable energy from the coal reserve which in turn influences the cost of final coal product. Since coals from many different coal mines may be fired at this plant, the costs for washing may vary widely between the different coals used. The costs of physical coal cleaning are usually reported in terms of the added cost of the cleaned product over the original run-of-mine coal. Capital costs (for construction of the coal cleaning facility) and operating costs can be separated; however, overall costs are often reported without identification of components. Capital costs reported by the Carbondale Coal Research Center range from $12 to $16 per ton of coal capacity, with operating costs ranging from $3.17 per ton to $4.40 per ton for systems featuring high Btu recovery. The USEPA COALCVAL2.0 computer program also assumes a coal washing cost of $3.25 to $3.33 per ton, depending on the type of mine. Western subbituminous coals are unlikely to be washed because of their inherently low sulfur content. Because coal washing on its own cannot achieved the desired emission reductions, post combustion controls will be included in the Project design. Because the Project intent is to purchase non PRB coals during supply deficiencies, coal supply availability and subsequent economics will drive the fuel supply decision process. Consequently, the range of fuel parameters for this Project represents the range of cost-effective fuels which generate emissions that can be effectively controlled by post-combustion control technology. Because of the need to transport the coal over large distances and the need to use reagents to remove sulfur and other impurities from the flue gas, the economic evaluation will favor higher heat content and lower sulfur coal supplies. 3.1.2 Wet Lime- and Limestone-Based FGD Processes Wet lime- and limestone-based FGD processes are frequently applied to pulverized coal fired boilers that combust medium-to-high sulfur eastern coals. All of the FGD systems installed in response to Phase I of the 1990 CAA were based on a wet FGD system using either lime or limestone as the reagent. Typically, the wet FGD processes on a pulverized coal facility are characterized by high efficiency (> 98 percent) and high reagent utilization (95 to 97 percent) when combined with a high sulfur fuel. The ability to realize high removal efficiencies on higher sulfur fuels is a major difference that the wet scrubbers have compared to semi-dry/dry FGD processes. The removal efficiency of the various types of wet scrubbers declines as the fuel sulfur content decreases; this is the case for low sulfur western and PRB coals. It is well known that SO2 removal 102607-145491 3-2 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.0 Coal Fired Boiler SO2 BACT Analysis efficiencies for wet FGD systems are generally higher for high sulfur coal applications than for low sulfur coal applications, for the fundamental physical reason that the chemical reactions that remove SO2 are faster if the inlet SO2 concentration is higher. The absolute emissions level becomes a limiting factor due to a reduction in the chemical driving forces of the reactions that are occurring. In a wet FGD system, the absorber module is located downstream of the induced draft (ID) fans (or booster ID fans, if required). Flue gas enters the module and is contacted with a slurry containing reagent and byproduct solids. The SO2 is absorbed into the slurry and reacts with the calcium to form CaSO3•1/2H2O and CaSO4•2H2O. SO2 reacts with limestone reagent through the following overall reactions: SO2 + CaCO3 + ½H2O → CaSO3•½H2O + CO2 SO2 + CaCO3 + 2H2O + ½O2 → CaSO4•2H2O + CO2 There are several types of wet absorber modules, and each has characteristic advantages and disadvantages. FGD equipment vendors have specific designs for one or more types, and all compete on a capital and operating cost basis. Depending on the process vendor, the absorber may be a co-current or countercurrent spray tower, with or without internal packing or trays, or a process in which the flue gas is bubbled into the reaction tank (commonly referred to as a jet bubbling reactor (JBR)). Regardless of the type of absorber used, the flue gas leaving the absorber will be saturated with water, and the stack will have a visible moisture plume. Because of the chlorides present in the mist carry-over from the absorber and the pools of low pH condensate that can develop, the conditions downstream of the absorber are highly corrosive to most materials of construction. Highly corrosion-resistant materials are required for the downstream ductwork and the flue stack. Careful design of the stack is needed to prevent the “rainout” from condensation that occurs in the downstream ductwork and stack. These factors contribute to the relatively high capital costs of the wet FGD SO2 control alternative. The reaction products are typically dewatered by a combination of hydrocyclones and vacuum filters. The resulting filter cake is suitable for landfill disposal. In early lime- and limestone-based FGD processes, the byproduct solids were primarily calcium sulfite hemihydrate (CaSO3•1/2H2O), and the byproduct solids were mixed with fly ash (stabilization) or fly ash and lime (fixation) to produce a physically stable material. In the current generation of wet FGD systems, air is bubbled through the reaction tank (or in some cases, a separate vessel) to practically convert all of the CaSO3•1/2H2O into calcium sulfate dihydrate (CaSO4•2H2O), which is commonly known as gypsum. This 102607-145491 3-3 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.0 Coal Fired Boiler SO2 BACT Analysis step is termed “forced oxidation” and has been applied to both lime- and limestone-based FGD processes. Compared to calcium sulfite hemihydrate, gypsum has much superior dewatering and physical properties, and forced oxidized FGD systems tend to have few internal scaling problems in the absorber and mist eliminators. Dewatered gypsum can be landfilled without stabilization or fixation. Many FGD systems in the United States are using the forced-oxidation process to produce a commercial grade of gypsum that can be used in the production of portland cement or wallboard. Marketing of the gypsum can eliminate or greatly reduce the need to landfill FGD byproducts. The absorber vessels are fabricated from corrosion-resistant materials such as epoxy/vinylester-lined carbon steel, rubber-lined carbon steel, stainless steel, or fiberglass. The absorbers handle large volumes of abrasive slurries. The byproduct dewatering equipment is also relatively complex and expensive. These factors result in relatively higher initial capital costs. Wet FGD processes are also characterized by higher raw water usage than semi-dry FGD systems. This can be a significant disadvantage or even a fatal flaw in areas where raw water availability is in short supply. Numerous suppliers offer FGD processes using limestone slurry as the reagent. The various wet FGD technologies that use lime/limestone slurry as the reagent are as follows: • Countercurrent Spray Tower. • Double Contact Spray Tower. • Jet Bubbling Reactor (JBR). • FLOWPAC. For the purposes of this analysis, all of the wet FGD systems identified, while having different equipment, will generally meet the emissions rate objective and have similar operating characteristics. 3.1.2.1 Countercurrent Spray Tower. A countercurrent spray tower has become one of the most widely used absorber types in wet lime- and limestone-based FGD service. Flue gas enters at the bottom of the absorber and flows upward. Slurry with 10 to 15 percent solids is sprayed downward from higher elevations in the absorber and is collected in a reaction tank at its base. The SO2 in the flue gas is transferred from the flue gas to the recycle slurry. The hot flue gas is also cooled and saturated with water. Recycled slurry is pumped continuously from the reaction tank to the slurry spray headers. Each header has numerous individual spray nozzles that break the slurry flow into small droplets and distribute them evenly across the cross section of the absorber. Prior to leaving the absorber, the treated flue gas passes through a two-stage, chevrontype mist eliminator that removes entrained slurry droplets from the gas. The mist eliminator is periodically washed to keep it free of solids. 102607-145491 3-4 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.0 Coal Fired Boiler SO2 BACT Analysis In the reaction tank, the SO2 absorbed from the flue gas reacts with soluble calcium ions in the recycle slurry to form insoluble calcium sulfite and calcium sulfate solids. In forced-oxidization processes, air is bubbled through the slurry to convert all of the solids to calcium sulfate dihydrate (gypsum). A lime or limestone reagent slurry is added to the reaction tank to replace the calcium consumed. To control the solids content of the recycle slurry, a portion of the slurry is discharged from the reaction tank to the byproduct dewatering equipment. Depending on the ultimate disposal of the byproduct solids, the dewatering equipment may include settling ponds, thickeners, hydrocyclones, vacuum filters, and centrifuges. The liquid that is separated from the byproduct solids slurry is stored in the reclaim water tank. Water in the reclaim water tank is returned to the absorber reaction tank as makeup water and used to prepare the reagent slurry. 3.1.2.2 Double Contact Spray Tower. The double contact spray tower uses the same process chemistry as the countercurrent spray tower, but the flue gas and slurry flow countercurrently in the first section of the absorber module and co-currently in the second stage. In this design, the recycled slurry is evenly distributed across the absorber by low-pressure fountain type nozzles. The resulting fountains of slurry fall back down into the reaction tank. Because of the lower nozzle pressure, the solids level in the recycle slurry can be raised to 15 to 25 percent without resulting in an unacceptable rate of nozzle wear. Compared to the countercurrent design, the dual contact spray tower operates at a higher flue gas velocity since there is less concern about the entrainment of slurry droplets in the flue gas. This alternative may use either a vertical gas flow mist eliminator or a horizontal gas flow mist eliminator that can also operate at a higher velocity than vertical gas flow mist eliminators. 3.1.2.3 Jet Bubbling Reactor. The absorber module for this technology is unique in the FGD industry because the surface area required for absorption of SO2 from the flue gas is created by bubbling the flue gas through a pool of slurry rather than by recycling slurry through the flue gas, which is the process used in other absorber types. Flue gas is pre-cooled with makeup water and slurry prior to entering the JBR’s inlet plenum. The inlet plenum is formed by upper and lower deck plates. From this plenum, the flue gas is directed through multiple, 6 inch diameter, sparger tube openings in the lower deck. These tubes are submerged a few inches beneath the level of slurry in the integral reaction tank located at the base of the JBR. The bubbling action of the flue gas as it exits the sparger tubes and rises through the slurry promotes SO2 absorption. The gas then leaves the reaction tank area and the outlet plenum via gas risers that pass through both the lower and upper decks. An external horizontal gas flow mist eliminator removes the residual mist carried over from the JBR. 102607-145491 3-5 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.0 Coal Fired Boiler SO2 BACT Analysis To establish the liquid-gas contact needed to absorb SO2 from the flue gas requires energy. In a spray tower system, this energy is provided by the spray pumps that produce a large number of fine droplets. In a JBR, this energy is provided by the fans necessary to account for the pressure drop across the spargers. Therefore, the JBR has two to three times as great a gas pressure drop as a spray tower FGD system, but less than 20 percent of the pumping horsepower requirement. 3.1.2.4 FLOWPAC. The FLOWPAC process is similar to a JBR in that the flue gas is forced to bubble through a limestone slurry. The flue gas enters the absorber under a sieve tray and passes up through holes in the sieve tray and into a turbulent limestone slurry bed. SO2 is removed from the flue gas as the flue gas is contacted with the limestone slurry. The FLOWPAC absorber is a cylindrical tank with a central recycle tank and downcomers located on the circumference of the tank. The sieve tray encircles the absorber recycle tank. Oxidation air is added into the recycle tank of the absorber along with agitation. The oxidation air lowers the effective density in the recycle tank, which causes circulation out of the recycle tank and through the downcomers. This circulation eliminates the need for large absorber recycle pumps. After the flue gas travels through the limestone slurry, it passes through a vertical mist eliminator prior to exiting to a chimney. 3.1.3 Semi-Dry Lime-Based FGD Systems Semi-dry spray dryer absorber (SDA) FGD processes have been extensively used. US utilities have installed numerous SDA FGD systems on boilers using low sulfur fuels. These installations, primarily located in the western United States, use either lignite or subbituminous coals such as PRB as the boiler fuel and generally have spray dryer systems designed for a maximum fuel sulfur content of less than 2 percent. The semi-dry lime-based FGD system has an inherent removal efficiency limitation of 94 percent from inlet concentration. The semi-dry FGD process uses calcium hydroxide [Ca(OH)2] produced from the lime reagent as either a slurry or as a dry powder to the flue gas in a reactor designed to provide good gas-reagent contact. The SO2 in the flue gas reacts with the calcium in the reagent to produce primarily calcium sulfite hemihydrate (CaSO3•1/2H2O) and a smaller amount of calcium sulfate dihydrate (CaSO4•2H2O) through the following reactions: SO2 + Ca(OH)2 → CaSO3•½H2O + ½H2O SO2 + Ca(OH)2 + ½O2 → CaSO4•2H2O 102607-145491 3-6 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.0 Coal Fired Boiler SO2 BACT Analysis Water is also added to the reactor (either as part of the reagent slurry or as a separate stream) to cool and humidify the flue gas, which promotes the reaction and reagent utilization. The amount of water added is typically sufficient to cool the flue gas to within 30° to 40° F of the flue gas adiabatic saturation temperature. Significantly less water is used in these semi-dry FGD processes compared to wet FGD processes. The reaction byproducts and excess reagent are dried by the flue gas and removed from the flue gas by a particulate control device (either fabric filter or DESP). Fabric filters are preferred for most systems, because the additional contact of the flue gas with the particulate on the filter bags provides additional SO2 removal and higher reagent utilization. A portion of the reaction byproducts collected is recycled to the reagent preparation system in order to increase the utilization of the lime. Because of the large amount of excess lime present in the FGD byproducts, the byproducts (and fly ash, if present) will experience pozzolanic (cementitious) reactions when wetted. When wetted and compacted, the byproduct makes a fill material with low permeability (low lengthening characteristics) and high bearing strength. However, other than as structural fill, this byproduct has limited commercial value and typically must be disposed of as a waste material. The semi-dry FGD processes offer benefits in addition to SO2 removal, including the lack of a visible vapor plume and SO3 removal. Because the semi-dry FGD systems do not saturate the flue gas with water, there is no visible plume from the stack under most weather conditions. Environmental concerns with SO3 emissions are also reduced with the semi-dry scrubber. SO3 is formed during combustion and will react with the moisture in the flue gas to form sulfuric acid (H2SO4) mist in the atmosphere. An increase in H2SO4 emissions will increase PM10 emissions. The gas temperature leaving the reactor is lowered below the sulfuric acid dew point, and significant SO3 removal will be attained as the condensed acid reacts with the alkaline reagent. By removing SO3 in the flue gas, the condensable particulate matter emissions can be reduced. This will reduce the potential for any SO3 plume that may cause opacity in stacks. Similar type SO3 removal is not achievable with a wet scrubber. The following four variants of semi-dry FGD processes are described further in this analysis: • SDA. • Circulating Dry Scrubber (CDS). • Flash Dryer Absorber. • Limestone Injection into the Furnace and ReActivation of Calcium (LIFAC). 102607-145491 3-7 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.0 Coal Fired Boiler SO2 BACT Analysis 3.1.3.1 Spray Dryer Absorber. All current SDA designs use a vertical gas flow absorber. These absorbers are designed for co-current or a combination of co-current and countercurrent gas flow. In co-current applications, gas enters the cylindrical vessel near the top of the absorber and flows downward and outward. In combination-flow absorbers, a gas disperser located near the middle of the absorber directs a fraction of the total flue gas flow upward toward the slurry atomizers. In both cases, the atomizers are located in the roof of the absorber. Both rotary and two-fluid nozzles have been applied to this approach. The atomizer produces an umbrella of atomized reagent slurry through which the flue gas passes. The SO2 in the flue gas is absorbed into the atomized droplets and reacts with the calcium to form calcium sulfite and calcium sulfate. Before the slurry droplet can reach the absorber wall, the water in the droplet evaporates and a dry particulate is formed. Some vendors base their designs on a single large rotary atomizer per absorber; others use up to three smaller rotary atomizers per absorber. Two-fluid atomizers are installed as an array of up to 16 nozzles per atomizer; all three approaches to spray atomizers have been successfully applied. The flue gas, then containing fly ash and FGD byproduct solids, leaves the absorber and is directed to a fabric filter. The fly ash and byproduct solids collected in the fabric filter are pneumatically transferred to a silo for disposal. To improve both reagent utilization and spray solids drying efficiency, a large portion of the solids collected is directed to a recycle system, where it is slurried and re-injected into the spray dryer along with the fresh lime reagent. 3.1.3.2 Circulating Dry Scrubber. The CDS FGD process is a semi-dry, lime-based FGD process that uses a circulating fluid bed contactor rather than an SDA. The CDS absorber module is a vertical solid/gas reactor between the unit’s air heater and its particulate control device. Water is sprayed into the reactor to reduce the flue gas temperature to the optimum temperature for reaction of SO2 with the reagent. Hydrated lime [Ca(OH)2] and recirculated dry solids from the particulate control device are injected concurrently with the flue gas into the base of the reactor just above the water sprays. The gas velocity in the reactor is reduced, and a suspended bed of reagent and fly ash is developed. The SO2 in the flue gas reacts with the reagent to form predominantly calcium sulfite. Fine particles of byproduct solids, excess reagent, and fly ash are carried out of the reactor and removed by the particulate removal device (either a fabric filter or DESP). More than 90 percent of these solids are returned to the reactor to improve reagent utilization and increase the surface area for SO2/reagent contact. 102607-145491 3-8 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.0 Coal Fired Boiler SO2 BACT Analysis The CDS FGD system produces an extremely high solids load on the particulate removal device as a result of recycling the byproduct/fly ash mixture. For this reason, some CDS FGD system vendors prefer to use an DESP rather than a fabric filter. Most of the recycled material can be collected in the first field of an DESP with minimal effect on the overall DESP sizing. In contrast, a fabric filter in this same service would require special design features to avoid the reduced bag life associated with frequent bag cleaning. 3.1.3.3 Flash Dryer Absorber. The flash dryer absorber is a variation of CDS technology. In this system, the fly ash is mixed with lime or limestone and water in a mixer/hydrator prior to being injected into the flash dryer. The flue gas is evaporatively cooled and humidified by the water being absorbed onto the dry particulate. Furthermore, SO2 is removed from the flue gas stream by the reaction with the lime or limestone. The dry particulate is then removed in a fabric filter. A portion of the dry particulate from the fabric filter is collected for disposal. 3.1.3.4 Limestone Injection into Furnace and ReActivation of Calcium. In the early 1980s, Tampella Power Inc. of Finland began development of a humidification process that would enhance the effectiveness of the furnace-injection FGD process by humidifying the flue gas and installing a solid/gas contact reactor upstream of the particulate control device. This process is referred to by the acronym LIFAC. The two major differences between the LIFAC process and the furnace-injection process are the use of a reactor to enhance reagent contact with the flue gas and the recirculation of a portion of the fly ash and byproduct solids collected in the particulate control device to the reactor. This recirculation greatly improves the effectiveness of the process’s reagent usage and its SO2 removal efficiency. This process is offered only by Tampella Power or one of its affiliated companies, and has been applied to full-scale, coal fired utility boilers in Finland, Russia, Canada, and the United States. 3.2 Step 2--Eliminate Technically Infeasible 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 102607-145491 3-9 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.0 Coal Fired Boiler SO2 BACT Analysis Step 1 of the BACT analysis and determine if they are technically feasible. Table 3-1 summarizes the evaluation of the technically feasible SO2 options. 3.2.1 Coal Washing Coal washing is a demonstrated technology of reducing SO2 emissions from a coal fired boiler; however, the effectiveness of coal washing is dependent on the coal type. As discussed in Subsection 3.1.1, coal washing utilizes various techniques such as high speed coal washes or agitating liquids to produce a separation of impurities from the coal. The pyretic sulfur will be separated from the coal product. Since IPL is proposing to utilize various types of coals, the effectiveness of coal washing will differ greatly. IPL is not aware of large-scale facilities that perform coal washing on western subbituminous coal, such as PRB, which is considered one of the design coals for the main boiler. Therefore, the supply of PRB coal that has been washed cannot be considered a reliable source for this Project. Coal washing is determined to be technically infeasible because PRB coal that has been washed may not be available. 3.2.2 Wet Lime- and Limestone-Based FGD Processes A wet lime- and limestone-based FGD process have been demonstrated technologies of controlling SO2 emissions from a coal fired boiler and are commercially available from several vendors. Wet lime- and limestone-based FGD processes, which include the countercurrent spray tower, double contact spray tower, jet bubbling reactor, and FLOWPAC, are equal for comparative purposes. Wet lime- and limestone-based FGD processes are considered technically feasible and will be considered further. 3.2.3 Semi-Dry Lime-Based FGD Systems Semi-dry SDA FGD processes have been extensively used on coal fired boilers for controlling SO2 emissions. However, the following four variants of semi-dry FGD processes are analyzed further in this analysis: • SDA. • CDS. • Flash Dryer Absorber. • LIFAC. 102607-145491 3-10 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.0 Coal Fired Boiler SO2 BACT Analysis Table 3-1 Summary of Step 2--Eliminate Technically Infeasible Options Technically Feasible (Yes/No) Technology Alternative Available Applicable Coal Washing Yes No – PRB coal that has been washed may not be available. Coal washing is not technically feasible. Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes – However, SDA has limited removal SO2 efficiency over the Project range of sulfur in fuels and will not be considered further. No – No installations comparable in size to this Project. Long-term high removal efficiency not demonstrated on range of sulfur in fuels of this Project. Yes – However, SDA has limited removal SO2 efficiency over the Project range of sulfur in fuels and will not be considered further. No – No installations comparable in size to this Project. Long-term high removal efficiency not demonstrated on range of sulfur in fuels of this Project. Wet Lime or Limestone FGD(1) Spray Tower Double Contact Spray Tower JBR FLOWPAC Dry and Semi-Dry Lime FGD SDA CDS Yes Flash Dryer Absorber Yes LIFAC Yes (1) All alternate technologies in wet lime or limestone FGD (i.e., spray tower, double contact spray tower, JBR, FLOWPAC) are equal for comparative purposes. 102607-145491 3-11 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.0 Coal Fired Boiler SO2 BACT Analysis 3.2.3.1 Spray Dryer Absorber. As discussed in Subsection 3.1.3.1, all current SDA designs use a vertical gas flow absorber that are for co-current or counter-current gas flow. All SDA systems are commercially available from several vendors. The systems are all considered technically feasible. However, SDAs cannot meet the expected BACT performance criteria when burning the proposed higher sulfur bituminous coal. A removal efficiency of 94 percent with a SDA would only result in a 0.35 lb/MBtu outlet emissions rate at the stack when firing the higher sulfur fuels proposed for this Project. If the IPL SGS Unit 4 was to be permitted to burn only PRB coal, then a SDA would be considered further as a SO2 control technology. As such, the SDA will not be considered further due to IPL’s range of sulfur in the proposed fuels. 3.2.3.2 Circulating Dry Scrubber. As discussed in Subsection 3.1.3.2, the CDS FGD process is a semi-dry, lime-based FGD process that uses a circulating fluid bed contactor rather than an SDA. CDS FGD processes have only been domestically applied to smaller coal-fired boilers, which are all under 100 MW. Since IPL’s main boiler is rated at 649 MW (net), the size and scale differences are too great. According to EPA’s NSR Manual (Draft), technologies that have not yet been applied to full scale operations need to be considered available. Thus, the CDS FGD process is not considered technically feasible and will not be considered further. 3.2.3.3 Flash Dryer Absorber. The flash dryer absorber is a demonstrated technology of controlling SO2 emissions from a coal fired boiler and is commercially available. An advantage of the flash dryer absorber is the minimal footprint that is required of the control equipment. The reactor, absorbent preparation system, and the particulate collector offers a small footprint compared to other SO2 control technologies. The flash dryer absorber is considered technically feasible. However, flash dryer absorbers cannot meet the expected BACT performance criteria when burning the proposed higher sulfur bituminous coal. A removal efficiency of 90 percent with a flash dryer absorber would only result in a 0.58 lb/MBtu outlet emissions rate at the stack when firing the higher sulfur fuels proposed for this Project. As such, the flash dryer absorber will not be considered further due to IPL’s range of sulfur in the proposed fuels. 3.2.3.4 Limestone Injection into Furnace and ReActivation of Calcium. The LIFAC process is a demonstrated technology of controlling SO2 emissions from a coal fired boiler on a limited number of installations and is considered commercially available. As described in Subsection in 3.1.3.4, the first step in the LIFAC process is limestone furnace injection (approximately 25 to 35 percent SO2 removal). The next step involves the flue gas humidification with dry ash recycle (SO2 removal up to 85 percent). The last step utilizes slurry ash recycle (increases the SO2 removal to 90 percent). However, LIFAC cannot meet the expected BACT performance criteria when burning the 102607-145491 3-12 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.0 Coal Fired Boiler SO2 BACT Analysis proposed higher sulfur bituminous coal. A removal efficiency of 90 percent with LIFAC would only result in a 0.58 lb/MBtu outlet emissions rate at the stack when firing the higher sulfur fuels proposed for this Project. In addition, LIFAC has not been applied domestically to similar sized boilers as proposed for the Project. LIFAC has been designed for plant capacities ranging from 25 to 200 MW. LIFAC will not be considered further because it is not technically feasible for the Project. 3.3 Step 3--Rank Remaining Control Technologies by Effectiveness A search of the information contained in the USEPA BACT/LAER Clearinghouse and other sources specified in Section 2.1 was conducted to determine the top level of SO2 control for coal fired pulverized coal boilers. A search was also conducted for recently permitted coal fired facilities whose BACT determinations have not yet been included in the current BACT/LAER Clearinghouse database. The results of this search for all coal fired boilers are listed in Attachment A, Table A-1, of this BACT analysis. Tables 3-2 and 3-3 (subbituminous and bituminous fuels, respectively) list the SO2 BACT determinations that have the closest attributes when compared to IPL’s SGS Unit 4, which include fuel type, boiler technology, and size of boiler. A review of the SO2 BACT determinations in Tables 3-2 and 3-3 indicates the following: • The most stringent SO2 permit proposed for a 2 x 980 MW pulverized coal boiler installation is 0.04 lb/MBtu, based on a 30 day average at Florida Power and Light Company (FPL), Glades Power Park located in Florida. The Glades Power Park proposed site is located approximately 100 miles from the Everglades National Park (Class I area). The close proximity of the Class I area and compliance with the stringent criteria were major factors in FPL proposing the SO2 emissions limit. Note, the PSD Air Permit Application was submitted on December 19, 2006, and the Air Permit Application remains “incomplete” (SFWMD WRAC Meeting on May 30, 2007, in Clewiston, Florida). Furthermore, the Florida Public Service Commission rejected the proposal for Glades Power Park on June 6, 2007, and the project was cancelled. This project is not considered further in this analysis, since the air permitting process did not result in a final BACT determination, much less a commercial demonstration of the proposed emission limit over a long-term period. 102607-145491 3-13 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.0 Coal Fired Boiler SO2 BACT Analysis Table 3-2 Subbituminous Fuels SO2 Top-Down RBLC Clearinghouse Review Results 102607-145491 3-14 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.0 Coal Fired Boiler SO2 BACT Analysis Table 3-3 Bituminous or Bituminous Blend of Fuels SO2 Top-Down RBLC Clearinghouse Review Results 102607-145491 3-15 Interstate Power and Light Sutherland Unit 4 Air Permit Application • • • • • 3.0 Coal Fired Boiler SO2 BACT Analysis The next most stringent permitted SO2 requirement for a pulverized coal boiler installation is 0.06 lb/MBtu at City Public Services of San Antonio, Calaveras Lake Station at J.K. Spruce located in Texas. Note, this is the most restrictive SO2 removal limit required in permit that has been issued at this time. The FGD system at this facility is documented to be a wet FGD and is based upon burning PRB coal. There are four proposed permits with SO2 removal limits of 0.06 lb/MBtu. All four projects are for pulverized coal boiler installations that burn a subbituminous coal and have a wet FGD as the documented SO2 control technology. The following are the four projects: 2 x 750 MW pulverized coal boiler installation at 0.06 lb/MBtu, based on a 24 hour basis at Sithe Global Desert Rock Power Plant located in New Mexico; 500 MW pulverized coal boiler installation at 0.06 lb/MBtu at BHP Billiton, Cottonwood Energy Center located in New Mexico; 750 MW pulverized coal boiler installation at 0.06 lb/MBtu, based on a 24 hour basis at Touquop Energy Project located in Nevada; and 2 x 750 MW pulverized coal boiler installation at 0.06 lb/MBtu, based on a 24 hour basis at Sierra Pacific and Nevada Power, Ely Energy Center located in Nevada. However, unlike IPL SGS Unit 4, none of these units fire a high sulfur coal as a primary alternate coal. The next most stringent SO2 emissions limit that has been permitted is 0.065 lb/MBtu for a 750 MW pulverized coal boiler installation at Western Farmers Electric Cooperative, Hugo Station located in Oklahoma. The project proposes to burn a subbituminous coal and utilize a wet FGD for SO2 control. The next most stringent SO2 emissions limit that has been proposed is 0.065 lb/MBtu for a 750 MW pulverized coal boiler installation at LS Power Development, Elk Run Energy Station located in Iowa. The project proposes to burn a subbituminous coal and utilize a semi-dry FGD for SO2 control. The proposed SO2 emissions limit has a tiered emissions limit approach. The first tier is an emissions limit of 0.065 lb/MBtu when the inlet SO2 emissions rate is equal to or below 1.0 lb/MBtu SO2. The second tier is an emissions limit of 0.09 lb/MBtu when the inlet SO2 emissions rate is greater than 1.0 lb/MBtu SO2. Both the proposed Tier 1 and Tier 2 are based on 30 day averages. The next most stringent SO2 emissions limit that has been permitted is at 0.09 lb/MBtu for four projects. The following are the four projects: a 200 MW pulverized coal boiler installation at the Newmont Mining 102607-145491 3-16 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.0 Coal Fired Boiler SO2 BACT Analysis Corporation, TS Power Plant located in Nevada, with dry FGD as the SO2 control (24 hour averaging for coal with a sulfur content greater than 0.45 percent; however, the SO2 limit is 0.065 when the coal has a sulfur content less than 0.45 percent); a 100 MW pulverized coal boiler installation at Black Hills Corporation, Wygen 3 located in Wyoming, with SDA as the SO2 control (12 month averaging); a 500 MW pulverized coal boiler installation at Wisconsin Public Service, Weston Unit 4 located in Wisconsin, with dry FGD as the SO2 control (12 month averaging); and 3 x 530 MW pulverized coal boiler installation at LS Power Development, White Pine Energy Station located in Nevada, with dry FGD as the SO2 control (24 hour averaging). • Another permitted project that is as stringent as the 0.09 lb/MBtu limit for SO2 control is the Kansas City Power & Light (KCP&L), Iatan Generating Station (Unit 2). Iatan 2 is a 800 MW pulverized coal boiler permitted to burn a subbituminous coal with a wet FGD for SO2 control (30 day averaging). The permit was issued on January 31, 2006; however, a collaboration agreement between KCP&L and Sierra Club revised the permit limits in 2007, and the SO2 limit set netted out of PSD and BACT review. The unit’s on-line commercial date is set for June 1, 2010. • Sunflower’s Holcomb Station draft air permit, which is proposed, determined a BACT limit of 0.095 lb/MBtu as BACT for three 700 MW pulverized coal coal fired units in western Kansas firing PRB coal and utilizing semi-dry FGD technology for SO2 control. Based upon the technologies identified as technically feasible and available in Steps 1 and 2, the following technologies presented in Table 3-4 are ranked in a “TopDown Approach” methodology. The proposed fuel alternatives of the Project and design considerations of the main boiler are the reasons for a wet FGD with a BACT emission limit of 0.06 lb/MBtu or 98 percent SO2 removal (whichever is higher in emissions). While FPL’s Glades Power Park proposed a more stringent emission limit, the decision to do so was apparently based on limited sulfur fuel and driven by Class I visibility concerns rather than a case-by-case BACT determination; and as discussed in Section 3.3, the project has since been cancelled and is not considered further. Wet FGD is the top control as evident in a review of previous determinations and 0.06 lb/MBtu represents the most stringent BACT limit actually permitted for a similar type unit as the Project. 102607-145491 3-17 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.0 Coal Fired Boiler SO2 BACT Analysis Table 3-4 Ranking of SO2 Control Technologies Control Option Control Effectiveness (lb/MBtu) Wet FGD System (Lime or Limestone) 0.06 Notes: 1. No other technologies are ranked, but wet FGD is based upon Step 2. 2. All wet FGD systems are expected to be similar in operating characteristics. 3.4 Step 4--Evaluate Most Effective Controls and Document Results In the following subsections, the technically feasible emissions control alternatives are evaluated with respect to their energy, environmental, and economic impacts on the Project. Although there are several types of SO2 control technologies available, as previously described in Section 3.1, only the wet FGD systems are capable of the SO2 removal efficiencies necessitated by the fuel flexibility requirements of this Project, as described in Section 3.2. All of the described alternate wet FGD technologies will have similar energy, environmental, and economic evaluations. Therefore, the following evaluation is based on a wet FGD. 3.4.1 Energy Evaluation of Alternatives In the wet lime/limestone processes (spray tower), the majority of the energy consumption is attributed to reagent preparation for grinding the limestone and the high pumping power requirements dictated by the high liquid-to-gas (L/G) ratio required for these processes. The high sulfur fuel (Illinois Basin coal) that will be used at this facility requires more limestone grinding and higher L/G, hence a higher auxiliary power usage. The ability to increase the L/G ratio at the expense of higher energy use allows this system the capability of achieving the high emissions removal rates required for this facility. Designing for both PRB and Illinois coal firing will result in some equipment inefficiencies as a result of the larger sized equipment being run when firing PRB. However, there are no significant energy impacts that would preclude the use of a wet FGD, as presented in this evaluation. 3.4.2 Environmental Evaluation of Alternatives When considering any FGD technology, there are potential environmental impacts associated with either direct operation or secondary impacts. While there are no significant environmental impacts that would preclude the use of a wet FGD, several 102607-145491 3-18 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.0 Coal Fired Boiler SO2 BACT Analysis potential environmental impacts are examined below for the wet FGD control technology systems: • Visible Stack Gas Visible Plume--A wet FGD system can result in a visible moisture plume almost year-round. • Water Consumption--All of the wet FGD systems utilize a significant amount of water to facilitate limestone preparation and to reduce the flue gas temperature to saturation, where the scrubbing of SO2 occurs. For comparison purposes, water consumption rates for semi-dry lime FGD systems are approximately 20 to 30 percent less than that required for wet lime/limestone FGD processes. However, from a facility-wide perspective, the use of a wet FGD allows for the recycling of cooling tower blowdown water back to the scrubber module instead of discharging to the river, which is an environmental advantage of a wet FGD for this Project. • Byproduct Disposal--The gypsum waste product from the wet FGD systems is a stable, landfill suitable product. The gypsum is nontoxic and can be used in the production of wallboard. Gypsum has been previously safely stored in landfills as a dry product or by a method called gypsum stacking, where the product is pumped to a disposal area. With gypsum stacking, the excess free water is allowed to settle and is collected for return to the process. The common drawback to the FGD processes evaluated thus far is the large disposal site requirement for byproduct disposal. For the wet lime and limestone FGD systems, fly ash is collected before the FGD system, allowing for the potential sale of fly ash. This presents a potential for less landfilling than the circulating lime processes, which would have the ash and byproduct as an inseparable mixture. The large available land area at the facility site will allow for the safe storage of the material in an onsite landfill. 3.4.3 Economic Evaluation of Alternatives Wet FGD systems represent the top control alternative for the reduction of SO2 emissions from the Project. There are no significant economic impacts that would preclude the use of a wet FGD, as presented in this analysis. Since wet FGD represents the only viable SO2 control technology option and represents the top control alternative, a comparative economic analysis is not warranted or required by the BACT review process. 102607-145491 3-19 Interstate Power and Light Sutherland Unit 4 Air Permit Application 3.5 3.0 Coal Fired Boiler SO2 BACT Analysis Step 5--Select SO2 BACT IPL has determined that a wet limestone FGD represents BACT for the Project’s main boiler as the most appropriate SO2 control technology for the facility. As stated in Subsection 3.1.2, the wet FGD processes for a SCPC boiler are characterized by high efficiency (> 98 percent) and high reagent utilization (95 to 97 percent) when starting with a high sulfur fuel. The removal efficiency is reduced as the fuel sulfur content decreases; this is the case for low sulfur western and PRB coals. The absolute emissions level becomes a limiting factor due to a reduction in the chemical driving forces of the reactions that are occurring. As a result, for installations that burn a range of fuels, there is a bottom emissions limit that the original equipment manufacturer (OEM) vendors will guarantee, with the reduced removal efficiency as a secondary criteria. For this Project, it is expected that the reduced efficiency would be between 95 to 98 percent, based on the inlet sulfur content of the proposed fuels. Based on the “top-down” approach, completion of the BACT analysis in Steps 1 through 5, and the entire range of fuels proposed for the Project, IPL proposes a wet FGD for the Project with a BACT emission limit of 0.06 lb/MBtu (based on a 30 day rolling average) or 98 percent SO2 removal, whichever occurs first, with a 0.08 lb/MBtu (based on a 30 day rolling average) upper limit. Table 3-5 summarizes the Project’s SO2 BACT determination for the main boiler. Table 3-5 Main Boiler SO2 BACT Determination Control Technology Emission Limit (lb/MBtu) Wet FGD System 0.06 lb/MBtu(1) or 98 percent removal (whichever occurs first) with 0.08 lb/MBtu(1) upper limit. (1) Based on a 30 day rolling average. IPL’s proposed SO2 BACT limits are based on engineering evaluation and a review of various OEM’s technical literature. There was no literature found or engineering calculations performed that would indicate that co-firing with a biomass blend of 5 percent would change the proposed BACT emissions limit. 102607-145491 3-20 Interstate Power and Light Sutherland Unit 4 Air Permit Application 4.0 4.0 Coal Fired Boiler NOx BACT Analysis Coal Fired Boiler NOx BACT Analysis This section presents the top-down, five-step BACT process used to evaluate and determine the Project’s NOx emissions limit for the main boiler. As this analysis will demonstrate, the proposed NOx BACT limit for the Project’s main boiler is an emissions limit of 0.05 lb/MBtu on a 30 day average basis. 4.1 Step 1--Identify All Control Technologies The first step in a top-down analysis, according to the EPA’s October 1990, Draft New Source Review Workshop Manual, is to identify all available control options. Available control options are those air pollution control technologies or techniques with a practical potential for application to the emission unit and the NOx emissions limit that is being evaluated. NOx is defined as the combination of nitrogen oxide (NO) and nitrogen dioxide (NO2). Typically, the NOx that is formed in coal fired plants consists of 90 to 95 percent NO, with the balance occurring as NO2. NOx in the flue gas is a result of oxidizing either nitrogen in the combustion air (thermal NOx) or nitrogen in the fuel (fuel NOx). Generally, when burning coal, less than 25 percent of the NOx produced is thermal NOx, and the balance is fuel NOx. NOx production occurs predominantly within the flame zone, where localized high temperatures sustain the NOx-forming reactions. NOx controls may be divided into two categories: combustion related NOx formation control and post-combustion emission reduction. Combustion related NOx formation control processes reduce the quantity of NOx formed in the combustion process. A post-combustion technology reduces the NOx emissions in the flue gas stream after the NOx has been formed in the combustion process. Both of these methods may be used independently or in combination to achieve the degree of NOx emissions reduction required. Combustion control methodologies seek to suppress NOx formation during the combustion process. Unfortunately, low NOx emissions are often counterproductive to combustion efficiency. Typically, combustion control methods include low NOx burners (LNB), overfire air (OFA), gas reburn, and advanced gas reburn (AGR). While none of these combustion control methods alone can achieve the NOx BACT emission levels currently being permitted for new coal fired units, they are considered standard equipment and form the baseline in new boiler design emissions estimates. Therefore, LNB/OFA is not only cost-effective, but is also considered the basis of the NOx baseline emissions for the Project in this BACT analysis. 102607-145491 4-1 Interstate Power and Light Sutherland Unit 4 Air Permit Application 4.0 Coal Fired Boiler NOx BACT Analysis Post-combustion controls are flue gas treatments that reduce NOx after its formation. The post-combustion alternatives include Selective Noncatalytic Reduction (SNCR) and SCR. All post-combustion control technologies rely on the injection of a nitrogen compound into the flue gas to react with (and remove) NOx. For this BACT analysis, aqueous ammonia is the reagent utilized with the SCR systems. 4.1.1 Selective Catalytic Reduction System In an SCR system, ammonia is injected into the flue gas stream just upstream of a catalytic reactor. The ammonia molecules in the presence of the catalyst dissociate a significant portion of the NOx into nitrogen and water. The aqueous ammonia is received and stored as a liquid. The ammonia is vaporized and subsequently injected into the flue gas by compressed air or steam as a carrier. Injection of the ammonia must occur at temperatures above 600° F to avoid chemical reactions that are significant and operationally harmful. Catalyst and other considerations limit the maximum SCR system operating temperature to 840° F. Therefore, the system is typically located between the economizer outlet and the air heater inlet. The SCR catalyst is housed in a reactor vessel, which is separate from the boiler. The conventional SCR catalysts are either homogeneous ceramic or metal substrate coated. The catalyst composition is vanadium-based, with titanium included to disperse the vanadium catalyst and tungsten added to minimize adverse SO2 and SO3 oxidation reactions. An economizer bypass may be required to maintain the reactor temperature during low load operation. This will reduce boiler efficiency at lower loads. A number of alkali metals and trace elements (especially arsenic) poison the catalyst, significantly affecting reactivity and life. Other elements such as sodium, potassium, and zinc can also poison the catalyst by neutralizing the active catalyst sites. Poisoning of the catalyst does not occur instantaneously, but is a continual steady process that occurs over the life of the catalyst. As the catalyst becomes deactivated, ammonia slip emissions increase, approaching design values. As a result, catalyst in a SCR system is consumable, requiring periodic replacement at a frequency dependent on the level of catalyst poisoning. However, effective catalyst management plans can be implemented that significantly reduce catalyst replacement requirements. There are two SCR system configurations that can be considered for application on pulverized coal boilers: high dust and tail end. A high dust application locates the SCR system before the particulate collection equipment, typically between the economizer outlet and the air heater inlet. A tail end application locates the catalyst downstream of the particulate and FGD control equipment. 102607-145491 4-2 Interstate Power and Light Sutherland Unit 4 Air Permit Application 4.0 Coal Fired Boiler NOx BACT Analysis The high dust application requires the SCR system to be located between the economizer outlet and the air heater inlet in order to achieve the required optimum SCR operating temperature of approximately 600° to 700° F. This system is subject to high levels of trace elements and other flue gas constituents that poison the catalyst, as previously noted. The tail end application of SCR would locate the catalyst downstream of the particulate control and FGD equipment. Less catalyst volume is needed for the tail end application, since the majority of the particulate and SO2 (including the trace elements that poison the catalyst) have been removed. However, a major disadvantage of this alternative is a requirement for a gas-to-gas reheater and supplemental fuel firing to achieve sufficient flue gas operating temperatures downstream of the FGD operating at approximately 125° F. The required gas-to-gas reheater and supplemental firing necessary to raise the flue gas to the sufficient operating temperature is costly. The higher front end capital costs and annual operating cost for the tail end systems present higher overall costs compared to the high dust SCR option with no established emissions control efficiency advantage. Therefore, this analysis will only consider the use of a high dust SCR system. 4.1.2 Selective Noncatalytic Reduction System Selective noncatalytic NOx reduction systems rely on the appropriate reagent injection temperature and good reagent/gas mixing rather than a catalyst to achieve NOx reductions. SNCR systems can use either ammonia (Thermal DeNOx) or urea (NOxOUT) as reagents. The optimum temperature range for the injection of ammonia or urea is 1,550° to 1,900° F. The NOx reduction efficiency of the SNCR system decreases rapidly at temperatures outside this range. Injection of reagent below this temperature window results in excessive ammonia slip emissions. Injection of reagent above this temperature window results in increased NOx emissions. A pulverized coal boiler operates at temperatures of between 2,500° and 3,000° F. Therefore, the optimum temperature window in a pulverized coal boiler occurs somewhere in the backpass of the boiler. To further complicate matters, this temperature location will change as a function of unit load. In addition, residence times in this temperature range are very limited, further detracting from optimum SNCR performance. Finally, there is no provision for feedforward control of reagent injection, relying only on feedback control. This results in overinjection of reagent and high ammonia slip emissions. SNCR systems are less efficient NOx reduction systems than SCR systems. In general, SNCR systems on large pulverized coal fired boilers will only be capable of up to 25 percent NOx reduction while maintaining an acceptable ammonia slip. This low 102607-145491 4-3 Interstate Power and Light Sutherland Unit 4 Air Permit Application 4.0 Coal Fired Boiler NOx BACT Analysis NOx emission reduction and the lack of any operational advantage over a standard SCR system for a new plant installation prevents this technology from being considered further in this BACT analysis. 4.2 Step 2--Eliminate Technically Infeasible 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. From a review of the aforementioned post-combustion NOx control technologies, it can be concluded that each are technically feasible as control technology alternatives for the Project’s main boiler. However, since SNCR cannot meet the currentday BACT emissions limit on its own, the SNCR will not be considered further. As such, only the SCR system will be considered further in the BACT analysis. It should be noted that the basis for NOx BACT assumes inclusion of LNB and OFA as a fundamental component of the boiler design. Table 4-1 summarizes the evaluation of the technically feasible NOx options. Table 4-1 Summary of Step 2--Eliminate Technically Infeasible Options Technically Feasible (Yes/No) Technology Alternative Available Applicable SCR SNCR Yes Yes Yes Yes – However, SNCR has limited NOx removal and will not be considered further. 4.3 Step 3--Rank Remaining Control Technologies by Effectiveness A search of the information contained in the USEPA BACT/LAER Clearinghouse and other sources specified in Section 2.1 was conducted to determine the top level of NOx control for pulverized coal boilers. A search was also conducted for recently permitted coal fired facilities whose BACT determinations have not yet been included in 102607-145491 4-4 Interstate Power and Light Sutherland Unit 4 Air Permit Application 4.0 Coal Fired Boiler NOx BACT Analysis the current BACT/LAER Clearinghouse database. The results of this search for all coal fired boilers are listed in Attachment A, Table A-2, of this BACT analysis. Table 4-2 lists the NOx BACT determinations that have the closest attributes when compared to IPL’s SGS Unit 4, which include fuel type, boiler technology, and size of boiler. Table 4-2 NOx Top-Down RBLC Clearinghouse Review Results A review of the NOx BACT determinations in Table 4-2 indicates the following: • The most stringent NOx removal permit proposed for a 2 x 980 MW pulverized coal boiler installation is 0.05 lb/MBtu, based on a 30 day rolling average at the FPL Glades Power Park located in Florida. The Glades Power Park proposed site is located approximately 100 miles from the Everglades National Park (Class I area). The close proximity of the Class I area and compliance with the stringent criteria were major factors in FPL proposing the NOx emissions limit. Note, the PSD Air Permit Application was submitted on December 19, 2006, and the Air Permit Application remains “incomplete” (SFWMD WRAC Meeting on May 30, 2007, in Clewiston, Florida). LNB and SCR are documented as the control technology. 102607-145491 4-5 Interstate Power and Light Sutherland Unit 4 Air Permit Application 4.0 Coal Fired Boiler NOx BACT Analysis • The next most stringent NOx removal permit proposed for a 750 MW pulverized coal boiler installation is 0.05 lb/MBtu, based on a 12 month rolling average at the LS Power Development, Elk Run Energy Station located in Iowa. The second part to the NOx emissions limit for Elk Run is to meet a 0.07 lb/MBtu limit, based on a 30 day rolling average. • The most stringent NOx emissions limit in place for a pulverized coal boiler firing PRB fuel is 0.05 lb/MBtu utilizing LNB and SCR. This emissions limit has been permitted on 750 and 800 MW units in Texas at the CPS of San Antonio J.K. Spruce and LS Power Sandy Creek Energy Stations, respectively. Ozone nonattainment concerns in San Antonio were the drivers for the low emissions limit in this case, not BACT. • There are three other permits that have been permitted with a NOx removal limit of 0.05 lb/MBtu. All three projects are for pulverized coal boiler installations that burn a subbituminous coal and have LNB and SCR as the documented NOx control technology. The following are the three projects: a 750 MW pulverized coal boiler installation at Western Farmers Electric Cooperative, Hugo Station located in Oklahoma; a 100 MW pulverized coal boiler installation at Black Hills Corporation, Wygen 3 located in Wyoming; and a 750 MW pulverized coal boiler installation at Louisville Gas and Electric Company, Trimble County Generating Station located in Kentucky. These three projects are very similar to SGS Unit 4. • There are four projects with proposed NOx removal limits of 0.06 lb/MBtu (based on a 24 hour rolling average). All four projects are for pulverized coal boiler installations that burn a subbituminous coal and have LNB and SCR as the documented NOx control technology. The following are the four projects: 2 x 750 MW pulverized coal boiler installation at Sithe Global Desert Rock Power Plant located in New Mexico; 500 MW pulverized coal boiler installation at BHP Billiton, Cottonwood Energy Center located in New Mexico; 750 MW pulverized coal boiler installation at Touquop Energy Project located in Nevada; and 2 x 750 MW pulverized coal boiler installation at Sierra Pacific and Nevada Power, Ely Energy Center located in Nevada. • The next most stringent NOx emissions limit in place for a permitted pulverized coal boiler firing PRB fuel is 0.067 lb/MBtu (with a 24 hour rolling average) for TS Power Plant, Newmont Nevada Energy Investment (200 MW) located in Nevada. It utilizes LNB and SCR as the documented NOx control technology. 102607-145491 4-6 Interstate Power and Light Sutherland Unit 4 Air Permit Application 4.0 Coal Fired Boiler NOx BACT Analysis • The next most stringent NOx emissions limit in place for permitted pulverized coal boilers is 0.07 lb/MBtu. Table A-2 includes no fewer than 10 pulverized coal boiler units permitted or proposed at this level. • Sunflower’s Holcomb Station Draft air permit, which is proposed, determined a BACT limit of 0.07 lb/MBtu, on a 30 day rolling average, as BACT for three 700 MW pulverized coal coal fired units in western Kansas firing PRB coal and utilizing LNB/OFA and SCR technology. • The next most stringent NOx emissions limit in place for a permitted pulverized coal boiler is 0.08 lb/MBtu for KCP&L’s Hawthorne Power Station (570 MW). Of the units listed here, based on a review of available records, the Hawthorne unit is the only one operating and actually demonstrating compliance with the stated emissions level. It is important to note that of the NOx emissions limits summarized above (with the exception of one), none are in actual operation at this time and demonstrating the stated NOx emissions limits. Based upon the technologies identified as technically feasible and available in Steps 1 and 2, the following technologies presented in Table 4-3 are ranked in a “TopDown Approach” methodology. Table 4-3 Ranking of NOx Control Technologies Control Option Control Effectiveness (lb/MBtu) SCR 0.05 (30 day rolling average) No other technologies ranked; SCR based upon Steps 1 and 2. 4.4 Step 4--Evaluate Most Effective Controls and Document Results In the following subsections, the technically feasible control alternatives are evaluated in a comparative approach with respect to their energy, environmental, and economic impacts on IPL SGS Unit 4. The following evaluation is based on an SCR system. 102607-145491 4-7 Interstate Power and Light Sutherland Unit 4 Air Permit Application 4.0 Coal Fired Boiler NOx BACT Analysis 4.4.1 Energy Evaluation of Alternatives The SCR system consumes electrical energy for SCR aqueous ammonia transport and vaporization, as well as for an incremental ID fan demand to overcome the SCR draft losses due to pressure drop across the catalyst. While the energy costs of postcombustion NOx control are real and quantifiable, they do not in and of themselves eliminate the control technology from further consideration. 4.4.2 Environmental Evaluation of Alternatives When considering post-combustion NOx control technologies, there are potential environmental impacts associated with their direct operation or secondary effects. Several potential environmental impacts are examined below for post-combustion NOx control technology systems: • Hazardous Waste--The vanadium content of the SCR catalyst may contribute to its classification as a hazardous waste. Therefore, spent catalyst may need to be handled and disposed of using appropriate hazardous waste procedures. As such, recycling of SCR catalysts for vanadium has become common. • Aqueous Ammonia Storage and Ammonia Slip--The use of ammonia in post-combustion NOx control systems introduces an element of environmental risk. Additionally, ammonia that is not consumed in the chemical reaction NOx control process is eventually released from the stack in a process known as ammonia slip. When catalyst surfaces are relatively new, ammonia slip will be very low. However, as the catalyst ages and becomes either deactivated or poisoned, ammonia slip emissions will gradually increase. H2SO4--The SCR catalyst oxidizes approximately 2 to 3 percent of the SO2 in the flue gas to SO3. Once the flue gas cools below 600° F, the ammonia present in the flue gas may react with SO3 to form ammonium sulfate and bisulfate salts, thus reducing the H2SO4 to some degree. This formation may be dependent on the unit’s operating conditions and 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 ammonium sulfate compounds are not formed, the SO3 will react with the moisture in the flue gas to form H2SO4 in the atmosphere. • 102607-145491 4-8 Interstate Power and Light Sutherland Unit 4 Air Permit Application • 4.0 Coal Fired Boiler NOx BACT Analysis As previously noted in Subsection 4.1.1, the performance and effectiveness of SCR systems are directly dependent on the temperature of the flue gas when it passes through the catalyst. Vanadium/titanium catalysts have been used on the majority of SCR system installations. The flue gas temperature range for optimum SCR operation using a conventional vanadium/titanium catalyst is approximately 600 to 750° F. At temperatures above 800° F, permanent damage to the vanadium/titanium catalyst can occur. Thus, the environmental impact of an SCR system that is operating outside of its temperature range is limited or no control of NOx emissions. 4.4.3 Economic Evaluation of Alternatives SCR systems represent the top control alternative for the reduction of NOx emissions from the Project. There are no significant economic impacts that would preclude the use of an SCR system, as presented in this analysis. As SCR represents the only viable NOx control technology option and represents the top control alternative, a comparative economic analysis is not warranted or required by the BACT review process. 4.5 Step 5--Select NOx BACT IPL has determined that the top NOx control alternative, LNB/OFA combined with an SCR system, represents NOx BACT for the Project’s main boiler, corresponding to an emissions limit of 0.05 lb/MBtu on a 30 day average basis. Table 4-4 summarizes the Project’s NOx BACT determination for the main boiler. IPL’s proposed NOx BACT limit is based on engineering evaluation and a review of various OEM’s technical literature. No literature was found nor engineering calculations performed that would indicate that co-firing with a biomass blend of 5 percent would change the proposed BACT emissions limit. Table 4-4 Main Boiler NOx BACT Determination Control Technology Emission Limit (lb/MBtu) SCR 0.05 (30 day rolling average) 102607-145491 4-9 Interstate Power and Light Sutherland Unit 4 Air Permit Application 5.0 5.0 Coal Fired Boiler PM/PM10 BACT Analysis Coal Fired Boiler PM/PM10 BACT Analysis This section presents the top-down, five-step BACT process used to evaluate and determine the Project’s PM/PM10 emissions limit for the main boiler. As this analysis will demonstrate, the proposed PM/PM10 particulate emissions (filterable) limit of 0.012 lb/MBtu (based on USEPA Test Method 5B) and total (filterable + condensable) PM/PM10 emissions limit of 0.018 lb/MBtu (based on USEPA Test Method 5B and 202, with artifact modification including SO3 and VOC) will represent PM/PM10 BACT. 5.1 Step 1--Identify All 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 PM/PM10 emissions limit that is being evaluated. There are several pre-combustion and post-combustion particulate removal systems which have demonstrated performance that is adequate to reliably achieve BACT-level particulate emissions limits on pulverized coal fired boilers. These control technologies include the following: • Coal washing. • DESP. • Fabric filter. • WESP. The following subsections describe and evaluate these technologies. 5.1.1 Coal Washing Pre-combustion control technology such as coal washing can be considered as a method for reducing particulate emissions. Coal washing utilizes various techniques such as high speed coal washes or agitating liquids to produce a separation of impurities from coal. However, coal washing is not considered a primary control technology for particulate as the majority of the particulate is inherent in the coal. A complete discussion of coal washing is included in Subsection 3.1.1. 5.1.2 Dry Electrostatic Precipitator Systems Initially, DESPs were installed in power plants in the 1950s and 1960s, when 30 to 40 percent plume opacity was considered acceptable. However, these DESPs were inadequate when later regulations forced some utilities to move to lower sulfur coals with 102607-145491 5-1 Interstate Power and Light Sutherland Unit 4 Air Permit Application 5.0 Coal Fired Boiler PM/PM10 BACT Analysis high resistivity ash. The existing DESPs, designed for other conditions, were unable to meet the higher removal efficiencies required. As a result, it was not unusual for coal fired power plants to suffer reductions in capacity due to excessive particulate emissions or stack opacity. This lack of performance was not due to the inability of the DESP technology to meet the high emission control levels required, but was more an issue of the operating conditions and requirements moving outside of the original design condition envelope. Through improvements in the technology and increased sizing, DESPs have demonstrated increased performance to meet newer regulations. DESPs of the necessary size and efficiency are available to control emissions from this size of unit. This increase in performance has allowed DESPs to remain the most widely used particulate removal technology for large coal fired installations. DESPs remove particulate by first charging fly ash particles. A utility DESP is essentially a large enclosure placed in the ductwork between the air heater and the ID fans. A series of parallel steel plates spaced approximately 12 to 16 inches apart is located within the DESP. Discharge electrodes made of rigid steel pipe-like shapes or stretched wires are located between and parallel to the plates. Transformer rectifier (TR) sets negatively charge the discharge electrodes and positively charge the plates to create a voltage differential. As the particulate-laden flue gas passes between the plates and the wires, the ash particles become negatively charged. The particles then migrate to the positively charged plate, where the ash accumulates. At various frequencies of time, rapping of the plates removes the accumulated ash from the plates. The impact of the rapping shears the ash particles from the plate, causing the accumulated ash to fall into the hopper for collection. The ash handling system can then remove the ash for disposal or beneficial reuse. However, some of the dust is re-entrained and carried to the next DESP collection field downstream of the DESP. DESP collection efficiency and cost are dependent on the DESP size and characteristics of the fly ash. The ease with which an DESP can collect fly ash is a function of the particulate and flue gas properties, such as particle size, resistivity, flue gas temperature, and flue gas composition. Factors such as these, along with flue gas flow rates and particulate emissions rates, determine the specific collection area or physical size of an DESP. The definition of specific collection area is the square feet of collection area per thousand acfm of flue gas treated. Operation also depends on the accuracy of electrode and plate alignment, uniformity and smoothness of gas flow through the DESP, rapping of the plates, and the size and electrical stability of the TR sets. 102607-145491 5-2 Interstate Power and Light Sutherland Unit 4 Air Permit Application 5.0 Coal Fired Boiler PM/PM10 BACT Analysis A fly ash property that significantly affects the sizing of precipitators is ash resistivity. When firing subbituminous coals, the resulting fly ash resistivity is high. The high resistivity significantly deteriorates the DESP efficiency unless properly conditioned with a flue gas conditioning system or a much larger DESP is sized to control PM/PM10. When firing bituminous coals, the resulting fly ash resistivity is low which does not require a flue gas conditioning system or a larger DESP. Resistivity is a measure of how easily the particulate acquires an electric charge. Fly ash resistivity varies with the moisture content, chemical composition, and temperature of the ash in the flue gas. The higher the ash resistivity, the more difficult it is to remove ash from the flue gas with an DESP. The major coal property affecting the fly ash resistivity for DESPs is the coal sulfur content. SO3 formed during combustion of the coal coats the fly ash particles and lowers surface resistivity. For the IPL SGS Unit 4 (which will fire the Project’s coal alternatives), the design of the DESP will be severely challenged because of the changes in fly ash characteristics. While technically feasible, it would be the least desirable technology to be operated on a coal fired power plant. 5.1.3 Fabric Filter Systems Fabric filter is a technology design that can meet particulate emissions limits on many coal fired boilers. Fabric filters use fabric bags as filters to collect particulate. The particulate-laden flue gas enters a fabric filter compartment and passes through a layer of particulate and filter bags. The collected particulate forms a cake on the bag, which can enhance the bag’s filtering efficiency. The pressure drop across the bags increases as the thickness of the dust cake increases. At a predetermined set point, the filtering bags are cleaned, dislodging a large portion of the dust cake. These bag cleaning cycles can vary from every 30 minutes to as long as 6 to 8 hours, depending on ash loading, flue gas flow rate, filter cake properties, and other operational parameters. Fabric selection is a very important feature of fabric filter operation. There are many fibers that can be used effectively as filters, with different properties that determine their appropriate applications. Several different finishes and textures have been developed for bag materials in order to increase their use and efficiency in filtration. In general, fibers can be made into woven or felted fabrics. In utility coal fired fabric filter applications, PPS felted bags have been used. There are also many coatings and chemical treatments available to provide lubrication and other properties to fibers to improve their performance. 102607-145491 5-3 Interstate Power and Light Sutherland Unit 4 Air Permit Application 5.0 Coal Fired Boiler PM/PM10 BACT Analysis With proper management of the bag life, the fabric filter offers an advantage over DESP applications. The advantage relates to the characteristics of the fabric filter that allow low emissions rates to be maintained independent of the wide range of ash characteristics and the fabric filter characteristics that allow the collected material on the bags to be contacted with the flue gas more thoroughly and over a longer period of time as compared to an DESP. This operational advantage is significant when considering the control of Hg and SO3 emissions when firing two distinctly different coals. Control of both of these pollutants is shown to be increased in a fabric filter as compared to an DESP. While just the ash retained on the bags can assist in controlling these pollutants, the advantage is particularly evident when adsorbents, such as activated carbon, hydrated lime, or trona, are injected upstream of the fabric filter to aid in the control of these pollutants. The additional contact time that the fabric filter provides directly relates to higher control efficiencies at lower adsorbent injection rates. 5.1.4 Wet Electrostatic Precipitator A WESP collects particles based on the same principle as a DESP; negatively charged particles are collected on positively charged surfaces. However, a WESP operates quite differently from a DESP. The collecting surfaces are wet instead of dry and are flushed with water rather than being rapped to remove the particulate. Typically, a WESP is installed downstream of an existing wet FGD system where the flue gas is already saturated, so the amount of added water is minimized. The particulate collection efficiency is enhanced by a lack of re-entrainment after contact with the wet walls (as contrasted with re-entrainment during rapping on a DESP). Therefore, the WESP is well suited for fine particulate or acid mist applications by reducing opacity, sulfuric acid mist, and other aerosols. It is not well suited for handling uncontrolled particulate emissions levels from a boiler. The amount of sludge wastewater produced for storage in that form would not be technically feasible. The WESP collecting fields impart a negative charge to the particles and collect them on positively charged collecting electrodes. Each collection field is equipped with independent electrical bus sections, each having a dedicated high voltage TR and controller. The controllers for each TR are located in an environmentally controlled enclosure. Each electrical field has a separate discharge electrode support frame suspended by alumina insulators. A heater-blower system dedicated to each module supplies warm purge air for each of the insulator compartments. The discharge electrode support frames are constructed from stainless steel, and discharge electrodes are suspended from the upper guide frame and held in the tube center line. The discharge electrode is a rigid electrode that is constructed from stainless steel and contains split corona generating elements that are welded to the electrode in an opposed orientation. 102607-145491 5-4 Interstate Power and Light Sutherland Unit 4 Air Permit Application 5.0 Coal Fired Boiler PM/PM10 BACT Analysis A WESP can be installed in either horizontal or vertical gas flow orientation. In a horizontal gas flow orientation, the WESP is very similar to a common DESP. The collection plates are arranged in parallel horizontal paths with discharge electrodes hanging between them. Vertical gas flow WESPs are usually of the tubular collection plate type. The collection plates are arranged in an array of vertical pipes or channels, with a discharge electrode hanging down the center of the pipe or channel. Channel shapes, such as squares or hexagons, have more efficient packing densities than circular pipes (with a small loss in the maximum voltage that can be applied before sparking) and are more common. When multiple electrical stages are used (analogous to the electrical fields in a horizontal gas flow DESP), the stages are stacked one above the other. Two to three fields are common. Several major hurdles exist with the use of a WESP as a primary filter collection device. First, the flue gas must be saturated with moisture prior to entering the ESP to allow the WESP to work correctly. This requires that a quenching system be installed to add water to the flue gas to reduce the flue gas temperature to the saturation point, or the WESP needs to be installed downstream of an existing wet FGD system. Secondly, the WESP adds additional cost, increases water demand on the plant, and generates a visible moisture plume at the stack outlet. In addition to these issues, the capital cost of a WESP is very high compared to other technologies due to the higher cost of the alloy materials required for the WESP. A higher grade of material is required to withstand the highly corrosive conditions presented by the wet and acidic flue gas stream. For these reasons, applications rarely find it economically feasible or beneficial to install a WESP for primary particulate control. 5.2 Step 2--Eliminate Technically Infeasible 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. Coal washing is a process that aids in the removal of mineral ash matter. Since IPL is proposing to utilize various types of coals, the effectiveness of coal washing will differ greatly. IPL is not aware of large-scale facilities that perform coal washing on western subbituminous coal, such as PRB, which is considered one of the design coals for the main boiler. Therefore, the supply of PRB coal that has been washed cannot be 102607-145491 5-5 Interstate Power and Light Sutherland Unit 4 Air Permit Application 5.0 Coal Fired Boiler PM/PM10 BACT Analysis considered a reliable source for this Project. Coal washing is determined to be technically infeasible because PRB coal that has been washed may not be available. Based on a review of the aforementioned PM/PM10 control technologies, it can be concluded that both a DESP and fabric filters are technically feasible as control technology alternatives for the Project’s main boiler. These two technologies will be considered further in the BACT analysis for primary particulate control. A WESP is considered technically feasible and available for primary particulate control; however, WESPs cannot meet the expected BACT performance criteria. As such, the WESP will not be considered further due to limited particulate control. Table 5-1 summarizes the evaluation of the technically feasible PM/PM10 options. Table 5-1 Summary of Step 2--Eliminate Technically Infeasible Options Technically Feasible (Yes/No) Technology Alternative Available Applicable Coal Washing Yes DESP Fabric Filter WESP Yes Yes Yes No – PRB coal that has been washed may not be available. Coal washing is not technically feasible. Yes Yes Yes – However, WESP has limited particular removal and will not be considered further. 5.3 Step 3--Rank Remaining Control Technologies by Effectiveness A search of the information contained in the USEPA BACT/LAER Clearinghouse and other sources specified in Section 2.1 was conducted to determine the top level of PM/PM10 control for pulverized coal boilers. A search was also conducted for recently permitted coal fired facilities whose BACT determinations have not yet been included in the current BACT/LAER Clearinghouse database. The results of this search for all coal fired boilers are listed in Attachment A, Table A-3, of this BACT analysis. As is the current trend in particulate BACT emissions limits, the review is limited to those sources that were permitted with both front-half and back-half emissions limits. Table 5-2 lists the PM/PM10 BACT determinations that have the closest attributes when compared to IPL’s SGS Unit 4, which include fuel type, boiler technology, and size of boiler. 102607-145491 5-6 Interstate Power and Light Sutherland Unit 4 Air Permit Application 5.0 Coal Fired Boiler PM/PM10 BACT Analysis A review of the PM/PM10 BACT determinations in Table 5-2 indicates the following: • PM/PM10 (filterable)--The lowest PM/PM10 (filterable) emissions limit permitted for a pulverized coal boiler unit is 0.012 lb/MBtu. There are eight projects that have established 0.012 lb/MBtu as BACT for PM/PM10. All of the pulverized coal boiler units in the eight projects burn a subbituminous coal and have a fabric filter as the documented PM/PM10 control technology. The following are the eight projects: a 100 MW pulverized coal boiler installation at Black Hills Corporation, Wygen 3 located in Wyoming; a 200 MW pulverized coal boiler installation at Newmont Mining Corporation, TS Power Plant located in Nevada; 3 x 700 MW pulverized coal boilers at Sunflower Electric Power, Holcomb Power Station located in western Kansas; a 900 MW pulverized coal boiler installation at Intermountain Service Corporation, Unit 3 located in Utah; a 500 MW pulverized coal boiler installation at Black Hills Corporation, Wygen 3 located in Wyoming; a 750 MW pulverized coal boiler at Xcel Energy, Comanche Station (Unit 3) located in Colorado; a 116 MW pulverized coal boiler at Rocky Mountain Power, Inc., Hardin Generator Project located in Montana; and a 600 MW pulverized coal boiler at Otter Tail Power Company located in South Dakota. • PM10 (filterable)--The next lowest PM10 (filterable) emissions limit proposed for a pulverized coal unit firing a PRB coal is 0.012 lb/MBtu at LS Power Development, Elk Run Energy Station located in Iowa. In addition, Elk Run proposes the following limits for PM/PM10: PM10 (filterable + condensable) is 0.030 lb/MBtu, PM (filterable) is 0.015 lb/MBtu, and PM (filterable + condensable) is 0.033 lb/MBtu. All limits for Elk Run are based on a 3 hour average, and a fabric filter is utilized for PM/PM10 control technology. • PM/PM10 (filterable)--The next lowest PM/PM10 (filterable) emissions limit permitted for pulverized coal boiler units includes several units ranging from 0.013 to 0.015 lb/MBtu. 102607-145491 5-7 Interstate Power and Light Sutherland Unit 4 Air Permit Application 5.0 Coal Fired Boiler PM/PM10 BACT Analysis Table 5-2 PM/PM10 Top-Down RBLC Clearinghouse Review Results 102607-145491 5-8 Interstate Power and Light Sutherland Unit 4 Air Permit Application • 5.0 Coal Fired Boiler PM/PM10 BACT Analysis PM/PM10 (filterable + condensable)--The lowest PM/PM10 (filterable + condensable) emissions limit permitted for a pulverized coal unit firing a PRB coal is 0.018 lb/MBtu, which utilizes a fabric filter for PM/PM10 control technology. This limit was established for at least three projects including: a 220 MW pulverized coal boiler at Municipal Energy Agency of Nebraska, Whelan Energy Center located in Nebraska; a 660 MW pulverized coal boiler at Omaha Public Power District, Nebraska City Unit 2 located in Nebraska (under construction); and 3 x 700 MW pulverized coal boilers at Sunflower Electric Power, Holcomb Power Plant located in Kansas. Sunflower’s Holcomb Station draft air permit determinations of BACT for PM/PM10 are 0.012 and 0.018 lb/MBtu for filterable and total (filterable and condensable), respectively, with a fallback limit of 0.035 lb/MBtu (filterable and condensable based on stack testing). • PM/PM10 (filterable + condensable)--The lowest PM/PM10 (filterable + condensable) emissions limit permitted for a pulverized coal unit firing a bituminous coal is 0.018 lb/MBtu. This limit was established for the Santee Cooper, Santee Cooper Cross Generating Station, which has 2 x 660 MW pulverized coal boilers (DESP for control) and Santee Cooper, Pee Dee Generating Station, which also has 2 x 660 MW pulverized coal boilers (DESP and fabric filter for control). The two projects listed above are located in South Carolina. The Santee Cooper Cross Generating Station has one unit operating (commercial operation in January 2007), and one unit still under construction. Based on the technologies identified as technically feasible and available in Steps 1 and 2, the following technologies presented in Table 5-3 are ranked in a “TopDown Approach” methodology. 5.4 Step 4--Evaluate Most Effective Controls and Document Results In the following subsections, the technically feasible control alternatives are evaluated in a comparative approach with respect to their energy, environmental, and economic impacts on the Project. 102607-145491 5-9 Interstate Power and Light Sutherland Unit 4 Air Permit Application 5.0 Coal Fired Boiler PM/PM10 BACT Analysis Table 5-3 Ranking of PM/PM10 Control Technologies Control Option Control Effectiveness (lb/MBtu) DESP PM/PM10 (filterable) limit of 0.012 lb/MBtu(1); PM/PM10 (filterable + condensable) limit of 0.018 lb/MBtu(2) Fabric Filter PM/PM10 (filterable) limit of 0.012 lb/MBtu(1); PM/PM10 (filterable + condensable) limit of 0.018 lb/MBtu(2) (1) The test method for the associated limit is based on USEPA Test Method 5B. The test method for the associated limit is based on USEPA Test Method 5B and 202, with artifact modification including SO3 and VOC. (2) 5.4.1 Energy Evaluation of Alternatives A disadvantage of a fabric filter is the higher pressure drop through the filter, resulting in increased fan power and energy requirements. However, this additional energy requirement of the fabric filter is generally offset by, or less than that required by, the TR sets and hopper heaters of an DESP. The fabric filter does provide a small advantage for startup operations in that the DESP cannot control emissions until the flue gas and DESP temperatures are within operating ranges. 5.4.2 Environmental Evaluation of Alternatives There are no environmental impacts that would preclude the use of fabric filters or DESP to control the Project’s emissions of PM/PM10. 5.4.3 Economic Evaluation of Alternatives An economic evaluation and cost comparison of the technically feasible alternative control technologies identified in Section 5.3 (Step 3) are presented below for the following top control options: • DESP. • Fabric filter. The cost estimates are based on budgetary quotes from equipment manufacturers and engineering cost estimates in accordance with the USEPA’s Office of Air Quality Planning and Standards (OAQPS) Control Cost Manual. 102607-145491 5-10 Interstate Power and Light Sutherland Unit 4 Air Permit Application 5.0 Coal Fired Boiler PM/PM10 BACT Analysis Tables 5-4 and 5-5 present the total capital investment for the installation of a fabric filter or DESP on the Project’s main boiler, respectively. As described in the tables, the purchased equipment cost includes the respective particulate control technologies, ash handling systems, ductwork, and fans differential. The direct installation costs, which include balance-of-plant items such as foundations and supports, handling and erection, electrical, piping, insulation, and paint, were calculated as a percentage of the purchased equipment cost and totaled with the purchased equipment cost to estimate the total direct costs of each control alternative. Finally, the total capital investment was calculated as the summation of the total direct costs and total indirect costs (including engineering and owner’s costs) and an allowance for funds used during construction. Tables 5-4 and 5-5 also present the annualized operating costs for the installation of an DESP or fabric filter on the Project’s main boiler. As described in the tables, the operating fixed and variable direct annual costs include operating labor, maintenance labor and materials, bag and cage replacement costs, and auxiliary and ID fan power costs. The indirect annual costs, which include the capital recovery costs, are totaled with the direct annual costs to estimate the total annual costs for the control system. 5.5 Step 5--Select PM/PM10 BACT IPL has determined that the top control of a fabric filter represents PM/PM10 BACT for the Project’s main boiler. Table 5-6 summarizes the top-down evaluation of the PM/PM10 control alternatives, including economic, energy, and environmental considerations, in accordance with the BACT determination methodology previously discussed. Since both the DESP and fabric filter meet the top-ranked control technology emissions limit, the decision to select the fabric filter alternative considers the added potential for additional SO3 and Hg removal, as previously described. In addition, the fabric filter has the lowest annualized cost. The total capital investment to install the DESP and the fabric filter technology on the Project’s main boiler is shown in Tables 5-4 and 5-5, respectively. Therefore, IPL proposes a fabric filter and PM/PM10 particulate emissions (filterable) limit of 0.012 lb/MBtu (based on USEPA Test Method 5B) and total (filterable + condensable) PM/PM10 emissions limit of 0.018 lb/MBtu (based on USEPA Test Method 5B and 202, with artifact modification including SO3 and VOC) as BACT for the Project, which is equivalent to the most stringent level in the RBLC for pulverized coal fired boilers of similar operation and size. 102607-145491 5-11 Interstate Power and Light Sutherland Unit 4 Air Permit Application 5.0 Coal Fired Boiler PM/PM10 BACT Analysis Table 5-4 Fabric Filter Engineering Analysis - Cost Analysis Technology: Date: 6/29/2007 Fabric Filter Cost Item $ CAPITAL COST Direct Costs Purchased equipment costs Fabric Filter System Initial FF bag inventory Ash handling system ID fan upgrades Flue gas ductwork Instrumentation and controls Subtotal capital cost (CC) Taxes Freight Total purchased equipment cost (PEC) $16,280,000 $1,641,000 $1,016,000 $1,964,000 $4,417,000 $323,000 $25,641,000 $1,795,000 $1,282,000 $28,718,000 Direct installation costs Foundation & supports Handling & erection Electrical Piping Insulation Painting Demolition Relocation Total direct installation costs (DIC) Site preparation Total direct costs (DC) = (PEC) + (DIC) Indirect Costs Engineering Owner's cost Construction management Start-up and spare parts Performance test Contingencies Total indirect costs (IC) Allowance for Funds Used During Construction (AFDC) Total Capital Investment (TCI) = (DC) + (IC) ANNUAL COST Direct Annual Costs Fixed annual costs Maintenance labor and materials Total fixed annual costs Variable annual costs Byproduct disposal Bag replacement cost Cage replacement cost ID fan power Auxiliary power Total variable annual costs Total direct annual costs (DAC) Indirect Annual Costs Cost for capital recovery Total indirect annual costs (IDAC) Total Annual Cost (TAC) = (DAC) + (IDAC) 102607-145491 Remarks/Cost Basis (CC) X (CC) X 7.0% 5.0% $4,308,000 $2,872,000 $2,872,000 $718,000 $574,000 $144,000 $0 $3,000 $11,491,000 (PEC) X (PEC) X (PEC) X (PEC) X (PEC) X (PEC) X (PEC) X (PEC) X 15.0% 10.0% 10.0% 2.5% 2.0% 0.5% 0.00% 0.01% $200,000 $40,409,000 Engineering estimate $4,849,000 $1,212,000 $4,041,000 $1,212,000 $81,000 $6,061,000 $17,456,000 (DC) X 12.0% (DC) X 3.0% (DC) X 10.0% (DC) X 3.0% Engineering es 0.2% (DC) X 15.0% $7,117,000 [(DC)+(IC)] X 8.20% 3 years (project time length) $64,982,000 $1,212,000 $1,212,000 (DC) X $2,862,000 $859,000 $179,000 $1,328,000 $551,000 $2,917,000 3.0% 29.7 21,469 21,469 2,384 988 tph and bags and cages and kW and kW and 11 120 50 0.06 0.06 $/ton $/bag $/cage $/kWh $/kWh 3 yr bag replacement rate 6 yr cage replacement rate 6 in. H2O d.p. Engineering estimate $4,129,000 $6,134,000 $6,134,000 (TCI) X 9.44% CRF at 7% interest & 20 year life $10,263,000 5-12 Interstate Power and Light Sutherland Unit 4 Air Permit Application 5.0 Coal Fired Boiler PM/PM10 BACT Analysis Table 5-5 DESP Engineering Analysis - Cost Analysis Technology: Date: Electrostatic Precipitator (ESP) Cost Item $ CAPITAL COST Direct Costs Purchased equipment costs ESP Ash handling system ID fan Flue gas ductwork Subtotal capital cost (CC) Instrumentation and controls Taxes Freight Total purchased equipment cost (PEC) $13,860,000 $1,009,000 $1,228,000 $3,413,000 $19,510,000 $390,000 $1,366,000 $976,000 $22,242,000 Direct installation costs Foundation & supports Handling & erection Electrical Piping Insulation Painting Demolition Relocation Total direct installation costs (DIC) Site preparation Total direct costs (DC) = (PEC) + (DIC) Indirect Costs Engineering Owners Cost Construction and field expenses Contractor fees Start-up Performance test Contingencies Total indirect costs (IC) Allowance for Funds Used During Construction (AFDC) Total Capital Investment (TCI) = (DC) + (IC) ANNUAL COST Direct Annual Costs Fixed annual costs Maintenance labor and materials Total fixed annual costs Variable annual costs Byproduct disposal ID fan power Auxiliary power Total variable annual costs Total direct annual costs (DAC) Indirect Annual Costs Cost for capital recovery Total indirect annual costs (IDAC) Total Annual Cost (TAC) = (DAC) + (IDAC) 102607-145491 Remarks (CC) X (CC) X (CC) X 2.0% 7.0% 5.0% $3,336,000 $2,224,000 $4,448,000 $556,000 $445,000 $111,000 $0 $2,000 $11,122,000 (PEC) X (PEC) X (PEC) X (PEC) X (PEC) X (PEC) X (PEC) X (PEC) X 15.0% 10.0% 20.0% 2.5% 2.0% 0.5% 0.00% 0.01% $200,000 $33,564,000 Estimate $4,028,000 $1,007,000 $3,356,000 $3,356,000 $1,007,000 $67,000 $5,035,000 $17,856,000 (DC) X (DC) X (DC) X (DC) X (DC) X (DC) X (DC) X 12.0% 3.0% 10.0% 10.0% 3.0% 0.2% 15.0% [(DC)+(IC)] X 8.20% $6,325,000 6/29/2007 3 years (project time length) $57,745,000 $2,155,000 $2,155,000 from CUECost $2,862,000 $664,000 $320,000 $3,846,000 29.7 tph and 1,192 kW and 575 kW and 11 $/ton 0.06 $/kWh 0.06 $/kWh 3 in. H2O d.p. Engineering estimate $6,001,000 $5,451,000 $5,451,000 (TCI) X 9.44% CRF at 7% interest & 20 year life $11,452,000 5-13 Interstate Power and Light Sutherland Unit 4 Air Permit Application 5.0 Coal Fired Boiler PM/PM10 BACT Analysis Table 5-6 Particulate Matter Top-Down BACT Summary Emissions Emissions, lb/h Emissions Reduction, tpy Total Capital Cost, $1,000 Total Annualized Cost, $1,000/yr Control CostEffectiveness, $/ton Fabric Filter (0.012 lb/MBtu) 74 192,137 64,982 10,263 DESP (0.012 lb/MBtu) 74 192,137 57,745 43,941 -- -- Control Alternative Uncontrolled Baseline 102607-145491 Energy Impacts Economic Impacts Incremental CostEffectiveness, $/ton Environmental Impacts Incremental Increase Over Baseline, kWh/yr Toxic Impacts (Yes/No) Adverse Environmental Impacts (Yes/No) 53 29,542,439 No No 11,452 60 14,144,681 No No -- -- -- -- -- -- 5-14 Interstate Power and Light Sutherland Unit 4 Air Permit Application 5.0 Coal Fired Boiler PM/PM10 BACT Analysis It should also be noted that the majority of issued permits in the RBLC do not properly account for condensable artifacts such as ammonia slip, SO3, and VOC. These artifacts exist i nthe vapor phase until exiting the stack, rendering them uncontrollable by the primary particulate control device such as a fabric filter or DESP. In fact, the test methods currently promulgated will actually form particulate that would otherwise exist as vapor in the back half train of the reference methods. Table 5-7 summarizes the Project’s PM/PM10 BACT determination for the main boiler. IPL’s proposed PM/PM10 BACT limit is based on engineering evaluation and a review of various OEM’s technical literature. No literature was found nor engineering calculations performed that would indicate that co-firing with a biomass blend of 5 percent would change the proposed BACT emissions limit. Table 5-7 Main Boiler PM/PM10 BACT Determination Control Technology Emission Limit (lb/MBtu) Fabric Filter PM/PM10 (filterable) limit of 0.012 lb/MBtu(1); PM/PM10 (filterable + condensable) limit of 0.018 lb/MBtu(2) (1) The test method for the associated limit is based on USEPA Test Method 5B. The test method for the associated limit is based on USEPA Test Method 5B and 202, with artifact modification including SO3 and VOC. (2) As indicated in Subsection 2.1.1.1 NSPS Subpart Da – Standards of Performance for Electric Utility Steam Generating Units for Which Construction is Commenced After September 18, 1978, the visible emission (opacity) limit for the main boiler is to not discharge into the atmosphere any gases that exhibit greater than 20 percent opacity (6 minute average), except for one 6 minute period per hour of not more than 27 percent opacity. A search of the information contained in the USEPA BACT/LAER Clearinghouse and other sources specified in Section 2.1 was conducted to determine the top level of visible emission control for pulverized coal boilers. The results of the review indicated the following: • The lowest emission limit currently in place for a PC boiler is 10 percent opacity (6 minute average) with a 20 percent opacity (6 minute average) for shutdown for the Comanche Station (Unit 3), Public Service Company of Colorado (Permitted: July 5, 2005) located in Colorado. The control technology was listed as fabric filter. 102607-145491 5-15 Interstate Power and Light Sutherland Unit 4 Air Permit Application • 5.0 Coal Fired Boiler PM/PM10 BACT Analysis The next lowest emission limit currently in place for a PC boiler is 10 percent opacity (6 minute average) for the Gascoyne Generating Station, Montana Dakota Utilities (Permitted: June 3, 2005) located in North Dakota. The control technology was listed as fabric filter. • The next lowest emission limit currently in place for a PC boiler is 10 percent opacity (6 minute average) for Maidsville, Longview Power, LLC (Permitted: March 6, 2005) located in West Virginia. The control technology was listed as dry solid injection with fabric filter and wet scrubber. Further review of the informational databases discussed in Section 2.1 indicated that PC boilers have not been required to install additional visible emission controls because the particulate matter control equipment ensures the control of opacity. IPL proposes a fabric filter and a visible emission limit of 10 percent opacity (6 minute average) based on continuous opacity monitoring system (COMS) as BACT for the Project, which is equivalent to the most stringent level in the RBLC for pulverized coal fired boilers of similar operation and size. Table 5-8 summarizes the Project’s visible emission BACT determination for the main boiler. IPL’s proposed visible emission BACT limit is based on engineering evaluation and a review of various OEM’s technical literature. No literature was found nor engineering calculations performed that would indicate that co-firing with a biomass blend of 5 percent would change the proposed BACT emissions limit. Table 5-8 Main Boiler Visible Emission (Opacity) BACT Determination Control Technology Emission Limit (% Opacity) Fabric Filter 10(1) (1) 6 minute average based on a continuous opacity monitoring system (COMS). 102607-145491 5-16 Interstate Power and Light Sutherland Unit 4 Air Permit Application 6.0 6.0 Coal Fired Boiler CO and VOC BACT Analysis Coal Fired Boiler CO and VOC BACT Analysis This section presents the top-down, five-step BACT process used to evaluate and determine the Project’s CO and VOC emissions limits for the main boiler. CO and VOC emissions are related as products of incomplete combustion and, as such, are addressed together in this control technology determination. As this analysis will demonstrate, the proposed CO and VOC BACT limits for the Project’s main boiler are emissions limit of 0.12 lb/MBtu and 0.0034 lb/MBtu, respectively. 6.1 Step 1--Identify All 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 and VOC emission limits that are being evaluated. CO and VOC related compounds (generally expressed as non-methane hydrocarbons) are formed during the combustion process as a result of the incomplete oxidation of the carbon contained in the fuel; or simply, they are the products of incomplete combustion. The following subsections review the CO and VOC control technologies. 6.1.1 Good Combustion Controls As products of incomplete combustion, CO and VOC emissions are very effectively controlled by ensuring the complete and efficient combustion of the fuel in the boiler (i.e., good combustion controls). Typically, measures taken to minimize the formation of NOx during combustion inhibit complete combustion, which increases the emissions of CO and VOC. High combustion temperatures, adequate excess air, and good air/fuel mixing during combustion minimize CO and VOC emissions. These parameters also increase NOx generation, in accordance with the conflicting goals of optimum combustion to limit CO and VOC, but lower combustion temperatures to limit NOx. The products of incomplete combustion are substantially different and often less pronounced when the unit is firing high sulfur bituminous coals, which is the rationale for the slightly higher BACT emissions limits found on units permitted to burn low sulfur PRB subbituminous coals. In addition, depending on the manufacturer, good combustion controls vary in terms of meeting CO emissions limits. 102607-145491 6-1 Interstate Power and Light Sutherland Unit 4 Air Permit Application 6.0 Coal Fired Boiler CO and VOC BACT Analysis 6.1.2 Oxidation Catalysts This control process utilizes a platinum/vanadium catalyst that oxidizes CO to CO2 and VOC to CO2 and water. The process is a straight catalytic oxidation/reduction reaction requiring no reagent. Catalytic CO and VOC emissions reduction methods have been proven for use on natural gas and oil fueled combustion turbine sources, but not coal fired boilers. The primary technical challenge for including an oxidation catalyst on a coal fired boiler is the location of the catalyst in a high temperature regime, which would most likely be prior to the economizer. This location, along with the potential fouling effects of the flue gas, would render the catalyst ineffective on even a short-term basis. 6.2 Step 2--Eliminate Technically Infeasible 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 application of an oxidation catalyst to a coal fired boiler presents many substantial challenges that render this control technology not technically feasible for further consideration as a control alternative for CO and VOC. A review of the RBLC reveals that the database contains no record of add-on control equipment for the control of CO and VOC, and IPL is not aware of this control technology having ever been applied to a solid fuel boiler. Technical challenges that render an oxidation catalyst control technically infeasible for this Project include the following: • The oxidation catalyst will not only oxidize CO and VOC, but will also oxidize a predominant portion of SO2 to SO3. The combination of this SO3 with SCR-related ammonia injection will likely result in the quick fouling of the air heater. • Acid gases and trace metals in the flue gas from the combustion of solid fuel will quickly poison the catalyst, making the control technology ineffective in its intended role. Good combustion controls are considered technically feasible for the control of CO and VOC and are considered further in the BACT analysis. CO catalyst is eliminated from further consideration. Table 6-1 summarizes the evaluation of the technically feasible CO and VOC options. 102607-145491 6-2 Interstate Power and Light Sutherland Unit 4 Air Permit Application 6.0 Coal Fired Boiler CO and VOC BACT Analysis Table 6-1 Summary of Step 2--Eliminate Technically Infeasible Options Technically Feasible (Yes/No) Technology Alternative Available Applicable Good Combustion Controls Oxidation Catalyst Yes Yes Yes No – There are no documented installations on coal fired pulverized coal boilers that demonstrate it as a viable option. 6.3 Step 3--Rank Remaining Control Technologies by Effectiveness A search of the information contained in the USEPA BACT/LAER Clearinghouse and other sources specified in Section 2.1 was conducted to determine the top level of CO and VOC control for pulverized coal boilers. A search was also conducted for recently permitted coal fired facilities whose BACT determinations have not yet been included in the current BACT/LAER Clearinghouse database. The results of this search for all coal fired boilers are listed in Attachment A, Tables A-4 and A-5, of this BACT analysis. As previously discussed, CO and VOC emissions, as products of incomplete combustion, are by their nature a function of the specific boiler type and the fuel characteristics, and are thus reflected in the emissions guarantees that vendors are willing to make. As such, the following review is limited to those CO and VOC determinations made for pulverized coal boilers firing low sulfur PRB coal. Table 6-2 lists the CO BACT determinations, which have the closest attributes when compared to IPL’s SGS Unit 4, that include fuel type, boiler technology, and size of boiler. 102607-145491 6-3 Interstate Power and Light Sutherland Unit 4 Air Permit Application 6.0 Coal Fired Boiler CO and VOC BACT Analysis Table 6-2 CO Top-Down RBLC Clearinghouse Review Results 102607-145491 6-4 Interstate Power and Light Sutherland Unit 4 Air Permit Application 6.0 Coal Fired Boiler CO and VOC BACT Analysis A review of the CO BACT determinations in Table 6-2 indicates the following: • CO: − The most stringent CO emissions limit proposed for a pulverized coal boiler unit firing bituminous or subbituminous coal is at a level of 0.10 lb/MBtu. There are five projects that have established 0.10 lb/MBtu as BACT for CO. All of the pulverized coal boiler units at the five projects propose to utilize good combustion controls as the documented CO control technology. The following are the five projects: a 750 MW pulverized coal boiler installation at Louisville Gas and Electric Company, Trimble County Generating Station located in Kentucky; 2 x 750 MW pulverized coal boiler installations at Peabody Energy, Thoroughbred Generating Station located in Kentucky; 2 x 750 MW pulverized coal boiler installation at Sithe Global Desert Rock Power Plant located in New Mexico; 750 MW pulverized coal boiler installation at Touquop Energy Project located in Nevada; and 2 x 750 MW pulverized coal boiler installation at Sierra Pacific and Nevada Power, Ely Energy Center located in Nevada. − The next most stringent CO emissions limit permitted to date for a pulverized coal boiler (600 MW) firing a bituminous coal at a level of 0.11 lb/MBtu is Longview Power, LLC, Maidsville Plant located in West Virginia. − The next most stringent CO emissions limit permitted to date for a pulverized coal boiler (2 x 615 MW) firing a subbituminous coal at a level of 0.12 lb/MBtu is Wisconsin Energy, Elm Road Generating Station located in Wisconsin. − The next most stringent CO emissions limit permitted to date for a pulverized coal boiler (750 MW) firing a subbituminous coal at a level of 0.13 lb/MBtu is Xcel Energy, Comanche Station Unit 3 located in Colorado. − The next most stringent CO emissions limits permitted to date for a pulverized coal boiler firing a subbituminous coal at levels of 0.135, 0.14, and 0.14 lb/MBtu are for Louisiana Generating (Big Cajun II), KCP&L (Iatan 2), and BHP Billiton (Cottonwood Energy), respectively. 102607-145491 6-5 Interstate Power and Light Sutherland Unit 4 Air Permit Application − 6.0 Coal Fired Boiler CO and VOC BACT Analysis The next most stringent CO emissions limits proposed to date for a pulverized coal boiler (750 MW) firing a subbituminous coal at a level of 0.15 lb/MBtu is LS Power Development, Elk Run Energy Station located in Iowa. The limit is based on a 30 day rolling average. − The next most stringent CO emissions limit permitted to date for a pulverized coal boiler firing PRB fuel is at a level of 0.15 lb/MBtu for several units identified in Table A-4, including Municipal Energy Agency of Nebraska, Whelan Energy Center, and Newmont TS Power Plant. Sunflower’s Holcomb Units are also permitted at this level, although they are proposed as SCPC boilers. Table 6-3 lists the VOC BACT determinations that have the closest attributes when compared to IPL’s SGS Unit 4, which include fuel type, boiler technology, and size of boiler. A review of the VOC BACT determinations in Table 6-3 indicates the following: • VOC: − The most stringent VOC emissions limit proposed for a pulverized coal unit firing a bituminous coal is 0.0024 lb/MBtu. Ozone nonattainment concerns are the drivers for this LAER determination. This limit was established for the Santee Cooper, Santee Cooper Cross Generating Station, which has 2 x 660 MW pulverized coal boilers (good combustion controls) and Santee Cooper, Pee Dee Generating Station, which also has 2 x 660 MW pulverized coal boilers (good combustion controls). The two projects listed above are located in South Carolina. The Santee Cooper Cross Generating Station has one operating unit (commercial operation date in January 2007) and one unit still under construction. It is unknown if the Santee Cooper Cross Generating Station demonstrated compliance with 0.0024 lb/MBtu. − The most stringent VOC emissions limit currently permitted for a PRB pulverized coal application is 0.0025 lb/MBtu on a 750 MW boiler at CPS Energy’s J.K. Spruce Unit in Texas. Ozone attainment concerns in San Antonio are the drivers for the low emission limits in this case, not BACT. 102607-145491 6-6 Interstate Power and Light Sutherland Unit 4 Air Permit Application 6.0 Coal Fired Boiler CO and VOC BACT Analysis Table 6-3 VOC Top-Down RBLC Clearinghouse Review Results 102607-145491 6-7 Interstate Power and Light Sutherland Unit 4 Air Permit Application 6.0 Coal Fired Boiler CO and VOC BACT Analysis − The next most stringent VOC emissions limit currently permitted for a subbituminous/bituminous blend coal pulverized coal application is 0.0027 lb/MBtu on a 900 MW boiler at Intermountain Power Service Corporation, Intermountain Power Station Unit 3 in Utah. − The next most stringent VOC emissions limit for a PRB coal pulverized coal application is 0.0030 lb/MBtu on the cancelled Bull Mountain Project. − The next most stringent VOC emissions limit currently permitted for a subbituminous/bituminous blend coal pulverized coal application is 0.0032 lb/MBtu on a 750 MW boiler at Louisville Gas and Electric Company, Trimble County Generating Station located in Kentucky. − The next most stringent VOC emissions limit currently permitted for a PRB coal pulverized coal application is 0.0034 lb/MBtu on the Centennial Hardin Power Project in Montana and Omaha Public Power District’s Nebraska City Unit 2. − The next most stringent VOC emissions limit proposed is 0.0035 lb/MBtu for Sunflower’s Holcomb Station Draft permit, Elk Run Energy Station, Comanche Station, and Wisconsin Energy’s Oak Creek Power Plant. − Other recent stringent VOC emissions limits permitted to date at a level of 0.0036 lb/MBtu include a 790 MW plant located at the MidAmerican Energy Co., Council Bluffs facility in Council Bluffs, Iowa. All of the previously listed units limit VOC emissions through the use of good combustion controls. Based on the technologies identified as technically feasible and available in Steps 1 and 2, the following technologies presented in Table 6-4 are ranked in a “TopDown Approach” methodology. 6.4 Step 4--Evaluate Most Effective Controls and Document Results In the following subsections, the technically feasible control alternatives are evaluated in a comparative approach with respect to their energy, environmental, and economic impacts on the Project. 102607-145491 6-8 Interstate Power and Light Sutherland Unit 4 Air Permit Application 6.0 Coal Fired Boiler CO and VOC BACT Analysis Table 6-4 Ranking of CO/VOC Control Technologies Control Effectiveness Control Option CO (lb/MBtu) VOC (lb/MBtu) Good Combustion Controls 0.12 0.0034 No other technologies ranked, but good combustion controls are based on Step 2. 6.4.1 Energy Evaluation of Alternatives There are no significant energy impacts that would preclude the use of good combustion controls to limit the emissions of CO and VOC. 6.4.2 Environmental Evaluation of Alternatives As previously discussed, the typical good combustion control measures taken to minimize the formation of CO and VOC, namely higher combustion temperatures, additional excess air, and optimum air/fuel mixing during combustion are often counterproductive to the control of NOx emissions during combustion. A proper balance of this phenomenon is a necessary task in obtaining and complying with the manufacturer’s guarantees, since overly aggressive CO and VOC limits can jeopardize NOx emissions design considerations. 6.4.3 Economic Evaluation of Alternatives Since there is only one feasible control technology to limit the emissions of CO and VOC from the Project’s main boiler, a comparative cost analysis is not applicable. 6.5 Step 5--Select CO and VOC BACT IPL has determined that good combustion controls represent CO and VOC BACT for the Project’s main boiler. Consistent with the top control identified in Section 6.3, IPL proposes a CO BACT emissions limit of 0.12 lb/MBtu and a VOC BACT emissions limit of 0.0034 lb/MBtu. The proposed BACT levels are based on the units demonstrating compliance with the evaluated BACT emissions level for a similar type boiler and fuel as discussed in Section 6.3, as well as expected manufacturer’s guarantee levels. Table 6-5 summarizes the Project’s CO and VOC BACT determinations for the main boiler, based on an 8 hour and 3 hour test run averaging period, respectively. 102607-145491 6-9 Interstate Power and Light Sutherland Unit 4 Air Permit Application 6.0 Coal Fired Boiler CO and VOC BACT Analysis Table 6-5 Main Boiler CO/VOC BACT Determinations Emission Limit (lb/MBtu) Control Technology CO VOC Good Combustion Controls 0.12 0.0034 IPL’s proposed CO and VOC BACT limits are based on engineering evaluation and a review of various OEM’s technical literature. No literature was found nor engineering calculations performed that would indicate that co-firing with a biomass blend of 5 percent would change the proposed BACT emissions limit. 102607-145491 6-10 Interstate Power and Light Sutherland Unit 4 Air Permit Application 7.0 7.0 Coal Fired Boiler Sulfuric Acid Mist BACT Analysis Coal Fired Boiler Sulfuric Acid Mist BACT Analysis This section presents the top-down, five-step BACT process used to evaluate and determine the Project’s H2SO4 emission limit for the main boiler. As this analysis will demonstrate, the proposed H2SO4 BACT limit for the Project’s main boiler is an emissions limit of 0.004 lb/MBtu (based on Controlled Condensate Test Method). 7.1 Step 1--Identify All 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 sulfuric acid mist emission limit that is being evaluated. Sulfuric acid is present in the flue gases generated from the combustion of coal, because a small fraction of the SO2 produced is further oxidized to SO3. SO3 reacts with water in the flue gas to form sulfuric acid vapor. Sulfuric acid can cause air heater fouling and equipment corrosion downstream, and when the flue gas containing sulfuric acid vapor is cooled, it condenses to form a submicron aerosol mist as it is emitted to the atmosphere. In addition to the SO3 formed during combustion, SCR catalysts used for NOx control further oxidize a fraction of SO2 to SO3. The combination of furnace and SCR oxidation has the capability to produce significant quantities of SO3. In addition, the SO3 content in the furnace exit gas can limit SCR operation at lower unit loads because of the lower flue gas temperatures that result from the low load operation. The potential to form ammonium sulfate salts that will foul active catalyst sites increases at the lower economizer outlet flue gas temperatures. Effective controls for H2SO4 include only post-combustion controls and include lime-based semi-dry scrubbers, wet FGDs, wet ESPs, and alkali injection systems. These control technology alternatives are described below. 7.1.1 Wet and Semi-Dry Lime-Based FGD Systems Semi-dry FGD systems were discussed in detail, along with their consideration as SO2 control alternatives, in Subsection 3.1.3. Historically, semi-dry scrubbers, in combination with fabric filters, have been determined as the top BACT control technology for H2SO4 for similar sized boilers using the same fuels as this Project. The gas temperature leaving a lime-based semi-dry scrubber is lowered below the sulfuric acid dew point, and significant SO3 removal is attained as the condensed acid reacts with 102607-145491 7-1 Interstate Power and Light Sutherland Unit 4 Air Permit Application 7.0 Coal Fired Boiler Sulfuric Acid Mist BACT Analysis the alkaline reagent and fly ash. By removing SO3 in the flue gas in this process, H2SO4 is effectively controlled. The wet lime FGD processes were previously described, along with their considerations as SO2 control alternatives in Subsection 3.1.2. As discussed, a wet FGD is typically installed downstream of a pulverized coal boiler and is usually the last control device for any emissions control before exiting the stack. The JBR described in Subsection 3.1.1.3 includes other added benefits, such as the removal of condensed SO3. The gypsum crystals produced in a JBR have a relatively larger size distribution, since there is less attrition due to circulation through slurry recycle spray pumps. Also, the JBR’s ability to remove more than 80 percent of the fine (less than 10 μm) particulate matter from the flue gas is substantially better than conventional spray absorbers. This increased particulate removal directly increases the removal of condensed SO3 from the system compared to most other competing wet scrubber designs, which remove virtually no SO3. SO3 is formed during combustion and will react with the moisture in the flue gas to form H2SO4 mist in the atmosphere. An increase in H2SO4 emissions will increase PM10 emissions. The gas temperature leaving the reactor is lowered below the sulfuric acid dew point and significant SO3 removal will be attained as the condensed acid reacts with the alkaline reagent. It should be noted that of recently, Alstom is developing a proprietary “Integrated AQCS” system which combines a SDA/FF with a downstream wet FGD. Both of the components, wet FGD and SDA have been used separately on many installations. However, the separate systems have not been combined together for an AQCS integrated solution. The primary requirement for the system to be viable will be the ability to route the purge stream from the Wet FGD to the SDA to eliminate waste water treatment which has not been demonstrated in practice. As previously discussed, a wet FGD system has been determined as BACT for SO2. Normally, an SDA is not included as part of the air quality control system when SO2 control is being accomplished by a wet FGD or other control device. 7.1.2 Wet Electrostatic Precipitator The WESP process is described in some detail, along with its consideration as a PM/PM10 control alternative, in Subsection 5.1.4. In high sulfur coal applications, the addition of a WESP is a feasible control alternative that allows sulfuric acid mist to condense and be collected as particulate or absorbed into the water stream along the charged collection surfaces. 102607-145491 7-2 Interstate Power and Light Sutherland Unit 4 Air Permit Application 7.0 Coal Fired Boiler Sulfuric Acid Mist BACT Analysis 7.1.3 Sorbent Injection Systems Injection of finely divided alkalis into the flue gas has been demonstrated for the removal of SO3 from flue gases. Most commercial experience is from units firing high sulfur oil where trace metals, mainly vanadium, increase SO2 oxidation. Magnesiumbased compounds have been used successfully for decades to capture SO3 in oil fired units. As coal fired units burning high sulfur bituminous coals have been retrofitted with SCR systems (primarily in the east), interest in the injection of alkali compounds directly into the flue gas duct of a unit has increased. Sorbents such as sodium bisulfite, trona, and hydrated lime have recently been tested on large coal fired units, with reported results showing the achievement of high control efficiencies of SO3 in high sulfur applications. 7.2 Step 2--Eliminate Technically Infeasible 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. From a review of the aforementioned H2SO4 control technologies, it can be concluded that alkali injection systems and WESP are technically feasible as control technology alternatives for the Project’s main boiler. As such, each will be considered further in the BACT analysis. A dry FGD system is considered technically feasible and applicable for this Project; however, a wet FGD is proposed as SO2 BACT. As discussed in Subsection 7.1.1, Alstom is developing a proprietary “Integrated AQCS” system that combines a SDA/FF with a downstream wet FGD. This arrangement of control equipment has not yet reached the licensing and commercial sales stage of development for a similar size of unit as the Project. Therefore, a dry FGD system with a wet lime FGD process is not considered technically feasible. In addition, the requirements to handle both lime and limestone on the same site, as well as additional nonsaleable grade of ash, would make this system combination (dry and wet FGD) environmentally and economically not a good choice. Table 7-1 summarizes the evaluation of the technically feasible H2SO4 options. 102607-145491 7-3 Interstate Power and Light Sutherland Unit 4 Air Permit Application 7.0 Coal Fired Boiler Sulfuric Acid Mist BACT Analysis Table 7-1 Summary of Step 2--Eliminate Technically Infeasible Options Technically Feasible (Yes/No) Technology Alternative Available Applicable FF/Wet FGD/WESP FF/Wet FGD/FF with Sorbent Injection Dry FGD/FF/Wet FGD Yes Yes Yes Yes Yes No – Dry FGD/FF/Wet FGD is being developed, and it has not been utilized in practice. 7.3 Step 3--Rank Remaining Control Technologies by Effectiveness A review of the information contained in the USEPA BACT/LAER Clearinghouse and other sources specified in Section 2.1 was conducted to determine the top level of H2SO4 control for pulverized coal boilers. A search was also conducted for recently permitted coal fired facilities whose BACT determinations have not yet been included in the current BACT/LAER Clearinghouse database. The results of this search for all coal fired boilers are listed in Attachment A, Table A-6, of this BACT analysis. Table 7-2 lists the H2SO4 BACT determinations that have the closest attributes when compared to IPL’s SGS Unit 4, which include fuel type, boiler technology, and boiler size. A review of the H2SO4 BACT determinations in Table 7-2 indicates the following: • The lowest H2SO4 emission limit permitted for a low sulfur PRB fuel boiler is 0.000184 lb/MBtu, utilizing an SDA/fabric filter at the City Utilities of Springfield Southwest Power Station. However, it appears that this yet-to-be demonstrated limit was taken so that the Project would not be subject to BACT review for H2SO4 and, as such, does not appear to represent an actual BACT determination. 102607-145491 7-4 Interstate Power and Light Sutherland Unit 4 Air Permit Application 7.0 Coal Fired Boiler Sulfuric Acid Mist BACT Analysis Table 7-2 H2SO4 Top-Down RBLC Clearinghouse Review Results 102607-145491 7-5 Interstate Power and Light Sutherland Unit 4 Air Permit Application 7.0 Coal Fired Boiler Sulfuric Acid Mist BACT Analysis • The next lowest H2SO4 emission limit permitted for subbituminous coal fuel boilers is 0.0037 lb/MBtu for three projects. The first utilizes a wet FGD at CPS of San Antonio, Calaveras Lake Station (San Antonio, Texas), and the second utilizes a dry FGD at Western Famers Electric Coop, Hugo Station (Oklahoma City, Oklahoma). The third project utilizes a dry FGD and fabric filter as H2SO4 control at Sandy Creek Energy Associates, Sandy Creek Energy (Waco, Texas). Ozone nonattainment concerns in San Antonio, Oklahoma City, and Waco, respectively, are the drivers of the low emission limit in these cases, not BACT. • The next most stringent H2SO4 emission limit permitted for a pulverized coal boiler is 0.0038 lb/MBtu firing a subbituminous/bituminous blend of coal at Louisville Gas and Electric Company, Trimble County Generating Station (Kentucky). Trimble County Generating Station utilizes a wet ESP for H2SO4 control. • Several H2SO4 emission limits that are being proposed between 0.004 and 0.005 are evident from the review of low sulfur PRB fired boilers utilizing wet FGD/dry FGD/fabric filter control technologies, including Sunflower’s Holcomb project at 0.004 lb/MBtu and Elk Run Energy Station at 0.0042 lb/MBtu. The wide range of H2SO4 emission limits proposed for subbituminous and blends of subbituminous with bituminous coal fired boilers (as summarized above) is, in large part, due to the fact that the emission reductions proposed are actually the result of an assumed collateral control benefit from control technologies used to limit emissions of SO2 and PM/PM10, and the variability in the assumed SO2 to SO3 conversion and fuel sulfur content. IPL is not aware of any data demonstrating continuous long-term compliance with the H2SO4 BACT determination emission limits proposed and summarized above. The first BACT determination that has been permitted or proposed utilizing bituminous coal (which is a coal being proposed by the Project) is for 2 x 750 MW pulverized coal boilers at Peabody Energy, Thoroughbred Generating Station located in Kentucky. The H2SO4 emission limit permitted was for 0.00497 lb/MBtu. This is significant because bituminous coals have a much greater sulfur content than subbituminous coals, which makes the level of control a limit of the technology. 102607-145491 7-6 Interstate Power and Light Sutherland Unit 4 Air Permit Application 7.0 Coal Fired Boiler Sulfuric Acid Mist BACT Analysis Based upon the technologies identified as technically feasible and available in Steps 1 and 2, the following technologies presented in Table 7-3 are ranked in a “TopDown Approach” methodology. Table 7-3 Ranking of H2SO4 Control Technologies Control Option Control Effectiveness (lb/MBtu) FF/Wet FGD/WESP FF/Wet FGD with Sorbent Injection 0.004 0.004 7.4 Step 4--Evaluate Most Effective Controls and Document Results In the following subsections, the technically feasible control alternatives are evaluated in a comparative approach with respect to their energy, environmental, and economic impacts on the Project. 7.4.1 Energy Evaluation of Alternatives While the energy impact of a WESP is considerably greater than that of sorbent injection, there are no significant energy impacts that would preclude the use of these technologies to limit H2SO4. 7.4.2 Environmental Evaluation of Alternatives When considering any WESP technology, there are potential environmental impacts associated with the direct operation of the technology. In general, the impacts are consistent with that of a wet FGD, which is the creation of a visible stack plume, increased water consumption, and the requirements of a wastewater treatment system. However, since a WESP is typically located after a wet FGD, its environmental impacts are essentially shared. The sorbent injection systems result in no environmental impacts. 7.4.3 Economic Evaluation of Alternatives The economic evaluations of the WESP and sorbent injection control alternatives have been assessed in this BACT analysis and are presented in Section 7.5. 102607-145491 7-7 Interstate Power and Light Sutherland Unit 4 Air Permit Application 7.0 Coal Fired Boiler Sulfuric Acid Mist BACT Analysis Tables 7-4 and 7-5 present the total capital investment for the installation of a WESP or sorbent injection system on the Project’s main boiler, respectively. As described in the tables, the purchased equipment costs include the respective sulfuric acid mist control technologies. The direct installation costs, which include balance-of-plant items such as foundations and supports, handling and erection, electrical, piping, insulation, and paint, were calculated as a percentage of the purchased equipment costs and totaled with the purchased equipment costs to estimate the total direct costs of each control alternative. Finally, the total capital investment was calculated as the summation of the total direct costs and total indirect costs (including engineering and owner’s costs) and an allowance for funds used during construction. Tables 7-4 and 7-5 also present the annualized operating costs for the installation of a wet ESP or sorbent injection system on the Project’s main boiler. As described in the tables, the operating fixed and variable direct annual costs includes operating labor, maintenance labor and materials, and auxiliary and ID fan power costs. The indirect annual costs, which includes the capital recovery costs, is totaled with the direct annual costs to estimate the total annual costs for the control system. 7.5 Step 5--Select H2SO4 BACT IPL has determined that a wet FGD/fabric filter, in combination with sorbent injection, represents the H2SO4 BACT for the Project’s main boiler. This is also the top control technology evident in recent permits for similar sized units and fuels. Since the H2SO4 BACT control technology determination is actually a collateral benefit of the wet FGD/fabric filter BACT determination for SO2 and PM/PM10 and not a technology installed expressly for the purpose of controlling H2SO4, the development of an emission limit (and eventual compliance) has to be carefully considered and estimated on the basis of assumptions relative to variations in fuel sulfur content (refer to Table 2-3), SO2 to SO3 conversion during the combustion process and across the SCR. The following assumptions form the basis for the H2SO4 BACT limitation for the proposed control technology: • Oxidation conversion of a total of 2.0 percent of SO2 to SO3 in the combustion process and across the SCR catalyst is assumed. • Fuel sulfur variability as presented in the BACT basis, Table 2-3. 102607-145491 7-8 Interstate Power and Light Sutherland Unit 4 Air Permit Application 7.0 Coal Fired Boiler Sulfuric Acid Mist BACT Analysis Table 7-4 Wet ESP Equipment Engineering Analysis - Cost Analysis (WESP) Technology: Date: 6/29/2007 Wet Electrostatic Precipitator (WESP) Cost Item $ CAPITAL COST Direct Costs Purchased equipment costs WESP system includes casing, electrical systems, penthouse blower and heater, access provisions Ash handling system Booster fans Electrical system upgrades Flue gas handling system Subtotal capital cost (CC) Instrumentation and controls Taxes Freight Total purchased equipment cost (PEC) Remarks/Cost Basis $30,025,000 $2,454,000 $4,662,000 $1,350,000 $3,681,000 $42,172,000 $843,000 $2,952,000 $2,109,000 $48,076,000 (CC) X (CC) X (CC) X 2.0% 7.0% 5.0% 5.0% 10.0% 10.0% 2.5% 2.0% 0.5% 0.00% 0.00% Direct installation costs Foundation & supports Handling & erection Electrical Piping Insulation Painting Demolition Relocation Total direct installation costs (DIC) $2,404,000 $4,808,000 $4,808,000 $1,202,000 $962,000 $240,000 $0 $0 $14,424,000 (PEC) X (PEC) X (PEC) X (PEC) X (PEC) X (PEC) X (PEC) X (PEC) X Site preparation Buildings Waste water treatment system Total direct costs (DC) = (PEC) + (DIC) $557,654 $0 $6,339,000 $63,058,000 Engineering estimate N/A Estimate $6,306,000 $3,153,000 $6,306,000 $946,000 $126,000 $12,612,000 $29,449,000 (DC) X (DC) X (DC) X (DC) X (DC) X (DC) X Indirect Costs Engineering Owner's cost Construction management Start-up and spare parts Performance test Contingencies Total indirect costs (IC) Allowance for Funds Used During Construction (AFDC) Total Capital Investment (TCI) = (DC) + (IC) ANNUAL COST Direct Annual Costs Fixed annual costs Maintenance materials and labor Total fixed annual costs Variable annual costs Auxiliary power ID fan power Service water Total variable annual costs Total direct annual costs (DAC) Indirect Annual Costs Cost for capital recovery Total indirect annual costs (IDAC) Total Annual Cost (TAC) = (DAC) + (IDAC) 102607-145491 $3,793,000 10.0% 5.0% 10.0% 1.5% 0.2% 20.0% [(DC)+(IC)] X 8.20% 1 year(s) $96,300,000 137.47 $1,892,000 $1,892,000 (DC) X $131,000 $348,000 $764,000 $1,243,000 3.0% 235 kW and 625 kW and 727 gpm and 0.06 $/kWh Engineering estimate 0.06 $/kWh 4" water pressure drop 2 $/1,000 gal Engineering estimate $3,135,000 $9,091,000 $9,091,000 (TCI) X 9.44% CRF at 7% interest & 20 year life $12,226,000 7-9 Interstate Power and Light Sutherland Unit 4 Air Permit Application 7.0 Coal Fired Boiler Sulfuric Acid Mist BACT Analysis Table 7-5 SO3 Sorbent Injection Equipment Engineering Analysis - Cost Analysis (SO3 Sorbent Injection) Technology: SO3 Sorbent Injection Cost Item Date: $ CAPITAL COST Direct Costs Purchased equipment costs Base Injection Equipment Subtotal capital cost (CC) Instrumentation and controls Taxes Freight Total purchased equipment cost (PEC) $2,379,569 $2,379,569 $48,000 $167,000 $119,000 $2,714,000 Direct installation costs Foundation & supports Handling & erection Electrical Piping Insulation Painting Demolition Relocation Total direct installation costs (DIC) Site preparation Total direct costs (DC) = (PEC) + (DIC) Indirect Costs Engineering Owners Cost Construction and field expenses Contractor fees Start-up Performance test Contingencies Total indirect costs (IC) Allowance for Funds Used During Construction (AFDC) Total Capital Investment (TCI) = (DC) + (IC) ANNUAL COST Direct Annual Costs Fixed annual costs Maintenance labor and materials Total fixed annual costs Variable annual costs Reagent Byproduct disposal Auxiliary power Total variable annual costs Total direct annual costs (DAC) Indirect Annual Costs Cost for capital recovery Total indirect annual costs (IDAC) Total Annual Cost (TAC) = (DAC) + (IDAC) 102607-145491 (CC) X (CC) X (CC) X 2.0% 7.0% 5.0% $407,000 $271,000 $543,000 $68,000 $54,000 $14,000 $0 $0 $1,357,000 (PEC) X (PEC) X (PEC) X (PEC) X (PEC) X (PEC) X (PEC) X (PEC) X 15.0% 10.0% 20.0% 2.5% 2.0% 0.5% 0.00% 0.01% $50,000 $4,121,000 Estimate $495,000 $124,000 $412,000 $412,000 $124,000 $8,000 $618,000 $2,193,000 (DC) X (DC) X (DC) X (DC) X (DC) X (DC) X (DC) X 12.0% 3.0% 10.0% 10.0% 3.0% 0.2% 15.0% [(DC)+(IC)] X 8.20% (DC) X 3.0% $777,000 10/24/2007 Remarks 3 years (project time length) $7,091,000 $123,630 $123,630 $1,319,000 $50,000 $14,000 $1,383,000 1.00 tph and 0.95 tph and 25 kW and 150 $/ton 6 $/ton 0.06 $/kWh Engineering estimate $1,506,630 $669,000 $669,000 (TCI) X 9.44% CRF at 7% interest & 20 year life $2,175,630 7-10 Interstate Power and Light Sutherland Unit 4 Air Permit Application 7.0 Coal Fired Boiler Sulfuric Acid Mist BACT Analysis Tables 7-4 and 7-5 provide the economic analysis for installation of the wet ESP and sorbent injection technology, respectively. Table 7-6 summarizes the top-down evaluation of the sulfuric acid mist BACT control alternatives, including economic, energy, and environmental considerations, in accordance with the BACT determination methodology previously discussed. Table 7-7 summarizes the Project’s H2SO4 BACT determination for the main boiler. Since a WESP and sorbent injection meet the top ranked control technology emission limit, the decision to select sorbent injection is based on the control technology with the lowest annualized cost and infinite incremental cost increase. Therefore, IPL proposes a sulfuric acid mist limit of 0.004 lb/MBtu (based on Controlled Condensate Test Method) as BACT for the Project. The proposed H2SO4 BACT limit is based on engineering evaluation and review of various OEM technical literature. There was no literature found or engineering calculations performed that would indicate that co-firing with a biomass blend of 5 percent would change the proposed BACT emission limit. 102607-145491 7-11 Interstate Power and Light Sutherland Unit 4 Air Permit Application 7.0 Coal Fired Boiler Sulfuric Acid Mist BACT Analysis Table 7-6 Sulfuric Acid Mist Top-Down BACT Summary Emissions Environmental Impacts Control CostEffectiveness, $/ton Incremental CostEffectiveness, $/ton Incremental Increase Over Baseline, kWh/yr Toxic Impacts (Yes/No) Adverse Environmental Impacts (Yes/No) 12,226 2,625 ∞ 7,537,216 No No 7,091 2,176 467 219,000 No No -- -- -- -- -- -- Emissions, lb/h Emissions Reduction, tpy Total Capital Cost, $1,000 Total Annualized Cost, $1,000/yr Wet FGD/FF/WESP (0.004 lb/MBtu) 24.7 4,657 96,300 Sorbent Injection (0.004 lb/MBtu) 24.7 4,657 Uncontrolled Baseline 1,088 -- Control Alternative Energy Impacts Economic Impacts -- Table 7-7 Main Boiler H2SO4 BACT Determination 102607-145491 Control Technology Emission Limit (lb/MBtu) FF/Wet FGD with Sorbent Injection 0.004 7-12 Interstate Power and Light Sutherland Unit 4 Air Permit Application 8.0 8.0 Coal Fired Boiler Fluorides BACT Analysis Coal Fired Boiler Fluorides BACT Analysis This section presents the top-down, five-step BACT process used to evaluate and determine the Project’s fluorides emission limit for the main boiler. Fluoride emissions are formed from hydrogenation of fuel-bound fluorides forming hydrogen fluoride (HF). As this analysis will demonstrate, the proposed fluorides (as HF) BACT limit for the Project’s main boiler is an emissions limit of 0.0002 lb/MBtu. 8.1 Step 1--Identify All 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 sulfuric acid mist emission limit that is being evaluated. Fluorides levels are fuel specific, present in the coal in trace amounts, and generally emitted as HF. As with other acids, for example, H2SO4 as previously discussed, HF (and thus fluorides) is cost-effectively controlled as a collateral benefit of the modern SO2 air pollution control equipment considered in this BACT analysis. A description of the SO2 control alternatives is presented in Section 4.3 of this BACT analysis. 8.2 Step 2--Eliminate Technically Infeasible 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. Coal washing utilizes various techniques such as high speed coal washes or agitating liquids to produce a separation of impurities from the coal. The trace elements such as fluorine will be separated from the coal product. Since IPL is proposing to utilize various types of coals, the effectiveness of coal washing will differ greatly. IPL is not aware of large-scale facilities that perform coal washing on western subbituminous coal, such as PRB, which is considered one of the design coals for the main boiler. Therefore, the supply of PRB coal that has been washed cannot be considered a reliable source for 102607-145491 8-1 Interstate Power and Light Sutherland Unit 4 Air Permit Application 8.0 Coal Fired Boiler Fluorides BACT Analysis this Project. Coal washing is determined to be technically infeasible because PRB coal that has been washed may not be available. A wet lime- and limestone-based FGD process have been demonstrated technologies of controlling fluoride emissions from a coal fired boiler and are commercially available from several vendors. Wet lime- and limestone-based FGD processes, which include the countercurrent spray tower, double contact spray tower, jet bubbling reactor, and FLOWPAC, are equal for comparative purposes. Wet lime- and limestone-based FGD processes are considered technically feasible and will be considered further. Dry and semi-dry lime FGD systems are considered technically feasible and applicable for this Project; however, a wet FGD is proposed as SO2 BACT. As discussed in Subsection 7.1.1, Alstom is developing a proprietary “Integrated AQCS” system that combines a SDA/FF with a downstream wet FGD. This arrangement of control equipment has not reached the licensing and commercial sales stage of development for a similar size of unit as the Project. In addition, IPL is unaware of any other type of dry and semi-dry lime FGD systems (CDS, Flash Dryer Absorber, and LIFAC) that are combined with a wet lime FGD process to control fluorides. Therefore, a dry and semiFGD system with a wet lime FGD process is not considered technically feasible. In addition, the requirements to handle both lime and limestone on the same site, as well as additional nonsaleable grade of ash, would make this system combination (dry and wet FGD) environmentally and economically not a good choice. As discussed in Subsection 3.2.3.4, the LIFAC process is a demonstrated technology of controlling SO2 emissions from a coal fired boiler on a limited number of installations and is considered commercially available. LIFAC has not been applied domestically to similar sized boilers as proposed for the Project. LIFAC has been designed for plant capacities ranging from 25 to 200 MW. LIFAC will not be considered further because it is not technically feasible for the Project. Table 8-1 summarizes the evaluation of the technically infeasible HF options, which is very similar to the SO2 options that were identified earlier in Table 3-1. 102607-145491 8-2 Interstate Power and Light Sutherland Unit 4 Air Permit Application 8.0 Coal Fired Boiler Fluorides BACT Analysis Table 8-1 Summary of Step 2--Eliminate Technically Infeasible Options Technically Feasible (Yes/No) Technology Alternative Available Applicable Coal Washing Yes No – PRB coal that has been washed may not be available. Coal washing is not technically feasible. Spray Tower Yes Yes Double Contact Spray Tower Yes Yes Jet Bubbling Reactor Yes Yes FLOWPAC Yes Yes SDA/FF/Wet FGD Yes No – SDA/FF/Wet FGD is being developed, and it has not been utilized in practice. CDS/FF/Wet FGD Yes No – No installations comparable in size to this Project for a CDS. Flash Dryer Absorber/FF/Wet FGD Yes No LIFAC Yes No – No installations comparable in size to this Project. Long-term high removal efficiency not demonstrated on range of sulfur in fuels of this Project. Wet Lime or Limestone FGD(1) Dry and Semi-Dry Lime FGD (1) All alternate technologies in wet lime or limestone FGD (i.e., spray tower, double contact spray tower, JBR, FLOWPAC) are considered comparatively equal. 102607-145491 8-3 Interstate Power and Light Sutherland Unit 4 Air Permit Application 8.3 8.0 Coal Fired Boiler Fluorides BACT Analysis Step 3--Rank Remaining Control Technologies by Effectiveness A search of the information contained in the USEPA BACT/LAER Clearinghouse and other sources specified in Section 2.1 was conducted to determine the top level of fluorides control for pulverized coal boilers firing subbituminous and bituminous coal. A search was also conducted for recently permitted coal fired facilities whose BACT determinations have not yet been included in the current BACT/LAER Clearinghouse database. The results of this search for all coal fired boilers are listed in Attachment A, Table A-7, of this BACT analysis. Table 8-2 lists the HF BACT determinations that have the closest attributes when compared to IPL’s SGS Unit 4, which include fuel type, boiler technology, and boiler size. A review of the HF BACT determinations in Table 8-2 indicates the following: • The most stringent fluorides emission limit permitted to date for a pulverized coal boiler burning a bituminous coal is an emission limit of 0.00010 lb/MBtu for the Longview Power, LLC, Maidsville Plant located in West Virginia. This unit controls fluorides with wet FGD, limestone injection, and a fabric filter. • The next most stringent fluorides emission limit permitted to date for a pulverized coal boiler burning a bituminous coal is an emission limit of 0.000159 lb/MBtu for the Peabody Energy Thoroughbred Generating Station located in Kentucky (wet FGD as control). • The most stringent fluorides emission limit permitted to date for a pulverized coal boiler burning a PRB subbituminous coal is an emission limit of 0.00020 lb/MBtu for the Wisconsin Public Service Weston Unit No. 4 located in Wisconsin (dry FGD as control). • The most stringent fluorides emission limit proposed to date for a pulverized coal boiler burning a bituminous coal/petcoke is an emission limit of 0.000230 lb/MBtu for the Florida Power and Light Glades Power Park located in Florida (wet FGD as control). • The next most stringent fluorides emission limit permitted to date for a pulverized coal boiler burning a bituminous coal is an emission limit of 0.00030 lb/MBtu for the Santee Cooper Cross Generating Station located in South Carolina (wet FGD as control). • The next most stringent fluorides emission limit proposed to date for a pulverized coal boiler burning a bituminous coal/petcoke is an emission limit of 0.000341 lb/MBtu for the Santee Cooper Pee Dee Generating Station located in South Carolina (wet FGD as control). 102607-145491 8-4 Interstate Power and Light Sutherland Unit 4 Air Permit Application 8.0 Coal Fired Boiler Fluorides BACT Analysis Table 8-2 Fluorides Top-Down RBLC Clearinghouse Review Results 102607-145491 8-5 Interstate Power and Light Sutherland Unit 4 Air Permit Application 8.0 Coal Fired Boiler Fluorides BACT Analysis • The most stringent fluorides emission limit permitted to date for a pulverized coal boiler burning a PRB subbituminous coal is an emission limit of 0.00037 lb/MBtu for the City Utilities of Springfield Southwest Power Station (dry FGD as control). • The next most stringent fluorides emission limit permitted to date for a pulverized coal boiler burning a PRB subbituminous coal is an emission limit of 0.0004 lb/MBtu for Omaha Public Power District’s Nebraska City Unit 2 and the Municipal Energy Agency of Nebraska Whelan Energy Center (dry FGD as control). • The next most stringent fluorides emission limit permitted to date for a pulverized coal boiler burning PRB is 0.00044 lb/MBtu for LS Power’s Plum Point Power Station in Arkansas. This unit also controls fluorides through a dry FGD and a fabric filter. • The next most stringent fluorides emission limit proposed to date for a pulverized coal boiler (750 MW) burning PRB is 0.00067 lb/MBtu for the LS Power Development, Elk Run Energy Station in Iowa. This unit also controls fluorides through a dry FGD and a fabric filter. Based on the technologies identified as technically feasible and available in Steps 1 and 2, the following technologies presented in Table 8-3 are ranked in a “TopDown Approach” methodology. Table 8-3 Ranking of HF Control Technologies Control Option Control Effectiveness (lb/MBtu) Wet FGD System (Lime or Limestone) 0.0002 Notes: 1. No other technologies ranked but wet FGD, based on Step 2. 2. All wet FGD systems expected to be similar in operating characteristics. 8.4 Step 4--Evaluate Most Effective Controls and Document Results Since fluorides are a collateral control benefit of the SO2 reduction technology, the energy, environmental, and economic impacts would be those caused by the BACT selected SO2 technology. 102607-145491 8-6 Interstate Power and Light Sutherland Unit 4 Air Permit Application 8.0 Coal Fired Boiler Fluorides BACT Analysis 8.4.1 Energy Evaluation of Alternatives The energy evaluations of the SO2 control alternatives assessed in this BACT analysis are presented in Section 3.4. 8.4.2 Environmental Evaluation of Alternatives The environmental evaluations of SO2 control alternatives assessed in this BACT analysis are presented in Section 3.4. 8.4.3 Economic Evaluation of Alternatives The economic evaluations of SO2 control alternatives assessed in this BACT analysis are presented in Section 3.4. 8.5 Step 5--Select Fluorides BACT IPL has determined that a wet FGD system represents the fluorides BACT for the Project’s main boiler. This is also the top control technology evident in recent permits for similar sized units and fuels. Fluorides BACT control technology determination is a collateral control benefit of the wet FGD BACT determination for SO2 and not a technology installed expressly for the purpose of controlling fluorides. The actual removal efficiency and effectiveness of these collateral emissions controls are difficult to exactly quantify since little, if any, data are available, and IPL is not aware of full scale commercial demonstration of compliance with the top control emission limits presented in Section 8.3. However, fluorides in the form of HF emissions can be controlled by the use of the wet FGD scrubber system. The lower flue gas temperatures produced by the wet FGD scrubber help to condense HF into a liquid. HF readily dissolves in water and will react with calcium in the wet FGD to form calcium fluoride in solution. Recent manufacturer guaranties have indicated a 90 to 98 percent control effectiveness of fluorides (as HF) associated with the SO2 emission control equipment proposed as BACT for this Project. Based on a 98 percent control effectiveness and the inlet fluorides concentration in the fuel, the proposed BACT emission limit for fluorides (as HF) is 0.0002 lb/MBtu. Table 8-4 summarizes the Project’s fluorides (as HF) BACT determination for the main boiler. The proposed HF BACT limit is based on an engineering evaluation and a review of various OEM technical literature. There was no literature found or engineering calculations performed that would indicate that co-firing with a biomass blend of 5 percent would change the proposed BACT emission limit. 102607-145491 8-7 Interstate Power and Light Sutherland Unit 4 Air Permit Application 8.0 Coal Fired Boiler Fluorides BACT Analysis Table 8-4 Main Boiler HF BACT Determination Control Technology Emission Limit (lb/MBtu) Wet FGD System (Lime or Limestone) 0.0002 102607-145491 8-8 Interstate Power and Light Sutherland Unit 4 Air Permit Application 9.0 9.0 Auxiliary Boiler BACT Analysis Auxiliary Boiler BACT Analysis The objective of this analysis is to determine BACT for the emissions from the auxiliary boiler. The small size and limited hours of operation (2,000 hours) for the auxiliary boiler greatly limits the amount of emissions that will be produced by this unit. The unit will fall under the guidelines of 40 CFR Part 60, Subpart Db, Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units. This section proposes control limits that meet or exceed the limits set forth in this regulation. 9.1 SO2 BACT Analysis This section presents the top-down, five-step BACT process used to evaluate and determine the Project’s SO2 emission limit for the 270 MBtu/h natural gas fired auxiliary boiler. 9.1.1 Step 1--Identify All Control Technologies The only potential control technology identified to limit SO2 emissions from an auxiliary boiler is fuel selection. Selecting a low sulfur fuel generates very low SO2 emissions. The auxiliary boiler proposes to burn natural gas; thus, the SO2 emissions will be negligible. 9.1.2 Step 2--Eliminate Technically Infeasible Options Fuel selection was the only control technology identified to limit SO2 emissions from the auxiliary boiler. There were no other SO2 control technologies identified for the Project’s 270 MBtu/h auxiliary boiler. 9.1.3 Step 3--Rank Remaining Control Technologies by Effectiveness A review of information contained in the USEPA BACT/LAER Clearinghouse (Attachment B) and other sources specified in Section 2.1 revealed that burning natural gas (low sulfur fuel) was identified as the top BACT control technology for auxiliary boilers. The results of the review indicate the following: • The lowest emission limit currently in place for an auxiliary boiler is 0.0006 lb/MBtu for three projects: the Wisconsin Public Service Weston Plant - Unit 4 (Permitted: October 2004), the Interstate Power and Light Emery Generating Station (Permitted: December 2002), and the MidAmerican Energy Company project located in Pottawattamie County (Permitted: June 2003). The only control technology that can be inferred from the projects is the utilization of natural gas (low sulfur fuel). 102607-145491 9-1 Interstate Power and Light Sutherland Unit 4 Air Permit Application 9.0 Auxiliary Boiler BACT Analysis 9.1.4 Step 4--Evaluate Most Effective Controls and Document Results In the following subsections, the technically feasible control alternatives are evaluated with respect to their energy, environmental, and economic impact to the auxiliary boiler. The only feasible control technology is low sulfur fuel. 9.1.4.1 Energy Evaluation of Alternatives. There are no significant energy impacts that would preclude the use of low sulfur fuel as the SO2 control technology as presented in this evaluation. 9.1.4.2 Environmental Evaluation of Alternatives. There are no significant environmental impacts that would preclude the use of low sulfur fuel as the SO2 control technology as presented in this evaluation. 9.1.4.3 Economic Evaluation of Alternatives. There are no significant economic impacts that would preclude the use of low sulfur fuel as the SO2 control technology as presented in this evaluation. 9.1.5 Step 5--Select SO2 BACT The proposed use of natural gas (low sulfur fuel) is the BACT for the auxiliary boiler. The estimated SO2 emission is 0.0006 lb/MBtu, which will be in compliance with the NSPS limit (Subpart Db). The value of 0.0006 lb/MBtu is the default SO2 emission rate prescribed by 40 CFR 75 Appendix D for the calculation of SO2 impacts utilizing natural gas in a boiler. 9.2 NOx BACT Analysis This section presents the top-down, five-step BACT process used to evaluate and determine the Project’s NOx emission limit for the 270 MBtu/h natural gas fired auxiliary boiler. 9.2.1 Step 1--Identify All Control Technologies As discussed in Section 4.0, NOx controls may be divided into two categories: combustion related NOx formation control and post-combustion emission reduction. Typically, NOx formation combustion control methods include LNB, OFA, gas reburn, and AGR. Post-combustion controls are flue gas treatments that reduce NOx after its formation. The post-combustion alternatives include SNCR and SCR. All postcombustion control technologies rely on the injection of a nitrogen compound (aqueous ammonia) into the flue gas to react with (and remove) NOx. 102607-145491 9-2 Interstate Power and Light Sutherland Unit 4 Air Permit Application 9.0 Auxiliary Boiler BACT Analysis 9.2.2 Step 2--Eliminate Technically Infeasible Options A review of the aforementioned NOx control technologies concluded that LNB, OFA, and SCR are the only technologies that are technically feasible as control technology alternatives for the Project’s 270 MBtu/h auxiliary boiler. Gas reburn, AGR, and SNCR technologies are not available for an auxiliary boiler; therefore, these options were determined to be technically infeasible. 9.2.3 Step 3 -- Rank Remaining Control Technologies by Effectiveness A review of information contained in the USEPA BACT/LAER Clearinghouse (Attachment B) and other sources specified in Section 2.1 revealed that good combustion practices, LNB, and gas recirculation were identified as the top BACT control technologies for auxiliary boilers burning natural gas. The results of the review indicated the following: • The lowest emission limit currently in place for an auxiliary boiler is 0.035 lb/MBtu for the Sempra Energy Resources Copper Mountain Power (Permitted: May 2004) located in Nevada. The control technology was listed as LNB with either internal or external flue gas recirculation. • The next lowest emission limit currently in place for an auxiliary boiler is 0.036 lb/MBtu for the Energetix Lawton Energy Cogen Facility (Permitted: December 2006). The control technology was listed as dryLNB. • The next lowest emission limit currently in place for an auxiliary boiler is 0.037 lb/MBtu for the Sierra Pacific Power Company Tracy Substation Expansion Project (Permitted: August 2005). The control technology was listed as best combustion practices. 9.2.4 Step 4--Evaluate Most Effective Controls and Document Results In the following subsections, the technically feasible control alternatives are evaluated in a comparative approach with respect to their energy, environmental, and economic impacts to the auxiliary boiler. 9.2.4.1 Energy Evaluation of Alternatives. All the control alternatives identified in Subsection 9.2.1 would have an adverse energy impact. However, there are no significant energy impacts that would preclude the use of good combustion practices and the burning of natural gas as NOx control technology as presented in this evaluation. 9.2.4.2 Environmental Evaluation of Alternatives. SCR and SNCR would have an adverse environmental impact. However, there are no significant environmental impacts that would preclude the use of good combustion practices and the burning of natural gas as NOx control technology as presented in this evaluation. 102607-145491 9-3 Interstate Power and Light Sutherland Unit 4 Air Permit Application 9.0 Auxiliary Boiler BACT Analysis 9.2.4.3 Economic Evaluation of Alternatives. All the control alternatives identified in Subsection 9.2.1 would have a negative economic impact. However, there are no significant economic impacts that would preclude the use of good combustion practices and the burning of natural gas as NOx control technology as presented in this evaluation. 9.2.5 Step 5--Select NOx BACT The proposed use of good combustion practices is BACT for the auxiliary boiler. The estimated NOx emission level supplied by the vendor is 0.037 lb/MBtu, which will be in compliance with the NSPS limit (Subpart Db). 9.3 PM/PM10 BACT Analysis This section presents the top-down, five-step BACT process used to evaluate and determine the Project’s PM/PM10 emission limit for the 270 MBtu/h natural gas fired auxiliary boiler. 9.3.1 Step 1--Identify All Control Technologies The following are the potential control technologies that can be used to limit PM from an auxiliary boiler: • Fuel selection. • Post-combustion particulate removal system. 9.3.1.1 Fuel Selection. The fuels typically burned in an auxiliary boiler are either distillate fuel oil or natural gas. IPL proposes to burn only natural gas, which is a very low PM/PM10 emitter. 9.3.1.2 Post-Combustion Particulate Removal Systems. The following postcombustion particulate removal systems have been identified to remove particulate on auxiliary boilers: • DESP. • Fabric filter. • WESP. Section 5.0 describes these particulate control technologies in more detail. 9.3.2 Step 2--Eliminate Technically Infeasible Options A review of the aforementioned PM/PM10 control technologies concludes that DESP, fabric filter, and WESP are technically feasible as control technology alternatives for the Project’s 270 MBtu/h auxiliary boiler that burns natural gas. 102607-145491 9-4 Interstate Power and Light Sutherland Unit 4 Air Permit Application 9.0 Auxiliary Boiler BACT Analysis 9.3.3 Step 3--Rank Remaining Control Technologies by Effectiveness A review of information contained in the USEPA BACT/LAER Clearinghouse (Attachment B) and other sources specified in Section 2.1 reveal that good combustion practices are identified as the top and only BACT control technologies utilized for auxiliary boilers burning natural gas. The results of this review indicated the following: • The lowest emission limit currently in place for an auxiliary boiler is 0.004 lb/MBtu for the Sierra Pacific Power Company Tracy Substation Expansion Project (Permitted: August 2005) located in Nevada. • The next lowest emission limit currently in place for an auxiliary boiler is 0.0075 lb/MBtu for two plants, which includes the Wisconsin Public Service Weston Plant - Unit 4 (Permitted: October 2004) and Interstate Power and Light Emergency Generating Station (Permitted: December 2002). • The next lowest permitted plant is the Mid-American Energy Company project located in Pottawattamie County in Iowa, which was permitted in June 2003 at 0.0076 lb/MBtu. 9.3.4 Step 4--Evaluate Most Effective Controls and Document Results In the following subsections, the technically feasible control alternatives are evaluated in a comparative approach with respect to their energy, environmental, and economic impacts to the auxiliary boiler. 9.3.4.1 Energy Evaluation of Alternatives. DESP, fabric filter, and WESP would all require additional auxiliary power; thus, they all would have an adverse energy impact. However, there are no significant energy impacts that would preclude the use of good combustion practices and the burning of natural gas as particulate control technology presented in this evaluation. 9.3.4.2 Environmental Evaluation of Alternatives. DESP, fabric filter, and WESP would all create additional waste; thus, they all would have an adverse environmental impact. There are no significant environmental impacts that would preclude the use of good combustion practices and the burning of natural gas as particulate control technology presented in this evaluation. 9.3.4.3 Economic Evaluation of Alternatives. DESP, fabric filter, and WESP would all represent a significant cost; thus, they all would have a negative economic impact. There are no significant economic impacts that would preclude the use of good combustion practices and the burning of natural gas as particulate control technology presented in this evaluation. 102607-145491 9-5 Interstate Power and Light Sutherland Unit 4 Air Permit Application 9.0 Auxiliary Boiler BACT Analysis 9.3.5 Step 5--Select PM/PM10 BACT The proposed use of good combustion practices and low sulfur fuel have been the only control measures used on these small boilers. Therefore, the proposed BACT for PM/PM10 is to ensure as complete fuel combustion as possible and to fire natural gas. The estimated PM/PM10 emission level supplied by the vendor is 0.007 lb/MBtu, which will be in compliance with the NSPS limit (Subpart Db). 9.4 CO BACT Analysis This section presents the top-down, five-step BACT process used to evaluate and determine the Project’s CO emission limit for the 270 MBtu/h natural gas fired auxiliary boiler. 9.4.1 Step 1--Identify All Control Technologies As discussed in Section 6.0 for the coal fired boiler BACT analysis, CO is formed during the combustion process because of incomplete oxidation of the carbon contained in the fuel. The auxiliary boiler has similar characteristics of a coal fired boiler in terms of CO production. CO control technologies identified are good combustion controls and oxidation catalysts. Good combustion controls are the optimization of the design, operation, and maintenance of the auxiliary boiler. The factors for good combustion include the air to fuel mixture, residence time, and optimum temperatures in the combustion chamber. As for oxidation catalysts, it converts CO in the flue gas to CO2 at temperatures ranging from 500º F to 700º F. 9.4.2 Step 2--Eliminate Technically Infeasible Options Based on a review of the aforementioned CO control technologies, it can be concluded that good combustion controls and oxidation catalysts are technically feasible as control technology alternatives for the Project’s 270 MBtu/h auxiliary boiler. However, the oxidation catalyst will not only oxidize CO, but will also oxidize a predominant portion of SO2 to SO3. The combination of this SO3 with moisture in the flue gas creates sulfuric acid, which can lead to a corrosive environment in the auxiliary boiler’s ductwork/stack. Table 9-1 provides a summary of Step 2--Eliminate Technically Infeasible Options. 102607-145491 9-6 Interstate Power and Light Sutherland Unit 4 Air Permit Application 9.0 Auxiliary Boiler BACT Analysis Table 9-1 Summary of Step 2--Eliminate Technically Infeasible Options Technology Alternative Technically Feasible (Yes/No) Good Combustion Controls Oxidation Catalyst Yes Yes 9.4.3 Step 3--Rank Remaining Control Technologies by Effectiveness A review of information contained in the USEPA BACT/LAER Clearinghouse (Attachment B) and other sources specified in Section 2.1 revealed that catalytic oxidation was identified as the top BACT control technology for auxiliary boilers burning natural gas. The results of the review indicated the following: • The lowest emission limit currently in place for an auxiliary boiler is 0.0164 lb/MBtu for the Interstate Power and Light Emery Generating Station (Permitted: December 2002) located in Iowa. The control technology was listed as catalytic oxidation. • The next lowest emission limit currently in place for an auxiliary boiler is 0.036 lb/MBtu for the Sempra Energy Resources Copper Mountain Power (Permitted: May 2004) located in Nevada. The control technology was listed as best combustion practices. • The next lowest emission limit currently in place for an auxiliary boiler is 0.08 lb/MBtu for the Wisconsin Public Service Weston Plant - Unit 4 (Permitted: October 2004). The control technology was listed as good combustion practices. It is important to note that the BACT determination of catalytic oxidation for the Emery Generating Station was apparently based on its extended usage of up to 6,000 hours per year. The auxiliary boiler for this Project is proposing to limit usage to no more than 2,000 hours per year. The intermittent operation of the Project’s auxiliary boiler is a consideration when considering the economic impact of catalytic oxidation versus good combustion practices. 9.4.4 Step 4--Evaluate Most Effective Controls and Document Results In the following sections, the technically feasible control alternatives are evaluated in a comparative approach with respect to their energy, environmental, and economic impacts to the auxiliary boiler. 102607-145491 9-7 Interstate Power and Light Sutherland Unit 4 Air Permit Application 9.0 Auxiliary Boiler BACT Analysis 9.4.4.1 Energy Evaluation of Alternatives. There are no significant energy impacts that would preclude the use of good combustion practices as CO control technology as presented in this evaluation. However, the catalytic oxidation system consumes electrical energy to overcome catalytic oxidation draft losses because of a pressure drop across the catalyst. While the energy costs of post-combustion CO control are real and quantifiable, they do not in and of themselves eliminate the control technology from further consideration. 9.4.4.2 Environmental Evaluation of Alternatives. There are no significant environmental impacts that would preclude the use of good combustion practices as CO control technology as presented in this evaluation. The oxidation catalysts will have an environmental impact because of the disposal waste that is generated from the spent catalyst. 9.4.4.3 Economic Evaluation of Alternatives. An economic evaluation and cost comparison of the technically feasible alternative control technologies identified in Subsection 9.4.3 (Step 3) are presented below for the following top control options: • Good combustion practices. • Catalytic oxidation. The cost estimates are based on budgetary quotes from equipment manufacturers and engineering cost estimates in accordance with the USEPA’s Office of Air Quality Planning and Standards (OAQPS) Control Cost Manual. Table 9-2 presents the total capital investment costs for the installation of a oxidation catalyst on the Project’s 270 MBtu/h natural gas fired auxiliary boiler. As described in the table, the purchased equipment costs include reactor housing and ductwork. The direct installation costs, which include balance-of-plant items such as foundations and supports, handling and erection, electrical, piping, insulation, and paint, were calculated as a percentage of the purchased equipment costs and totaled with the purchased equipment costs to estimate the total direct costs of each control alternative. Finally, the total capital investment is calculated as the summation of the total direct cost and total indirect costs (including engineering and owner’s cost) and an allowance for funds used during construction. No capital cost analysis is presented for good combustion controls, since it is inherent to the supply of the auxiliary boiler. 102607-145491 9-8 Interstate Power and Light Sutherland Unit 4 Air Permit Application 9.0 Auxiliary Boiler BACT Analysis Table 9-2 Auxiliary Boiler Catalytic Oxidation System Equipment Engineering Analysis - Cost Analysis IPL - Auxiliary Boiler Catalytic Oxidation System Engineering Analysis - Cost Analysis Sutherland Generating Station Technology: Catalytic Oxidation Cost Item Date: 6/29/2007 $ Remarks/Cost Basis CAPITAL COST Direct Costs Purchased equipment costs Reactor housing Initial catalyst Flue gas handling: ductwork and fans Subtotal capital cost (CC) Taxes Freight Total purchased equipment cost (PEC) $412,000 $53,000 $424,000 $889,000 $62,000 $44,000 $995,000 Engineering estimate Engineering estimate Engineering estimate (CC) X (CC) X 7.0% 5.0% Direct installation costs Foundation & supports Handling & erection Electrical Piping Insulation Painting Demolition Relocation Total direct installation costs (DIC) $149,000 $149,000 $100,000 $25,000 $100,000 $10,000 $0 $0 $533,000 (PEC) X (PEC) X (PEC) X (PEC) X (PEC) X (PEC) X (PEC) X (PEC) X 15.0% 15.0% 10.0% 2.5% 10.0% 1.0% 0.00% 0.00% Site preparation Buildings Total direct costs (DC) = (PEC) + (DIC) Indirect Costs Engineering Construction and field expenses Owner's cost Start-up Performance test Contingencies Total indirect costs (IC) Allowance for Funds Used During Construction (AFDC) Total Capital Investment (TCI) = (DC) + (IC) $50,000 $25,000 $1,603,000 $192,000 $80,000 $160,000 $48,000 $8,000 $240,000 $728,000 $96,000 $10,000 $48,000 $5,000 $63,000 Variable annual costs Auxiliary and ID fan power Catalyst replacement Catalyst disposal Total variable annual costs $46,000 $11,000 $30 $57,030 12.0% 5.0% 10.0% 3.0% 0.5% 15.0% [(DC)+(IC)] X 8.20% 1 year(s) 0.1 FTE and (DC) X 3.0% Engineering estimate 99 kW and 9,600 lb and 100,000 $/year 0.06 $/kWh 6 $/ton Estimated manpower level Engineering estimate 5 yr catalyst replacement rate 5 yr catalyst replacement rate $120,030 Indirect Annual Costs Cost for capital recovery Total indirect annual costs (IDAC) $229,000 $229,000 Total Annual Cost (TAC) = (DAC) + (IDAC) $349,000 102607-145491 (DC) X (DC) X (DC) X (DC) X (DC) X (DC) X $2,427,000 ANNUAL COST Direct Annual Costs Fixed annual costs Operating labor Maintenance labor & materials Catalyst activity testing Total fixed annual costs Total direct annual costs (DAC) Engineering estimate Engineering estimate (TCI) X 9.44% CRF at 7% interest & 20 year life 9-9 Interstate Power and Light Sutherland Unit 4 Air Permit Application 9.0 Auxiliary Boiler BACT Analysis Table 9-2 also presents the annualized operating costs for the installation of a oxidation catalyst system on the Project’s 270 MBtu/h natural gas fired auxiliary boiler. As described in the table, the operating fixed and variable direct annual costs include operating and support labor, maintenance labor and materials, and various testing and sampling costs. The indirect annual costs, which include the capital recovery costs, is totaled with the direct annual costs to estimate the total annual cost for the control system. No annual cost analysis is presented for good combustion controls, since it is inherent to the supply of the auxiliary boiler. 9.4.5 Step 5--Select CO BACT Table 9-3 summarizes the top-down evaluation of the CO control alternatives, including economic, energy, and environmental considerations, in accordance with the BACT determination methodology previously discussed. As Table 9-3 illustrates, the selected BACT CO control technology is not the top-ranked control alternative, which consists of catalytic oxidation and an associated emission limit of 0.0164 lb/MBtu. However, the total capital and annualized costs of catalytic oxidation on a limited use auxiliary boiler are considered cost-prohibitive. IPL has determined that good combustion practices represent CO BACT for the Project’s 270 MBtu/h natural gas fired auxiliary boiler. The CO emission level supplied by the vendor is 0.074 lb/MBtu. 9.5 VOC BACT Analysis This section presents the top-down, five-step BACT process used to evaluate and determine the Project’s VOC emissions limit for the 270 MBtu/h natural gas fired auxiliary boiler. 9.5.1 Step 1--Identify All Control Technologies As discussed in Section 6.0 for the coal fired boiler BACT analysis, VOCs are formed during the combustion process because of incomplete oxidation of the carbon contained in the fuel. The auxiliary boiler has similar characteristics of a coal fired boiler in terms of VOC production. The VOC control technologies identified are good combustion controls and oxidation catalysts. 102607-145491 9-10 Interstate Power and Light Sutherland Unit 4 Air Permit Application 9.0 Auxiliary Boiler BACT Analysis Table 9-3 Carbon Monoxide/Volatile Organic Compounds Top-Down BACT Summary Emissions Emissions, lb/h Emissions Reduction, tpy Total Capital Cost, $1,000 Total Annualized Cost, $1,000/yr Control CostEffectiveness, $/ton Oxidation Catalyst (0.0164 lb/MBtu) 4.4 68.2 2,427 349 5,123 Uncontrolled Baseline 20 -- -- -- -- Control Alternative 102607-145491 Energy Impacts Economic Impacts Incremental CostEffectiveness, $/ton -- Environmental Impacts Incremental Increase Over Baseline, kWh/yr Toxic Impacts (Yes/No) Adverse Environmental Impacts (Yes/No) 0 No No -- -- -- 9-11 Interstate Power and Light Sutherland Unit 4 Air Permit Application 9.0 Auxiliary Boiler BACT Analysis 9.5.2 Step 2--Eliminate Technically Infeasible Options Based on a review of the aforementioned VOC control technologies, it can be concluded that good combustion controls and oxidation catalysts are technically feasible as control technology alternatives for the Project’s 270 MBtu/h auxiliary boiler. However, the oxidation catalyst will not only oxidize VOC, but will also oxidize a predominant portion of SO2 to SO3. Combination of this SO3 with moisture in the flue gas creates sulfuric acid that could lead to a corrosive environment in the auxiliary boiler’s ductwork/stack. 9.5.3 Step 3--Rank Remaining Control Technologies by Effectiveness A review of information contained in the USEPA BACT/LAER Clearinghouse (Attachment B) and other sources specified in Section 2.1 revealed that good combustion practices was identified as the top BACT control technology for auxiliary boilers burning natural gas. The results of the review indicated the following: • The lowest emission limit currently in place for an auxiliary boiler is 0.005 lb/MBtu for the Sierra Pacific Power Company Tracy Substation Expansion Project (Permitted: August 2005). The control technology was listed as best combustion practices. • The next lowest emission limits currently in place for an auxiliary boiler are 0.0054 lb/MBtu for two projects, which include the Wisconsin Public Service Weston Plant - Unit 4 (Permitted: October 2004) and the Interstate Power and Light Emery Generating Station (Permitted: December 2002). The control technology listed for both projects was best combustion practices. 9.5.4 Step 4--Evaluate Most Effective Controls and Document Results In the following subsections, the technically feasible control alternatives are evaluated in a comparative approach with respect to their energy, environmental, and economic impacts to the auxiliary boiler. 9.5.4.1 Energy Evaluation of Alternatives. There are no significant energy impacts that would preclude the use of good combustion practices as VOC control technology as presented in this evaluation. However, the catalytic oxidation system consumes electrical energy to overcome catalytic oxidation draft losses because of a pressure drop across the catalyst. While the energy costs of post-combustion VOC control are real and quantifiable, they do not in and of themselves eliminate the control technology from further consideration. 102607-145491 9-12 Interstate Power and Light Sutherland Unit 4 Air Permit Application 9.0 Auxiliary Boiler BACT Analysis 9.5.4.2 Environmental Evaluation of Alternatives. There are no significant environmental impacts that would preclude the use of good combustion practices as VOC control technology as presented in this evaluation. The oxidation catalyst control alternative would have an environmental impact because of the disposal waste that is generated from the spent catalyst. 9.5.4.3 Economic Evaluation of Alternatives. An economic evaluation and cost comparison of the technically feasible alternative control technologies identified in Subsection 9.4.3 (Step 3) are presented below for the following top control options: • Good combustion practices. • Catalytic oxidation. The cost estimates are based on budgetary quotes from equipment manufacturers and engineering cost estimates in accordance with USEPA’s Office of Air Quality Planning and Standards (OAQPS) Control Cost Manual. The costs and economic impacts for CO and VOC control are identical for the auxiliary boiler. Therefore, Table 9-1, which contains the total capital investment and total annual costs for catalytic oxidation, are not repeated in this section. Refer to Subsection 9.4.4.3 of this report. 9.5.5 Step 5--Select VOC BACT IPL has determined that the top control of good combustion practices represents VOC BACT for the Project’s 270 MBtu/h natural gas fired auxiliary boiler. The estimated VOC emission level supplied by the vendor is 0.005 lb/MBtu. Table 9-3 summarizes the top-down evaluation of the VOC control alternatives, including economic, energy, and environmental considerations, in accordance with the BACT determination methodology previously discussed. 102607-145491 9-13 Interstate Power and Light Sutherland Unit 4 Air Permit Application 10.0 Emergency Generator and Fire Pumps BACT Analysis 10.0 Emergency Generator and Fire Pumps BACT Analysis In the event of the loss of normal auxiliary power, ac power will be supplied by a new 2,937 bhp, 2,000 kW, No. 2 fuel oil fired emergency generator. Additionally, a new emergency fire pump and fire booster pump will supply emergency fire water to the Project using 575 and 149 bhp diesel engines, respectively. The emergency generator and fire pumps will be periodically tested for no more than 1 to 2 hours per week (100 h/y) to confirm its ready-to-start condition. Because of their small size, infrequent operation, and status as emergency equipment, the installation of post-combustion emission controls such as SCR and SNCR for NOx, or FGD systems for SO2, or oxidation catalyst for CO, while technically feasible for emergency generators and fire pumps, are far from cost-effective as control devices and are therefore not practical as BACT control alternatives. As such, IPL has determined that BACT for the emergency generator and fire pumps is limited operation and good combustion controls while firing low sulfur (0.05 percent) distillate fuel oil based on manufacturer’s emission estimates presented in Appendix F. The proposed BACT determinations have no adverse environmental or energy impacts and are summarized below for each pollutant. 10.1 Select SO2 BACT The emergency generator and fire pumps will emit small quantities of SO2 as a result of the oxidation of sulfur in the fuel. A review of the informational databases discussed in Section 2.1 indicated that low sulfur distillate fuel oil is the most stringent permitted control for similar types of units operated in the manner proposed by IPL. No post-combustion FGD system has ever been applied to a generator/fire pump this small that is firing a low sulfur oil. Therefore, low sulfur fuel oil (containing less than 0.05 percent sulfur) is proposed as the BACT. The BACT control is good combustion control and low sulfur fuel oil. 10.2 Select NOx BACT A review of the information contained in the RBLC indicated the following: • The most stringent NOx emission limit permitted for a small diesel generator is the Duke Energy Field Services, LP, Mooreland Cryogenic Plant located in Oklahoma. The emission limit is 2.0 g/bhph (approximately 0.0059 lb/kW). 102607-145491 10-1 Interstate Power and Light Sutherland Unit 4 Air Permit Application 10.0 Emergency Generator and Fire Pumps BACT Analysis • The next most stringent NOx emission limit permitted for a small diesel generator is the Arizona Clean Fuel Yuma, LLC, located in Arizona. The emission limit is 4.0 g/bhph (approximately 0.012 lb/kW). Further review of the informational databases discussed in Section 2.1 indicated that emergency generators and fire pumps have not been required to install additional NOx controls because their operation is of an intermittent nature. As discussed in Subsection 2.1.1.4, the engines must meet the applicable NSPS, which will apply depending on the year of engine manufacture. The proposed BACT levels for NOx presented in Table 1-1 are based on the estimated emission levels supplied by vendors, which will be in compliance with the NSPS limit. The BACT control is good combustion control. 10.3 Select PM/PM10 BACT A review of the information contained in the RBLC indicated the following: • The most stringent PM/PM10 emission limit permitted for an internal combustion engine firing fuel oil to date is a requirement equivalent to 0.07 g/bhph (approximately 0.00021 lb/kWh) for the Ace Ethanol, LLC, Stanley Plant (1.38 MW unit), located in Wisconsin. The control technology for this unit is complete combustion. • The next most stringent PM/PM10 emission limit permitted for an internal combustion engine firing fuel oil to date is a requirement equivalent to 0.2 g/bhph (approximately 0.00059 lb/kWh) for the Arizona Clean Fuels Yuma, LLC (1.60 MW unit), located in Arizona. The control technology for this unit is complete combustion. The emergency generator and fire pumps will emit small quantities of particulates consisting of ash in the fuel and residual carbon and hydrocarbons caused from incomplete combustion. A review of the informational databases discussed in Section 2.1 indicated that good combustion control was the most stringent control permitted for similar units. Therefore, because of the very low operating hours of the emergency generator and fire pumps, good combustion control and engine design are proposed as BACT. As discussed in Subsection 2.1.1.4, the engines must meet the applicable NSPS, which will depend on the year of engine manufacture. The proposed BACT levels presented in Table 1-1 are based on the estimated emissions level supplied by vendors, which will be in compliance with the NSPS limit. The BACT control is good combustion control. 102607-145491 10-2 Interstate Power and Light Sutherland Unit 4 Air Permit Application 10.4 10.0 Emergency Generator and Fire Pumps BACT Analysis Select CO BACT A review of the information contained in the RBLC indicated the following: • The units with the most stringent CO emission limit permitted for a small diesel generator are the Okemo Mountain Inc. Mill River Lumber and the Sithe Mystic facilities. These facilities are in nonattainment areas where higher removal standards exist. The emission limit for these sites is 0.6 g/bhph (approximately 0.0018 lb/kWh). • The next most stringent CO emission limit for a small diesel generator is the Ace Ethanol, LLC, Stanley Plant located in Wisconsin. The emission limit for this site is 1 g/bhph (approximately 0.003 lb/kWh). The control technologies for CO emissions evaluated for use on the emergency generator and fire pumps are catalytic oxidation and proper design to minimize emissions. Because of the intermittent operation and low emissions, add-on controls would be prohibitively expensive. Thus, good combustion control is proposed as BACT for controlling the CO emissions from the emergency generator. As discussed in Subsection 2.1.1.4, the engines must meet the NSPS that will apply, depending on the year of engine manufacture. The proposed BACT levels for CO presented in Table 1-1 are based on the estimated emissions level supplied by vendors, which will be in compliance with the NSPS limit. The BACT control is good combustion control. 10.5 Select VOC BACT A review of the information contained in the RBLC indicated the following: • The unit with the most stringent VOC emission limit for a small diesel generator is the Ace Ethanol, LLC, Stanley Plant located in Wisconsin. The emission limit for this site is 0.120 g/bhph (approximately 0.00035 lb/kWh). The control technologies for VOC emissions evaluated for use on the emergency generator and fire pumps are catalytic oxidation and proper engine design to minimize emissions. Because of the intermittent operation and low emissions, add-on controls would be prohibitively expensive. Thus, good combustion control is proposed as BACT for controlling the VOC emissions from the emergency generator and fire pumps. As discussed in Subsection 2.1.1.4, the engines must meet the applicable NSPS, which will depend on the year of engine manufacture. The proposed BACT levels for VOC presented in Table 1-1 are based on the estimated emission level supplied by vendors, which will be in compliance with the NSPS limit. The BACT control is good combustion control. 102607-145491 10-3 Interstate Power and Light Sutherland Unit 4 Air Permit Application 10.6 10.0 Emergency Generator and Fire Pumps BACT Analysis Select H2SO4 BACT The emergency generator and fire pumps will emit small quantities H2SO2 as a result of the oxidation of SO2 in the exhaust. A review of the informational databases discussed in Section 2.1 indicated that low sulfur distillate fuel oil was the most stringent permitted control for similar types of units. Therefore, low sulfur fuel oil (containing less than 0.05 percent sulfur) is proposed as BACT. The BACT control is good combustion control and low sulfur fuel oil. 102607-145491 10-4 Interstate Power and Light Sutherland Unit 4 Air Permit Application 11.0 Gate Station Heater BACT Analysis 11.0 Gate Station Heater BACT Analysis The gate station heater receives high-pressure natural gas from a single interface point for the natural gas supply system. As the natural gas is extracted from the high pressure pipeline across a pressure reducing control valve, the reduction in pressure will naturally cool the gas below the dew point temperature and to a temperature too low to be combusted in the boilers. As such, a natural gas fired gate station heater will be used to heat the natural gas upstream of the pressure reducing device to prevent the gas from dropping below the recommended operating temperature. The gate station heater will have a maximum heat input limit of 3 MBtu/h and designed for continuous operation. Because of its small size, the installation of postcombustion emission controls, such as SCR and SNCR for NOx, or FGD systems for SO2, or oxidation catalyst for CO, while technically feasible for the gate state heater, are far from cost-effective as control devices and are therefore not practical as BACT control alternatives. As such, IPL has determined that BACT for the gate station heater, which is similar to a process heater, is good combustion controls while firing low sulfur pipeline natural gas. The proposed BACT determinations have no adverse environmental or energy impacts and are summarized below for each pollutant. 11.1 Select SO2 BACT The gate station heater will emit small quantities of SO2 as a result of the oxidation of sulfur in the fuel. A review of the informational databases discussed in Section 2.1 indicated that low sulfur pipeline natural gas is the most stringent permitted control for similar types of units operated in the manner proposed by IPL. No postcombustion FGD system has ever been applied to a gate station heater or process heater this small that is firing low sulfur pipeline natural gas. Therefore, low sulfur pipeline natural gas is proposed as the BACT. The BACT control is good combustion control and low sulfur pipeline natural gas. 11.2 Select NOx BACT A review of the information contained in the RBLC indicated the following: • The most stringent NOx emission limit permitted for a gate station heater is the Wisconsin Public Service, Weston Plant located in Wisconsin. The emission limit is 0.024 lb/MBtu for a 0.75 MBtu/h natural gas gate station heater. Firing natural gas is documented as the control technology. 102607-145491 11-1 Interstate Power and Light Sutherland Unit 4 Air Permit Application • 11.0 Gate Station Heater BACT Analysis The next most stringent NOx emission limit permitted for a small natural gas heater is the Interstate Power and Light, Emery Generating Station located in Iowa. The emission limit is 0.0490 lb/MBtu for a 9.0 MBtu/h natural gas heater. LNB is documented as the control technology. • The next most stringent NOx emission limit permitted for a small natural gas heater is Cresent City Power, LLC, located in Louisiana. The emission limit is 0.095 lb/MBtu for a 19.0 MBtu/h natural gas heater. LNB and good combustion practices are documented as the control technology. Further review of the informational databases discussed in Section 2.1 indicated that gate station heaters or small process heaters have not been required to install additional NOx controls because of their size. The proposed BACT levels for NOx presented in Table 1-1 are based on the estimated emission levels supplied by vendors. The BACT control is LNB and good combustion control. 11.3 Select PM/PM10 BACT A review of the information contained in the RBLC indicated the following: • The most stringent PM/PM10 emission limit permitted for a gate station heater is the Wisconsin Public Service, Weston Plant located in Wisconsin. The emission limit is 0.0033 lb/MBtu for a 0.75 MBtu/h natural gas gate station heater. Firing natural gas is documented as the control technology. • The next most stringent PM/PM10 emission limit permitted for a small natural gas heater is Cresent City Power, LLC, located in Louisiana. The emission limit is 0.007 lb/MBtu for a 19.0 MBtu/h natural gas heater. Firing natural gas and good combustion practices are documented as the control technology. • The next most stringent PM/PM10 emission limit permitted for a small natural gas heater is the Interstate Power and Light, Emery Generating Station located in Iowa. The emission limit is 0.0075 lb/MBtu for a 9.0 MBtu/h natural gas heater. Firing natural gas is documented as the control technology. The gate station heater will emit very small quantities of particulates from burning pipeline natural gas. A review of the informational databases discussed in Section 2.1 indicated that firing pipeline natural gas was the most stringent control permitted for similar units. Therefore, the proposed BACT control is pipeline natural gas and good combustion controls. 102607-145491 11-2 Interstate Power and Light Sutherland Unit 4 Air Permit Application 11.4 11.0 Gate Station Heater BACT Analysis Select CO BACT A review of the information contained in the RBLC indicated the following: • The most stringent CO emission limit permitted for a gate station heater is the Wisconsin Public Service, Weston Plant located in Wisconsin. The emission limit is 0.02 lb/MBtu for a 0.75 MBtu/h natural gas gate station heater. Firing natural gas is documented as the control technology. • The next most stringent CO emission limit permitted for a small natural gas heater is Cresent City Power, LLC, located in Louisiana. The emission limit is 0.08 lb/MBtu for a 19.0 MBtu/h natural gas heater. Good combustion practices is documented as the control technology. • The next most stringent CO emission limit permitted for a small natural gas heater is the Interstate Power and Light, Emery Generating Station located in Iowa. The emission limit is 0.082 lb/MBtu for a 9.0 MBtu/h natural gas heater. Good combustion practices is documented as the control technology. Further review of the informational databases discussed in Section 2.1 indicated that gate station heaters or small process heaters have not been required to install additional CO controls because of their size and because it would be prohibitively expensive. The proposed BACT levels for CO presented in Table 1-1 are based on the estimated emission levels supplied by vendors. The BACT control is good combustion control. 11.5 Select VOC BACT A review of the information contained in the RBLC indicated the following: • The most stringent VOC emission limit permitted for a gate station heater is the Wisconsin Public Service, Weston Plant located in Wisconsin. The emission limit is 0.0013 lb/MBtu for a 0.75 MBtu/h natural gas gate station heater. Firing natural gas is documented as the control technology. • The next most stringent VOC emission limit permitted for a small natural gas heater is Cresent City Power, LLC, located in Louisiana. The emission limit is 0.005 lb/MBtu for a 19.0 MBtu/h natural gas heater. Good combustion practices is documented as the control technology. • The next most stringent VOC emission limit permitted for a small natural gas heater is the Interstate Power and Light, Emery Generating Station located in Iowa. The emission limit is 0.0054 lb/MBtu for a 9.0 MBtu/h natural gas heater. Good combustion practices is documented as the control technology. 102607-145491 11-3 Interstate Power and Light Sutherland Unit 4 Air Permit Application 11.0 Gate Station Heater BACT Analysis Further review of the informational databases discussed in Section 2.1 indicated that gate station heaters or small process heaters have not been required to install additional VOC controls because of their size and because it would be prohibitively expensive. The proposed BACT levels for VOC presented in Table 1-1 are based on the estimated emission levels supplied by vendors. The BACT control is good combustion control. 11.6 Select H2SO4 BACT The gate station heater will emit small quantities of H2SO2 as a result of the oxidation of SO2 in the exhaust. A review of the informational databases discussed in Section 2.1 indicated that low sulfur pipeline natural gas is the most stringent permitted control for similar types of units operated in the manner proposed by IPL. Therefore, low sulfur pipeline natural gas is proposed as the BACT. The BACT control is good combustion control and low sulfur pipeline natural gas. 102607-145491 11-4 Interstate Power and Light Sutherland Unit 4 Air Permit Application 12.0 Cooling Tower BACT Analysis 12.0 Cooling Tower BACT Analysis A new multicell linear mechanical draft cooling tower will be used to dissipate heat from the condensing water of the Project’s main boiler. 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. 12.1 Step 1--Identify All Control Technologies 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. 12.2 Step 2--Eliminate Technically Infeasible Options A review of drift eliminators as particulate control technology for cooling towers concluded that they are technically feasible for the specific type of application discussed in Section 11.1. In addition, drift eliminators were the only control technology identified as technically feasible. 12.3 Step 3--Rank Remaining Control Technologies by Effectiveness A review of information contained in the USEPA BACT/LAER Clearinghouse and other sources specified in Section 2.1 revealed that drift eliminators are most frequently identified as the top BACT control technologies for cooling towers. The results of this review indicate the following: • The lowest emission limit currently in place for a utility sized cooling tower is 0.0005 percent drift for a variety of plants, including the Newmont Mining Corporation TS Power Plant located in Nevada (Permitted: May 2005), the Omaha Public Power District Nebraska City Station located in Nebraska (Permitted: March 2005), the Mustang 102607-145491 12-1 Interstate Power and Light Sutherland Unit 4 Air Permit Application 12.0 Cooling Tower BACT Analysis Energy Project located in Oklahoma (Permitted: February 2002), the Wallula Power Plant located in Washington (Permitted: October 2002), and the Rocky Mountain Power Project located in Colorado (Permitted: August 2002). 12.4 • The lowest permitted plant in Iowa is the Mid-American Energy Company project located in Pottawattamie County, which was permitted in June of 2003 at 0.0005 percent drift. • The Longview Project in West Virginia and the Weston Unit 4 project in Wisconsin have been permitted at a drift rate of 0.002 percent. • The Duke Energy Satsop Combustion Turbine Project in Grays Harbor County, Washington, and the Cornbelt Plant in Illinois have been permitted at a drift rate of 0.001 percent. Step 4--Evaluate Most Effective Controls and Document Results In the following subsections, the technically feasible control alternatives are evaluated in a comparative approach with respect to their energy, environmental, and economic impacts to the Project. 12.4.1 Energy Evaluation of Alternatives There are no significant energy impacts that would preclude the use of drift eliminators as particulate control technologies as presented in this evaluation. 12.4.2 Environmental Evaluation of Alternatives There are no significant environmental impacts that would preclude the use of drift eliminators as particulate control technologies as presented in this evaluation. 12.4.3 Economic Evaluation of Alternatives There are no significant economic impacts that would preclude the use of drift eliminators as particulate control technologies as presented in this evaluation. 12.5 Step 5--Select BACT 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. 102607-145491 12-2 Interstate Power and Light Sutherland Unit 4 Air Permit Application 13.0 Material Handling Systems BACT Analysis 13.0 Material Handling Systems BACT Analysis This section presents the top-down, five-step BACT process used to evaluate and determine the Project’s particulate emission controls for the material handling systems used to store and convey coal, limestone, fly ash, and biomass. Many of the material handling system components subject to particulate BACT review are described below. 13.1 Coal Handling The function of the coal handling system is to receive and unload coal delivered by rail cars; provide a means to stock out and store the coal in active and reserve storage piles; provide the means to reclaim, blend, and crush the coal to the desired size; and supply the coal to the Unit 4 silos to satisfy plant usage requirements. The coal handling system will also be sized to serve existing Units 1, 2, and 3 by providing a separate stockout facility to store coal unloaded by the Unit 4 unloading facility and to provide a separate reclaim facility to reclaim coal designated for Units 1, 2, and 3. Coal will be delivered to the facility by unit train consisting of approximately 150 cars. Each of the rail cars will carry approximately 120 tons of coal. The coal received in the plant will be unloaded by a rotary car dumper. The rotary car dumper will be equipped with a rail car positioner, hopper, grizzly, and traveling hammermill for the breaking of oversize and frozen coal. The unloaded coal will be collected by a hopper and withdrawn by two belt feeders (BF-1 and BF-2). A dust suppression system (DS-1) will control dust at BF-1 and BF-2, as well as Conveyor BC-1 loading points. A dust collection system (DC) will control dust in the dumper building above the unloading hopper. The coal will be transferred from the feeders to unloading Conveyor BC-1, which will take it to a transfer tower (TT-1). At TT-1, the coal will be directed to BC-4, which feeds the stacker/reclaimer (SR-1). Under normal operating conditions, the unloaded coal will be stacked out by Stacker/Reclaimer SR-1. During reclaiming, the boom conveyor of Stacker/Reclaimer SR-1 will be reversed to support reclaim onto BC-4. In case of a Stacker/Reclaimer SR-1 failure, the unloaded coal will be stacked out by an emergency stacking conveyor, BC-2, equipped with a telescopic chute (CHE-1) and spray ring for dust suppression. Depending on operating requirements, the coal from the emergency pile may be bulldozed directly into the yard storage or to the reclaim hopper (RH-1) and fed onto Reclaim Conveyor BC-3 for stacking by SR-1 or sent directly to the plant as required. Coal for existing Units 1, 2, and 3 will be fed from Reclaim Hoppers RH-4 and RH-5 onto a belt conveyor (BC-5A). Belt Conveyor BC-5A will discharge onto Belt Conveyor 102607-145491 13-1 Interstate Power and Light Sutherland Unit 4 Air Permit Application 13.0 Material Handling Systems BACT Analysis BC-5B, at Transfer Tower TT-3. Conveyor BC-5B will deliver coal to a new hopper, HPR-2, located over the existing hopper in the existing coal handling system for Units 1, 2, and 3. A side discharge chute and gate will be used to load coal trucks in an enclosed structure and DC. At the discharge point of Belt Conveyor BC-4, the coal will be directed through a three-way flow diverting flop gate to allow the coal to be sent directly to the crushers or onto Belt Conveyor BC-6 or Belt Conveyor BC-7 and stockpiled for blending during reclaiming operations. Coal directed onto Belt Conveyor BC-6 will be stockpiled using a telescopic chute (CHE-2) and reclaimed through an under-pile reclaim hopper (RH-2) onto reclaim Belt Conveyor BC-8. Belt conveyor BC-8 will discharge into a flow splitting gate; coal is directed simultaneously to both Belt Conveyors BC-10 and BC-11 for crushing. Coal directed onto Belt Conveyor BC-7 will be stockpiled using Telescopic Chute CHE-3 and reclaimed through an under-pile reclaim hopper (RH-3) onto the reclaim Belt Conveyor BC-9. Belt Conveyor BC-9 will discharge into a flow splitting gate to provide blending capability with coal from either BC-4 or BC-8. Belt Conveyors BC-10 and BC-11 will feed coal to the crusher surge bin (SB-1) located inside the crusher house (CH-1). Coal will be discharged from the crusher surge bin outlets to feed two ring granulator crushers (CR-1 and CR-2). The crusher house will contain a DC. Plant Conveyors BC-12 and BC-13 will deliver crushed coal from Crusher House CH-1 to Transfer Tower TT-4. The discharge chutework of Conveyors BC-12 and BC-13 will be provided with motorized flop gates to provide complete crossover redundancy to feed either of the two tripper conveyors (BC-14 and BC-15). Tripper Conveyors BC-14 and BC-15 will deliver coal to a traveling tripper--Conveyor BC-14 to Traveling Tripper TRP-1 and Conveyor BC-15 to Traveling Tripper TRP-2. Each traveling tripper will be equipped with a single discharge chute and will deliver coal to any selected plant silo. A DC will provide dust control in Transfer Tower TT-4 and the coal silos. The following is a summary of the new coal handling equipment that is subject to a particulate BACT review for the Project: • Coal Unloading--Rotary Car Dumper (DPR-1). • Coal Receiving--Belt Conveyor (BC-1). • Transfer Tower (TT-1). • Emergency Stockout--Belt Conveyor (BC-2). • Emergency Stockout Reclaim--Belt Conveyor (BC-3). • Stacker/Reclaimer Conveyor--Belt Conveyor (BC-4). • Stack/Reclaimer (SR-1). 102607-145491 13-2 Interstate Power and Light Sutherland Unit 4 Air Permit Application 13.0 Material Handling Systems BACT Analysis • Transfer Tower (TT-2). • Exiting Units Reclaim--Belt Conveyor (BC-5A). • Transfer Tower (TT-3). • Existing Units Feed--Belt Conveyor (BC-5B). • Truck Loadout. • Pile Stockout--Belt Conveyor (BC-6). • Pile Stockout--Belt Conveyor (BC-7). • Pile Reclaim--Belt Conveyor (BC-8). • Pile Reclaim--Belt Conveyor (BC-9). • Crusher Feed--Belt Conveyors (BC-10 and 11). • Crusher House (CH-1). • Plant Feed (SGS Unit 4)--Belt Conveyors (BC-12 and 13). • Tripper Conveyors--Belt Conveyors (BC-14 and 15). • Transfer Tower (TT-4). 13.2 Limestone Handling The function of the limestone handling system is to receive bulk limestone by bottom dump hopper rail cars (or, alternatively, by truck) to provide a means to stock out and store the limestone in an active storage pile and to provide reclaim capacity to satisfy plant usage requirements. Bulk limestone will be delivered by either bottom dump hopper rail cars or dump trucks and will be unloaded into the limestone unloading hopper, HPR-1. Belt Feeders FDR-1 and 2 will receive limestone from the unloading hopper outlets and transfer it to the receiving conveyor, CVY-1, which will transfer the material to the limestone storage pile through a telescopic chute, CHE-1, with wet suppression. The conical shaped limestone storage pile will be enclosed by a covered steel structure to protect the limestone from the weather. The limestone will be reclaimed from the storage pile by two underground belt feeders located below the vibrating drawdown hoppers, which will feed Reclaim Conveyor CVY-2. The reclaim conveyor will transfer the limestone to the distribution/silo fill conveyor (CVY-3). This conveyor will have a two-way chute with motorized diverter gate to fill each of two limestone silos equipped with fabric filter bin vents. The following is a summary of the limestone material handling equipment that is subject to a particulate BACT review for the Project: • Limestone Unloading--Railcar/Truck Bottom Dumper. • Limestone Receiving/Stockout--Belt Conveyor (CVY-1). 102607-145491 13-3 Interstate Power and Light Sutherland Unit 4 Air Permit Application 13.3 • Limestone Reclaim--Belt Conveyor (CVY-2). • Distribution Conveyor--Belt Conveyor (CVY-3). • Two Limestone Storage Silos. 13.0 Material Handling Systems BACT Analysis Fly Ash Handling The fly ash handling system is composed of two separate systems: saleable and waste. The saleable fly ash handling system removes fly ash from the DESP hoppers and transfers it to a saleable fly ash storage silo or a winter fly ash storage building via a continuously operating pneumatic vacuum and vacuum/pressure conveying system. The waste fly ash handling system removes fly ash from the fabric filter hoppers, air heater hoppers, SCR hoppers, and economizer hoppers and transfers it via a continuously operating pneumatic vacuum conveying system to a fly ash waste storage silo. Fly ash from the saleable storage silo will be loaded into closed ash hauling trucks or railcars for offsite sales, or conditioned and loaded into open dump trucks for placement in a landfill via a dry telescoping spout. The winter saleable fly ash storage building will be equipped with a pressurized conveying system to convey ash from the DESP vacuum filter/separator hopper to the building. A mechanical conveying system will transfer ash from the recovery hopper to a truck loadout system. Dust collection and ash return equipment will be included to keep the building under negative pressure. Fly ash from the waste storage silo will be conditioned and loaded into open dump trucks for placement in a landfill. The fly ash waste silo will also be equipped with a dry telescoping spout for loading into closed ash hauling trucks. The following sections provide detailed descriptions of the two fly ash handling systems. 13.4 Saleable Fly Ash Handling System The saleable fly ash handling system will service all unit DESP hoppers, one saleable fly ash storage silo, and one fly ash winter storage building. Each collection point in the fly ash handling system will be tied into a sealed, pneumatic vacuum conveying system. The conveying system will sequentially remove fly ash from the DESP hoppers and transfer the material to either the saleable fly ash storage silo or the winter storage building via a pressure conveying system. Two vacuum filter/separators located on top of the saleable fly ash storage silo will receive and transfer the material to the saleable fly ash storage silo via a double dump airlock valve. A third vacuum filter/separator, located at ground level next to the winter storage building, will receive and transfer the ash into the winter storage building via a pressure pneumatic conveying system for future recovery into dry ash trucks. Each 102607-145491 13-4 Interstate Power and Light Sutherland Unit 4 Air Permit Application 13.0 Material Handling Systems BACT Analysis vacuum filter/separator on the saleable fly ash silo will consist of a continuous operating filter section with filter bags, a pulse jet filter bag cleaning system, an integral surge hopper, and a double dump airlock valve assembly for discharge into the silo. The vacuum filter/separator for the winter fly ash storage building will consist of a continuous operating filter section with filter bags, pulse jet filter bag cleaning system, integral surge hopper, and a pressure airlock pneumatic conveyor to convey the ash to the winter storage building. Inside the building, a pressure conveying line will be provided with branches to direct the ash to various areas of the building. Two pneumatic conveying lines will convey material from the DESP branch lines to each filter/separator. The two conveying lines will be capable of transporting ash to the saleable fly ash storage silo or to the winter storage building pressure conveying/distribution system. One conveying line will be provided to convey material from the pressure airlock to the winter storage building, a distribution system with automatic valves will direct ash to various areas of the building. The saleable fly ash storage silo will be designed to receive and temporarily store saleable fly ash from the conveying system. The silo will have pass-through access for ash discharge to railcars and trucks. The saleable fly ash storage silo will be equipped with a bin vent filter and fluidizing system to promote ash discharge during unloading. A combination truck and rail car loading station will load saleable fly ash via a telescopic chute assembly. The truck loading area beneath the saleable fly ash storage area will be equipped with washdown facilities. A winter storage building will receive and temporarily store saleable fly ash from the DESP vacuum/pressure conveying system. To fill the building, one vacuum filter/separator located at ground level will receive ash from the DESP hoppers and discharge it through a pressure airlock into a pressure conveying line with multiple branches to distribute the ash within the building. Each branch will be equipped with an automatic isolation valve. Two dust collectors with ID fans will be provided to pull dust laden air from inside the building. The dust collector will maintain the building under a slight negative pressure. A rotary airlock and screw conveyor will be provided at the discharge of the dust collector hopper to convey accumulated dust back into the building. An air gravity conveyor, in conjunction with a front-end loader, will recover fly ash in the winter storage building to an ash recovery hopper. Ash collected in the recovery hopper will be conveyed by screw conveyor to a truck loadout area. The screw conveyor will discharge into a bucket elevator, which will convey the material up into a dry loadout station positioned over a truck drive-through. Trucks will be loaded via a telescopic chute assembly. 102607-145491 13-5 Interstate Power and Light Sutherland Unit 4 Air Permit Application 13.5 13.0 Material Handling Systems BACT Analysis Waste Ash Handling The waste fly ash handling system will service the fabric filter hoppers, air heater hoppers, SCR hoppers, economizer hoppers, and one fly ash waste storage silo. Each collection point in the waste fly ash handling system will be tied into a pneumatic vacuum conveying system via ash intake valves arranged in a straight branch line off the main conveying lines. The conveying system will sequentially remove fly ash from the hoppers and transfer the material to the fly ash waste storage silo. Two vacuum filter/separators located on top of the fly ash waste storage silo will receive and transfer the material to the fly ash waste storage silo via the double dump airlock valves. Each vacuum filter/separator on the fly ash waste silo will consist of a continuously operating filter section with filter bags, pulse jet filter bag cleaning system, integral surge hopper, and double dump airlock valve assembly for discharge into the silo. A dust detector will be furnished to detect broken filter bags and prevent intrusion of ash into the exhausters. Two pneumatic conveying lines will convey material from the fabric filter branch lines to each filter/separator. Each row of fabric filter hoppers will have an independent conveying line. The two conveying lines will be capable of transporting ash to the fly ash waste storage silo. Pneumatic conveying lines will convey material from the air heater hoppers, SCR hoppers, and economizer hoppers to each filter/separator. These conveying lines will tie into the conveying lines from the fabric filter. The fly ash waste storage silo will be designed to receive and temporarily store fly ash from the conveying system. The silo will have pass-through access for ash discharge to trucks. The fly ash waste storage silo will be equipped with a bin vent filter and fluidizing system to promote ash discharge during unloading. Ash conditioning pugmills will be provided as the primary means of ash unloading from the fly ash storage silo. Flow control valves will be provided to meter the ash and water into the pugmill. The silo will also be equipped with a dry fly ash loadout station equipped with a telescopic chute assembly. A summary of the saleable and waste fly ash handling equipment subject to particulate BACT review for the Project is provided below: • Saleable fly ash storage silo. • Saleable fly ash separators. • Combination railcar/truck loader (from saleable fly ash storage silo). • Saleable fly ash winter ash storage building. • Saleable fly ash truck loader (from winter storage building). 102607-145491 13-6 Interstate Power and Light Sutherland Unit 4 Air Permit Application 13.6 • Waste fly ash storage silo. • Waste fly ash separators. • Truck loader (from waste fly ash storage silo). 13.0 Material Handling Systems BACT Analysis FGD Solids Handling The FGD solids handling system will collect and dewater the solids produced within the wet FGD and transport the dewatered moist solids to an enclosed storage building or an emergency stockpile. The quality of FGD solids produced will be of “wallboard” grade gypsum. Two vacuum filters will dewater the FGD solids. The dewatered FGD moist solids will be discharged from the vacuum filters onto one of the two FGD solids product conveyors (GC-1A or 1B) through motorized diverter gates. Conveyor GC-1A will transfer the FGD moist solids to Transfer Conveyor GC-2. The Transfer Conveyor GC-2 will transfer the moist solids to an elevated shuttle belt conveyor, GC-3, located inside of the FGD solids storage building. The shuttle conveyor will prepare a series of conical or elongated piles of solids inside the building. Finally, the FGD moist solids from the storage building, or the emergency stockpile as necessary, will be loaded onto trucks. The FGD solids are disposed of as moist solids and either hauled by trucks offsite or to the onsite byproduct storage area. The FGD solids take the form of a wet solid material. The FGD solids are dewatered, but remain moist during all handling, conveyance, and storage operations and do not create any fugitive dust except for that resulting from truck transportation. 13.7 Bottom Ash Handling The bottom ash handling system collects and removes bottom ash from the bottom of the steam generator furnace and collects coal pulverizer (pyrites) rejects. All are gathered in the upper trough of a submerged scraper conveyor (SSC) and conveyed to a three-walled ash storage bunker. Bottom ash produced in the steam generator furnace will fall into the water-filled upper trough of the SSC. DeNOx and economizer ash will be transferred via dry drag chain conveyors to the SSC outside of the seal plates. Rejects from the coal pulverizers will be sluiced to the SSC outside of the seal plates. The collected ash and coal pulverizer rejects in the upper trough of the SSC will be conveyed up a dewatering slope and discharged into a three-sided concrete storage bunker located indoors. Periodically, the bottom ash will be loaded directly into ash dump trucks for offsite sales or transport to the onsite byproducts storage area. 102607-145491 13-7 Interstate Power and Light Sutherland Unit 4 Air Permit Application 13.0 Material Handling Systems BACT Analysis The bottom ash takes the form of a wet solid material. The bottom ash is dewatered, but remains moist during all handling, conveyance, and storage operations and does not create any fugitive dust except for that resulting from truck transportation. 13.8 Biomass Handling The biomass fuel is harvested into bales, which are of approximate dimensions of 3 feet by 3 feet by 8 feet and weigh approximately 700 pounds or 3 feet by 4 feet by 8 feet and weigh approximately 1,000 pounds. The bales will be delivered to the site on flatbed trailers with 54 (3 feet by 3 feet by 8 feet) bales or 36 (3 feet by 4 feet by 8 feet) bales on each trailer. The bales will then be unloaded with a forklift and piled in the storage building. The bales will be picked up with the forklift and placed on a conveyor. The binding twine will automatically be cut and retrieved from the bale prior to the bale feeding into the “debaler,” a hammermill, which will mill the biomass before sending it through a sizing screen. After passing through the screen, the biomass will be collected and conveyed to the “eliminator,” an attrition mill configured to reduce the biomass to the selected size for pneumatic conveying to the boiler. Prior to the biomass reaching the attrition mill, a magnetic belt traversing the feed conveyor will collect all foreign metal objects captured during the baling process. A fabric filter and separator will pull the biomass material from the eliminator grinder, where the heavy material will drop down a surge bin, and the lighter material will move into the fabric filter for collection. The biomass material will then be removed from the fabric filter through the tube conveyor to storage surge bins for pneumatic transport to the boiler. All of the equipment downstream of the eliminator grinder will be kept at a slight negative pressure for dust control. 13.9 Other Material Handling The transportation and handling of various materials associated with bulk material storage, material delivery, and material disposal within the site boundaries or offsite will result in particulate emissions. These include, for example, truck deliveries (onsite or offsite, as applicable) of limestone, ash, FGD solids, and coal, as well as bulk material storage piles and pile maintenance. 102607-145491 13-8 Interstate Power and Light Sutherland Unit 4 Air Permit Application 13.0 Material Handling Systems BACT Analysis A summary of various other material handling activities is provided as follows: • Haul roads for material deliveries and disposal. • Active coal storage piles. • Inactive coal storage piles. • Limestone storage pile. • Saleable fly ash winter storage pile. • Front-end loader/bulldozing activities for loading/unloading materials and pile maintenance. 13.10 Step 1--Identify All Control Technologies Particulate emissions from the Project’s material handling systems are generally the result of (depending on the specific material) material storage, material conveyance, unloading, processing/crushing, and haul roads. For those systems that can be easily enclosed, the most predominant and effective particulate control technology is an enclosure with a fabric filter dust collection system. In those circumstances where particulate capture is difficult to achieve (thereby reducing the control effectiveness of a fabric filter dust collection system), the application of water or chemical surfactants (i.e., wet suppression) can be used. These types of operations typically include partially enclosed material handling transfer points, storage piles, and haul roads. Telescopic chutes and pneumatic transfer systems are often used in combination with other dust control techniques such as dust suppression spray rings at unloading points and stockout points. Particulate emissions from haul roads and front-end loading activities are effectively controlled by paving, road washing, and/or wet suppression as previously discussed. 13.11 Step 2--Eliminate Technically Infeasible Options A review of the aforementioned material handling control technologies concluded that they are each technically feasible for the specific type of application discussed in Section 12.1. 13.12 Step 3--Rank Remaining Control Technologies by Effectiveness A review of information contained in the USEPA BACT/LAER Clearinghouse and other sources specified in Section 2.1 revealed that wet suppression, covered conveyance, and fabric filter dust collection systems are most frequently identified as the top BACT control technologies for material handling processes. Fabric filter dust 102607-145491 13-9 Interstate Power and Light Sutherland Unit 4 Air Permit Application 13.0 Material Handling Systems BACT Analysis collection systems achieve in excess of 99 percent control efficiency, with typical grain loading rates of 0.01 gr/dscf for coal and ash handling and 0.005 gr/dscf for limestone handling. 13.13 Step 4--Evaluate Most Effective Controls and Document Results In the following subsections, the technically feasible control alternatives are evaluated in a comparative approach with respect to their energy, environmental, and economic impacts to the Project. 13.13.1 Energy Evaluation of Alternatives There are no significant energy impacts that would preclude the use of the material handling particulate control technologies presented in this evaluation. 13.13.2 Environmental Evaluation of Alternatives There are no significant environmental impacts that would preclude the use of the material handling particulate control technologies presented in this evaluation. 13.13.3 Economic Evaluation of Alternatives Because the highest level of technically feasible controls are proposed (i.e., building enclosures, 100 percent conveyance belt enclosures, water suppression, dust collectors, and telescopic chutes) for the Project’s material handling systems, a comparative economic analysis is not required. 13.14 Step 5--Select BACT IPL has determined that for those material handling systems that can be reasonably and economically enclosed, the use of a 100 percent enclosure, wet suppression, and a fabric filter dust collection system represents particulate BACT. Road pavement and surface cleaning and wet suppression will control particulate emissions from delivery/haul roads and front-end loader operation. Material off-loading activities will employ pneumatic conveyance and telescopic chutes to control particulate emissions. The aforementioned control technologies represent the top control technologies evident in recent permits for similar sized units, fuels, and processes. Table 13-1 summarizes the material handling particulate emission sources (explained in detail in Section 13.1) and the selected BACT control technology. 102607-145491 13-10 Interstate Power and Light Sutherland Unit 4 Air Permit Application 13.0 Material Handling Systems BACT Analysis Table 13-1 Material Handling Particulate BACT Determinations System Emission Source BACT Control Technology Determination Rotary Car Dumper (DPR-1) Coal Unloading 100% building enclosure Dust collection system (0.01 gr/dscf) 100% belt enclosure and dust collection system (0.01 gr/dscf) 100% transfer tower enclosure (TT-1) and dust collection system (0.01 gr/dscf) 100% belt enclosure Telescopic chute and spray ring (CHE-1) 100% belt enclosure Belt Conveyor (BC-1) Coal Receiving Transfer Tower (TT-1) Belt Conveyor (BC-2) Emergency Stockout Belt Conveyor (BC-3) Emergency Stockout Reclaim Belt Conveyor (BC-4) Stacker/Reclaimer Conveyor Stack/Reclaimer (SR-1) Transfer Tower (TT-2) Belt Conveyor (BC-5A) Existing Units Reclaim Transfer Tower (TT-3) Coal Handling Belt Conveyor (BC-5B) Existing Units Feed Truck Loadout Belt Conveyor (BC-6) Pile Stockout Belt Conveyor (BC-7) Pile Stockout Belt Conveyor (BC-8) Pile Reclaim Belt Conveyor (BC-9) Pile Reclaim Belt Conveyors (BC-10 and 11) Crusher Feed Crusher House (CH-1) Belt Conveyors (BC-12 and 13) Plant Feed (SGS Unit 4) 102607-145491 Partial belt enclosure Dust suppression 100% transfer tower enclosure (TT-2) and dust collection system (0.01 gr/dscf) 100% belt enclosure and dust collection system (0.01 gr/dscf) 100% transfer tower enclosure (TT-3) and dust collection system (0.01 gr/dscf) 100% belt enclosure 100% building enclosure Dust collection system (0.01 gr/dscf) Loadout chute 100% belt enclosure Telescopic chute and spray ring (CHE-2) 100% belt enclosure Telescopic chute and spray ring (CHE-3) 100% belt enclosure and dust collection system (0.01 gr/dscf) 100% belt enclosure and dust collection system (0.01 gr/dscf) 100% belt enclosure 100% crusher building enclosure (CH-1) Dust collection system (0.01 gr/dscf) 100% belt enclosure 13-11 Interstate Power and Light Sutherland Unit 4 Air Permit Application 13.0 Material Handling Systems BACT Analysis Table 13-1 (Continued) Material Handling Particulate BACT Determinations System Coal Handling (Continued) Emission Source BACT Control Technology Determination Transfer Tower (TT-4) 100% transfer tower enclosure (TT-4) and dust collection system (0.01 gr/dscf) 100% belt enclosure 100% boiler house enclosure and dust collection system (0.01 gr/dscf) Belt Conveyors (BC-14 and 15) Tripper Conveyors Railcar/Truck Bottom Dumper Limestone Unloading Belt Conveyor (CVY-1) Limestone Receiving/Stock Out Limestone Handling Belt Conveyor (CVY-2) Limestone Reclaim Belt Conveyor (CVY-3) Distribution Conveyor Two Limestone Storage Silos Saleable Fly Ash Storage Silo Saleable Fly Ash Separators Combination Railcar and Truck Loader (from saleable fly ash storage silo) Saleable Fly Ash Winter Storage Building Fly Ash Handling 100% building enclosure Dust collection system (0.005 gr/dscf) 100% belt enclosure and dust collection system (0.005 gr/dscf) Telescopic chute (CHE-1) and dust suppression (DS-2) 75% storage building enclosure 100% belt enclosure 100% belt enclosure and dust collection system (0.005 gr/dscf) Bin vent fabric filter Bin vent fabric filter Exhaust vent fabric filter Telescopic chute Truck washdown facility 100% storage building enclosure Dust collection system (0.01 gr/dscf) Telescopic chute Saleable Fly Ash Truck Loader (from winter storage building) Waste Fly Ash Storage Silo Bin vent fabric filter Waste Fly Ash Separators Exhaust vent fabric filter Truck Loader (from waste fly ash storage silo) Telescopic chute FGD Waste Handling Wet Solids Material No fugitive or point source emissions Bottom Ash Handling Wet Solids Material No fugitive or point source emissions Biomass Handling Bale Conveyor No fugitive or point source emissions Hammermill No fugitive or point source emissions Eliminator Ginder Dust collection system (0.01 gr/dscf) Tube Conveyor Dust collection system (0.01 gr/dscf) Surge Bin w/rotary air lock Dust collection system (0.01 gr/dscf) 102607-145491 13-12 Interstate Power and Light Sutherland Unit 4 Air Permit Application 13.0 Material Handling Systems BACT Analysis Table 13-1 (Continued) Material Handling Particulate BACT Determinations System Emission Source BACT Control Technology Determination Haul Roads – Material Delivery and Disposal Paved roads Road surface cleaning Wet dust suppression Wet dust suppression and chemical surfactant Pile best management practices Crusting agent Wet dust suppression and chemical surfactant 75% storage building enclosure 100% storage building enclosure Dust collection system (0.01 gr/dscf) Limited operation Wet dust suppression Active Coal Storage Piles Other Material Handling Inactive Coal Storage Piles Limestone Storage Pile Saleable Fly Ash Winter Storage Pile Front End Loader/Dozer Note: Detailed material handling process flow diagrams identifying the material handling systems, emission sources, and particulate BACT control equipment are included in Appendix E of the air permit application. 102607-145491 13-13 Interstate Power and Light Sutherland Unit 4 Air Permit Application Attachment A Attachment A Coal Fired Boiler Top-Down RBLC Clearinghouse Review Results 102607-145491 A-1 Interstate Power and Light Sutherland Unit 4 Air Permit Application 102607-145491 Attachment A A-2 Interstate Power and Light Sutherland Unit 4 Air Permit Application 102607-145491 Attachment A A-3 Interstate Power and Light Sutherland Unit 4 Air Permit Application 102607-145491 Attachment A A-4 Interstate Power and Light Sutherland Unit 4 Air Permit Application 102607-145491 Attachment A A-5 Interstate Power and Light Sutherland Unit 4 Air Permit Application 102607-145491 Attachment A A-6 Interstate Power and Light Sutherland Unit 4 Air Permit Application 102607-145491 Attachment A A-7 Interstate Power and Light Sutherland Unit 4 Air Permit Application 102607-145491 Attachment A A-8 Interstate Power and Light Sutherland Unit 4 Air Permit Application 102607-145491 Attachment A A-9 Interstate Power and Light Sutherland Unit 4 Air Permit Application 102607-145491 Attachment A A-10 Interstate Power and Light Sutherland Unit 4 Air Permit Application 102607-145491 Attachment A A-11 Interstate Power and Light Sutherland Unit 4 Air Permit Application 102607-145491 Attachment A A-12 Interstate Power and Light Sutherland Unit 4 Air Permit Application 102607-145491 Attachment A A-13 Interstate Power and Light Sutherland Unit 4 Air Permit Application 102607-145491 Attachment A A-14 Interstate Power and Light Sutherland Unit 4 Air Permit Application 102607-145491 Attachment A A-15 Interstate Power and Light Sutherland Unit 4 Air Permit Application 102607-145491 Attachment A A-16 Interstate Power and Light Sutherland Unit 4 Air Permit Application 102607-145491 Attachment A A-17 Interstate Power and Light Sutherland Unit 4 Air Permit Application 102607-145491 Attachment A A-18 Interstate Power and Light Sutherland Unit 4 Air Permit Application 102607-145491 Attachment A A-19 Interstate Power and Light Sutherland Unit 4 Air Permit Application 102607-145491 Attachment A A-20 Interstate Power and Light Sutherland Unit 4 Air Permit Application 102607-145491 Attachment A A-21 Interstate Power and Light Sutherland Unit 4 Air Permit Application 102607-145491 Attachment A A-22 Interstate Power and Light Sutherland Unit 4 Air Permit Application Attachment B Attachment B Auxiliary Boiler Top-Down RBLC Clearinghouse Review Results 102607-145491 B-1 Interstate Power and Light Sutherland Unit 4 Air Permit Application 102607-145491 Attachment B B-2 Interstate Power and Light Sutherland Unit 4 Air Permit Application Appendix I Appendix I Air Dispersion Modeling Protocol and Electronic Modeling Files 102607-145491 I-1 October, 2007 Ms. Lori Hanson Lead Worker, Air Quality Modeling Group Iowa Department of Natural Resources 7900 Hickman Road; Suite 1 Urbandale, IA 50322 RE: Revised PSD Dispersion Modeling Protocol and Results for Interstate Power and Light (IPL) Sutherland Generation Station Unit 4, Marshalltown, Iowa Dear Ms. Hanson: Interstate Power and Light (IPL) submitted a preliminary PSD Dispersion Modeling Protocol to the Iowa Department of Natural Resources (IDNR) on April 11, 2007. Based on IDNR protocol comments dated May 2, 2007, and a pre-application meeting on September 24, 2007, IPL is submitting via this letter, a revised Protocol with corresponding modeling results. This Protocol will provide the basis of a mutually agreed upon final Ambient Air Quality Impact Analysis (AAQIA) in support of the air construction permit application. Should you have any questions concerning the content of this letter, please contact me at 319-786-4476, or by e-mail at [email protected] Sincerely, Alan Arnold Senior Environmental Specialist Interstate Power and Light Cc: Jeff Beer, IPL Project Director Andy Byers, Environmental Manager, Black & Veatch Tim Hillman, Air Permitting Manager, Black & Veatch 1 Ambient Air Quality Impact Analysis and Results Sutherland Generating Station Unit 4 As discussed in the pre-application introductory meeting held at IDNR’s office on February 7, 2007, Interstate Power and Light (IPL) is proposing to install Sutherland Generating Station Unit 4 (SGS4), a nominal 649 megawatt (MW) (net) supercritical pulverized coal-fired (PC) boiler at the existing Sutherland Generating Station located on the east side of Marshalltown, Iowa. The specific location of the SGS4, also referred to as “Project”, is illustrated in Figure 1. In addition to the new boiler, new material handling equipment will be installed for coal, limestone, ash, gypsum, and biomass. The coal material handling system will be designed to accommodate the unloading of coal in amounts capable of sustaining annual facility operations and will consist of a railcar unloader, fuel blending facility, active and longterm coal storage piles, and conveyor systems. Similarly, the other material systems will be designed to store, process, and transport their materials. The Project will also include ancillary equipment such as a cooling tower, auxiliary boiler, natural gas fuel heater, emergency diesel generator, and two emergency diesel fire pumps. Site arrangements for the proposed Project are contained in Attachment 1. As a part of this submittal, the main boiler, material handling systems and each auxiliary equipment have been evaluated in an Ambient Air Quality Impact Analysis (AAQIA). Marshall County Iowa is in attainment or unclassifiable for all pollutants. As such, the Prevention of Significant Deterioration (PSD) program will apply to the proposed Project. The PSD regulations are designed to ensure that the air quality in existing attainment areas does not significantly deteriorate or exceed the National Ambient Air Quality Standards (NAAQS) while providing a margin for future industrial and commercial growth. The Sutherland Generating Station is an existing major source; therefore, PSD applicability is based on comparing the emissions increase of each pollutant against the PSD significant emission rates (SERs) as defined in Chapter 33 of the IDNR Air Quality Program Rules. For each regulated pollutant that is subject to PSD review and for which a modeling significant level (MSL) exists, an air dispersion modeling analysis must be performed. Potential-to-emit calculations for the proposed Project (contained in Attachment 2) demonstrate that NOx, SO2, PM/PM10, and CO, exceed the SERs thereby requiring modeling. 2 Project Location IOWA Project Location Base Map Source: www.topozone.com USGS 7.5 Minute Quadrangle: Le Grand, IA Figure 1 Project Location Therefore, IPL is submitting via this letter, an AAQIA Protocol with corresponding modeling results (hereinafter referred to as the Protocol) that describes the air quality impact analysis methodology and results for the proposed Project for review and comment. The modeling results presented herein rely upon the methodologies discussed in this Protocol. After IDNR review and approval, this Protocol will provide the basis of a mutually agreed upon modeling methodology in support of the air construction permit application. PRE-CONSTRUCTION MONITORING Pre-application monitoring applicability is determined by comparing each pollutant's maximum model predicted concentration to the applicable Monitoring De Minimus Level. If the maximum model predicted concentration for a pollutant is less than the applicable Monitoring De Minimus Level, then an exemption from pre-application monitoring requirements can be requested for that pollutant. 3 In the event the maximum model predicted impacts exceed the applicable Monitoring De Minimus Level for a given pollutant, then the existing ambient air quality monitoring network may evaluated for representativeness of these data to the site location (in cooperation with IDNR Ambient Air Monitoring staff) pursuant to requesting a waiver from the pre-application monitoring requirements for that pollutant. Using the methodologies presented herein, modeling to determine the proposed Project’s pre-construction monitoring requirements was conducted and is presented in Table 1. The results indicate that for all applicable pollutants and averaging periods the proposed Project is less than the respective Monitoring De Minimus Levels. Additionally, as presented in Attachment 2, the proposed project’s potential-to-emit of VOC is less than 100 tpy, which according to footnote 1 of 40 CFR 52.21(i)(8)(i) is the trigger threshold for the gathering of pre-application ambient air quality data for ozone. As such, IPL requests an exemption from the pre-application monitoring requirements for all pollutants including ozone. Table 1 Comparison of the Project’s Maximum Modeled Impacts with the PSD Monitoring de minimis Levels Operation Typical Operation(b) Pollutant Averaging Period AERMOD 1st High Maximum Impact(a) (μg/m3) NOx Annual 0.59 14 SO2 24 hour 4.85 13 PM10 24 hour 4.92 10 CO 8 hour 19.19 575 Fluorides 24 hour 0.01 0.25 PSD Class II Monitoring de minimis Level (μg/m3) (a) Represents the first high maximum model-predicted, ground-level impact from the 5-year meteorological data set used. (b) Typical operation includes the continuous and simultaneous operation of the proposed Unit 4 PC boiler, auxiliary boiler, natural gas fired heater, cooling tower, coal, limestone, ash, gypsum, and biomass material handling processes, truck deliveries and coal combustion byproducts removals. On an annual basis, in addition to the above source operations, the modeling includes the auxiliary boiler operating for 2,000 hours per year. VOC EMISSIONS Typically emissions of VOCs are not modeled. Furthermore, since the proposed project will result in a net emission increase of less than 100 tons per year of VOC (see Attachment 2), an analysis of the potential effects of ozone is not required by the IDNR. However, an evaluation of VOC emissions and subsequent ozone formation is provided in 4 the Soils and Vegetation portion of the Additional Impacts Analysis by using a conservative screening methodology based on the “VOC/NOX Point Source Screening Tables” developed by Scheffe (EPA-OAQPS-TSD-SRAB, 1988). MODELING METHODOLOGY The air dispersion modeling methodology and AAQIA that are proposed for those regulated pollutants which are determined to have a potential to emit (PTE) greater than the PSD SER and thus subject to PSD review are discussed in the following sections. The AAQIA is conducted in accordance with United States Environmental Protection Agency's (USEPA) Guideline on Air Quality Models (incorporated as Appendix W of 40 CFR 51) and the IDNR’S Air Dispersion Modeling Guidelines For PSD Projects dated January 6, 2005, as well as a mutually agreed upon modeling methodology initiated by this revised Protocol. DISPERSION MODEL Consistent with the Appendix W Guideline on Air Quality Models, the American Meteorological Society/Environmental Protection Agency (AMS/EPA) Regulatory Model (AERMOD) (Version 07026) air dispersion model was used to predict maximum groundlevel concentrations associated with the proposed Project’s emissions. AERMOD is the product of AMS/EPA Regulatory Model Improvement Committee (AERMIC), formed to introduce state-of-the-art modeling concepts into USEPA’s air quality models. AERMOD incorporates air dispersion based on planetary boundary layer turbulence structure and scaling concepts, including treatment of both surface and elevated sources, and both simple and complex terrain. The AERMOD model includes a wide range of options for modeling air quality impacts of pollution sources. The AERMOD model was used to determine the maximum predicted ground-level concentration for each appropriate pollutant and applicable averaging period resulting from the emission sources at the proposed Project location. DISPERSION COEFFICIENT With the introduction of AERMOD, the choice of the use of the simple rural or urban dispersion coefficient is no longer available. The AERMOD model has the option of assigning specific sources to have an urban effect, thus enabling AERMOD to employ enhanced turbulent dispersion associated with anthropogenic heat flux, parameterized by population size of the urban area. Since the proposed Project is not located in an urbanized area, urban boundary layer option will not be invoked. SOURCE CHARACTERIZATION As previously noted, IPL is proposing to install SGS4, a nominal 649 MW (net) supercritical PC-fired boiler and associated systems at the existing Sutherland Generating Station. The associated systems include ancillary equipment such as a cooling tower, auxiliary boiler, natural gas fuel heater, emergency diesel generator, two emergency diesel 5 fire pumps, and new material handling equipment that will be installed for coal, limestone, ash, gypsum, and biomass. The coal material handling system will consist of a railcar unloader, fuel blending facility, active and long-term coal storage piles, and conveyor systems. Similarly, the limestone and ash systems will be designed to store, process, and transport their respective materials. Each proposed air emissions source (including fugitive emissions) was evaluated, quantified, and included in the air dispersion modeling analysis by applying the following methodologies: Point Sources • Includes: o PC boiler, auxiliary boiler, natural gas fuel heater, emergency diesel generator, two emergency diesel fire pumps, dust collectors/bin vents, and cooling tower exhaust cells • Source Details: o Vertical Discharge: Actual exit temperature, diameter, and velocity For vent and dust collector releases that exit vertically, the exit temperature was represented as 0 degrees Kelvin which forces the model to use each hour’s ambient temperature from the meteorological file as the release temperature o Horizontal Discharge: Actual exit temperature and stack diameter, and an exit velocity of 0.001 meters/second (such that the model retains the thermal buoyancy and eliminates the momentum buoyancy) 1 For vent and dust collector releases that exit horizontally, the exit temperature was represented as 0 degrees Kelvin which forces the model to use each hour’s ambient temperature from the meteorological file as the release temperature • Emissions: o Based on projected fuel burn rates, preliminary engineering design estimates, vendor data, and AP-42 emission factors. For annual average period modeling, the IDNR’s Air Dispersion Modeling Guidelines for PSD Projects was used to account for the proposed annual source operation limitations (e.g., 2,000 hours per year for the auxiliary boiler). • Controls: o Various pre- and post-combustion controls and good combustion practices for the combustion sources, drift eliminators for the cooling tower, and water suppression and dust collectors/bin vent filters for the captured (nonfugitive) material handling sources. 1 EPA AERMOD Implementation Guide (September 27, 2005). Available at http://www.epa.gov/scram001/7thconf/aermod/aermod_implmtn_guide.pdf . 6 Area Sources • Includes: o Material load-in (conveyor drop) and wind erosion from open air coal and limestone storage piles • Source Details: o Above emissions combined to create a single storage pile emission rate o Horizontal dimensions equal to that of each proposed pile o Release height equal to the median height of the base of the pile and the highest drop height o Initial vertical dimension of each pile set equal to the pile height divided by 4.32 • Emissions: o Based upon AP-42 emission factors for material drops3 using maximum system rated capacities for load-in and industrial wind erosion4 assuming daily disturbances for active piles • Controls: o Water sprays/wetted material drops onto piles to achieve a 95 percent dust control factor5 o Water sprays/wetted material and reduced drop heights (e.g., telescopic chutes6 provide a 75 percent control) to achieve a 98.75 percent dust control factor o Water sprays/wetted material, reduced drop heights, and wind blocking structures (berms/walls assumed to provide a 50 percent control based on blocking wind from two of the four sides) to achieve a 99.38 percent dust control factor Volume Sources • Includes: o Open conveyor(s), haul roads, pile maintenance activities • Source Details: o Open conveyor(s): Series of alternating volume sources traversing the length of each individual open conveyor Initial vertical dimension set equal to the height of the conveyor galley divided by 4.32 2 USEPA’s User’s Guide for the Industrial Source Complex (ISC3) Dispersion Models Volume I - User Instructions (EPA-454/B-95-003a), as well as Trinity’s BREEZE ISC and AERMOD User’s Guide, Version 3.5, Table 3-1. 3 USEPA, AP-42, Fifth Edition, Vol. I. Chapter 13 Miscellaneous Sources, Section 13.2.4 Aggregate Handling and Storage Piles. November 2006. 4 USEPA. Fugitive Dust Background Document and Technical Information Document for Best Available Control Measures. EPA-450/2-92-004. September 1992. 5 Wet Suppression - An average of the control efficiency for TSP and PM10 emissions from conveyor transfer points. AP-42, Section 11.19.2 Crushed Stone Processing and Pulverized Mineral Processing 6 Telescopic Chute - USEPA. Stationary Source Control Techniques Document for Fine Particulate Matter. EPA Contract No. 68-D-98-026. October, 1998 7 • • Initial lateral dimension set equal the center to center distance divided by 2.152 Release height set equal to the conveyor elevation above ground at the source’s placement along the conveyor route o Haul roads (per modified TCEQ Air Quality Modeling Guidelines7): Series of alternating volume sources traversing the length of each individual road Initial vertical dimension set equal to twice the vehicle height divided by 4.3 Initial lateral dimension set equal to the road width divided by 2.15 Release height set equal to height of the vehicle’s tire o Pile maintenance activities: Series of alternating volume sources traversing the length of each individual pile Initial vertical dimension set equal to twice the vehicle height divided by 4.3 Initial lateral dimension set equal to the bulldozer width divided by 2.15 Release height set equal to half the height of the pile plus the height of the bulldozer’s tire Emissions: o Open conveyor emissions based upon AP-42 factors.8 o Haul road emissions based upon AP-42 emission factors for paved roads9 using maximum project material consumption and waste production rates for consumable material deliveries (e.g., limestone, sorbent, powder activated carbon, switch grass, etc.) and waste material disposals (e.g., fly ash, bottom ash, gypsum, etc.) o Pile maintenance activities are assumed to be the result of the bulldozers/scrapers in contact with the piles as they traverse over each pile pushing material on an as needed basis. Emissions are based upon AP-42 emission factors for unpaved roads9 with bulldozers/scrapers maintaining each pile for 8 hours/day. Controls (from published Ohio EPA document on fugitive emissions10): o Open conveyor controls consist of watering/wetted material to achieve a 95 percent dust control factor o Haul road controls consist of water flushing to achieve a 80 percent dust control factor o Pile maintenance controls consist of watering/wetted material and speed reduction to achieve a 95 percent dust control factor 7 TCEQ’s Air Quality Modeling Guidelines, RG-25 (Revised), February 1999. USEPA, AP-42 Table 8.19.2-2 Uncontrolled Particulate Emission Factors for Open Dust Sources at Crushed Stone Plants, September 1985. 9 USEPA, AP-42, Fifth Edition, Vol. I. Chapter 13 Miscellaneous Sources, Section 13.2.2 Unpaved Roads. 10 Ohio EPA’s Reasonably Available Control Measures for Fugitive Dust Sources “RACM”, 1980, Table 2.1.1-3 Controlling Fugitive Dust from Paved and Unpaved Surfaces. 8 8 o Watering, speed reduction, and wind blocking structures (berms/walls assumed to provide a 50 percent control based on blocking wind from two of the four sides) to achieve a 97.5 percent dust control factor Additional modeling methodologies include special considerations for the ancillary combustion sources. Per IDNR guidance, the emergency diesel generator and two emergency diesel fire pumps will only be operated when the rest of the facility is not in operation (except for test and maintenance purposes). As such, and in accordance with IDNR modeling guidelines, these sources (along with the inclusion of the auxiliary boiler for conservatism) were evaluated in a separate air dispersion modeling analysis with unrestricted daily operation for comparison to, and assurance of compliance with, the applicable short-term National Ambient Air Quality Standards (NAAQS). BUILDING DOWNWASH The dispersion of a plume can be affected by nearby structures when the stack is short enough to allow the plume to be significantly influenced by surrounding building turbulence. This phenomenon, known as structure-induced downwash, generally results in higher model predicted ground-level concentrations in the vicinity of the influencing structure. Sources included in a PSD permit application are subject to Good Engineering Practice (GEP) stack height requirements outlined in 40 CFR Part 51, Sections 51.100 and 51.118. For these analyses, the buildings and structures of the proposed Project were analyzed to determine the potential to influence the plume dispersion from the proposed Project’s emission sources. Structure dimensions and relative locations were entered into the USEPA’s Plume Rise Model Enhancement (PRIME) version of the Building Profile Input Program (BPIP) to produce an AERMOD input file with direction specific building downwash parameters. RECEPTOR GRID The air dispersion modeling receptor locations were established at appropriate distances to ensure sufficient density and aerial extent to adequately characterize the pattern of pollutant impacts in the area. Specifically, a nested rectangular grid network that extends out 10 km from the center of the proposed location was used. As specified in the IDNR Air Dispersion Modeling Guidelines for PSD Projects, the nested rectangular grid network will consists of the following six tiers: • • • • • • 50 m along the facility fence line 50 m extending from the fence line to 0.5 km 100 m extending from 0.5 km to 1.5 km 250 m extending from 1.5 km to 3 km 500 m extending from 3 km to 5 km 1000 m extending from 5 km to 10 km 9 As necessary, a 50-m fine grid was placed over areas of maximum concentration that occurred beyond the fence line and 50-m grid to ensure the true maximum concentration is identified. Figure 2 illustrates the six tier grid. 50 m boundary spacing 50 m spacing 100 m spacing 250 m spacing 500 m spacing 1,000 m spacing Figure 2 Receptor Grid TERRAIN ELEVATIONS Terrain elevations at receptors were obtained from 7.5-minute United States Geological Survey (USGS) Digital Elevation Model (DEM) files and incorporated into the AERMOD model. There is no distinction in AERMOD between elevated terrain below release height 10 and terrain above release height, as with earlier regulatory models that distinguished between simple terrain and complex terrain. For applications involving elevated terrain, the user must now also input a hill height scale along with the receptor elevation. To facilitate the generation of both receptor elevations and hill height scales for AERMOD, a terrain preprocessor, called AERMAP, has been developed by USEPA. Using AERMAP (Version 06341), terrain elevations were determined using a method that locates the maximum terrain elevation near each receptor. This method ensures that the highest (most conservative) elevation of the surrounding nearby terrain points in the DEM files are used for each receptor. As for hill height scale, AERMAP searches for a surrounding terrain height that has the greatest influence on dispersion at each individual receptor. In order to appropriately calculate the hill height scale, the DEM array and domain boundary must include all terrain features that exceed a 10% elevation slope from any given receptor. According to the IDNR Modeling Checklist the maximum distance at which terrain in Iowa could exceed a 10 percent slope is 3.6 km. The DEM domain boundary, at a minimum, extends 3.6 km beyond the furthest receptor in each direction. METEOROLOGICAL DATA The AERMOD model utilizes a file of surface boundary layer parameters and a file of profile variables including wind speed, wind direction, and turbulence parameters. These two types of meteorological inputs are generated by the meteorological preprocessor for AERMOD, which is called AERMET (Version 06341). AERMET requires hourly input of specific surface and upper air meteorological data. These data at a minimum include the wind flow vector, wind speed, ambient temperature, cloud cover, and morning radiosonde observation, including height, pressure, and temperature. AERMET includes three stages of preprocessing of the meteorological data. The first two stages extract, quality check, and merge the available meteorological data. The third stage requires input of certain surface characteristics (surface roughness, Bowen ratio, and Albedo) representative of the area. IDNR has provided five years (2000-2004) of pre-processed (AERMOD ready) surface and upper air meteorological data for specific geographical areas throughout Iowa. As illustrated in Figure 3, the proposed Project is located in the Des Moines (DM) geographical area. As such, surface and upper air meteorological data from Des Moines and Omaha (OM) meteorological stations, respectively, were used in the AERMOD model. IDNR has already confirmed that the provided data files are appropriate for use in and meet the percent complete requirements of the AERMOD model. Additionally, since the meteorological files provided by IDNR are AERMOD-ready, Stage 3 of the AERMET process, inputting site characteristics (Bowen, Albedo, surface roughness), will not need to be performed. 11 MODELING ANALYSIS Based on the air dispersion modeling methodology outlined previously, source release parameters and emission rates for use in the air dispersion modeling were developed and are presented in Tables 2, 3, and 4. SGS4 will be able to operate on a range of coals, as well as a blend of coal with up to 5 percent biomass. Additionally, the unit will potentially operate at reduced loads. For these reasons, performance data was developed for multiple coals, both with and without blends of biomass, as well as reduced loads including 75 and 50 percent. Emission calculation details for all sources are provided in Attachment 2. The maximum model predicted ground-level concentrations for each of the modeled scenarios associated with the proposed Project was then determined for each regulated pollutant that is subject to PSD review and for which a Modeling Significance Level (MSL) exists. Project Location Figure 3 IDNR Meteorological Stations The first high maximum model-predicted impacts for the proposed Project’s continuously operating emissions sources as compared to the MSLs are presented in Tables 5 and 6. Table 5 presents an overall summary of the highest modeled impact out of all operating scenarios (i.e., out of various loads and fuels) while Table 6 presents each individual 12 operating scenario’s maximum impact for review. The impacts presented in Tables 5 and 6 conservatively have all sources given in Tables 2-4 operating simultaneously at their maximum design rates (exceptions are the emergency diesel generator and two emergency diesel fire pumps which, on a short-term basis, will not be operated when the rest of the facility is operation, except for testing and maintenance purposes, and were included in a separate short-term analysis discussed below). Annually, the auxiliary boiler was included in the modeling of the full facility, using IDNR’s guidance for restricted annual operation, as it may operate with the rest of the facility in any given year for up to 2,000 hours. As presented in Tables 5 and 6, the maximum model-predicted impacts are below all respective MSLs. Therefore, no further PSD modeling analyses are required. As mentioned previously and allowed by the IDNR, the ancillary combustion sources, including the auxiliary boiler, emergency diesel generator, and two emergency diesel fire pumps, were included in a separate air dispersion modeling analysis with unrestricted daily operation for comparison to and assurance of compliance with the applicable short-term NAAQS. As shown in Table 7, the modeling results for this scenario are all below the applicable NAAQS. It is important to note that the auxiliary boiler was conservatively included in both the short-term NAAQS analysis presented in Table 7, as well as the full facility modeling presented in Tables 5 and 6 since it may operate both when the rest of the facility is not in operation and when SGS4 is in operation. SOURCE INVENTORIES Since the modeling results given in Tables 5 and 6 indicate model-predicted concentrations below the MSLs for all pollutants, no cumulative analysis with source inventories will be required. BACKGROUND VALUES Since the modeling results given in Tables 5 and 6 indicate model-predicted concentrations below the MSLs for all pollutants, no ambient pollutant background values will be required. 13 Table 2 Stack Parameters and Pollutant Emission Rates for Unit 4 PC Boiler(a) ID(b) EP248A EP248B EP248C EP248D EP248E EP248F EP248G EP248H EP248I EP248J Percent Load (%) 100 100 100 100 100 100 75 75 50 50 Source Type Discharge Style Stack Height(d) (ft) Point Point Point Point Point Point Point Point Point Point Vertical Vertical Vertical Vertical Vertical Vertical Vertical Vertical Vertical Vertical 601 601 601 601 601 601 601 601 601 601 Exit Temp (oF) Exit Velocity (ft/s) 130 130 130 120 130 125 125 120 125 120 59.2 57.2 54.7 52.4 60.0 58.2 44.1 43.2 31.3 30.4 (a) Diameter (in) Exhaust Flow Rate (acfm) Operating Hours 316.56 316.56 316.56 316.56 316.56 316.56 316.56 316.56 316.56 316.56 1,940,460 1,876,128 1,793,722 1,719,350 1,967,862 1,909,549 1,445,407 1,416,164 1,027,703 996,132 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 Detailed Unit 4 performance and emissions calculations can be found in Attachment 2. IDs are the same as those that appear in the air dispersion modeling files. Short-term and annual emission rates are the same since Unit 4 is assumed to operate 8,760 hours per year. (d) Sutherland Generating Station’s base elevation is 863 ft (263 m). (e) PM10 emission rates given above represent total PM/PM10, including both filterable and condensable particulate matter. (f) Conservatively assumed fluoride emissions as HF emissions. (b) (c) 14 Emission Rate (lb/hr)(c) NOx 316.3 308.5 300.8 291.4 316.7 309.3 237.2 231.4 158.2 154.3 SO2 380.0 494.0 361.0 466.0 380.0 495.0 285.0 370.0 190.0 247.0 PM10(e) 113.9 111.0 108.3 104.9 114.0 111.4 85.35 83.25 57.00 55.50 CO 759.0 740.0 722.0 699.0 760.0 742. 0 569.0 555. 0 380.0 370. 0 F(f) 1.27 1.23 1.20 1.17 1.27 1.24 0.95 0.93 0.63 0.62 Table 3 Stack Parameters and Pollutant Emission Rates for the Ancillary Combustion Equipment(a) ID (b) EP297 Description (c) EP249(d) EP250A(e) EP250B(e) EP251(e) EP252(e) Natural Gas Heater Auxiliary Boiler Maximum hourly emission rate Diesel Generator Maximum hourly emission rate – Stack 1 Diesel Generator Maximum hourly emission rate – Stack 2 Diesel Fire Pump Maximum hourly emission rate Diesel Fire Pump Booster Maximum hourly emission rate Source Type Discharge Style Stack Height(f) (ft) Exit Temp (oF) Exit Velocity (ft/s) Diameter (in) Exhaust Flow Rate (acfm) Operating Hours NOx SO2 PM10 CO F Point Vertical 20.00 700 19.41 15 1,430 8,760 hr/yr 0.14 0.002 0.022 0.142 0 Point Vertical 285.00 650 44.00 60 51,850 24 hr/day 9.94 0.16 1.88 19.88 0 Point Vertical 10.00 761 227.96 10 7,460 24 hr/day N/A 0.49 0.12 1.72 0.003 Point Vertical 10.00 761 227.96 10 7,460 24 hr/day N/A 0.49 0.12 1.72 0.003 Point Vertical 12.00 918 246.50 6 2,900 24 hr/day N/A 0.20 0.10 0.95 0.001 Point Vertical 12.00 1,044 96.56 5 790 24 hr/day N/A 0.07 0.06 0.11 4E-4 (a) Emission Rate (lb/hr) Detailed performance and emissions calculations can be found in Attachment 2. IDs are the same as those that appear in the air dispersion modeling files. Short-term and annual emission rates are the same since this source is assumed to operate 8,760 hours per year. (d) The auxiliary boiler is an ancillary piece of equipment but may operate as needed when the rest of the proposed Project is still operational. Therefore, it was included in the short-term modeling demonstration for the proposed Project as a whole (with unlimited daily operations), the annual modeling demonstration for the proposed Project as a whole (using IDNR guidance for sources with restricted annual operations – limited to 2,000 hours per year), and the short-term NAAQS demonstration which also include the emergency diesel generator and emergency diesel fire pumps operating simultaneously for 24-hours per day. (e) The emergency diesel generator and two emergency diesel fire pumps will only be operated when the rest of the facility is not in operation (except for test and maintenance purposes). As such, and in accordance with IDNR modeling guidelines, these sources (along with the inclusion of the auxiliary boiler for conservatism) were evaluated in a separate analysis where they were operated 24 hours per day and their impacts compared to the short-term NAAQS. (f) Sutherland Generating Station’s base elevation is 863 ft (263 m). (b) (c) 15 Table 4 Stack Parameters and Pollutant Emissions for the Cooling Tower and Material Handling Sources(a) Stack / Release Height, (ft)(d) Exit Temp(e) (oF) Exit Velocity (ft/s) Exhaust Flow Rate (acfm) Operating Hours (hr/yr) Source Discharge Emission Unit Diameter PM10 Emission Type Style(c) Description (in) Rate(c) Cooling Tower Linear Mechanical LMCT1A Point Vertical 53 104 34.84 360 1,477,500 8,760 0.16 (f) Draft Cell 1A Linear Mechanical LMCT1B Point Vertical 53 104 34.84 360 1,477,500 8,760 0.16 (f) Draft Cell 1B Linear Mechanical LMCT2A 53 104 34.84 360 1,477,500 8,760 0.16 (f) Point Vertical Draft Cell 2A Linear Mechanical LMCT2B 53 104 34.84 360 1,477,500 8,760 0.16 (f) Point Vertical Draft Cell 2B Linear Mechanical LMCT3A Point Vertical 53 104 34.84 360 1,477,500 8,760 0.16 (f) Draft Cell 3A Linear Mechanical LMCT3B Point Vertical 53 104 34.84 360 1,477,500 8,760 0.16 (f) Draft Cell 3B Linear Mechanical LMCT4A Point Vertical 53 104 34.84 360 1,477,500 8,760 0.16 (f) Draft Cell 4A Linear Mechanical LMCT4B Point Vertical 53 104 34.84 360 1,477,500 8,760 0.16 (f) Draft Cell 4B Linear Mechanical LMCT5A Point Vertical 53 104 34.84 360 1,477,500 8,760 0.16 (f) Draft Cell 5A Linear Mechanical LMCT5B Point Vertical 53 104 34.84 360 1,477,500 8,760 0.16 (f) Draft Cell 5B Linear Mechanical LMCT6A Point Vertical 53 104 34.84 360 1,477,500 8,760 0.16 (f) Draft Cell 6A Linear Mechanical LMCT6B Point Vertical 53 104 34.84 360 1,477,500 8,760 0.16 (f) Draft Cell 6B Linear Mechanical LMCT7A Point Vertical 53 104 34.84 360 1,477,500 8,760 0.16 (f) Draft Cell 7A Linear Mechanical LMCT7B Point Vertical 53 104 34.84 360 1,477,500 8,760 0.16 (f) Draft Cell 7B Linear Mechanical LMCT8A Point Vertical 53 104 34.84 360 1,477,500 8,760 0.16 (f) Draft Cell 8A Linear Mechanical LMCT8B Point Vertical 53 104 34.84 360 1,477,500 8,760 0.16 (f) Draft Cell 8B (a) Detailed performance and emission calculations can be found in Attachment 2. (b) IDs are the same as those that appear in the air dispersion modeling files. (c) For horizontal releases, exit velocity was set equal to 0.001 m/s and exit temperature was set equal to 0 K which represented an ambient temperature release. (d) Sutherland Generating Station’s base elevation is 863 ft (263 m). (e) Sources that release at ambient temperature have a modeled exit temperature of 0 K (-459.7 °F) which simulates such. (f) Emission rate is lb/hr. (g) Emission rate is lb/(hr-ft2). Modeling ID(b) 16 Init. Lat. Dim. (ft) Init. Vert. Dim. (ft) N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A X Length (ft) Y Length (ft) N/A Table 4 (continued) Stack Parameters and Pollutant Emissions for the Cooling Tower and Material Handling Sources(a) Stack / Release Height, ft(d) Exit Temp(e) (oF) Exit Velocity (ft/s) Exhaust Flow Rate (acfm) Source Discharge Emission Unit Diameter PM10 Emission Type Style(c) Description (in) Rate(c) Coal Rotary Railcar EP254a Dump Dust Point Vertical 12.00 -459.7 38.00 78.00 75,000 8,760 2.20E-03 Collector (a) Rotary Railcar Vent EP254b Point Vertical 12.00 -459.7 38.00 78.00 75,000 8,760 2.20E-03 Dust Collector (b) Rotary Railcar EP255 Vault Vent Dust Point Vertical 12.00 -459.7 13.00 42.00 7,500 8,760 8.80E-03 Collector Transfer Tower 1 EP256 Point Vertical 55.00 -459.7 13.00 42.00 7,500 8,760 4.40E-03 Dust Collector Transfer Tower 2 EP262 Point Vertical 65.00 -459.7 13.00 42.00 7,500 8,760 8.36E-03 Dust Collector Belt Feeder BF-4 to EP264 Belt Conveyor BCPoint Vertical 12.00 -459.7 12.00 42.00 7,500 8,760 2.64E-03 8 Dust Collector Belt Feeder BF-5 to EP266 Belt Conveyor BCPoint Vertical 12.00 -459.7 13.00 42.00 7,500 8,760 1.32E-03 9 Dust Collector Crusher House 1 EP267 Point Vertical 125.00 -459.7 40.00 48.00 30,000 8,760 1.37E-02 Dust Collector Unit 4 Boiler House EP268 and Transfer Tower Point Vertical 53,000 8,760 190.00 -459.7 40.00 63.60 5.28E-03 4 Dust Collector Pile 5 Vault Vent EP269 Point Vertical 12.00 -459.7 13.00 42.00 7,500 8,760 1.76E-03 Dust Collector Transfer Tower 3 EP270 Point Vertical 35.00 -459.7 13.00 42.00 7,500 8,760 4.40E-04 Dust Collector Existing Transfer EP271 Tower Dust Point Vertical 55.00 -459.7 13.00 42.00 7,500 8,760 4.40E-04 Collector Future Truck Load EP272 Point Vertical 65.00 -459.7 40.00 30.00 12,000 8,760 2.20E-04 Out Dust Collector (a) Detailed performance and emission calculations can be found in Attachment 2. (b) IDs are the same as those that appear in the air dispersion modeling files. (c) For horizontal releases, exit velocity was set equal to 0.001 m/s and exit temperature was set equal to 0 K which represented an ambient temperature release. (d) Sutherland Generating Station’s base elevation is 863 ft (263 m). (e) Sources that release at ambient temperature have a modeled exit temperature of 0 K (-459.7 °F) which simulates such. (f) Emission rate is lb/hr. (g) Emission rate is lb/(hr-ft2). Modeling ID(b) 17 X Length (ft) Y Length (ft) Init. Lat. Dim. (ft) Init. Vert. Dim. (ft) (f) N/A N/A N/A N/A (f) N/A N/A N/A N/A (f) N/A N/A N/A N/A (f) N/A N/A N/A N/A (f) N/A N/A N/A N/A (f) N/A N/A N/A N/A Operating Hours (hr/yr) (f) N/A N/A N/A N/A (f) N/A N/A N/A N/A (f) N/A N/A N/A N/A (f) N/A N/A N/A N/A (f) N/A N/A N/A N/A (f) N/A N/A N/A N/A (f) N/A N/A N/A N/A Table 4 (continued) Stack Parameters and Pollutant Emissions for the Cooling Tower and Material Handling Sources(a) EP274 Emission Unit Description Coal (cont.) Coal Pile 2 North EP275 Coal Pile 2 South EP274 Coal Pile 2 Reclaim EP276 Coal Stock out Pile 3 EP277 Coal Stock out Pile 4 EP259 Transfer from elevating tripper to Belt Conveyor 4 Modeling ID(b) EP280a EP280b EP281 EP283 EP284 EP285 LMESPile Limestone Railcar Dump Dust Collector Railcar Vent Dust Collector Railcar Vault Vent Dust Collector Limestone Pile Hopper Vault Vent Dust Collector Limestone Silo 1 Dust Collector Limestone Silo 2 Dust Collector Limestone Storage Pile Stack / Release Height, ft(d) Exit Temp(e) (oF) Exit Velocity (ft/s) Diameter (in) Exhaust Flow Rate (acfm) Operating Hours (hr/yr) PM10 Emission Rate(c) X Length (ft) Source Type Discharge Style(c) Area Area Area Circular Area Circular Area N/A N/A N/A 20.00 20.00 20.00 N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 8,760 8,760 8,760 1.88E-07 4.80E-07 2.11E-07 (g) N/A 36.50 N/A N/A 2,328 N/A 8,760 N/A 36.50 N/A N/A 2,328 N/A Volume N/A 6.00 N/A N/A N/A Point Vertical 35.00 -459.7 38.00 Point Vertical 35.00 -459.7 Point Vertical 12.00 Point Vertical Point Y Length (ft) Init. Lat. Dim. (ft) Init. Vert. Dim. (ft) (g) 1,095 1,263 100 188.0 188.0 100 N/A N/A N/A 9.30 9.30 9.30 8.69E-07 (g) N/A N/A N/A 16.98 8,760 9.98E-07 (g) N/A N/A N/A 16.98 N/A 8,760 0.0693 (f) N/A N/A 1.39 2.79 78.00 75,000 8,760 6.60E-04 (f) N/A N/A N/A N/A 38.00 78.00 75,000 8,760 6.60E-04 (f) N/A N/A N/A N/A -459.7 13.00 42.00 7,500 8,760 1.98E-03 (f) N/A N/A N/A N/A 12.00 -459.7 13.00 42.00 7,500 8,760 8.80E-04 (f) N/A N/A N/A N/A Horizontal 110.00 -459.7 0.0033 12.00 1,500 8,760 4.40E-03 (f) N/A N/A N/A N/A Point Horizontal 110.00 -459.7 0.0033 12.00 1,500 8,760 8.80E-03 (f) N/A N/A N/A N/A Circular Area N/A 18.00 N/A N/A 1,104 N/A 8,760 1.01E-05 (g) N/A N/A N/A 8.37 (a) Detailed performance and emission calculations can be found in Attachment 2. IDs are the same as those that appear in the air dispersion modeling files. (c) For horizontal releases, exit velocity was set equal to 0.001 m/s and exit temperature was set equal to 0 K which represented an ambient temperature release. (d) Sutherland Generating Station’s base elevation is 863 ft (263 m). (e) Sources that release at ambient temperature have a modeled exit temperature of 0 K (-459.7 °F) which simulates such. (f) Emission rate is lb/hr. (g) Emission rate is lb/(hr-ft2). (b) 18 (g) Table 4 (continued) Stack Parameters and Pollutant Emissions for the Cooling Tower and Material Handling Sources(a) Modeling ID(b) EP292 EP293 EP286a EP286b EP287 EP288a EP288b EP289a EP289b EP290 EP294 Emission Unit Description Sorbent Injection Sorbent Short Term Silo Bin Vent Sorbent Long Term Silo Bin Vent Fly Ash Saleable Fly Ash Conveyor Blower Bin Vent 1 Saleable Fly Ash Conveyor Blower Bin Vent 2 Saleable Fly Ash Silo Bin Vent Saleable Fly Ash Storage Bin Vent 1 Saleable Fly Ash Storage Bin Vent 2 Waste Fly Ash Conveyor Blower Bin Vent 1 Waste Fly Ash Conveyor Blower Bin Vent 2 Waste Fly Ash Silo Bin Vent Lime Lime Silo Bin Vent Source Type Discharge Style(c) Stack / Release Height, ft(d) Point Horizontal 115.00 -459.7 0.003 13.20 5,000 8,760 4.40E-04 (f) N/A N/A N/A N/A Point Horizontal 280.00 -459.7 0.003 13.20 5,000 8,760 1.11E-05 (f) N/A N/A N/A N/A Point Horizontal 12.00 -459.7 0.003 15.00 4,000 8,760 1.44E-05 (f) N/A N/A N/A N/A Point Horizontal 12.00 -459.7 0.003 15.00 4,000 8,760 1.44E-05 (f) N/A N/A N/A N/A Point Horizontal 105.00 -459.7 0.003 13.20 2,000 8,760 1.44E-05 (f) N/A N/A N/A N/A Point Horizontal 23.00 -459.7 0.003 42.00 20,000 8,760 1.44E-05 (f) N/A N/A N/A N/A Point Horizontal 23.00 -459.7 0.003 42.00 20,000 8,760 2.29E-04 (f) N/A N/A N/A N/A Point Horizontal 28.00 -459.7 0.003 9.60 1,350 8,760 1.44E-05 (f) N/A N/A N/A N/A Point Horizontal 28.00 -459.7 0.003 9.60 1,350 8,760 1.44E-05 (f) N/A N/A N/A N/A Point Horizontal 105.00 -459.7 0.003 13.20 2,000 8,760 2.29E-04 (f) N/A N/A N/A N/A Point Horizontal 77.00 -459.7 0.003 13.39 5,000 8,760 5.17E-06 (f) N/A N/A N/A N/A (f) N/A N/A N/A N/A Exit Temp(e) (oF) Exit Velocity (ft/s) Diameter (in) Exhaust Flow Rate (acfm) Operating Hours (hr/yr) PM10 Emission Rate(c) PAC EP291 PAC Silo Bin Vent Point Horizontal 115.00 -459.7 0.003 13.20 1,000 8,760 4.40E-04 (a) Detailed performance and emission calculations can be found in Attachment 2. (b) IDs are the same as those that appear in the air dispersion modeling files. (c) For horizontal releases, exit velocity was set equal to 0.001 m/s and exit temperature was set equal to 0 K which represented an ambient temperature release. (d) Sutherland Generating Station’s base elevation is 863 ft (263 m). (e) Sources that release at ambient temperature have a modeled exit temperature of 0 K (-459.7 °F) which simulates such. (f) Emission rate is lb/hr. (g) Emission rate is lb/(hr-ft2). 19 X Length (ft) Y Length (ft) Init. Lat. Dim. (ft) Init. Vert. Dim. (ft) Table 4 (continued) Stack Parameters and Pollutant Emissions for the Cooling Tower and Material Handling Sources(a) Modeling ID(b) EP295 EP296 NORTHR1-33 SOUTHR1-38 NBPHR1-6 SBPHR1-6 NRPHR1-3 LMSPHR1-3 EP279A-CO EP278A-AZ Emission Unit Description Biomass Biomass Dust Collector 1 Biomass Dust Collector 2 Haul Roads North Pile Haul Road Srcs 1-33 South Pile Haul Road Srcs 1-38 North Blending Pile 3 Haul Road Srcs 16 South Blending Pile 4 Haul Road Srcs 16 North Reclaim Pile Haul Road Srcs 1-3 Limestone Pile Haul Road Srcs 1-3 West Gate Haul Road Srcs 1-93 North Gate Haul Road Srcs 1-52 Stack / Release Height, ft(d) Exit Temp(e) (oF) Exit Velocity (ft/s) Diameter (in) Exhaust Flow Rate (acfm) Operating Hours (hr/yr) X Length (ft) Y Length (ft) Init. Lat. Dim. (ft) Init. Vert. Dim. (ft) Source Type Discharge Style(c) Point Vertical 46.42 -459.7 84.20 30.00 24,800 8,760 4.14E-06 (f) N/A N/A N/A N/A Point Vertical 46.42 -459.7 84.20 30.00 24,800 8,760 4.14E-06 (f) N/A N/A N/A N/A Volume N/A 20.00 N/A N/A N/A N/A 8,760 1.62E-03 (f) N/A N/A 15.26 18.60 Volume N/A 20.00 N/A N/A N/A N/A 8,760 1.41E-03 (f) N/A N/A 15.26 18.60 Volume N/A 36.50 N/A N/A N/A N/A 8,760 8.91E-03 (f) N/A N/A 15.26 33.96 Volume N/A 36.50 N/A N/A N/A N/A 8,760 8.91E-03 (f) N/A N/A 15.26 33.96 Volume N/A 18.00 N/A N/A N/A N/A 8,760 1.78E-02 (f) N/A N/A 15.26 16.74 Volume N/A 18.00 N/A N/A N/A N/A 8,760 1.49E-02 (f) N/A N/A 15.26 16.74 Volume N/A 3.44 N/A N/A N/A N/A 8,760 1.96E-03 (f) N/A N/A 22.89 10.60 Volume N/A 3.44 N/A N/A N/A N/A 8,760 1.05E-03 (f) N/A N/A 22.89 10.60 (f) N/A N/A 5.58 0.70 PM10 Emission Rate(c) Open Conveyor Conveyor BC4 Srcs BC4_1-80 Volume N/A 1.50 N/A N/A N/A N/A 8,760 5.00E-04 1-80 (a) Detailed performance and emission calculations can be found in Attachment 2. (b) IDs are the same as those that appear in the air dispersion modeling files. (c) For horizontal releases, exit velocity was set equal to 0.001 m/s and exit temperature was set equal to 0 K which represented an ambient temperature release. (d) Sutherland Generating Station’s base elevation is 863 ft (263 m). (e) Sources that release at ambient temperature have a modeled exit temperature of 0 K (-459.7 °F) which simulates such. (f) Emission rate is lb/hr. (g) Emission rate is lb/(hr-ft2). 20 Table 5 Comparison of the Project’s Maximum Modeled Impacts with the PSD Class II Modeling Significance Levels Operation Typical Operation(b) Averaging Period Annual AERMOD 1st High Maximum Impact(a) (μg/m3) 0.59 PSD Class II Modeling Significance Level (μg/m3) 1 SO2 Annual 24 hour 3 hour 0.39 4.85 15.41 1 5 25 PM10 Annual 24 hour 0.77 4.92 1 5 CO 8 hour 1 hour 19.19 49.12 500 2,000 Pollutant NOx (a) Represents the first high maximum model-predicted, ground-level impact for all operating scenarios from the 5-year meteorological data set used. (b) On a short-term basis, typical operation includes the continuous and simultaneous operation of the proposed Unit 4 PC boiler, auxiliary boiler, natural gas fired heater, cooling tower, coal, limestone, ash, gypsum, and biomass material handling processes, truck deliveries, and coal combustion byproduct removals. It does not include the operation of the emergency diesel generator and two emergency diesel fire pumps, which, as allowed by IDNR, were modeled separately and compared to the short-term NAAQS (the results of which are presented in Table 7). On an annual basis, in addition to continuous and simultaneous operation of the sources listed immediately above, the modeling includes the auxiliary boiler operating for 2,000 hours per year. 21 Table 6 Individual Scenario Comparison of the Project’s Maximum Modeled Impacts with the PSD Class II Modeling Significance Levels (a) Typical Operation by Operating Scenario(b) Percent Load (%) Annual 1 ug/m3 EP248A EP248B EP248C EP248D EP248E EP248F EP248G EP248H EP248I EP248J 100 100 100 100 100 100 75 75 50 50 0.57 0.57 0.58 0.59 0.57 0.58 0.58 0.58 0.57 0.57 NOx SO2 Annual 1 ug/m3 0.28 0.37 0.28 0.39 0.27 0.38 0.26 0.35 0.21 0.29 PM10 24-hour 5 ug/m3 3.45 4.57 3.42 4.85 3.42 4.68 3.15 4.28 2.57 3.52 3-hour 25 ug/m3 11.27 14.84 11.03 15.41 11.21 15.23 9.71 13.14 7.47 10.23 Annual 1 ug/m3 0.77 0.77 0.77 0.77 0.77 0.77 0.77 0.77 0.77 0.76 24-hour 5 ug/m3 4.90 4.90 4.90 4.91 4.90 4.90 4.91 4.91 4.92 4.92 CO 8-hour 500 ug/m3 18.25 18.11 18.07 19.19 18.16 18.56 17.43 17.86 16.00 16.36 1-hour 2,000 ug/m3 47.86 47.54 47.43 49.12 47.60 48.37 43.24 43.64 35.42 35.58 (a) Represents the first high maximum model-predicted, ground-level impact for each individual operational scenario from the 5-year meteorological data set used. (b) IDs are the same as those that appear in the air dispersion modeling files. On a short-term basis, typical operation includes the continuous and simultaneous operation of the proposed Unit 4 PC boiler, auxiliary boiler, natural gas fired heater, cooling tower, coal, limestone, ash, gypsum, and biomass material handling processes, truck deliveries, and coal combustion byproducts removals. It does not include the operation of the emergency diesel generator and two emergency diesel fire pumps, which, as allowed by IDNR, were modeled separately and compared to the short-term NAAQS (the results of which are presented in Table 7). On an annual basis, in addition to continuous and simultaneous operation of the sources listed immediately above, the modeling includes the auxiliary boiler operating for 2,000 hours per year. 22 Table 7 Comparison of the Ancillary Equipment’s Maximum Modeled Impacts with the Short-term National Ambient Air Quality Standards Operation Ancillary Operation(b) Averaging Period 24 hour 3 hour AERMOD 1st High Maximum Impact(a) (μg/m3) 4.10 19.80 Background Concentration Value (μg/m3)(c) 20 20 Total (μg/m3) 24.10 39.80 NAAQS (μg/m3) 365 PM10 24 hour 1.58 45 46.58 150 CO 8 hour 1 hour 43.02 96.82 0 0 43.02 96.82 10,000 40,000 Pollutant SO2 (a) - Represents the first high maximum model-predicted, ground-level impact from the 5-year meteorological data set used. (b) Ancillary equipment includes the unlimited short-term operation of the auxiliary boiler, emergency diesel generator, and two emergency diesel fire pumps for the full extent of the averaging period of concern. It is important to note that the auxiliary boiler was conservatively included in both the short-term NAAQS analysis presented in this table, as well as the full facility modeling presented in Table 5 since it may operate both when the rest of the facility is not in operation and when SGS4 is in operation. (c) Taken from Table 4 Statewide Default Background Values of the IDNR’s Air Dispersion Modeling Guidelines for PSD Project (Version 010605) updated to include the most recent background value for PM10 24-hour averaging period as received in correspondence with IDNR staff. 23 ADDITIONAL IMPACTS ANALYSIS Federal PSD regulations require the preparation of an analysis of additional impacts due to construction and operation of a new major stationary source or major modification to an existing major source. The analysis considers projected air quality impacts that may occur as the result of general commercial, residential, industrial, and other growth associated with the new major stationary source, as well as impairment to vegetation, soils, and visibility. Additionally, this analysis identifies the proposed Project’s impacts upon threatened and endangered species. GROWTH The proposed project is to be located at the existing Sutherland Generating facility in Marshall County, specifically near Marshalltown, Iowa. IPL’s electric generating load and capability indicates a capacity deficiency for regulated load beginning in 2010, and that the deficit will continue to grow every year thereafter. The load and capability takes into account all owned generation added to date, as well as all purchased power contracts with accredited capacity that are currently performing, including eight wind contracts. IPL’s firm demand continues to grow on average, under normal weather conditions, approximately 40 MWs per year from the current projected load of approximately 2,916 WM in 2007, increasing to a net system peak load of approximately 3,256 MWs in 2016. The load demand growth is evident for both existing and new energy users, including residential, commercial, and industry sales classes. Therefore, the addition of SGS Unit 4 is intended to meet the aforementioned demand growth of IPL’s service area and provide reliability and flexibility in fleet-wide operation, especially as it relates to IPL’s older, smaller coal-fired units that may have to be operated differently, fuel switched, or even shutdown Because the proposed project is being installed to meet the existing and current projected electrical demands of the surrounding area, it is anticipated that little growth will be associated with its operation. There will be an increase in the local labor force during the construction phase of the Project, but this increase will be temporary, short-lived, and will not result in permanent/significant commercial and residential growth occurring in the vicinity of the project. Any temporary labor that may come from outside the commuting area will be absorbed into the surrounding hotel network. Project employment reflecting full-time jobs directly tied to the operation of proposed Project is estimated to be approximately 85 people. This will result in minor amounts of secondary employment created by the economic activity of the plant. Due to the expected small number of staff that will be required to operate and maintain the Project, the effects to ambient air quality from growth associated with Project operation are expected to be insignificant. Population increase is a secondary growth indicator of potential increases in air quality levels. Changes in air quality due to population increase are related to the amount of vehicle traffic, commercial/institutional facilities, and home fuel use. According to the US Census Bureau, the population of Marshall County has increased by 2.7 percent between 24 the 1990 and 2000 censuses. Since the Project is not serving to attract local business, rather it’s simply intended to meet the electric demands of the area, the net number of new, permanent jobs outside of the Project is estimated to be small. It can be concluded that the air quality impacts associated with secondary growth will not be significant because the increase in population due to the operation of the Project will be very small, compared to the overall existing population size of the surrounding area. Therefore, further air quality modeling analyses for the effects of growth are not proposed for this Project. VEGETATION While the model-predicted impacts from the Project are well below the secondary NAAQS, designed to protect flora and fauna, when considering pollutant effects on plants, it is important to recognize that the many factors that play a major role in determining whether a given quantity of pollutant will produce a predictable level of effect vary tremendously in nature. These factors include the type of exposure (acute or chronic), influences of stress from other biotic (insects and disease) or abiotic (edaphic or climatic) factors, the type of response measured, and the species or population under study. The NSR Workshop Manual states that the analysis of air pollution impacts on vegetation should be based on an inventory of species found in the impact area, i.e., significant impact area (SIA). Since the emissions from the proposed Project did not result in any exceedances of the significant impact levels, thus no SIA exists, an area with a 3-km radius centered at the facility was chosen for this analysis. A review of information gathered from topographic maps and aerial photography concluded that there are no state parks or designated sensitive areas within this 3-km area. A field survey of a 3-km radius (a 6x6-km area) surrounding the Sutherland facility was conducted in April 2007 for plant species mainly sensitive to NOx and SO2. For all other applicable PSD pollutants, the US Department of Agriculture’s Natural Resources Conservation Service (NRCS) was utilized to determine the inventory of plant species in the surrounding area. According to the NRCS, there are a total of 35 different plant species that are located within Marshall County (included in Attachment 3). For the purpose of defining the quantitative/qualitative impacts from the pollutants outlined in the following sections, other than NOx and SO2 which were identified via the site survey, it was conservatively assumed that for each pollutant a “sensitive” species is included in the list of 35 and that all 35 plant species are within the 3-km radius study area. The results from the modeling analysis are presented in Table 8 and were utilized to determine the effects on nearby vegetation. The following subsections briefly describe the potential effects of the PSD applicable pollutants emitted by the proposed Project on the nearby vegetation. Carbon Monoxide Carbon monoxide does not poison vegetation since it is rapidly oxidized to form carbon dioxide which is used for photosynthesis. However, extremely high concentrations can reduce the photosynthetic rate. According to the EPA document A Screening Procedure for the Impacts of Air Pollution Sources on Plant, Soils, and Animals, hereafter referred to 25 as EPA Screening Document, for the most sensitive vegetation, a CO concentration of 1,800,000 micrograms per cubic meter (1 week averaging period) could potentially reduce the photosynthetic rate. The maximum model-predicted 1-hour CO impact of 49.12 μg/m3 produced by the proposed Project, as referenced in Table 8, is significantly lower than this screening level (even at a conservative 1 hour averaging period). Consequently, no adverse impacts to vegetation at or near the proposed Project are expected from CO emissions. Table 8 Project’s Maximum Modeled Impacts Pollutant CO NO2 SO2 HF Averaging Period 1 hour 1 hour 4 hours 24 hours 1 month 1 year 1 hour 3 hours 1 hour AERMOD 1st High Maximum Impact* (μg/m3) 49.12 20.74 10.91 5.41 1.65 0.59 30.98 15.41 0.08 * Represents the first high maximum model-predicted, ground-level impact from the Project for the 5 year meteorological data set used. Nitrogen Oxides Different species of plants exhibit considerable divergence in terms of resistance to nitrogen oxides. All nitrous gases turn the edges of leaves brown or brownish black and cause blotches. Plant cells start to shrink and protoplasms detach themselves from the cell wall. This process ultimately results in the damaged parts of the cell drying out. Poisoning by nitrous gases is mainly due to nitrogen dioxide. However, for the purpose of this study, vegetation in the area surrounding the Project was examined with regard to the presence of plants sensitive to all NOx species that may be emitted by the facility. NOx Methods This study incorporated published information gathered from topographic maps, aerial photography, and soil surveys. These data were coupled with field surveys of a 3-km radius surrounding the Sutherland facility conducted in April 2007. The plant communities in the vicinity were identified on the basis of the structure (e.g., grassland and forest), position in landscape (e.g., upland and wetland), and dominant plant species. Plant 26 species were identified following the Flora of the Great Plains (Great Plains Flora Association, 1986, University Press of Kansas, Lawrence, KS). It is noted that in some instances land use classifications are used in lieu of plant communities, since in many areas the natural vegetation has been completely eliminated or highly modified. The sensitivity of the plant communities identified to NOx is determined on the basis of EPA plant species sensitivity listing provided in Air Quality Criteria for Oxides of Nitrogen11. The table is available from the Iowa Department of Natural Resource through their website12. Table 9 is a list of plant species and the sensitivity of each to NOx that was extracted from the 1993 EPA publication. That stated, it is noted that most studies of NOx sensitivity to plants to date have dealt with agricultural or otherwise economically valuable plant species. The majority of the plants encountered during this study are not included in the EPA list. Therefore, the EPA list is used as a guideline to the potential sensitivity of the dominant plant species found in each listed category. For instance, silver maple dominates the riparian woodland along the Iowa River but it is not included in the EPA list. However, the EPA list does include two species of maple as being plants having intermediate tolerance to NOx. Because all of the species are closely related (member of the genus Acer) logic follows that silver maple may also have intermediate tolerance to NOx, resulting in a rating of NOx tolerance for riparian woodland of ‘intermediate’ until it is proven otherwise. Similar reasoning was used to establish the tolerance of the other categories. The categories identified for the study are listed below by tolerance and composition here but are described below in the results sections: Tolerant • Woodland (upland deciduous) • Pasture • Emergent Wetland • Native Prairie • Urban/Residential • Commercial/Industrial Intermediate • Woodland (riparian) • Cropland (corn, soy beans) Sensitive • Cropland (alfalfa, clover) Using aerial photography, the study area was divided into a grid-work of 12 acre parcels. Figure 4 presents the aerial photography of the 3-km radius surrounding the Sutherland facility and the 12-acre parcel grid-work. The 12 acre parcel was chosen subjectively by considering the final size of the map and selecting a parcel of land that was small enough to meaningfully illustrate distribution yet large enough to not make the parcel evaluation 11 US EPA. “Air Quality Criteria for Oxides of Nitrogen, Volume II of III. EPA/600/8-91/049bF. August, 1993. 12 http://www.iowacleanair.com/prof/progdev/files/nox_veg_impacts.pdf 27 SENSITIVE Table 9 Relative Sensitivities of Plants to Nitrogen Dioxide INTERMEDIATE TOLERANT Conifers European larch Colorado blue spruce Nikko fir White fir White spruce Trees and Shrubs (non conifers) European white birch Japanese maple Japanese zelkova Little-leaf linden Norway maple Silver maple Field Crops and Grasses Alfalfa (lucerne) Barley Oats Red clover Spring clover Spring vetch Tobacco Fruit Trees and Shrubs Apple (wild) Pear (wild) Annual bluegrass Potato Rye Sweet corn Wheat Crabapple Grapefruit Japanese pear Orange 28 Austrian pine English yew Hinoki cypress Japanese black pine Loblolly pine Pitch pine Virginia pine Beech Black locust Black poplar Elder English oak European hornbeam Ginkgo (Maidenhair tree) Green ash Scotch elm Sweetgum White ash White oak Eastern cottonwood Kentucky bluegrass Tall fescue Smooth brome SENSITIVE Table 9 (continued) Relative Sensitivities of Plants to Nitrogen Dioxide INTERMEDIATE TOLERANT Garden Crops Carrot Bush bean Asparagus Celery Celery Bush Bean Leek Tomato Cabbage Lettuce Carrot parsley Kohlrabi Pea Onion Pinto bean Rhubarb Soybean Ornamental Shrubs and Flowers Azalea Cape jasmine Carissa Bougainvillea Common zinnia Croton Chinese hibiscus Dahlia Daisy common petunia Flossflower Gladiolus Oleander Fuchsia Japanese morning glory Pyracantha Gardenia Lily-of-the-valley Rose Plantain lily Snapdragon Ligustrum Rose Sweet Pea Oleander Shore juniper Tuberosus begonia Paperbark tree Spring heath Petunia Weeds Common mugwort Cheeseweed Lamb’s-quarters Common plantain Chickweed Nettle-leaved goosefoot Horseweed Common chickweed Pigweed Sunflower Dandelion Red root Notes: Species listed in bold italics are dominate species found in the study are that were not included in the 1993 EPA list but because other closely related species (same genus) are listed, the bold italics species is subjectively considered to have a similar tolerance. Source: Table 9-6, “Air Quality Criteria for Oxides of Nitrogen”, Volume II of III, EPA/600/891/049bF, August, 1993. unduly onerous. Each 12 acre parcel was assessed and placed in one of the above categories. The categories were color coded and mapped to illustrate the distribution of NOx sensitivity and plant communities in the project area (Figure 5). 29 NOx Results The study identified nine (9) categories of plant communities or general land use in the project vicinity that are described below. Each community is ranked with regard to NOx tolerance based on the 1993 EPA study and that is also briefly discussed. Table 9 provides the species sensitivity ratings from the EPA study. Figure 4 Aerial Photo of the Parceled Area 30 Figure 5 Distribution of Study Categories TOLERANT AREAS Woodland (Upland Deciduous). Upland deciduous woodlands are found only on the loess hills north of the Iowa River. These native woodlands are dominated by native oaks (Quercus spp.) and ashes (Fraxinus spp.). The presence of non-native honey locust (Gleditsia triacanthos) and the occasional black locust (Robinia pseudoacacia) attest to a moderate level of disturbance in much of this area. Most of these woods have been degraded by logging activity in the past and today are becoming dotted with rural residences. The understory is either dense and overgrown, or practically lacking due to use for holding livestock. If present, the dominant species in the understory are usually coralberry (Symphoricarpos orbiculatus), Missouri gooseberry (Ribes missouriense), 31 poison ivy (Toxicodendron radicans), and roughleaf dogwood (Cornus drummondii) which are all native, and multiflora rose (Rosa multiflora), an introduced species. Ground cover, like understory, may or may not be present. Native species present in this area are mostly composed of spring flowering species such as violets (Viola sp.), trout lilies (Erythronium sp.), and phlox (Phlox divaricata). Because the habitat present is comparatively xeric, the species diversity for the area appears to be rather low and composed of types able to withstand a substantial level of continued disturbance. This community is considered NOx ‘tolerant,’ since oaks, ash, and locust are included in the 1993 EPA listing. Pasture. Pastures are open grasses areas that generally are hayed or used for grazing livestock. These are planted grasslands composed of smooth brome (Bromus inermis). Few other species occur in these areas other than introduced or otherwise aggressive native plants. Also included in this category are a few small parcels of land that have been planted to warm season grasses in an attempt to re-establish the tallgrass prairie that was once present across the region. Warm season grass plantings usually contain the three or four dominant grass species of the native prairie (described below) but have an extremely limited diversity of native forbs present compared to historical conditions. This community is considered NOx ‘tolerant,’ since the dominant species (brome and fescue) are managed agricultural species with the ability to adapt to an extremely wide range of growing conditions. That ability is presumed here to include at least average or better resistance to pollutants such as NOx. Emergent Wetland. Emergent wetlands in the study area are represented by non-wooded habitats dominated by either canary reed grass (Phalaris arundicnacea) or broad-leaf cattail (Typha latifolia) or both. Canary reed grass is an aggressive, weedy, and introduced species that tends to grow in near monocultures where the ground is periodically inundated. Cattail is also aggressive, weedy, and grows in monocultures but it is native and typically grows in sites that are permanently wet. Few other species of consequence grow in these areas which have mostly been disturbed by forest clearing, trenching, or farming. This community is considered NOx ‘tolerant,’ since the dominant species are both widely distributed species with aggressive growing tendencies. For this reason the Emergent Wetland category is here presumed to include at least average or better resistance to pollutants such as NOx. Urban/Residential. Areas included in this category are either residential or light commercial. Also included here are schools, churches, and other public areas. Vegetation in these areas may be partially lacking but is predominantly present as lawns of fescue (Festuca sp.) and bluegrass (Poa sp.) or areas landscaped with an assortment of nursery reared ornamental flowers, shrubs and trees. This category is considered NOx tolerant since many of the species used in landscaping in the area are included on the EPA list as ‘tolerant,’ such as pine, poplar, oak ash, elm, locust., and Kentucky bluegrass. 32 Dense Commercial/Industrial (no vegetation). These are areas dominated by industrial and commercial development where vegetation is completely lacking, thus resulting in the areas being categorized as NOx tolerant. INTERMEDIATE AREAS Woodland (Riparian). Riparian forest is primarily located along the floodplains of major waterways in the region. In the study area this includes the area in close proximity to the Iowa River. Most of the species found in this habitat are native to the region. Silver maple (Acer saccharinum) is the dominant canopy species in the project area but cottonwood (Populus deltoides), willows (Salix spp.), and box elder (Acer negundo) at times be common. If an understory is present saplings of the same species are usually dominant. Ground cover may be completely lacking due to scouring from seasonal flooding or the area may support dense colonies of weedy, although native, herbaceous species such as giant ragweed (Ambrosia trifida) or stinging nettle (Urtica dioica). This habitat is determined to be of intermediate tolerance due to the dominance of silver maple. Although EPA (1993) does not list silver maple, the species of maple studied were included as intermediate tolerance. Cropland (corn, soy beans). Cropland dominates the study area in the vicinity of the Sutherland facility. With but minor exceptions, fields are planted to soy beans one year, rotated to corn the next, and back to soy beans the following year. According to the 1983 EPA criteria, corn is considered to be tolerant to NOx, while soy beans are considered to have intermediate tolerance to NOx. While cropland is mapped as having ‘intermediate’ tolerance to NOx, an averaged score for the area would have to be something greater than intermediate but less than tolerant. Native Prairie. Tallgrass prairie dominated by bluestem grasses (Andropogon ssp.), Indiangrass (Sorghastrum avenaceum), and switchgrass (Panicum virgatum) historically covered most of this region, but today has been virtually eliminated from most of Iowa by agricultural, commercial, and urban development. No relics of the native prairie were encountered within the study area. SENSITIVE AREAS Cropland (alfalfa, clover). Clover and alfalfa are grown in some areas of central Iowa for hay but no such crops were observed within the area studied. NOx Summary Nine categories of plant communities/land use were identified as potentially occurring in the project study area. Seven of these areas were found to be present. The Cropland (alfalfa, clover), a NOx sensitive category, was not found in the project study area. The Native Prairie, a NOx intermediate category, was likewise not found to occur in the study area. Figure 5 illustrates that approximately the east two-thirds of the study area is rated as having intermediate sensitivity to NOx. This includes the categories Woodland (riparian) and Cropland (corn, soybeans). The west third of the study area mostly lies within the city 33 limits of Marshalltown. These areas are mostly urban, residential, commercial or industrial and vary from having landscape plantings (lawns, specimen trees, gardens, and etc.) to no vegetation, resulting in these areas being classed NOx tolerant. According to the Air Quality Criteria for Oxides of Nitrogen13, the 1-hour NO2 concentration which results in 5% foliar injury for the most susceptible plant species is 7,520 micrograms per cubic meter. According to the EPA Screening Document, the minimum nitrogen dioxide concentrations at which adverse growth effects or tissue injury occurred for the most sensitive vegetation are: 3,760 micrograms per cubic meter (4 hours averaging time), 564 micrograms per cubic meter (1 month averaging time), and 94 micrograms per cubic meter (1 year averaging time). The graph listed in the US Fish and Wildlife Service document “A Biologist’s Manual for the Evaluation of Impacts of Coalfired Power Plants on Fish, Wildlife, and their Habitats” depicts metabolic and growth effects occurring for nitrogen dioxide at levels of 1,200 micrograms per cubic meter (1 hour) and 500 micrograms per cubic meter (24 hour). The maximum model-predicted impacts, as presented in Table 8, are 20.74 μg/m3 for 1hour, 10.91 μg/m3 for 4-hours, 5.41 μg/m3 for 24-hours, 1.65 μg/m3 for 1-month, and 0.59 μg/m3 for annual. These impacts are significantly below the aforementioned screening levels and as such, no adverse impacts to vegetation at or near the proposed Project are expected from nitrogen oxides stack emissions. Particulate Matter Exposure to a given mass concentration of airborne PM may lead to widely varying phytotoxic responses, depending on the particular mix of deposited particles. Effects of particulate deposition on individual plants or ecosystems are difficult to characterize because of the complex interactions among biological, physicochemical, and climatic factors. The diverse chemistry and size characteristics of ambient PM and the lack of clear distinction between effects attributed to phytotoxic particles and to other air pollutants further confuse the understanding of the direct effects on foliar surfaces. The majority of the documented toxic effects of particles on vegetation reflect their chemical content (e.g., acid/base, trace metal, nutrient), surface properties, or salinity. Studies indicate many phytotoxic gases are deposited more readily, assimilated more rapidly, and lead to greater direct injury of vegetation than do most common particulate materials (Guderian, 198614). Any PM deposited on above-ground plant parts may potentially exert physical or chemical effects. The effects of inert PM are mainly physical; whereas those of toxic particles are both chemical and physical. Deposition of inert PM on above-ground plant organs sufficient to coat them with a layer of dust may result in changes in radiation received, a rise in leaf temperature, and the blockage of stomata. The key phytotoxic factor leading to 13 14 http://www.iowacleanair.com/prof/progdev/files/nox_veg_impacts.pdf Guderian, R. (1986) Terrestrial ecosystems: particulate deposition. In: Legge, A. H.; Krupa, S. V., eds. Air pollutants and their effects on the terrestrial ecosystem. New York, NY: John Wiley & Sons; pp. 339-363. (Advances in environmental science and technology: v. 18). 34 plant injury is usually the chemical composition of PM, more specifically, the alkalinity of the applied dust. Foliar uptake of available metals could result in metabolic effects in above-ground tissues. All but 10 of the 90 elements that comprise the inorganic fraction of the soil occur at concentrations of < 0.1% (1000 μg/g) and are termed “trace” elements or trace metals. Trace metals with a density greater than 6 g/cm , referred to as “heavy metals,” are of particular interest because of their potential toxicity for plant and animals. Only a few metals, however, have been documented to cause direct phytotoxicity in field conditions. Although some trace metals are essential for vegetative growth or animal health, they are all toxic in large quantities, though only copper, nickel, and zinc have been documented as frequently being toxic. Toxicity due to cadmium, cobalt, and lead has been seen only under unusual conditions (Smith,1990c15). Generally, only the heavy metals cadmium, chromium, nickel, and mercury are released from stacks in the vapor phase. 3 Due to good combustion practices and the utilization of a highly effective air pollution control train adept at removing trace elements, the proposed Unit 4 will emit negligible amounts of these compounds. Consequently, no adverse impacts to vegetation at or near the proposed Project are expected from PM stack emissions. Sulfur Dioxide The response of plants to SO2 exposure is a complex process that involves not only the pollutant concentration and duration of exposure but also the genetic composition of the plant and the environmental factors under which exposure occurs. The response of a given species or variety of plants to a specific air pollutant cannot be precisely predicted on the basis of the known response of related plants to the same pollutant; neither can the response of a plant be predicted on the basis of its response to similar doses of other pollutants. Because of the variation in response shown by different plant species and different cultivars of the same species, making generalizations is difficult. In general, regardless of the condition of exposure, for a given plant species or variety there is a critical SO2 concentration and duration of exposure above which plant injury will occur. Such injury results from exceeding the plant’s capability to transform toxic SO2 and sulfite into much less toxic sulfate and ultimately to transfer or break down the sulfate. Possible plant responses to SO2 and related sulfur compounds include: 1) increased growth and yield due to fertilization effects; 2) no detectable response; 3) injury manifested as growth and yield reductions without visible symptoms on the foliage; 4) injury exhibited as chronic or acute symptoms on foliage with or without associated reduction in growth and yield; and 5) death of plants or plant communities. A number of species of plants are sensitive to low concentrations of SO2, and some may be used as bio-indicators of such pollution. However, even sensitive species may be 15 Smith, W. H. (1990c) Forest nutrient cycling: toxic ions. In: Air pollution and forests: interactions between air contaminants and forest ecosystems. 2nd ed. New York, NY: Springer-Verlag; pp. 225-268. (Springer series on environmental management). 35 asymptomatic, depending on the environmental conditions before, during and after exposure to SO2. Because of the absence of empirical data quantifying losses in growth or yield in relation to SO2 exposure, sensitive species are generally identified on the basis of visible symptoms. Visible damage to parts of plants above ground level are due to the direct action of SO2 entering the leaves via the stomata. It physiologically and biochemically impairs the photosynthesis, the respiration and the transpiration due to its detrimental effect on the pore aperture mechanism. Indirect damage is above all due to soil acidification (damage to mycorrhiza) and results in stunted growth. The conversion of SO2 to acid rain can take several days to occur. Therefore, when considering the effects nearby the facility it is mostly SO2 that is acidified on the ground by dew, snow, frost, and rain, rather than while the SO2 is airborne16. SO2 Methods This study incorporated published information gathered from topographic maps, aerial photography, and soil surveys. These data were coupled with field surveys of a 3-km radius surrounding the Sutherland facility conducted in April 2007. The plant communities in the vicinity were identified on the basis of the structure (e.g., grassland and forest), position in landscape (e.g., upland and wetland), and dominant plant species. Plant species were identified following the Flora of the Great Plains (Great Plains Flora Association, 1986, University Press of Kansas, Lawrence, KS). It is noted that in some instances land use classifications are used in lieu of plant communities, since in many areas the natural vegetation has been completely eliminated or highly modified. The plant communities/land use categories identified for the study are listed below and are described in the results: • Woodland (upland deciduous) • Woodland (riparian) • Pasture • Emergent Wetland • Native Prairie • Urban/Residential • Commercial/Industrial • Cropland (corn, soy beans) The sensitivity of plant species to SO2 is not well studied when considering natural floras. Most studies examine plant communities in a very broad sense, such as a coniferous or deciduous forest. These plant communities are composed of numerous dominant species and hundreds of less common species. A literature review suggests that a very small percentage of the species comprising most local floras has been critically examined with regard to SO2 sensitivity. In central Iowa where most counties have a flora of about 30016 Mulgrew and Williams, Biomonitoring of Air Quality Using Plants, http://www.umweltbundesamt.de/whocc/AHR10/III-GP-5.htm 36 350 species (University of Iowa Herbarium (http://www.cgrer.uiowa.edu/herbarium/), perhaps only 15 of those 300 species have been studied to any extent and more than likely the plants studied are widespread weeds or economically important species rather than dominant or secondary components of the natural flora. Ultimately, it is difficult to make more than gross generalizations about the affect, albeit real, of SO2 to whole plants communities. Comments made herein with regard to SO2 sensitivity are based strictly on previously published reports. SO2 Results Similar to the NOx analysis, the study area was divided into a grid-work of 12 acre parcels using aerial photography (see Figure 4). The 12 acre parcel was chosen subjectively by considering the final size of the map and selecting a parcel of land that was small enough to meaningfully illustrate distribution yet large enough to not make the parcel evaluation unduly onerous. Each 12 acre parcel was assessed based on a field assessment and aerial photography and the dominant community in each 12 acre parcel was mapped. The distribution of plant communities in the project vicinity is illustrated in Figure 6. The plant communities identified are described in the following sections. Woodland (Riparian). Riparian forest is primarily located along the floodplains of major waterways in the region. In the study area this includes the area in close proximity to the Iowa River. Most of the species found in this habitat are native to the region. Silver maple (Acer saccharinum) is the dominant canopy species in the project area but cottonwood (Populus deltoides), willows (Salix spp.), and box elder (Acer negundo) at times be common. If an understory is present saplings of the same species are usually dominant. Ground cover may be completely lacking due to scouring from seasonal flooding or the area may support dense colonies of weedy, although native, herbaceous species such as giant ragweed (Ambrosia trifida) or stinging nettle (Urtica dioica). This habitat is determined to be of intermediate tolerance due to the dominance of silver maple. Although EPA (1993) does not list silver maple, the species of maple studied were included as intermediate tolerance. According to Davis and Wilhour (197617), selected species of maple (Acer) are ‘sensitive’ to SO2. Sensitive is not defined but other plant species (no maples) are listed as ‘very sensitive.’ Although silver maple was not one of the species listed by Davis and Wilhour, it is assumed here that silver maple would exhibit sensitivity levels similar to some of the species listed, such as box elder (Acer negundo) and mountain maple (Acer glabrum). Therefore, the Riparian Forest can be considered a sensitive plant community. Woodland (Upland Deciduous). Upland deciduous woodlands are found only on the loess hills north of the Iowa River. These native woodlands are dominated by native oaks (Quercus spp.) and ashes (Fraxinus spp.). The presence of non-native honey locust (Gleditsia triacanthos) and the occasional black locust (Robinia pseudoacacia) attest to a moderate level of disturbance in much of this area. Most of these woods have been degraded by logging activity in the past and today are becoming dotted with rural residences. The understory is generally dense and overgrown, or practically lacking due to 17 http://fs.fed.us/air.documents/0_plantsb.pdf 37 Figure 6 Distribution of the Plant Communities use for holding livestock. If present, the dominant species in the understory are usually coralberry (Symphoricarpos orbiculatus), Missouri gooseberry (Ribes missouriense), poison ivy (Toxicodendron radicans), and roughleaf dogwood (Cornus drummondii) which are all native, and multiflora rose (Rosa multiflora), an introduced species. Ground cover, like understory, may or may not be present. Native species present in this area is mostly composed of spring flowering species such as violets (Viola sp.), trout lilies (Erythronium sp.), and phlox (Phlox divaricata). Because the habitat present is comparatively xeric, the species diversity for the area appears to be rather low and composed of types able to withstand a substantial level of continued disturbance. 38 The SO2 sensitivity of this plant community is difficult to assess based on species composition for lack of definitive and comparative data that is species specific. It is clear that oaks and ash, the dominant species in this community, are probably sensitive to SO2 to at least a small degree (Grill, D., Muller, M., Tausz, M. Strnad, B., Wonisch, A. and Raschi, A. 2004. Effects of sulphurous gases in two CO2 springs on total sulphur and thiols in acorns and oak seedlings. Atmospheric Environment 38: 3775-3780; Jensen, K. F. 1981. Forest Service Technical Report, Northeastern Forest Experiment Station, Broomall, PA). Pasture. Pastures are open grasses areas that generally are hayed or used for grazing livestock. These are planted grasslands composed of smooth brome (Bromus inermis). Few other species occur in these areas other than introduced or otherwise aggressive native plants. Also included in this category are a few small parcels of land that have been planted to warm season grasses in an attempt to re-establish the tallgrass prairie that was once present across the region. Warm season grass plantings usually contain the three or four dominant grass species of the native prairie (described below) but have an extremely limited diversity of native forbs present compared to historical conditions. No information could be found regarding the SO2 sensitivity of brome (Bromus sp.) and brome is a planted or otherwise introduced plants. Therefore, pasture as described herein is conservatively considered to be SO2 sensitive. Emergent Wetland. Emergent wetlands in the study area are represented by non-wooded habitats dominated by either canary reed grass (Phalaris arundicnacea) or broad-leaf cattail (Typha latifolia) or both. Canary reed grass is an aggressive, weedy, and introduced species that tends to grow in near monocultures where the ground is periodically inundated. Cattail is also aggressive, weedy, and grows in monocultures but it is native and typically grows in sites that are permanently wet. Few other species of consequence grow in these areas which have mostly been disturbed by forest clearing, trenching, or farming. Emergent wetland as herein described is not considered SO2 sensitive. No information could be found regarding SO2 sensitivity to canary reed grass and broad-leaf cattail. Both plants demonstrate very aggressive growth under a wide range of disturbed habitat conditions and it is reasonable to assume that affects from SO2 are probably negligible. Urban/Residential. Areas included in this category are either residential or light commercial. Also included here are schools, churches, and other public areas. Vegetation in these areas may be partially lacking but is predominantly present as lawns of fescue (Festuca sp.) and bluegrass (Poa sp.) or areas landscaped with an assortment of nursery reared ornamental flowers, shrubs and trees. This area is considered SO2 tolerant since it is mostly developed. It is recognized, however, that there may be ornamental species present that are known to be SO2 sensitive, such as gladiolas. 39 Dense Commercial/Industrial (no vegetation). These are areas dominated by industrial and commercial development where vegetation is completely lacking, thus resulting in the areas being considered SO2 tolerant. Cropland (corn, soy beans). Cropland dominates the study area in the vicinity of the Sutherland facility. With but minor exceptions fields are planted to soy beans one year, rotated to corn the next, and back to soy beans the following year. According to the University of Nebraska (http://www.panhandle.unl.edu/potato/html/air_pollutants.htm) corn is not sensitive to SO2, while soy beans are considered sensitive. Native Prairie. Tallgrass prairie dominated by bluestem grasses (Andropogon ssp.), Indiangrass (Sorghastrum avenaceum), and switchgrass (Panicum virgatum) historically covered most of this region, but today has been virtually eliminated from most of Iowa by agricultural, commercial, and urban development. No relics of the native prairie were encountered within the study area. SO2 Summary Seven categories of plant communities/land use were identified as occurring in the project vicinity. Three categories of sensitivity to SO2 can be more-or-less recognized based on a sampling of literature, non-sensitive or tolerant, sensitive or intermediate tolerance, and very sensitive. None of the plant communities present appear to be composed of dominant species that have been identified as very sensitive to SO2. The riparian and upland woodlands, due to the dominance of maple and oak (respectively), should be considered communities with sensitive or intermediate tolerance for SO2. The cropland is considered sensitive if soy beans are planted but tolerant if corn is planted. The remaining communities are not sensitive to SO2. By considering the distribution of plant communities/land use in Figure 6 is evident that most of the region surrounding the Sutherland Energy Center is to some degree sensitive to SO2. According to the Criteria Document18 for SO2, for the most sensitive vegetations, an exposure of 790-1,570 micrograms per cubic meter at 3-hours duration or 1,310-2,620 micrograms per cubic meter at a duration of 1-hour will cause visible injury to the plant. The SO2 impacts produced by the proposed Project, as referenced in Table 8, are 30.98 μg/m3 for 1-hour and 15.41 μg/m3 for 3-hour. The impacts are significantly lower than these sensitive levels; consequently, no adverse impacts to vegetation at or near the proposed Project are expected from SO2 stack emissions. Ozone The direct effect of ozone to plants is the destruction of chlorophyll and in particular chlorophyll b. There is a considerable difference in the sensitivity of various plants to ozone. Acute symptoms of ozone damage are necrosis, chlorosis, and so-called water marks. Ozone causes noticeable leaf damage in many crop and tree species. Research indicates this damage occurs at concentrations commonly monitored during the warm 18 Air Quality Criteria for Particulate Matter and Sulfur Oxides (1982): Volume III. U.S. Environmental Protection Agency, Washington, D.C., EPA/600/8-82/029CF. 40 months (i.e. 60 ppb to 120 ppb). Certain varieties of soybeans, clover, onions, spinach, muskmelon and alfalfa are especially susceptible. Trees, such as lilac, aspen and ash are also sensitive. Ozone is not directly emitted from pollutant sources, such as the Unit 4 boiler and ancillary equipment proposed for this Project. Instead, it is formed in a reversible reaction between O2, O3, NOx, and VOCs. The increase in ozone formation due to emissions of NOx and VOC from the Project was estimated using a conservative screening methodology approved by IDNR based on the “VOC/NOx Point Source Screening Tables” developed by Scheffe19. This conservative methodology is used to identify estimated incremental ozone plumes on an hourly basis. For the proposed Project, the ozone impact estimated from the Scheffe tables was less than 0.010 ppm (19.6 micrograms per cubic meter) on an hourly basis. In the article “The Response of Native, Herbaceous Species to Ozone: Growth and Fluorescence Screening,” New Phytologist, 120 (1992):29-37, Reiling and Davison found a reduction of growth rate in certain plants after being fumigated with 139.7 μg/m3 O3 for 2 weeks. The impacts related to the proposed Project estimated from the Scheffe tables are well below this level. Consequently, no adverse impacts to vegetation at or near the proposed Project are expected from ozone formation due to the operation of the Project. Fluorides Signs of inorganic fluoride phytotoxicity, such as chlorosis, necrosis and decreased growth rates, are most likely to occur in the young, expanding tissues of broadleaf plants and elongating needles of conifers. The induction of fluorosis has been clearly demonstrated in laboratory, greenhouse, and controlled field plot experiments. Toxicity is specific not only to plant species, but also to ionic species of fluoride, e.g., aluminum fluoride and hydrogen fluoride. However, most of the studies performed involved the fumigation of plants with hydrogen fluoride. According to GreenFacts, leaf necrosis has been known to occur at concentrations of 0.17 and 0.27 micrograms per cubic meter (exposure of 99 and 83 days, respectively) in the case of grapevines. The German Federal Ministry for Economic Cooperation and Development20 also references that for the highly sensitive Crocus, an exposure to a hydrogen fluoride concentration of 2 micrograms per cubic meter (276 hours exposure) can cause extremely severe leaf necrosis. The maximum model-predicted impact of 0.08 μg/m3 for 1-hour, as presented in Table 8, is significantly below the screening levels, even at a conservative 1 hour averaging period, and as such, no adverse impacts to vegetation at or near the proposed Project are expected from fluoride stack emissions. 19 Scheffe, R.D. “VOC/NOx Point Source Screening Tables”. US EPA, Office of Air Quality Planning and Standards. September, 1988. 20 German Federal Ministry for Economic Cooperation and Development. Environment Handbook – Document on Monitoring and Evaluating Environmental Impacts, Volume III: Compendium of Environmental Standards. http://144.16.93.203/energy/HC270799/HDL/ENV/enven/begin3.htm#Contents 41 SOILS A soil inventory was completed by obtaining a soil survey within the 3-km radius study area surrounding the facility. The soil survey was obtained from the Natural Resource Conservation Service. The different soil types that were found to be in excess of 1% of the total land area of the 3-km study area are listed in Table 10 and Attachment 3. The most abundant soil type in the vicinity of the Project was Tama silty clay loam, at 18.75%. According to the US Department of Agriculture Soil Conservation Service, the Tama silty clay loam series consists of very deep, well drained soils formed in loess. Tama silty clay loam soils are on interfluves and side slopes on uplands and on treads and risers on stream terraces. The full range of slope is from 0 to 20 percent. Tama silty clay loam soils are well drained. Surface runoff potential is negligible to high. Tama silty clay loam soils that are nearly level to gently sloping are cultivated with the principal crops being corn, soybeans, small grains, and legume hays. Tama silty clay loam soils that are on steeper slopes are commonly used as pasture lands. The native vegetation found within Tama silty clay loam soils are big bluestream, little bluestream, switchgrass, and other grasses of the tall grass prairie. Sulfates and nitrates caused by SO2 and NOx deposition onto the soil can be either beneficial or detrimental to soil depending on its composition. However, the proposed SO2 and NOx emission rates and consequently the impacts generated by the Project are not expected to have an adverse impact upon soils in the immediate vicinity since they are below the secondary NAAQS. Table 10 Soil Types Ackmore silt loam Lindley loam Ackmore-Colo complex Muscatine-Urban land complex Bremer silty clay loam Nevin silty clay loam Colo silty clay loam Nodaway silt loam Colo-Ely complex Nodaway silt loam, channeled Colo-Hanlon-Lawson complex Pits Colo-Urban land complex Tama silty clay loam Dinsdale silty clay loam Tama silty clay loam, benches Downs silt loam Tama-Urban land complex Fayette silt loam Water Lawler loam Zook silty clay loam Lawson silty clay loam NOTES: Data taken from the Natural Resources Conservation Service’s Web Soil Survey (http://websoilsurvey.nrcs.usda.gov/app/) for the 6x6-km domain in Marshall County, Iowa. 42 IDNR’S SOILS AND VEGETATION ANALYSIS TOOL INDR recently completed an analysis tool for determining the impacts emissions have on soils and vegetation. This analysis tool is being used in conjunction with the analysis above and is attached as Attachment 5. The analysis for lead was not conducted since the emission level did not exceed the applicable PSD SER. As seen in the analysis, all pollutants are below their applicable screening levels except for fluoride on a 10-day averaging period. However, review of the screening document utilized by IDNR to generate this tool, shows a screening level of 0.5 μg/m3 for fluorine on a 10-day average. The conservative 1-hour maximum impact of 0.07 μg/m3, as referenced in Table 8, is well below the screening level. The results from the screening tool indicate that there are no adverse impacts expected to soils and vegetation at or near the proposed Project. THREATENED AND ENDANGERED SPECIES Various species of wildlife and plants have been rendered extinct or have been so depleted in numbers that they are in danger of or threatened with extinction as a consequence of economic growth and development unrestrained by adequate concern and conservation. The US Congress passed the Endangered Species Preservation Act in 1966 and subsequently the Endangered Species Act of 1973 to conserve to the extent practicable the various species of wildlife and plants facing extinction since these species are of esthetic, ecological, educational, historical, recreational, and scientific value. An “endangered” species is one that is in danger of extinction throughout all or a significant portion of its range. A “threatened” species is one that is likely to become endangered in the foreseeable future. On April 11, 2007, IPL sent a letter to the US Fish and Wildlife Service requesting information of the potential impacts on endangered species from the proposed Project. On May 17, 2007, the US Fish and Wildlife Service responded stating that there are four species found in the Project area (including the distribution line upgrade project): the bald eagle, the prairie bush clover, the northern monkshood, and the western prairie fringed orchid. However, according to the US Fish and Wildlife Service and the Natural Resources Conservation Service’s websites, there is a more exhaustive list, therefore, these sources were utilized for this analysis. The following subsections briefly describe the potential effects of the PSD applicable pollutants produced by the proposed Project on the nearby threatened and endangered species Wildlife Species According to the US Fish and Wildlife Service, there are a total of 14 animal species that are listed as being threatened or endangered in the state of Iowa; however, only 7 of those listed actually occur in the state. For this analysis, it was conservatively assumed that all 14 animal species are found in the 3-km radius study area. A list of these is contained in Attachment 3. Information pertaining to the affects the pollutants emitted from the proposed Project would have on these 14 threatened or endangered animals is minimal. Therefore, it was conservatively assumed that a comparison to information provided in laboratory 43 experiments that were performed on test species would suffice. Lethal concentrations are usually reported as several different values, with the most common ones being: the LC50 which is the concentration of the chemical in air that kills 50% of the test animals in a given time and the lethal concentration low (LCLo) which is the lowest concentration of a chemical in air reported to have caused death in humans or animals. Table 11 presents a summary of the laboratory findings for the PSD pollutants of concern for the proposed Project. From the impacts referenced above, the emissions from the proposed Project are not expected to adversely impact the animal species; therefore, it is assumed that these emissions will not put at risk the efforts to conserve the 14 listed threatened and endangered species. Plant Species According to the Natural Resources Conservation Service, there are a total of 154 plant species in Iowa that are listed on either the federal or state level as being threatened or endangered; however, none of these 154 plant species are found in Marshall County. A list of these is contained in Attachment 3. From the inventory referenced above, there are several plant species, e.g. violets and trout lilies, which are within the 3-km radius study area for the proposed Project that are similar (same genus) to some of those found on the threatened or endangered list. From the impacts referenced above, the emissions from the proposed Project are not expected to adversely impact the most sensitive vegetation; therefore, it is assumed that these emissions will not put at risk the efforts to conserve these threatened and endangered species. Table 11 Lethal Concentrations of Select Pollutants on Laboratory Animals Chemical Value CO LC50 – 2,103 mg/m3 (4 hours) NO2 SO2 Ozone HF Test Animal Rat 3 Guinea Pig 3 LC50 – 16.8 mg/m (4 hours) Rat LCLo – 123 mg/m3 Dog LC50 – 346 mg/m3 (24 hours) Mouse LC50 – 57.3 mg/m (1 hour) 3 LC50 – 41.9 mg/m Mouse 3 LC50 – 1,062 mg/m (1 hour) 44 Rat VISIBILITY A visibility analysis is performed to determine the impact that a proposed PSD source would have on Class II sensitive areas such as state parks, wilderness areas, or scenic sites and over looks. Since the modeling results given in Tables 5 and 6 indicate the proposed Project will not have a significant impact for any pollutant, IPL has chosen to analyze the visibility impacts upon the nearest state park, Union Grove, located approximately 14 km northeast of the proposed Project location. Additionally, the IDNR has requested that visibility analyses be performed on the Rock Creek State Park, the nearest state park considering the predominant wind flows in this portion of the state, located approximately 29 km south of the proposed Project location. Figures 7 and 8 respectively illustrate the locations of the Union Grove and Rock Creek State Parks with respect to the proposed Project location. As defined in the CAA, the PSD requirements provide for a system of area classifications. Class I areas are generally national parks and wilderness areas. Class II areas, such as the state park, can accommodate well-managed and industrial growth. As such, visibility analyses were performed to evaluate the potential for visibility impairment inside the selected Class II scenic vista. A visibility impairment screening analysis was conducted at the aforementioned Class II area to provide a conservative indication of the perceptibility of plumes from the proposed main boiler emission source. The analysis was performed in accordance with the USEPA’s Workbook for Plume Visual Impact Screening and Analysis (Revised) (EPA454/R-92-023, October 1992, hereinafter referred to as the “Workbook”), using the VISCREEN model. It should be noted that the visibility impairment analyses and model VISCREEN are typical for assessments in PSD Class I areas where visibility preservation is a factor in the permit approval process. However, since no applicable Class II visibility model is available, this model and the methodology for Class I areas as outlined in the Workbook were used. 45 45o 55o Union Grove State Park Project Location Figure 7 Location of Union Grove State Park for Visibility Analyses 46 Project Location Rock Creek State Park o o 182 175 Figure 8 Location of Rock Creek State Park for Visibility Analyses In accordance with the Workbook’s visual screening procedures, the VISCREEN plume visual impact screening model would first be used with default worst-case Level 1 screening parameters. However, it is important to note that Level 1 analyses incorporate numerous worst-case default assumptions and parameters. As such, and in accordance with USEPA guidance, a more representative worst-case Level 2 screening analysis with situation-specific meteorological parameters was conducted. Tables 12 and 13 present the Level 2 visual screening parameters used in the VISCREEN modeling respectively for Union Grove and Rock Creek. Many of the input parameters for a Level 2 analysis are the same as the default worst-case values for a Level 1 analysis specified in the Workbook. The shaded parameters in Tables 12 and 13 designate the more representative, situationspecific inputs of the Level 2 analysis. The situation-specific Level 2 screening parameters are described below. 47 Table 12 VISCREEN Level 2 Model Inputs Level 2 (Representative Worst-Case Analysis)(a) VISCREEN Modeling Parameter Union Grove State Park Maximum Emissions Particulate Emissions(b) 114.0 lb/h NOx (as NO2) Emissions (b) 316.7 lb/h Primary NO2 Emissions 0 lb/h (model default) Soot Emissions 0 lb/h (model default) (b) Sulfate Emissions (SO4) 25.30 lb/h Source-Observer Distance 13.87 km Minimum Source-Class II Distance 13.87 km Maximum Source-Class II Distance 14.98 km Background Visual Range (c) 40 km Plume-Source-Observer Angle(a) 11.25 degrees (a) Background Ozone Concentration Stability Class 0.04 ppm (c,d) D (c,d) Wind Speed 2.00 m/sec (a) 1.5 g/cm3 Background Fine Particulate Density Background Fine Particulate Size Index(a) (a) Background Coarse Particulate Density Background Coarse Particulate Size Index(a) 2.5 g/cm3 6.0 μ/m Plume Particulate Density(a) 2.5 g/cm3 Plume Particulate Size Index(a) 2.0 μ/m (a) 2.0 g/cm3 Plume Soot Density Plume Soot Size Index(a) 0.1 μ/m (a) 1.5 g/cm3 Plume Primary SO4 Density Plume Primary SO4 Size Index(a) (a) 0.3 μ/m 0.5 μ/m VISCREEN model default values. (b) Highest emissions of all operating scenarios. Worst-case situation specific parameter. (d) Five years of meteorological data analyzed from Des Moines as obtained and analyzed by the IDNR visibility tool. Represents the meteorological conditions that are only expected to be worse than these conditions approximately 4 days per year. (c) 48 Table 13 VISCREEN Level 2 Model Inputs Level 2 (Representative Worst-Case Analysis)(a) VISCREEN Modeling Parameter Rock Creek State Park Maximum Emissions Particulate Emissions(b) 114.0 lb/h NOx (as NO2) Emissions (b) 316.7 lb/h Primary NO2 Emissions 0 lb/h (model default) Soot Emissions 0 lb/h (model default) (b) Sulfate Emissions (SO4) 25.30 lb/h Source-Observer Distance 29.22 km Minimum Source-Class II Distance 29.22 km Maximum Source-Class II Distance 34.42 km Background Visual Range (c) 40 km Plume-Source-Observer Angle(a) 11.25 degrees (a) Background Ozone Concentration Stability Class 0.04 ppm (c,d) D (c,d) Wind Speed 4.00 m/sec (a) 1.5 g/cm3 Background Fine Particulate Density Background Fine Particulate Size Index(a) (a) Background Coarse Particulate Density Background Coarse Particulate Size Index(a) 2.5 g/cm3 6.0 μ/m Plume Particulate Density(a) 2.5 g/cm3 Plume Particulate Size Index(a) 2.0 μ/m (a) 2.0 g/cm3 Plume Soot Density Plume Soot Size Index(a) 0.1 μ/m (a) 1.5 g/cm3 Plume Primary SO4 Density Plume Primary SO4 Size Index(a) (a) 0.3 μ/m 0.5 μ/m VISCREEN model default values. (b) Highest emissions of all operating scenarios. Worst-case situation specific parameter. (d) Five years of meteorological data analyzed from Des Moines as obtained and analyzed by the IDNR visibility tool. Represents the meteorological conditions that are only expected to be worse than these conditions approximately 4 days per year. (c) 49 The worst-case Level 1 VISCREEN stability class default value of ‘F’ and wind speed of 1 m/sec were found not to be representative of the general climatological conditions in the vicinity of the proposed Project. IDNR has developed a tool for determining more representative conditions of the area. The tool performs joint frequency distributions for a given meteorological dataset (Des Moines in this case) to find the combination of stability class and wind speed, which is expected to be worse than 99 percent of the conditions existing in the area. That is, for only 1 percent of the time (i.e., about 4 days per year) are the conditions expected to be worse than those selected for these analyses. These analyses are consistent with the methodologies in the Workbook. They consider the persistence as well as the frequency of occurrence of the stabilities and wind speeds insomuch as the transport times to the Class II areas may be of sufficient length to allow the plume to break up and not remain visible. Based on the instructions contained within the IDNR visibility tool, if the conservative Class I visibility thresholds are exceeded using the 1 percent meteorological conditions, the next worst stability class and wind speed combination should be used until the conditions under which the visibility thresholds are not exceeded is found. Tables 14 and 15 give the worst-case meteorological conditions summary indicating the cumulative frequencies of all applicable combinations of stability class and wind speed respectively for Union Grove and Rock Creek. For Rock Creek, the 1 percent condition was found to be suitable in demonstrating Class II visibility below the conservative Class I visibility thresholds. For Union Grove, however, the 1 percent condition was yet too conservative. The areaspecific Level 2 worst-case conditions for Union Grove were determined by the tool to be “E,4” and occur during the night-time hours from 1 to 6 am. The next condition of “D,2”, which occurs only 0.01 percent more of this same time period, was required to be used in the analysis to demonstrate the conservative Class I visibility thresholds were not exceeded. The results of the meteorological analyses are presented back in Tables 12 and 13 as the shaded stability class and wind speed values used in the analysis that indicated no exceedance. Results of the VISCREEN modeling are included in Tables 16 and 17 for Union Grove and Rock Creek State Parks, respectively. As previously noted, the modeling methodology utilized for this analysis is designed for Class I areas. The areas presented in this analysis are classified as Class II and, as such, has no set criteria from which to evaluate visual impacts. Therefore, the conservative Class I criteria were used in the analysis. CLASS I AREA IMPACTS ANALYSIS The nearest Class I areas are the Rainbow Lake Wilderness Area and Hercules-Glades Wilderness Area located approximately 510 and 590 km, respectively, from the proposed Project. Given the magnitude of these distances, no Class I area analyses are proposed for this Project. 50 Table 14 Worst-case Meteorological Conditions Summary for Union Grove State Park(a) Dispersion Condition (stability, wind speed) F,1 F,2 E,1 F,3 E,2 D,1 E,3 E,4(b) D,2(c) E,5 D,3 D,4 D,5 D,6 D,7 D,8 σyσzu (m3/s) 1.93E+04 3.85E+04 5.01E+04 5.78E+04 1.00E+05 1.18E+05 1.50E+05 2.01E+05 2.36E+05 2.51E+05 3.54E+05 4.72E+05 5.90E+05 7.08E+05 8.26E+05 9.44E+05 Transport Time (hours) 7.7 2.6 7.7 1.5 2.6 7.7 1.5 1.1 2.6 0.9 1.5 1.1 0.9 0.7 0.6 0.5 Frequency (f) and Cumulative Frequency (cf) of occurrence of given dispersion condition associated with source-site wind directions for given time of day (%) 1-6 f 0.10 0.16 0.01 0.47 0.03 0.01 0.14 0.12 0.01 0.19 0.03 0.06 0.10 0.14 0.15 0.05 cf 0.10 0.26 0.27 0.74 0.77 0.78 0.92 1.04 1.05 1.24 1.27 1.33 1.43 1.57 1.72 1.77 (a) 7-12 f 0.03 0.03 0.04 0.05 0.00 0.05 0.05 0.06 0.03 0.01 0.13 0.10 0.16 0.32 0.30 0.27 cf 0.03 0.06 0.10 0.15 0.15 0.20 0.25 0.31 0.34 0.35 0.48 0.58 0.74 1.06 1.36 1.63 13-18 f 0.01 0.01 0.02 0.01 0.01 0.00 0.02 0.01 0.00 0.06 0.06 0.08 0.21 0.29 0.29 0.29 cf 0.01 0.02 0.04 0.05 0.06 0.06 0.08 0.09 0.09 0.15 0.21 0.29 0.50 0.79 1.08 1.37 19-24 f 0.17 0.08 0.01 0.33 0.02 0.00 0.12 0.26 0.00 0.27 0.02 0.12 0.05 0.09 0.09 0.07 cf 0.17 0.25 0.26 0.59 0.61 0.61 0.73 0.99 0.99 1.26 1.28 1.40 1.45 1.54 1.63 1.70 Represents output from the IDNR visibility tool design to determine the joint frequency distribution for combinations of stability class and wind speed. Des Moines meteorological data downloaded from the IDNR website was used in the analysis. (b) This condition is the first occurrence of a cumulative frequency combination of stability and wind speed above 1 percent and was the starting point for the visibility analysis. Note that this combination reaches a 1 percent occurrence during the night-time hours of 1 to 6 am when no visible plume would be detected. (c) This condition is the next worst-case combination (only occurring 0.01 percent more of the time) and was used to demonstrate visibility impacts below the conservative Class I visibility thresholds. 51 Table 15 Worst-case Meteorological Conditions Summary for Rock Creek State Park(a) Dispersion Condition (stability, wind speed) F,1 F,2 E,1 F,3 E,2 D,1 E,3 E,4 E,5 D,2 D,3 D,4(b) D,5 D,6 D,7 D,8 (a) σyσzu (m3/s) 4.77E+04 9.54E+04 1.32E+05 1.43E+05 2.65E+05 3.47E+05 3.97E+05 5.29E+05 6.62E+05 6.94E+05 1.04E+06 1.39E+06 1.73E+06 2.08E+06 2.43E+06 2.78E+06 Transport Time (hours) 16.2(c) 5.4 16.2(c) 3.3 5.4 16.2(c) 3.3 2.3 1.8 5.4 3.3 2.3 1.8 1.5 1.3 1.1 Frequency (f) and Cumulative Frequency (cf) of occurrence of given dispersion condition associated with source-site wind directions for given time of day (%) 1-6 f 0.03 0.05 0.01 0.14 0.03 0.04 0.06 0.16 0.09 0.03 0.06 0.16 0.17 0.29 0.26 0.16 cf 0.00 0.05 0.05 0.19 0.22 0.22 0.28 0.44 0.53 0.56 0.62 0.78 0.95 1.24 1.50 1.66 7-12 f 0.00 0.00 0.00 0.03 0.00 0.01 0.00 0.03 0.00 0.00 0.06 0.12 0.21 0.35 0.27 0.24 cf 0.00 0.00 0.00 0.03 0.03 0.03 0.03 0.06 0.06 0.06 0.12 0.24 0.45 0.80 1.07 1.31 13-18 f 0.00 0.01 0.00 0.01 0.02 0.00 0.01 0.03 0.03 0.00 0.10 0.08 0.18 0.36 0.40 0.29 19-24 cf 0.00 0.01 0.01 0.02 0.04 0.04 0.05 0.08 0.11 0.11 0.21 0.29 0.47 0.83 1.23 1.52 f 0.13 0.05 0.03 0.16 0.02 0.02 0.19 0.28 0.20 0.01 0.04 0.16 0.26 0.26 0.33 0.26 cf 0.00 0.05 0.05 0.21 0.23 0.23 0.42 0.70 0.90 0.91 0.95 1.11 1.37 1.63 1.96 2.22 Represents output from the IDNR visibility tool design to determine the joint frequency distribution for combinations of stability class and wind speed. Des Moines meteorological data downloaded from the IDNR website was used in the analysis. (b) This condition is the first occurrence of a cumulative frequency combination of stability and wind speed above 1 percent and was the starting point for the visibility analysis. Note that this combination reaches a 1 percent occurrence during the night-time hours of 1 to 6 am when no visible plume would be detected. (c) Dispersion conditions with transport times longer than 12 hours are not added to the cumulative frequency summation. Table 16 VISCREEN Level 2 Model Results for Union Grove State Park Delta E Contrast Background Theta (Degrees) Distance (km) Plume Criteria Plume Criteria Sky 10 15.0 1.379 4.94 0.011 0.08 Sky 140 15.0 0.840 2.00 -0.017 0.08 Terrain 10 13.9 3.286 3.96 0.030 0.09 Terrain 140 13.9 0.533 2.00 0.015 0.09 52 Table 17 VISCREEN Level 2 Model Results for Rock Creek State Park Delta E Contrast Background Theta (Degrees) Distance (km) Plume Criteria Plume Criteria Sky 10 34.4 0.341 3.00 0.003 0.05 Sky 140 34.4 0.163 2.00 -0.004 0.05 Terrain 10 29.2 0.446 3.35 0.005 0.06 Terrain 140 29.2 0.084 2.00 0.003 0.06 MODELING DATA SUBMITTAL Electronic files, including all input and output files, of the air dispersion modeling analyses are included on electronic media in Attachment 5. Please review the proposed modeling methodology and results and provide comments. Should you have any questions concerning the content of this letter, please contact me at 319-786-4476, or by e-mail at [email protected] Sincerely, Alan Arnold Senior Environmental Specialist Interstate Power and Light Cc: Jeff Beer, IPL Project Director Andy Byers, Environmental Manager, Black & Veatch Tim Hillman, Air Permitting Manager, Black & Veatch 53 Attachment 1 Project Arrangements Attachment 2 Performance and Emissions Calculations Emissions Calculations - Stack Project Date Engineer Basis Composition of Gas Exiting Stack (lb/hr) Fuel Type: Case: Interstate Power and Light (IP&L) 17-Oct-07 William Stevenson Stack PRB - 1 M10- Run PRB-1 IL - 1 M10- Run IL-1 PRB - 2 M10- Run PRB-2 IL - 2 M10- Run IL-2 Oxygen Nitrogen Chlorine Carbon Dioxide Sulfur Dioxide Moisture 353,161 4,800,280 0 1,358,469 380 837,451 423,364 4,813,179 0 1,280,117 494 699,458 336,116 4,566,406 0 1,292,086 361 700,434 399,863 4,547,159 0 1,209,205 466 567,035 Total Flue Gas Flow Rate (lb/hr) 7,349,741 7,216,612 6,895,403 6,723,728 261,473 288,852 232,601 257,966 Oxygen Nitrogen Chlorine Carbon Dioxide Sulfur Dioxide Moisture 11,040 171,360 0 30,870 6 46,490 13,230 171,820 0 29,090 8 38,830 10,500 163,010 0 29,360 6 38,880 12,500 162,320 0 27,480 7 31,480 Total Flue Gas Flow Rate (moles/hr) 259,766 252,978 241,756 233,787 Stack Exit Conditions Fuel Type: Case: Fuel Burn Rate, MBtu/hr Fuel Higher Heating Value, Btu/lb Fuel Burn Rate, lb/hr Wet Molecular Weight, lb/mole Flue Gas Density, lb/cuft Total Gas Flow Rate, acfm Total Gas Flow Rate leaving A/H, acfm Temperature, F Pressure, in w.g. Stack Exit Velocity, ft/sec Stack Exit Area (ft2) Stack Diameter (feet) PRB - 1 M10- Run PRB-1 6,326 8,300 762,157 28.29 0.0631 1,940,460 2,392,341 130 0 59.2 546.63 26.38 IL - 1 M10- Run IL-1 6,169 10,800 571,210 28.53 0.0641 1,876,128 2,337,509 130 0 57.2 546.63 26.38 PRB - 2 M10- Run PRB-2 6,017 8,300 724,913 28.52 0.0641 1,793,722 2,202,160 130 0 54.7 546.63 26.38 IL - 2 M10- Run IL-2 5,828 10,800 539,605 28.76 0.0652 1,719,350 2,135,983 120 0 52.4 546.63 26.38 Nitrogen Oxide NOX Uncontrolled Emission Rate, lb/Mbtu 0.20 0.20 0.20 0.20 NOX Uncontrolled Emission Rate, ppmvw (actual O 2) 106 106 108 108 NOX Controlled Emission Rate, lb/MBtu 0.05 0.05 0.05 0.05 NOX Controlled Emissions, lb/hr 316.3 308.5 300.8 291.4 26 27 27 27 5,025 92.4% 380 35,493 98.6% 494 4,780 92.4% 361 33,529 98.6% 466 Moisture Added by wet FGD Composition of Gas Exiting Stack (moles/hr) NOX Controlled Emissions, ppmvw (actual O2) Sulfur Dioxide Uncontrolled SO 2 Emissions, lb/hr Scrubber Removal Efficiency, % Controlled SO 2 Emissions, lb/hr Controlled SO 2 Emissions, moles/hr 6 8 6 7 Controlled SO 2 Emissions, ppmw 23.1 31.6 24.8 29.9 Controlled SO 2 Emissons, lb/MBtu 0.06 0.08 0.06 0.08 Carbon Monoxide (CO) CO Emission Rate, lb/MBtu CO Emission Rate, lb/hr 0.12 759 0.12 740 0.12 722 0.12 699 Emissions Calculations - Stack Project Date Engineer Basis Fuel Type: Case: Sulfur Trioxide (SO3) Interstate Power and Light (IP&L) 17-Oct-07 William Stevenson Stack PRB - 1 M10- Run PRB-1 IL - 1 M10- Run IL-1 PRB - 2 M10- Run PRB-2 IL - 2 M10- Run IL-2 SO2 to SO3 Conversion Rate (Boiler and SCR Total), % 2.00 2.00 2.00 2.00 Uncontrolled SO 3 Emissions, lb/hr 125.5 886.8 119.4 837.7 Uncontrolled SO 3 Emissions, moles/hr 1.57 11.08 1.49 10.47 Uncontrolled SO 3 Emissions, ppmvw (actual O2) 6.0 43.8 6.2 44.8 153.8 1086.3 146.3 1026.2 Uncontrolled SO 3 Emissions as H2SO4, lb/hr Controlled SO 3 Emissions, lb/hr Controlled SO 3 Emissions, lb/MBtu Controlled SO 3 Emissions, as H2SO4 lb/hr Controlled SO 3 Emissions, as H2SO4 lb/MBtu Particulate (PM+PM10) Ash Content in Fuel, percent Unburned Carbon, lb/hr Uncontrolled Particulate Emissions, lb/hr Uncontrolled Particulate Emission Rate , lb/MBtu Uncontrolled Particulate, Emissions, gr/acf Controlled Particulate Emissions (Filterable), lb/hr Controlled Particulate Emission Rate (Filterable), lb/MBtu Controlled Particulate, Emissions (Filterable), gr/acf Controlled Particulate Emissions (Filterable + Condensible), lb/hr Controlled Particulate Emission Rate (Filterable + Condensible), lb/mmbtu Controlled Particulate, Emissions (Filterable + Condensible), gr/acf Volatile Organic Compounds (VOC) VOC Emission Rate, lb/MBtu VOC Emission Rate, lb/hr Mercury (Hg) Hg Emission Rate, lb/MW-hr Ammonia Slip (NH3) 20.7 20.1 19.6 19.0 0.0033 0.0033 0.0033 0.0033 25.3 24.7 24.1 23.3 0.0040 0.0040 0.0040 0.0040 4.93% 380 30,439 4.81 1.83 75.9 0.012 0.0046 113.9 0.018 0.0068 9.52% 370 43,874 7.11 2.73 74.0 0.012 0.0046 111.0 0.018 0.0069 4.93% 361 28,952 4.81 1.88 72.2 0.012 0.0047 108.3 0.018 0.0070 9.52% 350 41,446 7.11 2.81 69.9 0.012 0.0047 104.9 0.018 0.0071 0.0034 21.51 0.0034 20.97 0.0034 20.46 0.0034 19.81 6.6E-05 6.6E-05 6.6E-05 6.6E-05 Ammonia Slip, ppmvd (at 3% O2) Ammonia Slip, lb/hr Fluorides as HF HF Emission Rate, lb/Mbtu HF Emission Rate, lb/hr 2.00 7.3 2.00 7.3 2.00 6.9 2.00 6.9 0.0002 1.27 0.0002 1.23 0.0002 1.20 0.0002 1.17 Consumables Water (gpm) Limestone (lb/hr) Sorbent Injection (lb/hr)5 Powdered Activated Carbon -- PAC sorbent injection (lb/hr) Ammonia (Anhydrous) (lb/hr) Ammonia (Aqueous @ 19% NH 3) (lb/hr) 543 7,786 222 431 375 1,976 747 59,305 2,011 421 366 1,928 484 7,407 212 396 357 1,880 677 55,827 1,899 384 346 1,822 30,363 28,917 1,953 7,515 12,589 43,799 41,680 2,614 10,876 95,663 28,879 27,504 1,844 7,148 11,995 41,376 39,374 2,457 10,274 90,062 Waste Products Total Fly Ash Removed (lb/hr) Sellable Fly Ash (lb/hr) Non-sellable Fly Ash (lb/hr) Bottom Ash (lb/hr) Total Byproducts [gypsum] from FGD -- dry basis (lb/hr) Assumptions: 1. Fly Ash / Bottom Ash Split is 80/20. 2. Unit MW at Design Load is 649 MW Net References: 1. M-10 Run: IPL Base Load Coal Plant - M-10 Run PRB-1 by Kris Gamble, 5/18/07 2. M-10 Run: IPL Base Load Coal Plant - M-10 Run IL-1 by Kris Gamble, 5/18/07 3. M-10 Run: IPL Base Load Coal Plant - M-10 Run PRB-2 (Max fuel input at mean ambient temperature) by Kris Gamble, 7/31/2007 4. M-10 Run: IPL Base Load Coal Plant - M-10 Run IL-2 (Max fuel input at mean ambient temperature) by Kris Gamble, 7/31/2007 5. SOLVAY Chemicals, SOLVAir Select Application Guide (Sorbent Injection Rate) Notes: 1. Stack Exit Area and Stack Diameter was set by the PRB - Biomass Fuel case due to the fact that it had the greatest stack flow which drives the stack diameter. Emissions Calculations - Stack Project Date Engineer Basis Composition of Gas Exiting Stack (lb/hr) Fuel Type: Case: Interstate Power and Light (IP&L) 17-Oct-07 William Stevenson Stack PRB - 2 75% of Max. Heat Input PRB-2 IL - 2 75% of Max. Heat Input IL-2 PRB - 2 50% of Max. Heat Input PRB-2 IL - 2 50% of Max. Heat Input IL-2 Oxygen Nitrogen Chlorine Carbon Dioxide Sulfur Dioxide Moisture 292,251 3,690,683 0 1,018,760 285 557,461 362,083 3,757,638 0 960,128 370 459,511 255,388 2,661,283 0 679,246 190 374,026 288,811 2,662,403 0 640,154 247 312,105 Total Flue Gas Flow Rate (lb/hr) 5,559,440 5,539,730 3,970,133 3,903,720 187,991 213,141 126,349 146,793 Oxygen Nitrogen Chlorine Carbon Dioxide Sulfur Dioxide Moisture 9,130 131,750 0 23,150 4 30,940 11,320 134,140 0 21,820 6 25,510 7,980 95,000 0 15,430 3 20,760 9,030 95,040 0 14,550 4 17,320 Total Flue Gas Flow Rate (moles/hr) 194,974 192,796 139,173 135,944 Stack Exit Conditions Fuel Type: Case: Fuel Burn Rate, MBtu/hr Fuel Higher Heating Value, Btu/lb Fuel Burn Rate, lb/hr Wet Molecular Weight, lb/mole Flue Gas Density, lb/cuft Total Gas Flow Rate, acfm Total Gas Flow Rate leaving A/H, acfm Temperature, F Pressure, in w.g. Stack Exit Velocity, ft/sec Stack Exit Area (ft2) Stack Diameter (feet) PRB - 2 75% of Max. Heat Input PRB-2 4,744 8,300 571,566 28.51 0.0641 1,445,407 1,738,831 125 0 44.1 546.63 26.38 IL - 2 75% of Max. Heat Input IL-2 4,627 10,800 428,426 28.73 0.0652 1,416,164 1,725,456 120 0 43.2 546.63 26.38 PRB - 2 50% of Max. Heat Input PRB-2 3,163 8,300 381,084 28.53 0.0644 1,027,703 1,228,459 125 0 31.3 546.63 26.38 IL - 2 50% of Max. Heat Input IL-2 3,085 10,800 285,648 28.72 0.0653 996,132 1,211,621 120 0 30.4 546.63 26.38 Nitrogen Oxide NOX Uncontrolled Emission Rate, lb/MBtu 0.20 0.20 0.20 0.20 NOX Uncontrolled Emission Rate, ppmvw (actual O 2) 106 104 99 99 NOX Controlled Emission Rate, lb/MBtu 0.05 0.05 0.05 0.05 NOX Controlled Emissions, lb/hr 237.2 231.4 158.2 154.3 26 26 25 25 3,769 92.4% 285 26,621 98.6% 370 2,513 92.4% 190 17,749 98.6% 247 Moisture Added by wet FGD Composition of Gas Exiting Stack (moles/hr) NOX Controlled Emissions, ppmvw (actual O2) Sulfur Dioxide Uncontrolled SO 2 Emissions, lb/hr Scrubber Removal Efficiency, % Controlled SO 2 Emissions, lb/hr Controlled SO 2 Emissions, moles/hr 4 6 3 4 Controlled SO 2 Emissions, ppmw 20.5 31.1 21.6 29.4 Controlled SO 2 Emissons, lb/MBtu 0.06 0.08 0.06 0.08 Carbon Monoxide (CO) CO Emission Rate, lb/MBtu CO Emission Rate, lb/hr 0.12 569 0.12 555 0.12 380 0.12 370 Emissions Calculations - Stack Project Date Engineer Basis Fuel Type: Case: Sulfur Trioxide (SO3) Interstate Power and Light (IP&L) 17-Oct-07 William Stevenson Stack PRB - 2 75% of Max. Heat Input PRB-2 IL - 2 75% of Max. Heat Input IL-2 PRB - 2 50% of Max. Heat Input PRB-2 IL - 2 50% of Max. Heat Input IL-2 SO2 to SO3 Conversion Rate (Boiler and SCR Total), % 2.00 2.00 2.00 2.00 Uncontrolled SO 3 Emissions, lb/hr 94.2 665.1 62.8 443.4 Uncontrolled SO 3 Emissions, moles/hr 1.18 8.31 0.78 5.54 Uncontrolled SO 3 Emissions, ppmvw (actual O2) 6.0 43.1 5.6 40.8 115.4 814.8 76.9 543.2 Uncontrolled SO 3 Emissions as H2SO4, lb/hr Controlled SO 3 Emissions, lb/hr 15.5 15.1 10.3 10.1 0.0033 0.0033 0.0033 0.0033 Controlled SO 3 Emissions, as H2SO4 lb/hr 19.0 18.5 12.7 12.3 Controlled SO 3 Emissions, as H2SO4 lb/MBtu 0.004 0.004 0.004 0.004 4.93% 285 22,827 4.81 1.84 56.9 0.012 0.0046 85.4 0.018 0.0069 9.52% 278 32,907 7.11 2.71 55.5 0.012 0.0046 83.3 0.018 0.0069 4.93% 190 15,220 4.81 1.73 38.0 0.012 0.0043 56.9 0.018 0.0065 9.52% 185 21,940 7.11 2.57 37.0 0.012 0.0043 55.5 0.018 0.0065 0.0034 16.13 0.0034 15.73 0.0034 10.75 0.0034 10.49 6.6E-05 Controlled SO 3 Emissions, lb/Mbtu Particulate (PM+PM10) Ash Content in Fuel, percent Unburned Carbon, lb/hr Uncontrolled Particulate Emissions, lb/hr Uncontrolled Particulate Emission Rate , lb/mmbtu Uncontrolled Particulate, Emissions, gr/acf Controlled Particulate Emissions (Filterable), lb/hr Controlled Particulate Emission Rate (Filterable), lb/MBtu Controlled Particulate, Emissions (Filterable), gr/acf Controlled Particulate Emissions (Filterable + Condensible), lb/hr Controlled Particulate Emission Rate (Filterable + Condensible), lb/MBtu Controlled Particulate, Emissions (Filterable + Condensible), gr/acf Volatile Organic Compounds (VOC) VOC Emission Rate, lb/MBtu VOC Emission Rate, lb/hr Mercury (Hg) Hg Emission Rate, lb/MW-hr Ammonia Slip (NH3) 6.6E-05 6.6E-05 6.6E-05 Ammonia Slip, ppmvd (at 3% O2) Ammonia Slip, lb/hr Fluorides as HF HF Emission Rate, lb/MBtu HF Emission Rate, lb/hr 2.00 5.6 2.00 5.7 2.00 4.0 2.00 4.0 0.0002 0.95 0.0002 0.93 0.0002 0.63 0.0002 0.62 Consumables Water (gpm) Limestone (lb/hr) Sorbent Injection (lb/hr)5 Powdered Activated Carbon -- PAC sorbent injection (lb/hr) Ammonia (Aqueous @ 19% NH 3) (lb/hr) 391 5,840 167 313 1,483 554 44,480 1,508 311 1,447 263 3,894 111 221 990 379 29,657 1,005 218 966 22,770 21,686 1,454 5,636 9,452 32,851 31,261 1,956 8,157 71,797 15,182 14,459 982 3,757 6,301 21,903 20,843 1,315 5,439 47,835 Waste Products Total Fly Ash Removed (lb/hr) Sellable Fly Ash (lb/hr) Non-sellable Fly Ash (lb/hr) Bottom Ash (lb/hr) Total Byproducts [gypsum] from FGD -- dry basis (lb/hr) Assumptions: 1. Fly Ash / Bottom Ash Split is 80/20. 2. Unit MW at Design Load is 649 MW Net References: 1. M-10 Run: IPL Base Load Coal Plant: 75% of Maximum Heat Input - Mean Ambient PRB-2 by Kris Gamble, 5/18/07 2. M-10 Run: IPL Base Load Coal Plant: 75% of Maximum Heat Input - Mean Ambient IL-2 by Kris Gamble, 5/18/07 3. M-10 Run: IPL Base Load Coal Plant: 50% of Maximum Heat Input - Mean Ambient PRB-2 by Kris Gamble, 5/18/07 4. M-10 Run: IPL Base Load Coal Plant: 50% of Maximum Heat Input - Mean Ambient IL-2 by Kris Gamble, 5/18/07 5. SOLVAY Chemicals, SOLVAir Select Application Guide (Sorbent Injection Rate) Notes: 1. Stack Exit Area and Stack Diameter was set by the PRB - Biomass Fuel case due to the fact that it had the greatest stack flow which drives the stack diameter. Emissions Calculations - Stack Project Date Engineer Basis Composition of Gas Exiting Stack (lb/hr) Fuel Type: Case: Interstate Power and Light (IP&L) 17-Oct-07 William Stevenson Stack PRB - BM M10- Run PRB Coal - Biomass IL - BM M10- Run Illinois Coal - Biomass Oxygen Nitrogen Chlorine Carbon Dioxide Sulfur Dioxide Moisture 376,484 4,869,907 0 1,362,592 380 845,488 444,174 4,886,735 0 1,288,479 495 716,861 Total Flue Gas Flow Rate (lb/hr) 7,454,851 7,336,744 265,302 293,964 Oxygen Nitrogen Chlorine Carbon Dioxide Sulfur Dioxide Moisture 11,770 173,840 0 30,960 6 46,930 13,880 174,440 0 29,280 8 39,790 Total Flue Gas Flow Rate (moles/hr) 263,506 257,398 Moisture Added by wet FGD Composition of Gas Exiting Stack (moles/hr) Stack Exit Conditions Fuel Type: PRB - BM IL - BM M10- Run PRB Coal - Biomass 6,333 8,207 771,688 28.29 0.0631 1,967,862 2,427,142 130 0 60.0 M10- Run Illinois Coal - Biomass 6,187 10,488 589,902 28.50 0.0640 1,909,549 2,381,044 125 0 58.2 546.63 26.38 546.63 26.38 Nitrogen Oxide NOX Uncontrolled Emission Rate, lb/MBtu 0.20 0.20 NOX Uncontrolled Emission Rate, ppmvw (actual O 2) 105 105 NOX Controlled Emission Rate, lb/MBtu 0.05 0.05 NOX Controlled Emissions, lb/hr 316.7 309.3 Case: Fuel Burn Rate, MBtu/hr Fuel Higher Heating Value, Btu/lb Fuel Burn Rate, lb/hr Wet Molecular Weight, lb/mole Flue Gas Density, lb/cuft Total Gas Flow Rate, acfm Total Gas Flow Rate leaving A/H, acfm Temperature, F Pressure, in w.g. Stack Exit Velocity, ft/sec Stack Exit Area (ft 2) Stack Diameter (feet) NOX Controlled Emissions, ppmvw (actual O 2) Sulfur Dioxide Uncontrolled SO 2 Emissions, lb/hr Scrubber Removal Efficiency, % Controlled SO 2 Emissions, lb/hr Controlled SO 2 Emissions, moles/hr 26 26 4,873 92.2% 380 33,907 98.5% 495 6 8 Controlled SO 2 Emissions, ppmw 22.8 31.1 Controlled SO 2 Emissons, lb/MBtu 0.06 0.08 Carbon Monoxide (CO) CO Emission Rate, lb/MBtu CO Emission Rate, lb/hr 0.12 760 0.12 742 Emissions Calculations - Stack Project Date Engineer Basis Fuel Type: Case: Sulfur Trioxide (SO3) Interstate Power and Light (IP&L) 17-Oct-07 William Stevenson Stack PRB - BM M10- Run PRB Coal - Biomass IL - BM M10- Run Illinois Coal - Biomass SO2 to SO3 Conversion Rate (Boiler and SCR Total), % 2.00 2.00 Uncontrolled SO 3 Emissions, lb/hr 121.7 847.1 Uncontrolled SO 3 Emissions, moles/hr 1.52 10.58 Uncontrolled SO 3 Emissions, ppmvw (actual O 2) 5.8 41.1 149.1 1037.8 Uncontrolled SO 3 Emissions as H2SO4, lb/hr Controlled SO 3 Emissions, lb/hr Controlled SO 3 Emissions, lb/Mbtu 20.7 20.2 0.0033 0.0033 Controlled SO 3 Emissions, as H2SO4 lb/hr 25.3 24.7 Controlled SO 3 Emissions, as H2SO4 lb/MBtu 0.004 0.004 4.93% 380 30,785 4.86 1.83 76.0 0.012 0.0045 114.0 0.018 0.0068 9.16% 371 43,591 7.05 2.66 74.2 0.012 0.0045 111.4 0.018 0.0068 0.0034 21.53 0.0034 21.04 6.6E-05 6.6E-05 Particulate (PM+PM 10) Ash Content in Fuel, percent Unburned Carbon, lb/hr Uncontrolled Particulate Emissions, lb/hr Uncontrolled Particulate Emission Rate , lb/MBtu Uncontrolled Particulate, Emissions, gr/acf Controlle