Oklahoma Gas & Electric

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1 Oklahoma Gas & Electric Sooner Generating Station Best Available Retrofit Control Technology Evaluation Prepared by: Sargent & Lundy LLC Chicago, Illinois Trinity Consultants Oklahoma City, Oklahoma May 27, 2008

2 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Table of Contents Page Table of Contents 1 EXECUTIVE SUMMARY INTRODUCTION OG&E s Sooner Generating Station BART Applicability Review BART Requirements SOONER UNITS 1 & 2 BART DETERMINATION METHODOLOGY Presumptive BART Emission Rates BART DETERMINATION FOR NITROGEN OXIDES (NOx) Step 1: Identify Potentially Feasible NOx Control Options Step 2: Technical Feasibility of Potential Control Options Step 3: Rank the Technically Feasible NOx Control Options by Effectiveness Step 4: Evaluate the Technically Feasible NOx Control Technologies Step 5: Evaluate Visibility Impacts Propose BART for NOx Control at Sooner Units 1 & BART ANALYSIS FOR MAIN BOILER SULFUR DIOXIDE (SO 2 ) Step 1: Identify Potentially Feasible SO 2 Control Options Step 2: Technical Feasibility of Potential Control Options Step 5: Evaluate Visibility Impacts Propose BART for SO 2 Control BART ANALYSIS FOR MAIN BOILER PARTICULATE MATTER Step 1: Identify Available Retrofit PM10 Control Options Step 2: Eliminate Technically Infeasible Retrofit Options Step 3: Rank the Technically Feasible PM10 Control Options by Effectiveness Step 4: Evaluate Impacts and Document the Results Step 5: Evaluate Visibility Impacts Propose BART for PM10 Control BART SUMMARY 62 Economic Evaluation Methodology for 2 Technically Feasible Control Options 2 TOC-1

3 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No EXECUTIVE SUMMARY OG&E s Sooner Generating Station is located at County Road 230 near Red Rock, Oklahoma. The station includes two nominal 570 MW (gross) coal-fired units designated as Sooner Unit 1 and Sooner Unit 2. Sooner Units 1 & 2, which became operational in 1974, are dry bottom tangentially-fired pulverized coal (PC) boilers. Both boilers fire subbituminous coal as their primary fuel, and both units are equipped with electrostatic precipitators for particulate control. On July 6, 2005, the U.S. Environmental Protection Agency (EPA) published the final Regional Haze Regulations and Guidelines for Best Available Retrofit Technology Determinations (the Regional Haze Rule 70 FR 39104). The Regional Haze Rule requires certain States, including Oklahoma, to develop programs to assure reasonable progress toward meeting the national goal of preventing any future, and remedying any existing, impairment of visibility in Class I Areas. The Regional Haze Rule requires states to submit a plan to implement the regional haze requirements (the Regional Haze SIP). The Regional Haze SIP must provide for a Best Available Retrofit Technology (BART) analysis of any existing stationary facility that might cause or contribute to impairment of visibility in a Class I Area. BART-eligible sources include those sources that: (1) have the potential to emit 250 tons or more of a visibility-impairing air pollutant; (2) were in existence on August 7, 1977 but not in operation prior to August 7, 1962; and (3) whose operations fall within one or more of the specifically listed source categories in 40 CFR (including fossil-fuel fired steam electric plants of more than 250 mmbtu/hr heat input and fossil-fuel boilers of more than 250 mmbtu/hr heat input). Sooner Units 1 & 2 are fossil-fuel fired boilers with heat inputs greater than 250 mmbtu/hr. Both units were in existence prior to August 7, 1977, but not in operation prior to August 7, 1962, and based on a review of existing emissions data, both units have the potential to emit more than 250 tons per year of visibility impairing pollutants. Therefore, Sooner Units 1 & 2 meet the definition of a BART-eligible source. BART is required for any BART-eligible source that emits any air pollutant which may reasonably be anticipated to cause or contribute to any impairment of visibility in a Class I Area. U.S.EPA has determined that an individual source will be considered to contribute to visibility impairment if emissions from the source result in a change in visibility, measured as a change in deciviews ( -dv), that is greater than or equal to 0.5 dv in a Class I area. Visibility impact modeling previously conducted by OG&E determined that the maximum predicted visibility ES-1

4 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No impacts from Sooner Units 1 & 2 exceeded the 0.5 -dv threshold at the Wichita Mountains Class I Area. Therefore, Sooner Units 1 & 2 were determined to be BART-applicable sources, subject to the BART determination requirements. Guidelines for making BART determinations are included in Appendix Y of 40 CFR Part 51 (Guidelines for BART Determinations Under the Regional Haze Rule). States are required to use the Appendix Y guidelines to make BART determinations for fossil-fuel-fired generating plants having a total generating capacity in excess of 750 MW. The BART determination process described in Appendix Y includes the following steps: Step 1. Identify All Available Retrofit Control Technologies. Step 2. Eliminate Technically Infeasible Options. Step 3. Evaluate Control Effectiveness of Remaining Control Technologies. Step 4. Evaluate Impacts and Document the Results. Step 5. Evaluate Visibility Impacts. This report is the BART determination for Sooner Units 1 & 2. Because the Sooner Generating Station has a total generating capacity in excess of 750 MW, the Appendix Y guidelines were used to prepare the BART determination. Based on an evaluation of potentially feasible retrofit control technologies, including an assessment of the costs and visibility improvements associated therewith, OG&E is proposing the BART control technologies and emission rates listed in Table ES-1. Table ES-1 Sooner Units 1 & 2 Proposed BART Permit Limits and Control Technologies Pollutant NO x Proposed BART Emission Limit 0.15 lb/mmbtu (30-day average) Proposed BART Technology Combustion controls including LNB and OFA SO 2 Existing Permit Limits Low sulfur coal PM 10 filterable Existing Permit Limits NA ES-2

5 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No INTRODUCTION On July 6, 2005, the U.S. Environmental Protection Agency (EPA) published the final Regional Haze Regulations and Guidelines for Best Available Retrofit Technology Determinations (the Regional Haze Rule 70 FR 39104). EPA issued the Regional Haze Rule under the authority and requirements of sections 169A and 169B of the Clean Air Act (CAA). Sections 169A and 169B require EPA to address regional haze visibility impairment in 156 federally-protected parks and wilderness areas (Class I Areas). As mandated by the CAA, the Regional Haze Rule requires certain large stationary sources to install the best available retrofit technology (BART) to reduce emissions of pollutants that may impact visibility in a Class I Area. The Regional Haze Rule requires certain States, including Oklahoma, to develop programs to assure reasonable progress toward meeting the national goal of preventing any future, and remedying any existing, impairment of visibility in Class I Areas. The Regional Haze Rule requires states to submit a plan to implement the regional haze requirements (the Regional Haze SIP). The Regional Haze SIP must provide for a BART analysis of any existing stationary facility that might cause or contribute to impairment of visibility in a Class I Area. To address the requirements for BART, Oklahoma must: Identify all BART-eligible sources within the State. Determine whether each BART-eligible source emits any air pollutant which may reasonably be anticipated to cause or contribute to any impairment of visibility in a Class I Area. BART-eligible sources which may reasonably be anticipated to cause or contribute to visibility impairment are classified as BART-applicable sources. Require each BART-applicable source to identify, install, operate, and maintain BART controls. 1.1 OG&E s Sooner Generating Station OG&E s Sooner Generating Station is located at County Road 230 near Red Rock, Oklahoma. The station includes two nominal 570 MW (gross) coal-fired units designated as Sooner Unit 1 and Sooner Unit 2. Sooner Units 1 & 2, which became operational in 1974, are dry bottom tangentially-fired pulverized coal (PC) boilers. Both boilers fire subbituminous coal as their primary fuel, and both units are equipped with electrostatic precipitators for particulate control. 1.2 BART Applicability Review BART-eligible sources include those sources that: (1) have the potential to emit 250 tons or more of a visibility-impairing air pollutant; (2) were in existence on August 7, 1977 but not in operation prior to August 7, 1962; and 1

6 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No (3) whose operations fall within one or more of the specifically listed source categories in 40 CFR (including fossil-fuel fired steam electric plants of more than 250 mmbtu/hr heat input and fossil-fuel boilers of more than 250 mmbtu/hr heat input). Sooner Units 1 & 2 are fossil-fuel fired boilers with heat inputs greater than 250 mmbtu/hr. Both units were in existence prior to August 7, 1977, but not in operation prior to August 7, Based on baseline emissions data, summarized below in Table 2-1, both units have the potential to emit more than 250 tons per year of visibility impairing pollutants. Therefore, the facilities meet the definition of a BART-eligible source. BART is required for any BART-eligible source that emits any air pollutant which may reasonably be anticipated to cause or contribute to any impairment of visibility in a Class I Area. U.S.EPA has determined that an individual source will be considered to cause visibility impairment if emissions from the source result in a change in visibility, measured as a change in deciviews ( dv), that is greater than or equal to 1.0 dv on the visibility in a Class I area. An individual source is considered to contribute to visibility impairment if emissions from the source result in a -dv change greater than or equal to 0.5 dv in a Class I area. Class I areas nearest the Sooner Station include: Distance from Class I Area Name Sooner Station (km) Wichita Mountains National Wildlife Refuge (Oklahoma) 235 Caney Creek Wilderness Area (Arkansas) 346 Upper Buffalo Wilderness Area (Arkansas) 329 Hercules-Glades Wilderness Area (Missouri) 364 Visibility impact modeling was conducted by OG&E to determine the baseline predicted maximum 98 th percentile -dv visibility impact from Sooner Units 1 & 2. The maximum predicted visibility impact associated with the Sooner Station exceeded the 0.5 -dv threshold at the Wichita Mountains Class I Area. Therefore, the facility was determined to be a BART-applicable source subject to the BART determination requirements. 1.3 BART Requirements A determination of BART must be based on an analysis of the best system of continuous emission control technology available and associated emission reductions achievable. The BART analysis must take into consideration: (1) the technology available; (2) the costs of compliance; (3) the energy and non-air-quality environmental impacts of compliance; (4) any pollution control equipment in use at the source; (5) the remaining useful life of the source; and (6) the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology. 2

7 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Guidelines for making BART determinations are included in Appendix Y of 40 CFR Part 51 (Guidelines for BART Determinations Under the Regional Haze Rule). States are required to use the Appendix Y guidelines to make BART determinations for fossil-fuel-fired generating plants having a total generating capacity in excess of 750 MW, but are not required to use the guidelines when making BART determinations for other types of sources. Because the Sooner Generating Station has a total generating capacity in excess of 750 MW, the Appendix Y guidelines were used to prepare the BART determination. The Appendix Y guidelines for BART determinations identify the following five steps in a case-bycase BART analysis: Step 1. Identify All Available Retrofit Control Technologies. Step 2. Eliminate Technically Infeasible Options. Step 3. Evaluate Control Effectiveness of Remaining Control Technologies. Step 4. Evaluate Impacts and Document the Results. Step 5. Evaluate Visibility Impacts. A more detailed description of each step is provided below. Step 1. Identify all available retrofit control technologies. Available retrofit control options are those air pollution control technologies with a practical potential for application to the emissions unit and the regulated pollutant under evaluation (70 FR col. 1). Step 1 of the BART determination requires applicants to identify potentially applicable retrofit control technologies that represent the full range of demonstrated alternatives. Potentially applicable retrofit control alternatives can include pollution prevention strategies, the use of add-on controls, or a combination of control strategies. Control technologies required under the new source review (NSR) program as best available control technology (BACT) or lowest achievable emission rate (LAER) are available for BART purposes and must be included as potential control alternatives. However, EPA does not consider BART as a requirement to redesign the source when considering available control alternatives. In an effort to identify all potentially applicable retrofit technologies appropriate for use at each station, information sources consulted included, but were not necessarily limited to, the following: EPA's RACT/BACT/LAER Clearinghouse (RBLC) Database; New & Emerging Environmental Technologies (NEET) Database; EPA s New Source Review bulletin board; Information from control technology vendors and engineering/environmental consultants; 3

8 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Federal and State new source review permits and BACT determinations for coal-fired power plants; Recently submitted Federal and State new source review permit applications submitted for coal-fired generating projects; and Technical journals, reports, newsletters and air pollution control seminars. Step 2. Eliminate Technically Infeasible Options. In step 2 of the BART determination, the technical feasibility of each potential retrofit technology is evaluated. Control technologies are considered technically feasible if either (1) they have been installed and operated successfully for the type of source under review under similar conditions, or (2) the technology could be applied to the source under review. A demonstration of technical infeasibility must be based on physical, chemical and engineering principles, and must show that technical difficulties would preclude the successful use of the control option on the emission unit under consideration. The economics of an option are not considered in the determination of technical feasibility/infeasibility. Options that are technically infeasible for the intended application are eliminated from further review. Step 3. Evaluate Control Effectiveness of Remaining Control Technologies. Step 3 of the BART determination involves evaluating the control effectiveness of all the technically feasible control alternatives identified in Step 2 for the pollutant and emissions under review. Control effectiveness is generally expressed as the rate at which a pollutant is emitted after the control system has been installed. The most effective control option is the system that achieves the lowest emissions level. Step 4. Evaluate Impacts and Document the Results. Step 4 of the BART determination involves an evaluation of potential impacts associated with the technically feasible retrofit technologies. The following evaluations should be conducted for each technically feasible technology: (1) costs of compliance; (2) energy impacts; and (3) non-air quality environmental impacts. Costs of Compliance The economic analysis performed as part of the BART determination examines the costeffectiveness of each control technology, on a dollar per ton of pollutant removed basis. Annual emissions using a particular control device are subtracted from baseline emissions to calculate tons of pollutant controlled per year. Annual costs are calculated by adding 4

9 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No annual operation and maintenance costs to the annualized capital cost of an option. Cost effectiveness ($/ton) of an option is simply the annual cost ($/yr) divided by the annual pollution controlled (ton/yr). In addition to the cost effectiveness relative to the base case, the incremental costeffectiveness to go from one level of control to the next more stringent level of control may also be calculated to evaluate the cost effectiveness of the more stringent control. Energy Impact Analysis The energy requirements of a control technology should be examined to determine whether the use of that technology results in any significant or unusual energy penalties or benefits. Two forms of energy impacts associated with a control option can normally be quantified. First, increases in energy consumption resulting from increased heat rate may be shown as total Btu s or fuel consumed per year or as Btu s per ton of pollutant controlled. Second, the installation of a particular control option may reduce the output and/or reliability of equipment. This reduction would result in decreased electricity available to the power grid and/or increased fuel consumption due to use of less efficient electrical and steam generation methods. Non-Air Quality Environmental Impact Analysis The primary purpose of the environmental impact analysis is to assess collateral environmental impacts due to control of the regulated pollutant in question. Environmental impacts may include solid or hazardous waste generation, discharges of polluted water from a control device, increased water consumption, and land use impacts from waste disposal. Impact analyses conducted in step 4 should take into consideration the remaining useful life of the source. For example, the remaining useful life of the source may affect the cost analysis (specifically, the annualized costs of retrofit controls). Step 5. Evaluate Visibility Impacts. Step 5 of the BART determination addresses the degree of improvement in visibility that may reasonably be anticipated to result from the use of a particular control technology. CALPUFF modeling, or other appropriate dispersion modeling, should be used to determine the visibility improvement expected from the potential BART control technology applied to the source. Modeling should be conducted for SO 2, NO x, and direct PM emissions (PM 2.5 and/or PM 10 ). 5

10 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Although visibility improvement must be weighted among the five factors in a BART determination (along with the costs of compliance, energy and non-air-quality environmental impacts, existing pollution control technologies in use at the source, and the remaining life of the source) only potential retrofit control technologies meeting the other four factors were evaluated for visibility impacts. For example, potential retrofit technologies that are not technically feasible will not be evaluated for visibility impacts. The final regulation also states that sources that elect to apply the most stringent controls available need not conduct an air quality modeling analysis for the purpose of determining its visibility impacts (see, 70 FR col. 1). BART control technologies and corresponding emission rates are established based on information developed from the 5-step BART determination process described above. 2.0 SOONER UNITS 1 & 2 BART DETERMINATION METHODOLOGY The BART determination process described in Appendix Y of 40 CFR Part 51 (summarized above) was used to identify BART controls for Sooner Units 1 & 2. The methodology was used to evaluate BART control technologies for NO x, SO 2, and PM 10. Existing operating parameters and baseline emissions for Sooner Units 1 & 2 are summarized in Table 2-1. The operating parameters and emissions summarized in Table 2-1 form the basis for the Sooner Unit 1 & 2 BART determination. Baseline emissions from Sooner Units 1 & 2 were developed based on an evaluation of actual emissions data submitted by the facility pursuant to the federal Acid Rain Program. In accordance with EPA guidelines in 40 CFR 51 Appendix Y Part III, emission estimates used in the modeling analysis to determine visibility impairment impacts should reflect steady-state operating conditions during periods of high capacity utilization. Therefore, baseline emissions (lb/hr) represent the highest 24-hour block emissions reported during the baseline period. Baseline emission rates (lb/mmbtu) were calculated by dividing the maximum hourly mass emission rate by the full load heat input to the boiler. 6

11 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Table 2-1 Plant Operating Parameters for BART Evaluation Parameter Sooner Unit 1 Sooner Unit 2 Plant Configuration Pulverized Coal-Fired Boiler Pulverized Coal-Fired Boiler Firing Configuration tangentially-fired tangentially-fired Plant Output nominal 570 MW (gross) nominal 570 MW (gross) Maximum Input to Boiler 5,116 mmbtu/hr 5,116 mmbtu/hr Primary Fuel subbituminous coal subbituminous coal Existing NOx Controls combustion controls combustion controls Existing SO 2 Controls low-sulfur coal low-sulfur coal Existing PM 10 Controls electrostatic precipitator electrostatic precipitator Baseline Emissions Pollutant Baseline Actual Emissions Baseline Actual Emissions lb/hr lb/mmbtu lb/hr lb/mmbtu NOx 3, , SO 2 4, , PM Presumptive BART Emission Rates In the final Regional Haze Rule U.S.EPA established presumptive BART emission limits for SO 2 and NO x for certain electric generating units (EGUs) based on fuel type, unit size, cost effectiveness, and the presence or absence of pre-existing controls. 1 The presumptive limits apply to EGUs at power plants with a total generating capacity in excess of 750 MW. For these sources, EPA established presumptive emission limits for coal-fired EGUs greater than 200 MW in size. The presumptive levels are intended to reflect highly cost-effective technologies as well as provide enough flexibility to States to consider source specific characteristics when evaluating BART. The BART SO 2 presumptive emission limit for coal-fired EGUs greater than 200 MW in size without existing SO 2 control is either 95% SO 2 removal, or an emission rate of 0.15 lb/mmbtu, unless a State determines that an alternative control level is justified based on a careful consideration of the statutory factors. For NO x, EPA established a set of BART presumptive emission limits for coal-fired EGUs greater than 200 MW in size based upon boiler size and coal type. The BART NO x presumptive emission limit applicable to Sooner Units 1 & 2 (tangentiallyfired boilers firing subbituminous coal) is 0.15 lb/mmbtu. 1 See, 40 CFR 51 Appendix Y Part IV, and 70 FR

12 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No States, as a general matter, should presume that owners and operators of greater than 750 MW power plants can cost effectively meet the presumptive levels. However, the BART process allows consideration of site-specific retrofit costs and site-specific visibility impacts. States have the ability to consider the specific characteristics of the source at issue and to find that the presumptive limits would not be appropriate for that source. Emission control technologies and emission limits that differ from the presumptive levels can be established if it can be demonstrated that an alternative emission rate is justified based on a consideration of the five statutory factors, including the costs of compliance and the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology. 3.0 BART DETERMINATION FOR NITROGEN OXIDES (NOx) The formation of NO x is determined by the interaction of chemical and physical processes occurring primarily within the flame zone of the boiler. There are two principal forms of NO x designated as thermal NO x and fuel NO x. Thermal NO x formation is the result of oxidation of atmospheric nitrogen contained in the inlet gas in the high-temperature, post-flame region of the combustion zone. Fuel NO x is formed by the oxidation of nitrogen in the fuel. NO x formation can be controlled by adjusting the combustion process and/or installing post-combustion controls. The major factors influencing thermal NO x formation are temperature, the concentration of combustion gases (primarily nitrogen and oxygen) in the inlet air, and residence time within the combustion zone. Advanced burner designs can regulate the distribution and mixing of the fuel and air to reduce flame temperatures and residence times at peak temperatures to reduce NO x formation. Coal properties have a major influence on the formation of fuel NO x. Nitrogen compounds are released from the coal during coal combustion. Fuel NO x conversion is generally dependent on the fuel rank. In general, a higher percentage of fuel- NO x is converted to NO x as the rank of fuel decreases. In other words, units firing lower rank coals (e.g., subbituminous coal or lignite) will have higher uncontrolled NO x emissions. 3.1 Step 1: Identify Potentially Feasible NOx Control Options Potentially available control options were identified based on a comprehensive review of available information. NO x control technologies with potential application to Sooner Units 1 & 2 are listed in Table

13 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Table 3-1 List of Potential NO x Control Options Control Technology Combustion Controls Low NO x Burners & Overfire Air (LNB/OFA) Flue Gas Recirculation (FGR) Post-Combustion Controls Selective Noncatalytic Reduction (SNCR) Selective Catalytic Reduction (SCR) Innovative Control Technologies Rotating Overfire Air (ROFA) ROFA + SNCR (Rotamix) Wet NO x Scrubbing 3.2 Step 2: Technical Feasibility of Potential Control Options NO x control technologies can be divided into two general categories: combustion controls and postcombustion controls. Combustion controls reduce the amount of NO x that is generated in the boiler. Post-combustion controls remove NO x from the boiler exhaust gas. The technical feasibility of each potentially applicable NO x control technology is evaluated below Combustion Controls The rate of NO x formation in the combustion zone is a function of free oxygen, peak flame temperature and residence time. Combustion techniques designed to minimize the formation of NO x will minimize one or more of these variables. Combustion control options that may be applicable to the OG&E boilers are described below Low NO x Burners and Overfire Air Low NO x burners (LNB) 2 limit NO x formation by controlling both the stoichiometric and temperature profiles of the combustion flame in each burner flame envelope. This control is achieved with design features that regulate the aerodynamic distribution and mixing of 2 The term LNB is used generically in this BART analysis, and refers to advanced low-nox burners available from leading boiler/burner manufacturers. The term does not represent any vendor-specific trade name. As used in this BART analysis, the term LNB refers to the available advanced low-nox burner technologies. 9

14 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No the fuel and air, yielding reduced oxygen (O 2 ) in the primary combustion zone, reduced flame temperature and reduced residence time at peak combustion temperatures. The combination of these techniques produces lower NO x emissions during the combustion process. In the OFA process, the injection of air into the firing chamber is staged into two zones, in which approximately 5% to 20% of the total combustion air is diverted from the burners and injected through ports located above the top burner level. Staging of the combustion air reduces NO x formation by two mechanisms. First, staged combustion results in a cooler flame, and second the staged combustion results in less oxygen reacting with fuel molecules. The degree of staging is limited by operational problems since the staged combustion results in incomplete combustion conditions and a longer flame. LNB/OFA emission control systems have been installed as retrofit control technologies on existing coal-fired boilers. Coal-fired boilers retrofit with LNB/OFA combustion technologies would be expected to operate with actual average NO x emission levels in the range of 85 to 180 3% O 2 (approximately 0.12 to 0.25 lb/mmbtu) depending on the fuel, burner configuration, and averaging time. Based on a review of emissions data available from the U.S. EPA s electronic emissions data reporting website, subbituminousfired boilers retrofit with LNB/OFA have achieved actual average NO x emission rates in the range of 0.12 to 0.18 lb/mmbtu. 3 Although combustion control systems on coal-fired boilers have demonstrated the ability to achieve average NO x emission rates below 0.15 lb/mmbtu, combustion control systems may not be as effective under all boiler operating conditions, especially during load changes and low load operations. Controlling the stoichiometric and temperature profiles of the combustion flame, and maintaining the air/fuel mixing needed for NO x control, becomes more difficult under these operating scenarios. Therefore, it is likely that shortterm boiler NO x emissions will be higher under certain operating conditions. Furthermore, the mechanisms used to reduce NO x formation (e.g., cooler flame and reduced O 2 availability) also tend to increase the formation and emission of CO and VOCs. Based on information available from burner control vendors, emissions achieved in practice at existing similar sources, and engineering judgment, it is expected that combustion controls, including LNB and OFA, on the tangentially-fired Sooner boilers can be designed to meet the presumptive NO x BART emission rate of 0.15 lb/mmbtu (approximately Emission data are available from U.S.EPA s Electronic Data Reporting website: 10

15 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No % O 2 ). An average emission rate of 0.15 lb/mmbtu should be achievable on a 30-day rolling average basis under all normal boiler operating conditions and while maintaining acceptable CO and VOC emission rates Flue Gas Recirculation Flue gas recirculation (FGR) controls NO x by recycling a portion of the flue gas back into the primary combustion zone. The recycled air lowers NO x emissions by two mechanisms: (1) the recycled gas, consisting of products that are inert during combustion, lowers the combustion temperatures; and (2) the recycled gas will reduce the oxygen content in the primary flame zone. The amount of recirculation is based on flame stability. FGR control systems have been used as a retrofit NOx control strategy on natural gas-fired boilers, but have not generally been considered as a retrofit control technology on coalfired units. Natural gas-fired units tend to have lower O 2 concentrations in the flue gas and low particulate loading. In a coal-fired application, the FGR system would have to handle hot particulate-laden flue gas with a relatively high O 2 concentration. Although FGR has been used on coal-fired boilers for flue gas temperature control, it would not have application on a coal-fired boiler for NOx control. Because of the flue gas characteristics (e.g., particulate loading and O2 concentration), FGR would not operate effectively as a NOx control system on a coal-fired boiler. Therefore, FGR is not considered an applicable retrofit NOx control option for Sooner Units 1 & 2, and will not be considered further in the BART determination Post-Combustion Controls Post-combustion NO x control systems with potential application to Sooner Units 1 & 2 are discussed below Selective Non-Catalytic Reduction Selective non-catalytic reduction (SNCR) involves the direct injection of ammonia (NH 3 ) or urea (CO(NH 2 ) 2 ) at high flue gas temperatures (approximately 1600ºF ºF). The ammonia or urea reacts with NO x in the flue gas to produce N 2 and water as shown in the equations below. (NH 2 ) 2CO + 2NO + ½O 2 2H 2 O + CO 2 + 2N 2 2NH 3 + 2NO + ½O 2 2N 2 + 3H 2 O Flue gas temperature at the point of reagent injection can greatly affect NO x removal efficiencies and the quantity of NH 3 or urea that will pass through the SNCR unreacted 11

16 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No (referred to as NH 3 slip). In general, SNCR reactions are effective in the range of 1,700 o F. At temperatures below the desired operating range, the NO x reduction reactions diminish and unreacted NH 3 emissions increase. Above the desired temperature range, NH 3 is oxidized to NO x resulting in low NO x reduction efficiencies. Mixing of the reactant and flue gas within the reaction zone is also an important factor to SNCR performance. In large boilers, the physical distance over which reagent must be dispersed increases, and the surface area/volume ratio of the convective pass decreases. Both of these factors make it difficult to achieve good mixing of reagent and flue gas, delivery of reagent in the proper temperature window, and sufficient residence time of the reagent and flue gas in that temperature window. In addition to temperature and mixing, several other factors influence the performance of an SNCR system, including residence time, reagent-to-no x ratio, and fuel sulfur content. SNCR control systems have been installed as retrofit NO x control systems on small and medium sized (i.e., less than approximately 300 MW) coal-fired boilers. However, because of design and operating limitations, SNCR has not been used on large subbituminous coalfired boilers. Large subbituminous coal-fired boilers, including Sooner Units 1 & 2, would not be able to achieve adequate reagent mixing and residence time within the required flue gas temperature window to achieve effective NOx reduction. The physical size of the Sooner boilers makes it technically infeasible to locate and install ammonia injection points capable of achieving adequate NH 3 /NOx contact within the required temperature zone. Higher ammonia injection rates would be needed to achieve adequate NH 3 /NOx contact. Higher ammonia injection rates would result in relatively high levels of unreacted ammonia in the flue gas (ammonia slip), which could lead to plugging of downstream equipment. Another design factor limiting the applicability of SNCR control systems on large subbituminous coal-fired boilers is related to the reflective nature of subbituminous ash. Subbituminous coals typically contain high levels of calcium oxide and magnesium oxide that can result in reflective ash deposits on the waterwall surfaces. Because most heat transfer in the furnace is radiant, reflective ash can result in less heat removal from the furnace and higher exit gas temperatures. If ammonia is injected above the appropriate temperature window, it can actually lead to additional NO x formation. SNCR control systems have not been designed or installed on large subbituminous coalfired boilers, and, as described above, there are several currently unresolved technical difficulties with applying SNCR to large subbituminous coal-fired boilers (including the 12

17 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No physical size of the boiler, inadequate NH 3 mixing, and ash characteristics). Even assuming that SNCR could be installed on Sooner Units 1 & 2, NO x control effectiveness would be marginal, and, depending on boiler exit temperatures, could actually result in additional NO x formation. Because SNCR has not been designed for or demonstrated on a large subbituminous coal-fired boiler, it was determined that the control technology is not applicable to Sooner Units 1 & 2, and SNCR will not be evaluated further in the BART determination Selective Catalytic Reduction Selective Catalytic Reduction (SCR) involves injecting ammonia into boiler flue gas in the presence of a catalyst to reduce NO x to N 2 and water. Anhydrous ammonia injection systems may be used, or ammonia may be generated on-site from a urea feedstock. The overall SCR reactions are: 4NH 3 + 4NO + O 2 4N 2 + 6H 2 O 8NH 3 + 4NO 2 + 2O 2 6N H 2 O The performance of an SCR system is influenced by several factors including flue gas temperature, SCR inlet NO x level, the catalyst surface area, volume and age of the catalyst, and the amount of ammonia slip that is acceptable. The optimal temperature range depends on the type of catalyst used, but is typically between 560 o F and 750 o F to maximize NO x reduction efficiency and minimize ammonium sulfate formation. This temperature range typically occurs between the economizer and air heater in a large utility boiler. Below this range, ammonium sulfate is formed resulting in catalyst deactivation. Above the optimum temperature, the catalyst will sinter and thus deactivate rapidly. Another factor affecting SCR performance is the condition of the catalyst material. As the catalyst degrades over time or is damaged, NO x removal decreases. SCR has been installed as a retrofit control technology on existing coal-fired boilers, including boilers firing subbituminous coal. SCR control systems on subbituminous coalfired boilers have achieved annual average NO x emission rates in the range of 0.04 to approximately 0.10 lb/mmbtu. 4 Several design and operating variables will influence the performance of the SCR system, including the volume, age and surface area of the catalyst (e.g., catalyst layers), uncontrolled NO x emission rate, flue gas characteristics (including 4 Emission data are available from U.S.EPA s Electronic Data Reporting website: 13

18 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No temperature, sulfur content, and particulate loading), and catalyst activity. 5 Catalyst that has been in service for a period of time will have decreased performance because of normal deactivation and deterioration. Catalyst that is no longer effective due to plugging, blinding or deactivation must be replaced. Based on emission rates achieved in practice at existing subbituminous coal-fired units, and taking into consideration long-term operation of an SCR control system (including catalyst plugging and deactivation) it is anticipated that SCR could achieve a controlled NO x emission rate of 0.07 lb/mmbtu (30-day rolling average) on Sooner Units 1 & 2. An emission rate of 0.07 lb/mmbtu is equivalent to an average NO x concentration in the flue gas of approximately 50 3% O 2. Reducing NOx emissions below 50 3% O 2 would tend to increase collateral environmental impacts associated with the SCR, including increased ammonia slip, increased SO 2 to SO 3 oxidation, and more frequent catalyst changes Innovative NO x Control Technologies A number of innovative NO x control systems, including multi-pollutant control systems, were identified as potential retrofit control technologies during the review of available documents. Innovative NO x control technologies with potential application to the BART study include boosted over-fire air (e.g., MobotecUSA s ROFA system), advanced SNCR control systems (e.g., MobotecUSA s Rotamix system), Enviroscrub s multi-pollutant Pahlman process, and wet NO x scrubbing systems Rotating Opposed Fired Air and Rotomix Rotating opposed fired air (ROFA) is a boosted overfire air system that includes a patented rotation process which includes asymmetrically placed air nozzles. 6 Like other OFA systems, ROFA stages the primary combustion zone to burn overall rich, with excess air added higher in the furnace to burn out products of incomplete combustion. The ROFA nozzles are designed to increase turbulence within the furnace. Increased turbulence should prevent the formation of stratified laminar flow, enable the furnace volume to be used more 5 See, e.g., Sanyal, A., Pircon, J.J., What and How Should You Know About U.S. Coal to Predict and Improve SCR Performance, proceedings of the USEPA, DOE, EPRI, Combined Power Plant Air Pollution Control Mega Symposium, Chicago, IL, August See also, Gutberlet, H., Schluter, A., Licata, A., Deactivation of SCR Catalyst, proceedings of the DOE s 2000 Conference on Selective Catalytic and Selective Non-Catalytic Reduction for NOx Control, Pittsburgh, PA, See, MobotecUSA at 14

19 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No effectively for the combustion process, and reduce the maximum temperatures of the combustion zone. The ROFA system consists of air injection boxes, duct work and supports, the ROFA fan, and control system instrumentation. A ROFA system was installed on an existing 80-MW (gross) bituminous-fired utility boiler in the summer of Test results showed that the ROFA system reduced NO x emissions from baseline levels between 0.58 and 0.62 lb/mmbtu to approximately 0.22 lb/mmbtu at full load. At lower loads (approximately 40 MW), the ROFA system reduced NO x emissions from 0.59 lb/mmbtu to lb/mmbtu. 7 The turbulent air injection and mixing provided by ROFA allows for the effective mixing of chemical reagents with the combustion products in the furnace. MobotecUSA s Rotamix system combines the rotating opposed overfire air system with urea injection into the flue gas (SNCR) to reduce NO x emissions. The turbulent mixing created by the ROFA system is designed to improve distribution of the ammonia/urea reagent and may reduce the ammonia/urea injection required by the SNCR control system. A Rotamix control system was installed on the same 80-MW unit in the spring of ROFA and Rotamix systems have been demonstrated on smaller coal-fired boilers but have not been demonstrated in practice on boilers similar in size to Sooner Units 1 & 2. As discussed in subsection , overfire air control systems are a technically feasible retrofit control technology on Sooner Units 1 & 2, and, based on engineering judgment, the ROFA design could also be applied to the boilers. However, there is no technical basis to conclude that the ROFA design would provide additional NO x reduction beyond that achieved with other OFA designs. Therefore, ROFA control systems will not be evaluated as a specific control system, but will be included in the overall evaluation of combustion controls (e.g., LNB/OFA). The Rotamix system is a SNCR control system (i.e., ammonia injection system) coupled with the ROFA rotating injection nozzle design. The technical limitations discussed in , including the physical size of the boiler, inadequate NH 3 /NO x contact, fly ash characteristics, and flue gas temperatures, would equally apply to the Rotamix control system. There is no technical basis to conclude that Rotamix urea injection design addresses these unresolved technical difficulties. Therefore, like other SNCR control 7 Coombs, K.A., Crilley, J.S., Shilling, M., Higgins, B., SCR Levels of NOx Reduction with ROFA and Rotamix (SNCR) at Dynegy s Vermilion Power Station, Presented at 2004 Stack Emissions Symposium, Clearwater Beach, Florida, July 28-30,

20 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No systems, the Rotamix system is determined not to be an applicable NOx control system for Sooner Units 1 & 2, and will not be evaluated further in the BART determination Pahlman Multi-Pollutant Control Process The Pahlman Process is a patented dry-mode multi-pollutant control system. The process uses a sorbent composed of oxides of manganese (the Pahlmanite sorbent) to remove NO x and SO 2 from the flue gas. 8 Manganese compounds are soluble in water in the +2 valence state but not in the +4 state. This property is used in the Pahlman sorbent capture and regeneration procedure, in that Pahlmanite sorbent is reduced from the insoluble +4 state to the +2 state during the formation of manganese nitrates and sulfates. These species are water-soluble, allowing the sulfate, nitrate and Mn +2 ions to be dissociated and the Mn +2 to be oxidized again to Mn +4 and regenerated. In general, the liquid metal oxide Pahlmanite sorbent is injected as the flue gas enters a spray dryer. The sorbent dries as it passes through the spray dryer and is collected downstream at the fabric filter baghouse. NO x and SO 2 will react with the sorbent to form manganese sulfates and nitrates as the flue gas passes through the filter cake. The filter cake is pulsed off-line into a wet regeneration process. The regenerated sorbent is stored in liquid form to be employed again via the spray dryer. The captured nitrogen and sulfur can be purified and may be converted into granular fertilizer by-products. To date, bench- and pilot-scale testing have been conducted to evaluate the technology on utility-sized boilers. 9 The New & Emerging Environmental Technologies (NEET) Database identifies the development status of the Pahlman Process as full-scale development and testing. 10 The process is an emerging multi-pollutant control, and there is limited information available to evaluate it s technically feasibility and long-term effectiveness on a large subbituminous-fired boiler. It is likely that OG&E would be required to conduct extensive design engineering and testing to evaluate the technical feasibility and long-term effectiveness of the control system on Sooner Units 1 & 2. BART does not require applicants to experience extended time delays or resource penalties to 8 See, Enviroscrub Technologies Corporation, 9 See, Wocken, C.A., Evaluation of Enviroscrub s Multipollutant Pahlman Process for Mercury Removal at a Facility Burning Subbituminous Coal, Energy & Environmental Research Center, University of North Dakota, April NEET is an on-line repository for information about emerging technologies that reduce emissions from stationary, mobile, and indoor sources. NEET was developed and is operated by RTI International with support from the U.S.EPA Office of Air Quality Planning and Standards. 16

21 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No allow research to be conducted on an emerging control technique. Therefore, at this time the Pahlman Process is not considered an available NO x control system for Sooner Units 1 & 2, and will not be further evaluated in the BART determination Wet NO x Scrubbing Systems Wet scrubbing systems have been used to remove NO x emissions from fluid catalytic cracking units (FCCUs) at petroleum refineries. An example of a wet scrubbing system is Balco Technologies LoTOx system. The LoTOx system is a patented process, wherein ozone is injected into the flue gas stream to oxidize NO and NO 2 to N 2 O 5. This highly oxidized species of NO x is very soluble and rapidly reacts with water to form nitric acid. The conversion of NO x to nitric acid occurs as the N 2 O 5 contacts liquid sprays in the scrubber. Wet scrubbing systems have been installed at chemical processing plants and smaller coalfired boilers. The NEET Database classifies wet scrubbing systems as commercially established for petroleum refining and oil/natural gas production. However the technology has not been demonstrated on large coal-fired boilers and it is likely that OG&E would incur substantial engineering and testing to evaluate the scale-up potential and long-term effectiveness of the system. Therefore, at this time wet NO x scrubbing is not considered to be an applicable or commercially available retrofit control system for Sooner Units 1 & 2, and will not be further evaluated in this BART determination. The results of Step 2 of the NO x BART Analysis (technical feasibility analysis of potential NO x control technologies) are summarized in Table

22 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Table 3-2 Technical Feasibility of Potential NO x Control Technologies - Sooner Generating Station Control Technology In Service on Controlled NO x Emission Rate Existing PC Boilers (lb/mmbtu) Yes No In Service on Other Combustion Sources? Technically Feasible on Sooner Units 1 & 2? Low NOx Burners and Overfire Air SNCR NA X Yes SNCR has been applied to several smaller coalfired boilers lb/mmbtu X Yes Technically feasible. SCR 0.07 lb/mmbtu X Yes Not a technically feasible retrofit technology for Sooner Units 1 & 2. SNCR has been used as a retrofit technology on small and medium sized (<300 MW) coal-fired boilers, but has not been demonstrated on larger boilers. There are several currently unresolved technical difficulties associated with applying SNCR on a large subbituminous coal-fired boiler. SCR is a technically feasible retrofit technology for Sooner Units 1 & 2. The effectiveness of the SCR system will depend on site-specific considerations including the ammonia injection rate, site-specific flue gas characteristics, ammonia slip, and frequency of catalyst changes. ROFA NA X Yes ROFA has been demonstrated on small coal-fired boilers, and would be a technically feasible retrofit control technology. However, there is no technical basis to conclude that ROFA will provide additional NOx control beyond that achievable with other OFA systems. Therefore, ROFA will be evaluated along with other OFA control systems. 18

23 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Table 3-2 continued: Control Technology In Service on Controlled NO x Emission Rate Existing PC Boilers (lb/mmbtu) Yes No In Service on Other Combustion Sources? Technically Feasible on Sooner Units 1 & 2? Rotamix (SNCR) NA X Yes Rotamix control systems have been demonstrated on small coal-fired boilers. However, there are several currently unresolved technical difficulties associated with applying SNCR-type systems on a large subbituminous coal-fired boiler. Therefore, Rotamix is not considered an available retrofit control technology for Sooner Units 1 & 2. Pahlman Process NA X No Bench- and pilot-scale testing has been conducted on coal-fired boilers, however, there is limited data available assessing the technical feasibility of this system on large coal-fired boilers. Wet NO x Scrubbing NA X Yes The system has been used on refinery fluid catalytic cracking units and small coal-fired boilers, but has not been used on large coal-fired boilers. Wet NOx scrubbing systems are not commercially available or technically feasible for Sooner Units 1 &2. 19

24 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Step 3: Rank the Technically Feasible NOx Control Options by Effectiveness The technically feasible and commercially available NO x control technologies are listed in Table 3-3, in descending order of control efficiency. Table 3-3 Technically Feasible NO x Control Technologies Sooner Station Control Technology Sooner Unit 1 Sooner Unit 2 Approximate NO x Emission Rate (lb/mmbtu) Approximate NO x Emission Rate (lb/mmbtu) Selective Catalytic Reduction (SCR) Low-NOx Burners and Overfire Air Baseline Step 4: Evaluate the Technically Feasible NOx Control Technologies NO x Control Technologies Economic Evaluation The most effective NO x retrofit control system, in terms of reduced emissions, that is considered to be technically feasible for Sooner Units 1 & 2 includes combustion controls (LNB/OFA) and post-combustion SCR. This combination of controls should be capable of achieving the lowest controlled NO x emission rate on an on-going long-term basis. The effectiveness of the SCR system is dependent on several site-specific system variables, including the size of the SCR, catalyst layers, NH 3 / NO x stoichiometric ratio, NH 3 slip, and catalyst deactivation rate. Based on emission rates achieved in practice at similar sources, and including a reasonable margin to account for normal system fluctuations, the combination of combustion controls and SCR should achieve a controlled NO x emission rate of 0.07 lb/mmbtu (30-day average). The next most effective NO x retrofit control system that is considered technically feasible for Sooner Units 1 & 2 includes combustion controls (LNB/OFA). The combination of LNB/OFA 11 Baseline NOx emissions used in this BART analysis were based on the highest 24-hour block emissions reported by each unit during the baseline period. Baseline NOx emission rates (lb/mmbtu) were calculated by dividing the maximum hourly mass emission rate (lb/hr) by the full load heat input to each boiler. The relatively high short-term baseline emission rates were used to predict maximum potential visibility impacts, and to provide a conservative estimate of the cost effectiveness of potentially feasible retrofit control technologies. The short-term baseline emission rates should in no way be interpreted as a potential violation of the facility s permitted emission limits, which are averaged over a longer period of time. 20

25 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No on Sooner Units 1 & 2 (large tangentially fired boilers firing subbituminous coal) should be capable of meeting the BART presumptive limit of 0.15 lb/mmbtu. Economic impacts associated with the SCR control systems were evaluated in accordance with EPA guidelines (40 CFR Part 51 Appendix Y). In accordance with the guidelines in Part III of Appendix Y, emission estimates used in the modeling analysis to determine visibility impairment impacts should reflect steady-state operating conditions during periods of high capacity utilization. Therefore, projected emission rates (lb/hr) were calculated based on the expected controlled emission rate (lb/mmbtu) achievable on a 30-day rolling average and heat input to the boiler at full load. Annual emissions (tpy) were calculated assuming a 90% capacity factor for each unit. Cost estimates were compiled from a number of data sources. In general, the cost estimating methodology followed guidance provided in the EPA Air Pollution Cost Control Manual. 12 Major equipment costs were developed based on equipment costs recently developed for similar projects, and include the equipment, material, labor, and all other direct costs needed to retrofit Sooner Units 1 & 2 with the control technology. Fixed and variable O&M costs were developed for each control system. Fixed O&M costs include operating labor, maintenance labor, maintenance material, and administrative labor. Variable O&M costs include the cost of consumables, including reagent (e.g., ammonia), byproduct management, water consumption, and auxiliary power requirements. Auxiliary power requirements reflect the additional power requirements associated with operation of the new control technology, including operation of any new ID fans as well as the power requirements for pumps, reagent handling, and by-product handling. Summarized in Table 3-4 are the expected controlled NO x emission rates, and maximum annual NO x mass emissions, associated with each technically feasible retrofit technology. Table 3-5 presents the capital costs and annual operating costs associated with building and operating each control system. Table 3-6 shows the average annual cost effectiveness and incremental annual cost effectiveness for each NO x control system. A detailed summary of the cost estimates used in this BART determination is included in Attachment A. 12 U.S. Environmental Protection Agency, EPA Air Pollution Cost Control Manual, 6 th Ed., Publication Number EPA 452/B , January

26 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Control Technology Table 3-4 Annual NOx Emissions NOx Emission Rate Maximum Annual NOx Emissions (tpy) (1) Annual Reduction in Emissions (tpy from baseline) (lb/mmbtu) Unit 1 Unit 2 Unit 1 Unit 2 Unit 1 Unit 2 LNB/OFA + SCR ,412 1,412 10,709 10,366 LNB/OFA ,025 3,025 9,096 8,753 Baseline NOx Emissions ,121 11, (1) Maximum annual emissions for the BART analysis are based on a maximum heat input of 5,116 mmbtu/hr per boiler for 7,884 hours per year (90% capacity factor). Table 3-5 NOx Emission Control System Cost Summary (per boiler) Control Technology Total Capital Investment* ($) Total Capital Investment ($/kw-gross) Annual Capital Recovery Cost ($/year) Annual Operating Costs ($/year) Total Annual Costs ($/year) LNB/OFA + SCR $192,018,500 $336 $16,477,200 $14,487,400 $30,964,600 LNB/OFA $14,055,900 $25 $1,206,100 $877,100 $2,083,200 * Capital costs for NOx retrofit control systems will be similar for Sooner Units 1 & 2. Capital costs include the cost of major components and indirect installation costs such as foundations, mechanical erection, electrical, piping, and insulation for the control system. Capital costs for the SCR system includes costs associated with installation of LNB/OFA systems. Control Technology Table 3-6 NOx Emission Control System Cost Effectiveness (total for both boilers) Total Annual Cost ($/year) Annual Emission Reduction (tpy) Average Cost Effectiveness ($/ton) Incremental Cost Effectiveness ($/ton) LNB/OFA + SCR $61,929,200 21,075 $2,939 $17,905 LNB/OFA $4,166,400 17,849 $233 NA The average annual cost effectiveness of LNB/OFA+SCR on Sooner Units 1 & 2 is estimated to be approximately $2,939/ton. This cost compares to an average annual cost effectiveness for LNB/OFA combustion controls of approximately $233/ton. Equipment costs, retrofit challenges, and annual operating costs all have a significant impact on the annualized cost of a SCR control system. Significant annual operating costs include the energy cost associated with the additional pressure drop across the SCR and costs associated with replacing the SCR catalyst as it degrades over time. Based on projected actual emissions, SCR could reduce 22

27 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No overall NO x emissions from Sooner Units 1 & 2 (combined) by approximately 3,226 tpy (compared to advanced combustion controls); however, the incremental cost associated with this reduction is approximately $57,762,800 per year, or $17,905/ton. As part of the BART rulemaking, EPA established presumptive NO x emission limits applicable to EGUs greater than 200 MW at power plants with a generating capacity greater than 750 MW. The presumptive NO x emission limits were based on control strategies that EPA considered to be generally cost-effective for such units (see, 70 FR 39134). The presumptive NO x emission limit applicable to Sooner Units 1 & 2 (tangentially-fired units firing subbituminous coal) is 0.15 lb/mmbtu. For all types of boilers, other than cyclone units, the presumptive limits were based on the use of combustion control technologies. EPA estimated that the costs of such controls in most cases range from just over $100 to $1000 per ton (see, 70 FR 39135). The average cost effectiveness of combustion controls (LNB/OFA) on Sooner Units 1 & 2 is similar to the BART cost-effectiveness developed by EPA for NO x control on large EGU boilers. Both the average and incremental cost effectiveness of SCR on Sooner Units 1 & 2 are significantly greater than the cost effectiveness of NO x control at other BART-applicable units. The costs associated with SCR would result in significant economic impacts on the Sooner Generating Station (approximately $57,762,800 per year additional costs). Therefore, SCR should not be selected as BART based on lack of cost effectiveness. Although SCR does not appear to be cost effective, it will be included in the evaluation of the remaining factors to assure that the BART determination considers all relevant information NO x Control Technologies Environmental Impacts Combustion modifications designed to decrease NO x formation (lower temperature and less oxygen availability) also tend to increase the formation and emission of CO and VOCs. Therefore, the combustion controls must be designed to reduce the formation of NO x while maintaining CO and VOC formation at an acceptable level. Other than the NO x /CO-VOC trade-off, there are no environmental issues associated with using combustion controls to reduce NO x emissions. Operation of an SCR system has certain collateral environmental consequences. 13 First, in order to maintain low NO x emissions some excess ammonia will pass through the SCR. Ammonia slip will increase with lower NO x emission limits, and will also tend to increase as the catalyst becomes deactivated. Ammonia slip from an SCR designed to achieve a controlled 13 See, Hinton, W.S., Cushing, K.M., Gooch, J.P., Balance-of-Plant Impacts Associated with SCR/SNCR Installations, proceedings of the ICAC Forum,

28 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No NO x emission rate of 0.07 lb/mmbtu (30-day average) is expected to be in the range of 2-5 ppm during the initial operation of the SCR. As the catalyst ages and becomes either deactivated or blinded, ammonia slip can increase; however, the ammonia slip rate is not expected to exceed 7-10 ppm under normal operating conditions. Second, undesirable reactions can occur in an SCR system, including the oxidation of NH 3 and SO 2 and the formation of sulfate salts. A fraction of the SO 2 in the flue gas (approximately 1-1.5%) will oxidize to SO 3 in the presence of the SCR catalyst. SO 3 can react with water to form sulfuric acid mist or with the ammonia slip to form ammonium sulfate ((NH 4 ) 2 SO 4 ). Sulfuric acid mist and (NH 4 ) 2 SO 4 are classified as condensable particulates. The formation of condensible particulates will increase as the size of the SCR increases. Finally, the storage of ammonia on-site increases the risks associated with an accidental ammonia release. Depending on the type, concentration, and quantity of ammonia used, ammonia storage/handling will be subject to regulation as a hazardous substance under CERCLA, Section 313 of the Emergency Planning and Community Right-to-Know Act, Section 112(r) of the Clean Air Act, and Section 311(b)(4) of the Clean Water Act. One strategy that can be used to minimize the risk associated with on-site ammonia handling, is to design the ammonia handling system as a urea-to-ammonia conversion system. Urea ((NH 2 ) 2 CO) can be delivered to the station as an aqueous solution or as a dry solid, and urea storage/handling does not create the process safety concerns associated with handling anhydrous ammonia NO x Control Technologies Energy Impacts Both NOx control systems require auxiliary power. Auxiliary power requirements associated with the LNB/OFA control systems are generally insignificant, but may include booster fans for the overfire air injection ports to increase turbulence within the boiler. Auxiliary power requirements associated with the SCR include additional fan power to overcome pressure drop through SCR vessel. Energy impacts associated with each control technology were included in the BART economic impact evaluation as an auxiliary power cost. A summary of the Step 4 economic and environmental impact analysis is provided in Table

29 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Control Technology Annual Controlled Emissions* (tpy) Table 3-7 Sooner Units 1 & 2 Summary of NO x BART Impact Analysis Annual Emission Reductions (tpy) Average Cost Effectiveness ($/ton) Incremental Cost Effectiveness ($/ton) Summary of Environmental Impacts LNB/OFA+SCR 2,824 21,075 $2,939 $17,905 Increased SO 2 to SO 3 oxidation, and increased condensible PM emissions including H 2 SO 4. Ammonia emissions associated with ammonia slip. LNB/OFA 6,050 17,849 $ Potential to increase CO/VOC emissions. Baseline 23,899 base *Annual controlled emissions and annual emission reductions represent total emissions from both units. 3.5 Step 5: Evaluate Visibility Impacts To evaluate the relative effectiveness of potentially feasible NO x retrofit control technologies, NO x emissions were modeled at the projected post-retrofit controlled emission rates, while SO 2 and PM 10 emissions were modeled at the pre-bart baseline emission rates. In accordance with EPA guidelines (40 CFR Part 51 Appendix Y Part III), post-retrofit emission rates used in the modeling analysis to determine visibility impairment impacts reflect steady-state operating conditions during periods of high capacity utilization. Post-retrofit emission rates (average lb/hr rate on a 24-hour basis) were calculated using the expected controlled emission rate achievable on a 30-day rolling average multiplied by the boiler heat input (mmbtu/hr) at full load. The visibility modeling methodology is described further in Attachment B of this document, including detailed inputs and results. The results in Table 3-8 summarize the 98 th percentile -dv impact from NO x emissions associated each NO x retrofit control scenario. The most significant improvement in visibility can be attributed to NO x reductions associated with combustion controls (LNB/OFA). Visibility improvements in the range of 75% reductions in modeled impacts are achieved at each Class I Area. The largest reduction in visibility impairment (0.80 -dv) occurs at the Wichita Mountains Class I Area. Modeled impacts associated with NO x emissions based on LNB/OFA controls at the presumptive NO x emission limit (0.15 lb/mmbtu) are below the threshold impact level of 0.5 -dv level at all Class I Areas. 25

30 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Wichita Mountains NOx Control Wildlife Refuge Technology % Option 98 th % Improvement over -dv* Previous Table 3-8 Sooner Units 1 & 2 - NO x Visibility Assessment Visibility Improvement Upper Buffalo Hercules-Glades Wilderness Area Wilderness Area % % 98 th % Improvement over -dv ment over 98 th % Improve- -dv Previous Previous Caney Creek Wilderness Area 98 th % -dv % Improvement over Previous Baseline LNB/OFA % % % 0.l4 74% LNB/OFA + SCR % % % % * -dv values included in this table represent the modeled visibility impacts only from NOx emissions associated with each NOx retrofit control scenario. Post-combustion SCR control systems could reduce NO x emissions from Sooner Units 1 & 2 below the BART presumptive level; however, modeled visibility improvements at the lower NO x emission rates do not justify the costs associated with SCR control. LNB/OFA control systems are expected to reduce overall NO x emissions from Sooner Units 1 & 2 by approximately 17,049 tpy (from baseline). SCR control systems would reduce overall NO x emissions by an additional 3,226 tpy. At the lower NO x emission rates, modeled visibility impairment at the Class I Areas would be reduced by only 0.05 to dv. Because only small improvements in visibility impacts result from the lower emission rate, the cost effectiveness of SCR control, on a $/dv basis, will be significant. Tables 3-9 and 3-10 summarize the cost effectiveness of the technically feasible NO x retrofit control technologies on Sooner Units 1 & 2 as a function of visibility impairment improvement at the Class I Areas. Table 3-9 Sooner Units 1 & 2 - NO x Average Visibility Cost Impact Evaluation NOx Control Technology Option Total Annual Cost Modeled Visibility Impairment* Visibility Impairment Improvement from Baseline Average Improvement Cost Effectiveness ($/yr) 98 th % -dv* (dv) ($/dv/yr) Baseline LNB/OFA $4,166, $5.2 MM/dv LNB/OFA + SCR $61,227, $64.4 MM/dv * -dv values included in this table represent the modeled visibility impacts only from NOx emissions associated with each NOx retrofit control scenario. Visibility impairment at the nearest Class I Area (Wichita Mountains) was used for the cost effectiveness evaluation. 26

31 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No NOx Control Technology Option Table 3-10 Sooner Units 1 & 2: NO x Incremental Visibility Cost Impact Evaluation Total Annual Cost Incremental Annual Cost Modeled Visibility Impairment Incremental Visibility Impairment Improvement Incremental Improvement Cost Effectiveness ($/yr) ($/yr) 98 th % -dv* (dv) ($/dv/yr) Baseline LNB/OFA $4,166, LNB/OFA + SCR $61,227,200 $57,060, $380 MM/dv * -dv values included in this table represent the modeled visibility impacts only from NOx emissions associated with each NOx retrofit control scenario. Visibility impairment at the nearest Class I Area (Wichita Mountains) was used for the cost effectiveness evaluation. Although SCR control systems reduce modeled visibility impacts at the four Class I Areas, the incremental cost effectiveness of SCR control (with respect to visibility improvement) is very high. Incremental cost effectiveness of SCR control is in the range of $380 million per dv improvement at the Wichita Mountains. This cost is significantly higher than costs incurred at other BART applicable sources. A review of BART determinations at other coal-fired units suggests that BART cost effectiveness values are typically in the range of less than $1.0 million to approximately $13 million per dv improvement. 14 The combination of low visibility impacts with LNB/OFA controls (less than dv at all Class I Areas) and the high cost of SCR controls contribute to the large incremental cost effectiveness of SCR at the Sooner Generating Station. To determine whether alterative NOx control scenarios might provide more cost effective visibility improvements, cumulative impact modeling was conducted using a variety of SCR control scenarios. A goal of the cumulative impact modeling was to determine whether alternative NOx control scenarios (i.e., SCR control on some, but not all of the OG&E BART applicable sources) would provide more cost effective NOx control. To quantify cost effectiveness, visibility impairment was modeled for several NOx control scenarios, while SO 2 and PM emissions were held constant at their respective baseline emission rates. Modeled NOx control scenarios are listed in Table Results of the cumulative NOx impact modeling are summarized in Table See e.g., BART evaluations for Xcel (Sherco, MN); Great River Energy (Coal Creek, ND); Trigen Energy Co. (CO); Entergy White Bluff Power Plant (AR). 27

32 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Table 3-11 Cumulative NO x Visibility Assessment (Muskogee Units 4 & 5 and Sooner Units 1 & 2)* Unit Base Case Case 1 Case 2 Case 3 Case 4 NOx Controls (Emission Rate - lb/mmbtu) Muskogee Unit 4 LNB/OFA (0.15) SCR (0.07) SCR (0.07) SCR (0.07) SCR (0.07) Muskogee Unit 5 LNB/OFA (0.15) LNB/OFA (0.15) LNB/OFA (0.15) SCR (0.07) SCR (0.07) Sooner Unit 1 LNB/OFA LNB/OFA SCR SCR SCR (0.15) (0.15) (0.07) (0.07) Sooner Unit 2 LNB/OFA LNB/OFA LNB/OFA LNB/OFA (0.15) (0.15) (0.15) (0.15) * For each case PM and SO 2 emissions were held constant at the baseline emission rates. Baseline emissions for SO 2 were: 0.80 lb/mmbtu (Muskogee Unit 4), 0.85 lb/mmbtu (Muskogee Unit 5), and 0.86 lb/mmbtu (Sooner Units 1 & 2). NOx Control Technology Option Table 3-12 Cumulative NOx Visibility Modeling Results (Muskogee Units 4 & 5 and Sooner Units 1 & 2) Upper Buffalo Wilderness Area 98 th % -dv Modeled Visibility Impairment* Caney Creek Wilderness Area 98 th % -dv Hercules-Glades Wilderness Area 98 th % -dv (0.07) SCR (0.07) Wichita Mountains Wildlife Refuge Base Case Case Case Case Case * -dv values included in this table reflect cumulative modeled contributions from NOx, SO 2 and PM emissions from both the Sooner and Muskogee Stations. For each case PM and SO 2 emissions were held constant at their respective baseline emission rates, while NOx emissions varied depending the NOx control system on each unit (see Table 3-11). The dv values in this table are not directly related to dv values in Tables 3-8 (NOx) and 4-9 (SO 2 ), which reflect modeled impacts from the Sooner Station only for each individual pollutant. 98 th % -dv Results of the cumulative impact modeling suggest that SCR controls would contribute only minimally to visibility improvement at the Class I Areas in comparison to LNB/OFA. Modeled impacts at the Wichita Mountains (at the 98 th percentile -dv level) improved from dv with LNB/OFA on all four units to dv with SCR on all four units, an improvement of approximately 4%. Modeled improvements were even lower at the other Class I Areas, and, in fact, modeled impairments at the Hercules-Glades and Upper Buffalo Wilderness Areas actually 28

33 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No increased with the addition of SCR controls. It is suspected that increased sulfuric acid mist emissions (associated with SO 2 to SO 3 conversion across the SCR) off-set reductions in controlled NOx emissions. 3.6 Propose BART for NOx Control at Sooner Units 1 & 2 OG&E is proposing combustion controls (LNB/OFA), and a controlled NO x emission rate of 0.15 lb/mmbtu (30-day average) as BART for Sooner Units 1 & 2. This combination of control technologies represents the most cost effective technically feasible NO x retrofit technology for the existing boilers. A controlled emission rate of 0.15 lb/mmbtu is equivalent to the presumptive level for large tangentially-fired units firing subbituminous coals. The average cost effectiveness of LNB/OFA control systems is estimated to be in the range of $233/ton and $5.2 MM/dv/yr. These cost effectiveness numbers are in line with U.S. EPA s cost estimate for BART controls on large EGUs, and are not of such magnitude as to exclude combustion controls as BART. The addition of SCR control systems could provide incremental NO x reductions, however, costs associated with SCR control are significant, and incremental visibility improvements are limited. The average cost effectiveness of an SCR control system is estimated to be $2,908/ton and $64.4 MM/dv/yr. These costs are significantly higher than the average cost of NO x control at similar sources. In the BART rule, EPA estimated that the cost of controls to meet the BART NO x presumptive level on large EGUs in most cases range from just over $100 to $1000 per ton (see, 70 FR 39135). Furthermore, the modeled incremental visibility improvements associated with SCR control are only in the range of 0.05 to dv. Because of the limited improvement in modeled visibility impacts, the cost effectiveness of SCR control, on a $/dv basis is significant. Compared to the costs and modeled visibility impacts associated with LNB/OFA controls, the incremental cost effectiveness of SCR is estimated to be $17,688/ton and more than $380 MM/dv/yr. Both costs are significantly higher than the expected cost of BART controls on large EGUs, and should preclude SCR from consideration as BART. Finally, cumulative impact modeling, summarized in Tables 3-11 and 3-12, supports the conclusion that post-combustion SCR controls provide limited improvement in modeled visibility impairment. 29

34 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No BART ANALYSIS FOR MAIN BOILER SULFUR DIOXIDE (SO 2 ) SO X emissions from coal combustion consist primarily of sulfur dioxide (SO 2 ), with a much lower quantity of sulfur trioxide (SO 3 ) and gaseous sulfates. These compounds form as the organic and pyretic sulfur in the coal are oxidized during the combustion process. On average, about 95% of the sulfur present in the fuel will be emitted as gaseous SO 15 X, Boiler size, firing configuration and boiler operations generally have little effect on the percent conversion of fuel sulfur to SO 2. The generation of SO 2 is directly related to the sulfur content and heating value of the fuel burned. The sulfur content and heating value of coal can vary dramatically depending on the source of the coal. Sooner Units 1 & 2 utilize subbituminous coal as their primary fuel source. Heating values, ash contents, and sulfur contents for subbituminous fuel utilized at the Sooner Station are summarized in Table 4-1. Table 4-1 Sooner Generating Station Typical Coal Characteristics Constituent Units Range Heating Value Btu/lb 8,500 8,900 Ash % Sulfur Content % Potential Uncontrolled SO 2 lb/mmbtu * Coal characteristics included in this table represent average values based on fuel shipments to the Sooner Station. Characteristics summarized in this table are not intended to limit the heating value, moisture content, ash content, or sulfur content of fuels utilized at the Sooner Station, as short-term coal characteristics may vary from the values summarized above. 4.1 Step 1: Identify Potentially Feasible SO 2 Control Options Several techniques can be used to reduce SO 2 emissions from a pulverized coal-fired combustion source. SO 2 control techniques can be divided into pre-combustion strategies and post-combustion controls. SO 2 control options identified for potential application to Sooner Units 1 & 2 are listed in Table AP-42, Section 1.1 Bituminous and Sub-Bituminous Coal Combustion, page 1.1-3, September

35 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Table 4-2 Sooner Generating Station List of Potential SO 2 Retrofit Control Options Control Strategy / Technology Pre-Combustion Controls Fuel Switching Coal Washing Coal Processing Post-Combustion Controls Wet Flue Gas Desulfurization Wet Lime FGD Wet Limestone FGD Wet Magnesium Enhanced Lime FGD Jet Bubbling Reactor FGD Dual Alkali Scrubber Wet FGD with Wet Electrostatic Precipitator Dry Flue Gas Desulfurization Spray Dryer Absorber Dry Sorbent Injection Circulating Dry Scrubber 4.2 Step 2: Technical Feasibility of Potential Control Options The technical feasibility of each potential control option is discussed below Pre-Combustion Control Strategy The generation of SO 2 is related to the sulfur content and heating value of the fuel burned. The sulfur content and heating value of coal can vary dramatically depending on the source of the coal. Potentially feasible pre-combustion control strategies designed to reduce overall SO 2 emissions are described below Fuel Switching One potential strategy for reducing SO 2 emissions is reducing the amount of sulfur contained in the coal. Sooner Units 1 & 2 fire subbituminous coal as their primary fuel. Subbituminous coal has a relatively low heating value, low sulfur content, and low uncontrolled SO 2 emission rate. Typical coal characteristics based on existing 31

36 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No subbituminous coal shipments to OG&E s Sooner Generating Station are summarized in Table 4-1. Because of the relatively low sulfur content, subbituminous coals generate the lowest uncontrolled SO 2 emissions. In fact, several coal-fired utilities have switched to low-sulfur coal as an SO 2 emission control strategy. Bituminous coals from mines in the Eastern and Midwestern U.S. generally have higher heating values but also have a significantly higher sulfur content. Lignites from the upper Midwest and Texas have a relatively low sulfur content (but higher than subbituminous) but also have high moisture contents and relatively low heating values. Fuels currently used at the Sooner Station generate low uncontrolled SO 2 emissions. Switching to alternative coals (i.e., 100% bituminous coal or lignite) will not reduce potential uncontrolled SO 2 emissions or controlled SO 2 emissions from Sooner Units 1 & 2. No environmental benefits accrue from burning an alternative coal; therefore, fuel switching is not considered a feasible option for this retrofit project Coal Washing Coal washing, or beneficiation, is one pre-combustion method that has been used to reduce impurities in the coal such as ash and sulfur. In general, coal washing is accomplished by separating and removing inorganic impurities from organic coal particles. Inorganic impurities, including inorganic ash constituents and inorganic iron disulfide (FeS 2 or pyrite), are typically more dense than the coal particles. This property is generally used in a wet cleaning process to separate coal particles from the inorganic impurities. Each coal seam has different washability characteristics depending on the characteristics of the inorganic constituents. Based on information available from the Kentucky Coal Council, inorganic sulfur in high-sulfur eastern bituminous coals may be reduced by % and inorganic ash may be reduced by 9 15% through coal washing. 16 Coal washing is generally done at the mine to maximize the value of the coal and reduce freight charges to the power plant. The coal washing process generates a solid waste stream consisting of inorganic materials separated from the coal, and a wastewater stream that must be treated prior to discharge. Solids generated from wastewater processing and coarse material removed in the washing process must be disposed in a properly permitted landfill. Solid wastes from coal washing 16 See, 32

37 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No typically contain pyrites and other dense inorganic impurities including silica and trace metals. The solids are typically dewatered in a mechanical dewatering device and disposed of in a landfill. The wastewater stream generally consists of an acidic liquid slurry made up of water, uncombusted coal fines, and impurities in the coal, including calcium, trace metals, chloride, sulfate, and dissolved and suspended solids. 17 The wastewater slurry must be treated to remove solids, coal fines, and trace metals prior to discharge. Coal slurry treatment systems may include surface impoundments, mechanical dewatering systems, chemical processing systems, and/or thermal dryers. While washing may be effective in removing rock inclusions from coal, including sulfurbearing pyrites, a significant amount of coal may also be lost in the washing process. An inherent consequence of coal washing, in addition to generating wastewater and solid waste streams, would be the need for the mine to process significantly more coal to make up for coal lost in the washing process. Sooner Units 1 & 2 are designed to utilize subbituminous coals. Based on a review of available information, no information was identified regarding the washability or effectiveness of washing subbituminous coals. Subbituminous coals have a relatively high ash content and an excessive amount of fines, and significant dewatering equipment would be required to process and separate the fines from the wastewater stream. It is likely that the excess fines production, and the difficulties associated with handling and dewatering the fines, have restricted the commercial viability of subbituminous coal washing. Furthermore, the coal washing process would generate significant solid and liquid waste streams that would require proper management and disposal. Based on a review of available information, there are currently no commercial subbituminous coal washing facilities, and washed subbituminous coals are not available through commercial channels. Therefore, coal washing is not considered an available retrofit control option for Sooner Units 1 & Coal Processing Pre-combustion coal processing techniques have been proposed as one strategy to reduce the sulfur content of coal and help reduce uncontrolled SO 2 emissions. Coal processing 17 See, USEPA Report to Congress, Wastes from the Combustion of Fossil Fuels, Office of Solid Waste and Emergency Response, EPA 530-S , March 1999 (general composition of selected large-volume and low-volume wastes). 33

38 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No technologies are being developed to remove potential contaminants from the coal prior to use. These processes typically employ both mechanical and thermal means to increase the quality of subbituminous coal and lignite by removing moisture, sulfur, mercury, and heavy metals. In one process, raw coal from the mine enters a first stage separator where it is crushed and screened to remove large rock and rock material. 18 The processed coal is then passed on to an intermediate storage. From the intermediate storage facility the coal goes to a thermal process. In this process coal passes through pressure locks into the thermal processors where steam at 460 o F and 485 psi is injected. Moisture in the coal is released under these conditions. Mineral inclusions are also fractured under thermal stress, removing both included rock and sulfur-forming pyrites. After it has been treated for a sufficient time in the main processor, the coal is discharged into a second pressurized lock. The second pressurized lock is vented into a water condenser to return the processor to atmospheric pressure and to flash cool the coal to approximately 200 o F. Water is removed from the coal at various points in the process. This water, along with condensed process steam, is either reused within the process or treated prior to being discharged. To date, the use of processed fuels has only been demonstrated with test burns in a pulverized coal-fired boiler. No coal-fired boilers have utilized processed fuels as their primary fuel source on an on-going, long-term basis. Although burning processed fuels, or a blend of processed fuels, has been tested in a pulverized coal-fired boiler, using processed fuels in Sooner Units 1 & 2 would require significant research, test burns, and extended trials to identify potential impacts on plant systems, including the boiler, material handling, and emission control systems. Therefore, processed fuels are not considered commercially available, and will not be analyzed further in this BART analysis Post-Combustion Flue Gas Desulfurization Over the past decade, post-combustion flue gas desulfurization (FGD) has been the most frequently used SO 2 control technology for large pulverized coal-fired utility boilers. FGD systems typically have been installed on boilers firing high-sulfur bituminous coals. FGD systems, including wet scrubbers and dry scrubbers, have been designed to effectively and economically remove SO 2 from pulverized coal-fired utility boiler flue gas. FGD systems with a potential applicability to Sooner Units 1 & 2 are described below. 18 The coal processing description provided herein is based on the K-Fuel process under development by KFx, Inc. 34

39 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Wet Scrubbing Systems Wet FGD technology is an established SO 2 control technology. Wet scrubbing systems offered by vendors may vary in design; however, all wet scrubbing systems utilize an alkaline scrubber slurry to remove SO 2 from the flue gas. Design variations may include changes to increase the alkalinity of the scrubber slurry, increase slurry/so 2 contact, and minimize scaling and equipment problems. All wet scrubbing FGD systems use an alkaline slurry that reacts with SO 2 in the flue gas to form insoluble calcium sulfite (CaSO 3 ) and calcium sulfate (CaSO 4 ) salts. Wet FGD systems may be generally categorized as lime (CaO) or limestone (CaCO 3 ) scrubbing systems. The scrubbing process and equipment for either lime- or limestone scrubbing is similar. The alkaline slurry consisting of hydrated lime or limestone may be sprayed countercurrent to the flue gas, as in a spray tower, or the flue gas may be bubbled through the alkaline slurry as in a jet bubbling reactor. Equations 4-1 through 4-5 summarize the chemical reactions that take place within the wet scrubbing systems to remove SO 2 from flue gas. SO 2 + CaO + ½H 2 O CaSO 3 ½H 2 O (4-1) SO 2 + CaO + 2H 2 O CaSO 4 2H 2 O (4-2) SO 2 + CaCO 3 + H 2 O CaSO 3 H 2 O + CO 2 (4-3) CaSO 3 + ½O 2 + 2H 2 O CaSO 4 2H 2 O (4-4) SO 2 + 2H 2 O + ½ O 2 + CaCO 3 CaSO 4 2H 2 O + CO 2 (4-5) Potentially feasible wet scrubbing systems are described below. Wet Lime Scrubbing The wet lime scrubbing process uses an alkaline slurry made by adding lime (CaO) to water. The alkaline slurry is sprayed in the absorber and reacts with SO 2 in the flue gas. Insoluble CaSO 3 and CaSO 4 salts are formed in the chemical reaction that occurs in the scrubber (see equations 4-1 and 4-2), and are removed as a solid waste by-product. The waste by-product is made up of mainly CaSO 3, which is difficult to dewater. Solid waste by-products from wet lime scrubbing are typically managed in dewatering ponds and landfills. Wet Limestone Scrubbing Limestone scrubbers are very similar to lime scrubbers except limestone (CaCO 3 ) is mixed with water to formulate the alkali scrubber slurry. SO 2 in the flue gas reacts with the limestone slurry to form insoluble CaSO 3 and CaSO 4 which is removed as a solid waste by- 35

40 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No product (see equations 4-3 and 4-4). The use of limestone instead of lime requires different feed preparation equipment and a higher liquid-to-gas ratio. The higher liquid-to-gas ratio typically requires a larger absorbing unit. The limestone slurry process also requires a ball mill to crush the limestone feed. Forced oxidation of the scrubber slurry can be used with either the lime or limestone wet FGD system to produce gypsum solids instead of the calcium sulfite by-product. Air blown into the reaction tank provides oxygen to convert most of the calcium sulfite (CaSO 3 ) to relatively pure gypsum (calcium sulfate) as shown in equation 4-4. Forced oxidation of the scrubber slurry provides a more stable by-product and reduces the potential for scaling in the FGD. The gypsum by-product from this process must be dewatered, but may be salable thus reducing the quantity of solid waste that needs to be landfilled. Wet scrubbing systems using limestone as the reactant have demonstrated the ability to achieve control efficiencies of greater than 95% on large pulverized coal-fired boilers firing high-sulfur bituminous coals. Wet lime and limestone FGD control systems with forced oxidation are technically feasible SO 2 retrofit technologies. However, wet scrubbing systems have not been used on large boilers firing subbituminous coals, and the actual control efficiency of a wet FGD system will depend on several factors, including the uncontrolled SO 2 concentration entering the system. Based on engineering judgment it is expected that a wet lime or limestone FGD control system with forced oxidation could achieve average controlled SO 2 emissions in the range of 0.08 lb/mmbtu (30-day rolling average) on Sooner Units 1 & 2. Wet lime and wet limestone scrubbing systems will achieve the same SO 2 control efficiencies; however, the higher cost of lime typically makes wet limestone scrubbing the more attractive option. For this reason, wet lime scrubbing will not be evaluated further in this BART determination. Wet Magnesium Enhanced Lime Scrubbing Magnesium Enhanced Lime (MEL) scrubbers are another variation of wet FGD technology. Magnesium enhanced lime typically contains 3% to 7% magnesium oxide (MgO) and 90 95% calcium oxide (CaO). The presence of magnesium effectively increases the dissolved alkalinity, and consequently makes SO 2 removal less dependent on the dissolution of the lime/limestone. In normal lime/limestone spray-tower operation the amount of SO 2 absorbed depends principally upon the soluble-alkali content of the absorbing slurry. When magnesium is present, the soluble alkali level of the absorbent increases primarily because of the presence of sulfite and bicarbonate salts of magnesium. 36

41 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No As these magnesium alkalies are more soluble than the corresponding calcium alkalies, there is an increase in the SO 2 absorption capacity of the slurry. 19 Commercial operation of wet FGD systems has shown that soluble Mg in the absorbing slurry can improve SO 2 removal efficiency. 20 MEL scrubbers have been installed on coalfired utility boilers located in the Ohio River Valley. 21 Most are located in a corridor from Pittsburgh, Pennsylvania to Evansville, Indiana, and use a reagent that naturally contains approximately 5% MgO. Because of the increased alkalinity in the scrubbing liquid, MEL wet scrubbing systems have demonstrated the ability to achieve SO 2 removal efficiencies equivalent to wet lime/limestone scrubbers using smaller absorber towers. Solids from the MEL FGD process consist primarily of calcium sulfite and magnesium sulfite solids. Dewatering the sulfite solids from an unoxidized MEL FGD system can be difficult, and produces a filter cake consisting of approximately 40-50% solids. Typically, unoxidized MEL FGD filter cake is fixed using fly ash and landfilled. This continues to be one of the drawbacks of the unoxidized MEL FGD process. Systems to oxidize the MEL solids to produce a usable gypsum byproduct consisting of calcium sulfate (gypsum) and magnesium sulfate continue to be developed. 22 Wet limestone FGD control systems can be designed to achieve the same control efficiencies as the magnesium enhanced limestone systems. However, to achieve the same control efficiencies, limestone-based systems require a higher liquid-to-gas ratio, and therefore larger absorber towers. Coal-fired units equipped with MEL FGD typically fire high-sulfur eastern bituminous coal and use locally available reagent. There are no subbituminous-fired units equipped with a MEL-FGD system. Because MEL-FGD systems have not been used on subbituminous-fired boilers, and because of the cost and limited availability of magnesium enhanced reagent (either naturally occurring or blended), and because limestone-based wet FGD control systems can be designed to achieve the same control efficiencies as the magnesium enhanced systems, MEL-FGD control systems will not be evaluated further as a commercially available retrofitted control system. 19 Combustion Fossil Power, page Combustion Fossil Power, page Nolan, P.S., Flue Gas Desulfurization Technologies for Coal-Fired Power Plant, Coal-Tech 2000 International Conference, November 13-14, See, Benson, L., Babu, M., Smith, K., New Magnesium-Enhanced Lime FGD Process, Dravo Lime, Inc. Technology Center. 37

42 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Jet Bubbling Reactor Another variation of the wet FGD control system is the jet bubbling reactor (JBR). Unlike the spray tower wet FGD systems, where the scrubbing slurry contacts the flue gas in a countercurrent reaction tower, in the JBR-FGD flue gas is bubbled through a limestone slurry. Spargers are used to create turbulence within the reaction tank and maximize contact between the flue gas bubbles and scrubbing slurry. SO 2 in the flue gas reacts with the limestone slurry to form insoluble CaSO 3 and CaSO 4 which is removed as a solid waste by-product (see equations 4-3, 4-4, and 4-5). Flue gas exits from the reaction vessel through mist eliminators to reduce carryover of the reactant. Although the reaction vessel used to contact flue gas with the scrubbing slurry is different than the spray tower used in a conventional wet FGD system, JBR-FGD systems use the same reaction chemistry to remove SO 2 from the flue gas. JBR-FGD systems do not require the large slurry pumps associated with other wet FGD technologies; however, auxiliary power is shifted to larger fans, booster fans, agitators, and oxidation air blowers to accommodate the larger pressure drop through the system. There is currently a limited number of commercially operating JBR-WFGD control systems installed on coal-fired utility units in the U.S. A JBR-WFGD control system was installed at Georgia Power s 100 MW coal-fired Yates plant in Based on publicly available emissions data, the Yates Plant has an average inlet SO 2 concentration of approximately 3,500 ppm, and has achieved average SO 2 removal efficiencies of approximately 93%. In addition to the Yates Plant, a JBR control system has been in use at the 40 MW equivalent Abbott Steam plant at the University of Illinois. Most of the JBR-WFGD control experience has been in Japan. Chiyoda Corporation has installed JBR-WFGD systems on several coal-fired plants overseas. Based on information available on Chiyoda s website, a majority of the plants equipped with JBR-WFGD are smaller units (e.g., less then 200 MW); however, Chiyoda lists JBR-WFGD systems in operation on three plants located overseas in the 600 MW range. Commercial deployment of the JBR-WFGD control system continues to develop in the U.S. A project experience list available from Chiyoda identifies several U.S. power plants that have decided to install JBR-WFGD control systems, with control system startup dates between 2008 and Although the commercial deployment of the control system continues, there is still a very limited number of operating units in the U.S. Furthermore, coal-fired boilers currently considering the JBR-WFGD control system are all located in the eastern U.S., and all fire eastern bituminous coals. The control system has not been proposed as a retrofit 38

43 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No technology on any large subbituminous coal-fired boilers. However, other than scale-up issues, there do not appear to be any overriding technical issues that would exclude application of the control technology on a large subbituminous coal-fired unit. Assuming that the JBR-WFGD control system is commercially available for Sooner Units 1 & 2, the JBR is essentially a wet FGD scrubbing system. Unlike the spray tower systems, where the scrubbing slurry contacts the flue gas in a countercurrent reaction tower, in the JBR-WFGD flue gas is bubbled through the limestone slurry. SO 2 in the flue gas reacts with the limestone slurry to form insoluble calcium sulfate and calcium sulfite, which is removed as a solid waste by-product. Although the reaction vessel used to contact flue gas with the scrubbing slurry uses a different design, the reaction chemistry to remove SO 2 from the flue gas is the same for all wet FGD designs. There are no data available to conclude that the JBR-WFGD control system will achieve a higher SO 2 removal efficiency than a more traditional spray tower WFGD design, especially on units firing low-sulfur subbituminous coal. Furthermore, the costs associated with JBR-WFGD and the control efficiencies achievable with JBR-WFGD are similar to the costs and control efficiencies achievable with spray tower WFGD control systems. Therefore, the JBR-WFGD will not be evaluated as a unique retrofit technology, but will be included in the overall assessment of WFGD controls. Dual-Alkali Wet Scrubber Dual-alkali scrubbing is a desulfurization process that uses a sodium-based alkali solution to remove SO 2 from combustion exhaust gas. The process uses both sodium-based and calcium-based compounds. The sodium-based reagent absorbs SO 2 from the exhaust gas, and the calcium-based solution (lime or limestone) regenerates the spent liquor. Calcium sulfites and sulfates are precipitated and discarded as sludge, while the regenerated sodium solution is returned to the absorber loop. The dual-alkali process requires lower liquid-to-gas ratios then scrubbing with lime or limestone. The reduced liquid-to-gas ratios generally mean smaller reaction units, however additional regeneration and sludge processing equipment is necessary. The sodium-based scrubbing liquor, typically consisting of a mixture of sodium hydroxide, sodium carbonate and sodium sulfite, is an efficient SO 2 control reagent. However, the high cost of the sodium-based chemicals limits the feasibility of such a unit on a large utility boiler. In addition, the process generates a less stable sludge that can create material handling and disposal problems. 39

44 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No It is projected that a dual-alkali system could be designed to achieve SO 2 control similar to a limestone-based wet FGD. However, because of the limitations discussed above, and because dual-alkali systems are not currently commercially available, dual-alkali scrubbing systems will not be addressed further in this BART determination. Wet FGD with Wet Electrostatic Precipitator Wet FGD systems can result in increased emissions of condensable particulates and acid gases. In particular, SO 3 generated in the unit s boiler can react with moisture in the wet FGD to generate sulfuric acid mist. Sulfuric acid mist emissions from boilers firing high sulfur coals and equipped SCR and wet FGD can contribute to significant opacity problems if the H 2 SO 4 concentration in the stack gas exceeds approximately 15 ppm. 23 Wet electrostatic precipitation (WESP) has been proposed on other coal-fired projects as one technology to reduce sulfuric acid mist emissions from coal-fired boilers. WESPs have been proposed for boilers firing high-sulfur eastern bituminous coals controlled with wet FGD. 24 WESP has been demonstrated as an effective control technology to abate sulfuric acid mist emissions from industrial applications with relatively low flue gas flow rates and high acid mist concentrations, such as sulfuric acid plants. However, until recently, the technology has not been applied to the utility industry because of the high gas flow volumes and low acid mist concentrations associated with utility flue gas. In a utility application, the WESP would be located downstream from the wet FGD to remove micron-sized sulfuric acid aerosols from the flue gas stream as a condensable particulate. Electrostatic precipitation consists of three steps: (1) charging the particles to be collected via a high-voltage electric discharge, (2) collecting the particles on the surface of an oppositely charged collection electrode surface, and (3) cleaning the surface of the collecting electrode. In a WESP system, the collecting electrodes are typically cleaned with a liquid wash. Particulate mass loading, particle size distribution, particulate electrical resistivity, and precipitator voltage and current will influence ESP performance. The wet cleaning mechanism can also affect the nature of the particles that can be captured, and the performance efficiencies that can be achieved. 23 See, Duellman, D.M., Erickson, C.A., Licata, T., Operating Experience with SCR s and High Sulfur Coals & SO 3 Plumes, presented at the ICAC NOx Forum, February See for example, the Thoroughbred Generating Station PSD Permit Application submitted to the Kentucky Department of Environmental Protection, and the Prairie States Energy Center PSD Permit Application submitted to the Illinois Environmental Protection Agency. 40

45 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No WESP has not been widely used in utility applications, and has only been proposed on boilers firing high sulfur coals and equipped with SCR. Sooner Units 1 & 2 fire low-sulfur subbituminous coal. Based on the fuel characteristics listed in Table 4-1, and assuming 1% SO 2 to SO 3 conversion in the boiler, potential uncontrolled H 2 SO 4 emissions from Sooner Units 1 & 2 will only be approximately 5 ppm. This emission rate does not take into account inherent acid gas removal associated with alkalinity in the subbiuminous coal fly ash. Based on engineering judgment, it is unlikely that a WESP control system would be needed to mitigate visible sulfuric acid mist emissions from Sooner Units 1 & 2, even if WFGD control was installed. WESPs have been proposed to control condensable particulate emissions from boilers firing a high-sulfur bituminous coal and equipped with SCR and wet FGD. This combination of coal and control equipment results in relatively high concentrations of sulfuric acid mist in the flue gas. WESP control systems have not been proposed on units firing subbituminous coals, and WESP would have no practical application on a subbituminous-fired units. Therefore, the combination of WFGD+WESP will not be evaluated further in this BART determination. Wet FGD Scrubbing - Conclusions Wet FGD technology is an established SO 2 control technology. Wet scrubbing systems have been designed to utilize various alkaline scrubbing solutions including lime, limestone, and magnesium-enhanced lime. Wet scrubbing systems may also be designed with spray tower reactors or reaction vessels (e.g., jet bubbling reactor). Although the flue gas/reactant contact systems may vary, the chemistry involved in all wet scrubbing systems is essentially identical. A large majority of the wet FGD systems designed to remove SO 2 from existing high-sulfur utility boilers have been designed as wet limestone scrubbers with spray towers and forced oxidation systems. Wet scrubbing systems using limestone as the reactant have demonstrated the ability to achieve control efficiencies of greater than 95% on large pulverized coal-fired boilers firing high-sulfur bituminous coals. The chemistry of wet scrubbing consists of a complex series of kinetic and equilibrium-controlled reactions occurring in the gas, liquid and solid phases. In general, the amount of SO 2 removed from the flue gas is governed by the vapor-liquid equilibrium between SO 2 in the flue gas and the absorbent liquid. If no soluble alkaline species are present in the liquid, the liquid quickly becomes saturated with SO 2 and absorption is limited. 25 Likewise, as the flue gas SO 2 concentration goes down, absorption 25 Combustion Fossil Power A Reference Book on Fuel Burning and Steam Generation, edited by Joseph P. Singer, Combustion Engineering, Inc., 4 th ed., 1991 (pp ). 41

46 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No will be limited by the SO 2 equilibrium vapor pressure. Therefore, high control efficiencies would not be expected on a boiler firing low sulfur coals because of the reduced SO 2 concentration in the boiler flue gas. Although WFGD control systems have not been used on subbituminous coal-fired units there are no technical limitations that would preclude its use on Sooner Units 1 & 2. Therefore, WFGD is determined to be a technically feasible SO 2 control retrofit technology. Based on the fuel characteristics listed in Table 4-1, taking into consideration the reduced SO 2 concentration in the flue gas and reduced SO 2 loading to the scrubbing system, and allowing a reasonable operating margin to account for normal operating conditions (e.g., load changes, changes in fuel characteristics, and minor equipment upsets) it is concluded that a WFGD retrofit control system could achieve a controlled SO 2 rate of 0.08 lb/mmbtu (30-day average) Dry Flue Gas Desulfurization Another scrubbing system that has been designed to remove SO 2 from coal-fired combustion gases is dry scrubbing. Dry scrubbing involves the introduction of dry or hydrated lime slurry into a reaction tower where it reacts with SO 2 in the flue gas to form calcium sulfite solids (see equations 4-1 and 4-2). Dry scrubbing includes a separate lime preparation system and reaction tower. Unlike wet FGD systems that produce a slurry byproduct that is collected separately from the fly ash, dry FGD systems produce a dry byproduct that must be removed with the fly ash in the particulate control equipment. Therefore, dry FGD systems must be located upstream of the particulate control device to remove the reaction products and excess reactant material. Various dry FGD systems have been designed for use with pulverized coal-fired boilers. Dry scrubbing systems that may be technically feasible on Sooner Units 1 & 2 are discussed below. Spray Dryer Absorber Spray dryer absorber (SDA) systems have been used in large coal-fired utility applications. SDA systems have demonstrated the ability to effectively reduce uncontrolled SO 2 emissions from pulverized coal units. The typical spray dryer absorber uses a slurry of lime and water injected into the tower to remove SO 2 from the combustion gases. The towers must be designed to provide adequate contact and residence time between the exhaust gas and the slurry to produce a relatively 42

47 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No dry by-product. The process equipment associated with a spray dryer typically includes an alkaline storage tank, mixing and feed tanks, an atomizer, spray chamber, particulate control device and a recycle system. The recycle system collects solid reaction products and recycles them back to the spray dryer feed system to reduce alkaline sorbent use. Various process parameters affect the efficiency of the SDA process including: the type and quality of the additive used for the reactant, reactant stoichiometric ratio, how close the SDA is operated to saturation conditions, and the amount of solids product recycled to the atomizer. The control efficiency of a SDA system is limited to approximately 94% of the SO 2 loading to the system, and is a function of numerous operating variables including gasto-liquid contact and system operating temperatures. In a dry FGD system, the amount of reactant slurry introduced to the spray dryer must be controlled to insure that the reaction products leaving the absorber vessel are dry. Therefore, the outlet temperature from the absorber must be maintained above the saturation temperature. SDA systems are typically designed to operate within approximately 30 o F adiabatic approach to the saturation temperature. Operating closer to the adiabatic saturation temperature allows higher SO 2 control efficiencies; however, outlet temperatures too close to the saturation temperature will result in severe operating problems including reactant build-up in the absorber modules, blinding of the fabric filter bags, and corrosion in the fabric filter and ductwork. High SO 2 removal efficiencies in a SDA are also dependent upon good gas-to-liquid contact. Reactant spray nozzle designs are vendor-specific; however, both dual-fluid nozzles and rotary atomizers have been used in large coal-fired boiler applications. Dual-fluid nozzles (slurry and atomizing air) typically consist of a stainless steel head with multiple, ceramic two-fluid nozzle inserts. Slurry enters through the nozzle head and is distributed to the nozzle inserts. Atomizing air enters concentrically into a reservoir in the nozzle head and mixes with the slurry. The atomizing air expands as it passes through the air holes and nozzle exit. This expansion creates the shear necessary to atomize the slurry. Each nozzle is provided with a feed lance assembly consisting of a concentric feed pipe (air around slurry), hose connections, and the nozzle head. The feed lance assembly is inserted down through the SDA roof through a nozzle shroud assembly. Rotary atomizers are comprised basically of a high-speed rotating atomizer wheel coupled to a drive device and speed-increasing gear box. Because the reactant slurry is abrasive, the atomizing nozzles typically consist of a stainless steel head and multiple abrasion-resistant 43

48 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No ceramic nozzle inserts. The rotary atomizers are inserted down through the SDA roof. The reactant slurry is atomized as it passes through the rapidly rotating nozzles. The atomizing nozzle assembly (either the duel-fluid feed lance assembly or the rotary atomizer assembly) is typically located in the SDA penthouse, and flange mounted to the roof of the absorber vessel. Overhead cranes or hoists located in the penthouse can be used to remove the nozzle assemblies from the absorber vessel for repair and maintenance. Because of the abrasive nature of the reactant slurry, nozzle assemblies must be removed and replaced on a routine basis. Depending on the design of the SDA system, one or more spare nozzle assemblies will be available for use. The nozzle assemblies may be changed without shutting down the SDA system. During that time period, the SDA may not be able to maintain maximum control efficiencies. SDA control systems are a technically feasible and commercially available retrofit technology for Sooner Units 1 & 2. Based on the fuel characteristics listed in Table 4-1 and allowing a reasonable margin to account for normal operating conditions (e.g., load changes, changes in fuel characteristics, reactant purity, atomizer change outs, and minor equipment upsets) it is concluded that dry FGD designed as SDA could achieve a controlled SO 2 emission rate of 0.10 lb/mmbtu (30-day average) on an on-going long-term basis. Dry Sorbent Injection Dry sorbent injection involves the injection of powdered absorbent directly into the flue gas exhaust stream. Dry sorbent injection systems are simple systems, and generally require a sorbent storage tank, feeding mechanism, transfer line and blower and an injection device. The dry sorbent is typically injected countercurrent to the gas flow. An expansion chamber is often located downstream of the injection point to increase residence time and efficiency. Particulates generated in the reaction are controlled in the system s particulate control device. Typical SO 2 control efficiencies for a dry sorbent injection system are generally around 50%. Because the control efficiency of the dry sorbent system is lower then the control efficiency of either the wet FGD or SDA, the system will not be evaluated further. Circulating Dry Scrubber A third type of dry scrubbing system is the circulating dry scrubber (CDS). A CDS system uses a circulating fluidized bed of dry hydrated lime reagent to remove SO 2. Flue gas 44

49 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No passes through a venturi at the base of a vertical reactor tower and is humidified by a water mist. The humidified flue gas then enters a fluidized bed of powdered hydrated lime where SO 2 is removed. The dry by-product produced by this system is similar to the spray dry absorber by-product, and is routed with the flue gas to the particulate removal system. Based on engineering judgment and information available from equipment vendors, the CDS flue gas desulfurization system should be capable of achieving SO 2 removal efficiencies similar to those achieved with a spray dryer absorber. In fact, vendors advise that the CDS system is capable of achieving even higher removal efficiencies with increased reactant injection rates and higher Ca/S stoichiometric ratios. However, to date the CDS has had limited application, and has not been used on large pulverized coal boilers. The largest CDS unit, in Austria, is on a 275 MW size oil-fired boiler burning oil with a sulfur content of 1.0 to 2.0%. Operating experience on smaller pulverized coal boilers in the U.S. has shown high lime consumption rates, and significant fluctuations in lime utilization based on inlet SO 2 loading. 26 Furthermore, CDS systems result in high particulate loading to the unit s particulate control device. Based on the limited application of CDS dry scrubbing systems on large boilers, it is likely that OG&E would be required to conduct extensive design engineering to scale up the technology for boilers the size of Sooner Units 1 & 2, and that OG&E would incur significant time and resource penalties evaluating the technical feasibility and long-term effectiveness of the control system. Because of these limitations, CDS dry scrubbing systems are not currently commercially available as a retrofit control technology for Sooner Units 1 & 2, and will not be evaluated further in this BART determination. The results of Step 2 of the SO 2 BART analysis (technical feasibility analysis of potential SO 2 control technologies) are summarized in Table See, Lavely, L.L., Schild, V.S., and Toher, J., First North American Circulating Dry Scrubber and Precipitator Remove High Levels of SO2 and Particulate, 45

50 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Table 4-3 Technical Feasibility of Potential SO 2 Control Technologies Control Technology In Service on SO 2 Emission Rate Existing PC Boilers? (lb/mmbtu) Yes No In Service on Other Combustion Sources? Fuel Switching NA X PCs have been designed to burn a variety of fuels. Coal Washing Coal Processing NA -- X X Washing has not been used on subbituminous coals. Processed coal has been demonstrated in PC boilers. Technically Feasible Retrofit Technology for Sooner Units 1 & 2? Not technically feasible. The fuel currently used is low-sulfur and fuel switching will not reduce controlled SO 2 emissions. Not technically feasible nor commercially available. Coal washing has not been used on subbituminous coals and washed subbituminous coal is not commercially available. Furthermore, it is unlikely that firing a washed subbituminous coal would result in any significant reduction in controlled SO 2 emissions. Not technically available nor commercially available. Processed coal has not been demonstrated on a long-term basis as the primary flue in a PC boiler, and is not commercially available as a retrofit technology. Wet FGD (lime, limestone, or magnesium enhanced lime) 0.08 lb/mmbtu (approx. 40 3% O 2 ) X Wet FGD has been used on bituminous coal-fired PC boilers. Technically feasible, however limited commercial experience with wet FGD on large subbituminous fired units. Jet Bubbling Reactor Wet FGD Control System 0.08 lb/mmbtu (approx. 40 3% O 2 ) X JBR-FGD systems are in use on a limited number of coal-fired boilers. Technically feasible, but may not be commercially available for Sooner Units 1 & 2 (large subbituminous fired units). Because there is no operating experience with JBR-WFGD systems on large subbituminous-fired units, the control system was evaluated as an alternative WFGD control system. 46

51 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Table 4-3 continued: Dual-Alkali Wet Scrubber Wet FGD with WESP Dry FGD Spray Dryer Absorber Dry Sorbent Injection Circulating Dry Scrubber NA X In use at a limited number of coalfired facilities. NA X The WESP control system is in use at a limited number of high-sulfur coal lb/mmbtu (approx. 50 3% O 2 ) 0.4 lb/mmbtu (approx % O 2 ) X X fired units. In use on subbituminous coalfired boilers. Dry sorbent injection has been used on a limited number of coalfired units. NA X CDS is in use at a limited number of coal-fired boilers. Not commercially available. Not technically feasible nor commercially available for units firing a low-sulfur subbituminous coal. Technically feasible. Technically feasible, but not as effective as other SO 2 control options therefore excluded as BART. CDS Dry FGD was determined not to be commercially available for Sooner Units 1 & 2 (large subbituminous fired units). In addition, there is no commercial experience with units similar to Sooner Units 1 & 2, so CDS- DFGD was excluded as BART. Step 3: Rank the Technically Feasible SO 2 Control Options by Effectiveness Both technically feasible SO 2 retrofit technologies (i.e., Wet- and Dry-FGD) are capable of meeting the BART presumptive level of 0.15 lb/mmbtu. However, in order to evaluate the cost effectiveness of each control technology, annual emissions and costs were estimated at the design emission limits of 0.08 lb/mmbtu for WFGD and 0.10 lb/mmbtu for DFGD. This approach was taken in order to determine whether either control technology was cost effective at the anticipated design emission rate. The technically feasible SO 2 control technologies are listed in Table 4-4 in descending order of control efficiency based on anticipated design emission rates. 47

52 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Table 4-4 Summary of Technically Feasible SO 2 Control Technologies Control Technology SO 2 Emission Rate* (lb/mmbtu) Sooner 1 Sooner 2 Wet FGD Dry FGD Spray Dryer Absorber Baseline Uncontrolled SO 2 Emissions * Emission rates are based on 30-day rolling averages that can be achieved on an on-going long-term basis under all normal operating conditions. 4.3 Step 4: Evaluate the Technically Feasible SO 2 Control Technologies Two post-combustion flue gas desulfurization control system designs (WFGD and SDA) are technically feasible and capable of achieving very low SO 2 emission rates. An evaluation of the economic, energy and environmental impacts associated with each control system is provided below Economic Evaluation Summarized in Table 4-5 are the expected controlled SO 2 emission rates and annual SO 2 mass emissions associated with each technically feasible control technology. Table 4-6 presents the capital costs and annual operating costs associated with building and operating each control system. Table 4-7 shows the average annual and incremental cost effectiveness for each SO 2 control system. Control Technology SO 2 Emissions (lb/mmbtu) Table 4-5 Sooner Units 1 & 2 Annual SO 2 Emissions (per boiler) Emissions (tpy)* Sooner 1 Sooner 2 Reduction in Emissions Reduction in Emissions (tpy)* (tpy)* Emissions (tpy)* Wet FGD ,613 15,731 1,613 15,731 Dry FGD SDA ,017 15,327 2,017 15,327 Baseline , , * Annual emissions and annual emission reductions for the BART analysis were calculated based on a full load heat input of 5,116 mmbtu/hr (per boiler), and assuming 7,884 hours/year (90% capacity factor). 48

53 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Table 4-6 Sooner Units 1 & 2 SO 2 Emission Control System Cost Summary (per boiler) Control Technology Total Capital Investment* ($) Total Capital Investment ($/kw-gross) Annual Capital Recovery Cost ($/year) Annual Operating Costs ($/year) Total Annual Costs ($/year) Wet FGD $441,658,000 $730 $37,899,000 $42,998,900 $80,897,800 Dry FGD SDA $390,406,000 $651 $33,500,900 $40,021,700 $73,522,600 * Capital costs for SO 2 control systems will be similar for Units 1 & 2. Capital costs include the cost of major components and indirect installation costs such as foundations, mechanical erection, electrical, piping, and insulation for the control system. Capital costs reflect the combined cost for control systems on both Units 1 & 2. Capital costs for the Wet FGD scenario include the cost of new chimneys on both units, and capital costs for the Dry FGD scenario include the cost of a post-scrubber fabric filter baghouse. Table 4-7 Sooner Units 1 & 2 SO 2 Emission Control System Cost Effectiveness (total for two boilers) Control Technology Total Annual Cost ($/year) Annual Emission Reduction (tpy) Average Annual Cost Effectiveness ($/ton) Incremental Annual Cost Effectiveness* ($/ton) Wet FGD $161,795,600 31,462 $5,143 $18,255 Dry FGD SDA $147,045,200 30,654 $4, *Incremental cost effectiveness of the wet FGD control systems compared to the SDA control system. The average cost effectiveness of the potentially feasible SO 2 control technologies range from approximately $4,797/ton for dry FGD to $5,143/ton for wet FGD. To support the BART rulemaking process, EPA calculated the cost effectiveness of both wet- and dry-fgd systems. Based on EPA s analysis, the average cost effectiveness for controlling all BART-eligible EGUs greater than 200 MW without existing SO 2 controls was estimated at $919 per ton SO 2 removed. Moreover, the range of cost effectiveness numbers demonstrated that the majority of these units could meet the presumptive SO 2 emission limits at a cost of $400 to $2,000 per ton of SO 2 removed (see, 70 FR 39133). Therefore, the average effectiveness of SO 2 removal at Sooner Units 1 & 2 is more than double the average cost effectiveness calculated by EPA for SO 2 control on large EGUs. EPA s calculation of average cost effectiveness included specific estimates for the Sooner Generating Station. EPA estimated that the least cost alternative for Sooner would be wet FGD with estimated cost effectiveness ranging from $1,751/ton to $1,790/ton. As demonstrated by Table 4-7, wet FGD is actually 290% more costly than EPA estimated, and the actual cost effectiveness for dry FGD is 270% worse than the cost effectiveness estimated by EPA for a least cost scrubber installation at Sooner. 49

54 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Although the wet FGD control system may provide an incremental reduction in overall SO 2 emissions from Sooner Units 1 & 2, the incremental costs associated with the additional SO 2 reductions are significantly higher than the average cost effectiveness of either control system. Wet FGD systems have a higher initial capital requirement (compared to dry systems), require more energy to operate, and have somewhat higher annual operating costs. The total annual costs for wet FGD control systems on Sooner Units 1 & 2 are estimated to be approximately $14,750,400/year higher than the total annual costs for dry FGD systems. The incremental cost effectiveness of the wet FGD systems is estimated to be approximately $18,255/ton, which is substantially higher than the average cost effectiveness of the dry FGD control systems ($4,797/ton). The additional costs associated with wet FGD would result in significant economic impacts on the Sooner Generating Station (e.g., $14,750,400 per year additional costs). Therefore, wet FGD should not be selected as BART based on lack of cost effectiveness Environmental Impacts of Wet FGD In addition to the economic impacts, there are several collateral environmental impacts associated with a wet FGD system. First, wet FGD systems generate a calcium sulfate waste by-product that must be properly managed. Historically, solid wastes generated from wet FGD systems have been dewatered and disposed of in landfills. Most new wet FGD systems utilize a forced oxidation system that results in a gypsum by-product that can sometimes be sold into the local gypsum market. If an adequate local gypsum market is not available, the gypsum byproduct will require proper disposal. Second, wet FGD systems will result in greater particulate matter emissions from the following sources: 1. SO 3 remaining in the flue gas will react with moisture in the wet FGD to generate sulfuric acid mist. Sulfuric acid mist is classified as a condensable particulate. Condensable particulates from the wet FGD system can be captured using additional emission controls (e.g., WESP). However the effectiveness of a WESP system on a subbituminous fired unit has not been demonstrated and the additional cost of the WESP system significantly increases the cost of SO 2 control. 2. Wet FGD systems must be located downstream of the unit s particulate control device; therefore, dissolved solids from the wet FGD system will be emitted with the wet FGD plume. Wet FGD control systems also generate lower stack temperatures that can reduce plume rise and result in a visible moisture plume. 3. Wet FGD systems use more reactant (e.g., limestone) than do dry systems, therefore the limestone handling system and storage piles will generate more fugitive dust emissions. 50

55 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Third, wet FGD systems also require significantly more water than the dry systems. Based on preliminary engineering calculations, it is estimated that a wet FGD system would require approximately 675 million gallons per year (total for both units based on a 90% capacity), which represents an increase of about 30% over water consumption associated with dry FGD control systems. Water consumption is an important factor when assessing potential environmental impacts, and it is beneficial to minimize water consumption and maximize water recycle/reuse as much as practical. Finally, wet FGD systems generate a wastewater stream that must be treated and discharged. Wet FGD wastewater consists of a saturated solution of calcium sulfate, calcium sulfite, sodium chloride, with trace amounts of flyash and unreacted limestone. Traces of metal ions will also be present due to flyash carryover from the flue gas to the FGD scrubber liquor. Wet FGD wastewater treatment systems typically require calcium sulfate/sulfite desaturation, heavy metals precipitation, coagulation/precipitation, and sludge dewatering. Treated wastewater is typically discharged to surface water pursuant to an NPDES discharge permit, and solids are typically disposed of in a landfill. Dry FGD control systems are designed to evaporate water within the reaction vessel, and therefore do not generate a wastewater stream Environmental Impacts of Dry Scrubbing Collateral environmental impacts are less significant with dry scrubbing systems (spray dryer absorber). First, dry scrubbing systems utilize lime as the reactant rather than limestone. Limebased scrubbing systems use less reactant than limestone-based systems, reducing overall particulate matter emission from the facility s material handling system. Lime in a dry scrubbing system will be hydrated prior to use. It is estimated, based on preliminary engineering calculations, that a dry system would require approximately 458 million gallons per year (total for both units based on 90% capacity factor); however, water consumption with a dry system is approximately 30% less than the water requirements for a wet system. Furthermore, water used to hydrate the lime will be evaporated in the absorber vessel, and dry FGD systems will not generate a wastewater stream. Dry scrubbing systems are located upstream of the unit s particulate control device. FGD solids mixed with fly ash will be captured in the particulate control device. The mixture of dry FGD solids and fly ash is generally not salable; however the material does not require dewatering and is easily landfilled. Assuming the unit is equipped with a fabric filter baghouse for particulate control, the alkaline filter cake associated with the dry scrubber will augment the capture of acid gases (including sulfuric acid), and will minimize condensable particulate emissions without the need for additional controls (e.g., WESP). 51

56 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Energy Impacts Both FGD control systems have significant auxiliary power requirements. Auxiliary power is required for material handling, reactant preparation, pumps, mixers, and to overcome significant pressure drops through the reaction vessels. Based on engineering estimates, auxiliary power requirement for wet and dry FGD control systems are approximately 2.25% and 1.5% of the gross energy output of the generating unit, respectively. Sooner Units 1 & 2 have a gross rating of 570 MW (each); therefore, annual auxiliary power requirements for FGD control systems would be in the range of 135,000 to 200,000 MWh per year (at a 90% capacity factor). Energy impacts associated with each control technology were included in the BART economic impact evaluation as an auxiliary power cost. Control Technology A summary of the Step 4 economic and environmental BART impact analysis is provided in Table 4-8. Annual Emissions Annual Emission Reductions (tpy) Table 4-8 Sooner Units 1 & 2 Summary of SO 2 BART Impact Analysis* Total Annual Costs ($/year) Average Cost Effectiveness ($/ton) Incremental Cost Effectiveness ($/ton) Summary of Collateral Environmental Impacts (tpy) Wet FGD 3,226 31,462 $161,795,600 $5,143 $18,255 Increased PM emissions, including sulfuric acid mist and other condensable particulates. Increased NOx, CO, VOC, and PM 10 emissions associated with decreased unit heat rate and increased energy consumption. Increased water use and wastewater treatment/discharge. DFGD-SDA 4,034 30,654 $147,045,200 $4,797 NA Less water required. Increased solid waste generation rates (compared to wet FGD with forced oxidation and gypsum byproduct market). No wastewater generation or discharge. *Emissions and costs summarized in this table represent totals for both boilers. Emissions and costs were estimated based on a full load boiler heat input of 5,116 mmbtu/hr and a 90% capacity factor. 52

57 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Step 5: Evaluate Visibility Impacts To evaluate the relative effectiveness of potentially feasible SO 2 retrofit control technologies, SO 2 emissions were modeled at the projected post-retrofit controlled emission rates, while NO x and PM 10 emissions were modeled at the pre-bart baseline emission rates. In accordance with EPA guidelines (40 CFR Part 51 Appendix Y Part III), post-retrofit emission rates used in the modeling analysis to determine visibility impairment impacts reflect steady-state operating conditions during periods of high capacity utilization. Post-retrofit emission rates (average lb/hr rate on a 24-hour basis) were calculated using the expected controlled emission rate achievable on a 30-day rolling average multiplied by the boiler heat input (mmbtu/hr) at full load. The visibility modeling methodology is described further in Attachment B of this document, including detailed inputs and results. The results in Table 4-9 summarize the 98 th percentile -dv impact from SO 2 emissions associated each SO 2 retrofit control scenario. Table 4-9 Sooner Units 1 & 2 - SO 2 Visibility Assessment Visibility Improvement Wichita Mountains Wildlife Refuge Upper Buffalo Wilderness Area Hercules-Glades Wilderness Area Caney Creek Wilderness Area % Improvemenmenmenment % Improve- % Improve- % Improve- SO 2 Control 98 th % over 98 th % over 98 th % over 98 th % over Technology Option -dv* Previous -dv Previous -dv Previous -dv Previous Baseline DFGD SDA % % % % WFGD % % % % * -dv values included in this table represent the modeled visibility impacts only from SO 2 emissions associated with each SO2 retrofit control scenario. With either FGD control system, modeled visibility impact improvements at the four Class I Areas are reduced by an average of approximately 0.5 -dv, ranging from dv improvement (Hercules-Glades) to dv (Wichita Mountains with dry FGD). Although the wet FGD control systems result in lower SO 2 mass emission rates, modeled visibility impairments are generally less with dry FGD controls. Modeled impacts associated with SO 2 emissions with either FGD control system are below the threshold impact level of 0.5 -dv level at all Class I Areas. A summary of the cost effectiveness of both FGD control systems as a function of visibility impairment improvement at the Class I Areas is provided in Table

58 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Table 4-10 Sooner Units 1 & 2 - SO 2 Average Visibility Cost Impact Evaluation SO 2 Control Technology Option Total Annual Cost Modeled Visibility Impairment* Visibility Impairment Improvement from Baseline Average Improvement Cost Effectiveness ($/yr) 98 th % -dv* (dv) ($/dv/yr) Baseline DFGD SDA $147,045, $125.7 MM/dv WFGD $161,045, $138.8 MM/dv * -dv values included in this table represent the modeled visibility impacts only from SO 2 emissions associated with each SO 2 retrofit control scenario. Visibility impairment at the nearest Class I Area (Wichita Mountains) was used for the cost effectiveness evaluation. Although FGD control systems reduce modeled visibility impacts at the four Class I Areas, the cost effectiveness of FGD control (with respect to visibility improvement) is very high. With either FGD control system, cost effectiveness ranges from approximately $125.7 million to $138.8 million per dv improvement at the Wichita Mountains. These costs are significantly higher than costs incurred at other BART applicable sources. A review of BART determinations at other coal-fired units suggests that BART cost effectiveness values are typically in the range of less than $1.0 million to approximately $13 million per dv improvement. 27 The combination of relatively low baseline SO 2 emissions, low baseline visibility impacts (less than 1.2 -dv at all Class I Areas), and distance to the Class I Areas, all contribute to the large cost effectiveness values at the Sooner Generating Station. To determine whether alterative SO 2 control scenarios might provide more cost effective visibility improvements, cumulative impact modeling was conducted using a variety of FGD control scenarios. A goal of the cumulative impact modeling was to determine whether alternative SO 2 control scenarios (i.e., FGD control on some, but not all of the OG&E BART applicable sources) would provide more cost effective SO 2 control. To quantify cost effectiveness, visibility impairment was modeled for several SO 2 control scenarios, while NOx and PM emissions were held constant at their respective baseline emission rates. Modeled SO 2 control scenarios are listed in Table Results of the cumulative SO 2 impact modeling are summarized in Table See e.g., BART evaluations for Xcel (Sherco, MN); Great River Energy (Coal Creek, ND); Trigen Energy Co. (CO); Entergy White Bluff Power Plant (AR). 54

59 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Table 4-11 Cumulative SO 2 Visibility Assessment (Muskogee Units 4 & 5 and Sooner Units 1 & 2)* Unit Base Case Case 1 Case 2 Case 3 Case 4 SO 2 Controls (Emission Rate - lb/mmbtu) Muskogee Unit 4 Baseline (0.80) DFGD (0.10) DFGD (0.10) DFGD (0.10) DFGD (0.10) Muskogee Unit 5 Baseline (0.85) Baseline (0.85) Baseline (0.85) DFGD (0.10) DFGD (0.10) Sooner Unit 1 Baseline (0.86) Baseline (0.86) DFGD (0.10) DFGD (0.10) DFGD (0.10) Sooner Unit 2 Baseline (0.860) Baseline (0.86) Baseline (0.86) Baseline (0.86) DFGD (0.10) * For each case PM and NOx emissions were held constant at the baseline emission rates. Baseline emissions for NOx were: 0.15 lb/mmbtu for both Muskogee units (assuming LNB/OFA controls). SO 2 Control Technology Option Table 4-12 Cumulative SO 2 Visibility Modeling Results (Muskogee Units 4 & 5 and Sooner Units 1 & 2) Upper Buffalo Wilderness Area 98 th % -dv Modeled Visibility Impairment* Caney Creek Hercules-Glades Wilderness Area Wilderness Area 98 th % -dv 98 th % -dv Wichita Mountains Wildlife Refuge 98 th % -dv Base Case Case Case Case Case * -dv values included in this table reflect cumulative modeled contributions from NOx, SO 2 and PM emissions from both the Sooner and Muskogee Stations. For each case PM and NOx emissions were held constant at their respective baseline emission rates, while SO 2 emissions varied depending the SO 2 control system on each unit (see Table 4-11). The dv values in this table are not directly related to dv values in Tables 3-8 (NOx) and 4-9 (SO2), which reflect modeled impacts from the Sooner Station only for each individual pollutant. Results of the cumulative impact modeling suggest that visibility improvement at the Class I Areas is essentially linear with SO 2 emission reductions from the OG&E generating stations (see, Figure 4-1). For example, modeled visibility impairment at the Wichita Mountains was reduced by dv with one FGD at the Muskogee Station, and by an additional dv with a second FGD at Muskogee. Similarly, visibility impairment at the Wichita Mountains was reduced by dv with one FGD control system at the Sooner Station, and by an additional dv with a second FGD at Sooner. However, because of the relatively small improvement in visibility impairment, 55

60 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No the cost effectiveness for FGD control systems ranged from approximately $120 MM/dv (Sooner Station) to more than $260 MM/dv (Muskogee Station). Cost effectiveness values associated with the cumulative impact modeling at the Wichita Mountains Wildlife Refuge are summarized in Table Figure 4-1 Cumulative SO 2 Visibility Modeling Results (Muskogee Units 4 & 5 and Sooner Units 1 & 2) 3.00 Wichita Mountains Modeled Visibility Impairment vs. FGD Control Systems Wichita Mts Caney Creek Herc-Glades Upper Buffalo Modeled Visibility Impairment (delta-dv Baseline Case 1 (Muskogee Unit 4) Case 2 (Muskogee Unit 4 and Sooner Unit 1) FGD Control Scenario Case 3 (Muskogee 4 & 5 and Case 4 (Muskogee 4 & 4 and Sooner Unit 1) Sooner 1 & 2) Table 4-13 Cumulative SO 2 Visibility Modeling Results Wichita Mountains Case 98 th % -dv Incremental Improvement Incremental Increase in Annual Cost Cost Effectiveness Baseline $MM/dv Case $71,067,900 $273.3 Case $70,415,900 $125.7 Case $71,067,900 $263.2 Case $70,415,900 $

61 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Propose BART for SO 2 Control OG&E is proposing that no additional SO 2 controls (beyond baseline low sulfur subbituminous coal) are BART for Sooner Units 1 & 2. In the final Regional Haze Rule, EPA established presumptive BART emission limits for SO 2 from coal-fired EGUs greater than 200 MW at power plants with a total generating capacity in excess of 750 MW The BART SO 2 presumptive emission limit for these units is either 95% SO 2 removal or an emission rate of 0.15 lb/mmbtu, unless an alternative control level is justified based on a careful consideration of the statutory factors. Statutory factors include the costs of compliance and the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology. In the case of the Sooner Station, the poor cost effectiveness of the feasible controls dictates a decision that no additional controls are warranted. The cost effectiveness of FGD control on Sooner Units 1 & 2 is poor in comparison to the cost effectiveness estimates used by EPA in establishing presumptive BART. EPA believed the average cost effectiveness would be $919 per ton SO 2 removed, with the majority of the BART applicable units meeting the presumptive standards at a cost of $400 to $2,000 per ton of SO 2 removed. To support the presumptive BART analysis, EPA developed cost effectiveness estimates for Sooner Units 1 & 2 of $1,751 to $1,790 per ton of SO 2 removed. In fact, the actual cost effectiveness of the potentially feasible SO 2 control technologies at the Sooner Station is $4,797 to $5,143 per ton of SO 2 removed. Therefore, SO 2 removal at Sooner Units 1 & 2 is nearly three times less cost effective than EPA expected, and it is well outside of the cost effectiveness range that EPA used to support its presumptive BART determination. The cost effectiveness of FGD controls at the Sooner Station calculated on the basis of visibility improvement also is poor. The cost effectiveness is estimated to be in the range of $125.7 to $138.8 million per dv improvement, which is significantly less cost effective that other BART applicable sources. Although FGD control systems (either wet or dry FGD) will reduce SO 2 emissions and modeled visibility impairment at the Class I Areas, the combination of relatively low baseline SO 2 emissions, low baseline visibility impacts (less than dv at all Class I Areas), and distance to the Class I Areas, all contribute to the poor cost effectiveness values. Based on the poor cost effectiveness of FGD retrofit controls and the relatively small degree of improvement in visibility, FGD control systems should not be selected as BART on Sooner Units 1 & 2. As a result, OG&E is proposing low sulfur subbituminous coal and the existing permit limits as BART for SO 2. 57

62 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No BART ANALYSIS FOR MAIN BOILER PARTICULATE MATTER PM composition and emission levels are a complex function of boiler firing configuration, boiler operation, pollution control equipment and coal properties. Uncontrolled PM emissions from coalfired boilers include the ash from combustion of the fuel, noncombustible metals present in trace quantities and unburned carbon resulting from incomplete combustion. Other sources of PM include condensable organics and minerals present in the combustion air. Coal ash may either settle out in the boiler (bottom ash) or be entrained in the flue gas (fly ash). The distribution of ash between the bottom ash and fly ash fractions affects the PM emission rate and is a function of the boiler firing method and furnace type. With a PC boiler approximately 80% of the ash will be emitted with the flue gas as fly ash and 20% will settle out in the combustion bed as bottom ash. PM 10 emissions from Sooner Units 1 & 2 are currently controlled with cold-side electrostatic precipitators (ESPs). 5.1 Step 1: Identify Available Retrofit PM10 Control Options The principal techniques for PM control are post-combustion methods (applicable to most boiler types and sizes). There are two generally recognized PM control devices that are used to control PM emission from PC boilers: ESPs and fabric filters (or baghouses). Sooner Units 1 & 2 are currently equipped with ESP control systems. Retrofit PM 10 control options with potential application to a subbituminous-fired PC boiler are listed in Table 5-1. The technical feasibility of each potential control option is discussed below. Table 5-1 PM 10 Retrofit Control Options with Potential Application to a Subbituminous-Fired PC Boiler PM 10 Control Technologies Electrostatic Precipitation (ESP) existing Fabric Filtration (FF) 5.2 Step 2: Eliminate Technically Infeasible Retrofit Options Electrostatic Precipitators (ESPs) Sooner Units 1 & 2 are currently equipped with ESPs for PM 10 control. ESP technology consists of three steps: (1) charging the particles to be collected via a high-voltage electric discharge, (2) collecting the particles on the surface of an oppositely charged collection electrode surface, and (3) 58

63 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No cleaning the surface of the collecting electrode. Particulate material captured on the collecting electrodes is removed by rapping the electrodes. The collected particulates drop into hoppers below the precipitator and are periodically removed with the fly ash handling system. Operating parameters that influence ESP performance include fly ash mass loading, particle size distribution, fly ash electrical resistivity, and precipitator voltage and current. Other factors that determine ESP collection efficiency are collection plate area, gas flow velocity, and cleaning cycle. Baseline controlled PM 10 emissions from Units 1 & 2 are approximately 194 lb/hr and 299 lb/hr, respectively. Based on a maximum heat input of 5,116 mmbtu/hr (each boiler), baseline PM 10 emission rates from Sooner Units 1 & 2 are and lb/mmbtu, respectively. 28 These controlled rates require the existing ESPs to achieve average overall particulate matter control efficiencies of greater than 99% Fabric Filters Fabric filtration consists of a number of filtering elements (bags) along with a bag cleaning system contained in a main shell structure incorporating dust hoppers. Particulate-laden gas enters a fabric filter compartment and passes through a layer of filter bags. The collected particulate forms a cake on the bag that enhances the bag s filtering efficiency. Excessive caking will increase the pressure drop across the fabric filter at which point the filters must be cleaned. The particulate removal efficiency of fabric filters is dependent upon a variety of particle and operational characteristics. Particle characteristics that affect the collection efficiency include particle size distribution and particle cohesion characteristics. Operational parameters that may affect fabric filter collection efficiency include bag material, air-to-cloth ratio, and operating pressure loss. In addition, certain filter properties (e.g., structure of the fabric and fiber composition) can affect the system's particle collection efficiency. Fabric filter baghouses are considered a technically feasible particulate matter control option for Sooner Units 1 & 2, and a fabric filter baghouse (or polishing baghouse) would be required if the units were retrofit with dry FGD. However, retrofitting the existing units with baghouses for particulate matter control only (i.e., not in conjunction with a dry FGD) would require substantial modifications to the units without providing any significant reduction in controlled PM emissions. 28 Baseline PM 10 emissions used in this BART analysis were based on the highest 24-hour block emissions reported by each unit during the baseline period. Baseline PM 10 emission rates (lb/mmbtu) were calculated by dividing the maximum hourly mass emission rate (lb/hr) by the full load heat input to each boiler. The relatively high short-term baseline emission rates were used to predict maximum potential visibility impacts, and to provide a conservative estimate of the cost effectiveness of potentially feasible retrofit control technologies. The short-term baseline emission rates should in no way be interpreted as a potential violation of the facility s permitted emission limits, which are averaged over a longer period of time. 59

64 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Extensive ductwork would be required to redirect flue gas flow though the fabric filter and back to the existing stacks. Furthermore, baghouses would provide only an incremental reduction in PM/ PM 10 control compared to the existing ESP control systems. 5.3 Step 3: Rank the Technically Feasible PM10 Control Options by Effectiveness The effectiveness of each retrofit technology identified as being technically feasible for PM 10 control is summarized in Table 5-2 in descending order of control efficiency. Table 5-2 Summary of Technically Feasible Main Boiler PM 10 Control Technologies Control Technology PM10 Emissions* lb/mmbtu) % Reduction (from base case) Fabric Filter Baghouse ESP - Existing Potential PM Emissions * The PM 10 emission rate for the baghouse case is based on filterable PM 10 emission limits included in recently issued PSD permits for new coal-fired units. The PM 10 emission rate for the ESP case is based on the Units baseline PM 10 emission rates. Potential PM emissions were calculated assuming an average fuel heating value of 8,500 Btu/lb and an ash content of 6.0%, and assuming 80% of the fuel ash will be emitted as fly ash. 5.4 Step 4: Evaluate Impacts and Document the Results Economic Evaluation Based on the controlled PM 10 emission rates included in Table 5-2, and assuming a maximum heat input to each boiler of 5,116 mmbtu/hr and 7,884 hours/year operation (90% capacity factor), potential PM 10 emissions from Sooner Units 1 & 2 would be reduced from approximately 1,573 tpy to 605 tpy with a fabric filter baghouse (total potential emissions from both units). Equipment costs associated with retrofitting Sooner Units 1 & 2 with a baghouse are estimated to be in the range of $125 to 135/kW-gross, or approximately $75,000,000. Taking into consideration indirect installation costs for foundations, mechanical erection, electrical, piping, and insulation, and including engineering, and contingencies, total capital requirement for a fabric filter baghouse would be in the range of $104,000,000/unit. The annualized capital recovery cost for the baghouse control systems (assuming equipment life of 25 years and 7% pretax marginal rate of return) would be in the range of $8,900,000/yr (per unit). Ignoring O&M costs associated with baghouse operation (including bag replacement costs and energy cost associated with increased pressure drop) the cost effectiveness of the 60

65 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No retrofit baghouse control system would be more than $18,000/ton of PM removed (e.g., $8.9 MM/yr/unit x 2 units / 968 tpy potential emission reductions). It is apparent that a retrofit baghouse control system would not be cost effective for particulate matter control only. Although baghouses may provide an incremental reduction in PM 10 emissions, the costs associated with a fabric filter retrofit project are significant. Retrofitting Sooner Units 1 & 2 with baghouses for particulate matter control would require a significant capital investment for a minimal reduction in emissions. The cost effectiveness of the retrofit baghouse control systems is excessive, and should preclude fabric filter control systems from consideration as BART Environmental Evaluation There are no environmental considerations that would preclude the use of either fabric filters or ESP control systems as BART on Sooner Units 1 & 2. Both PM control systems generate a fly ash solid waste that must be properly managed Energy Impact Evaluation There are significant auxiliary power requirements associated with the fabric filter control system. Auxiliary power is required to overcome pressure drop through the baghouse and filter cake. Based on engineering estimates, auxiliary power requirements for a fabric filter baghouse are approximately 0.5% of the gross energy output of the generating unit. Sooner Units 1 & 2 have a gross rating of 570 MW (each); therefore, annual auxiliary power requirements for a baghouse control system would be in the range of 45,000 MWh per year (at a 90% capacity factor). Annual operating costs associated with the auxiliary power requirement would be significant, and the increased auxiliary power requirement would reduce the overall efficiency of both units. 5.5 Step 5: Evaluate Visibility Impacts Replacing the existing ESPs on Sooner Units 1 & 2 with baghouses is not a cost effective retrofit control option for PM control. Furthermore, based on visibility impact modeling, particulate matter emissions from Sooner Units 1 & 2 contribute only minimally to modeled visibility impacts at the Class I Areas (see, Attachment B). A majority (more than 90%) of the modeled visibility impacts are associated with NO x and SO 2 emissions. Reducing particulate matter emissions from the existing baseline rate (with ESP control) would provide no discernible reduction in modeled visibility impacts at the Class I areas. 61

66 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Propose BART for PM10 Control Based on visibility impact modeling, and economic impacts associated with retrofit PM controls, OG&E is not proposing any change to its existing PM/ PM 10 emission limits as BART. Therefore, OG&E is proposing no change to existing permitted PM emission limits as BART for particulate matter control. 6.0 BART SUMMARY Table 6-1 summarizes the proposed BART control technologies and associated emission limits for Sooner Units 1 & 2.. Table 6-1 Proposed BART Permit Limits and Control Technologies Pollutant NO x Proposed BART Emission Limit 0.15 lb/mmbtu (30-day average) Proposed BART Technology Combustion controls including LNB and OFA SO 2 Existing Permit Limits Low sulfur subbituminous coal PM 10 filterable Existing Permit Limits NA 62

67 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Attachment A Sooner Units 1 & 2 BART Determination - Cost Estimate Details Page A-1

68 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Economic Evaluation Methodology for Technically Feasible Control Options Summarized below are the basic principles and methodologies used to prepare the economic analysis of technologically feasible control options. The cost-effectiveness evaluations were "study" estimates of ±30% accuracy, based on: (1) engineering estimates; (2) vendor quotations provided for similar projects and similar equipment; (2) S&L s internal cost database; and (4) cost estimating guidelines provided in U.S.EPA s, EPA Air Pollution Control Cost Manual, Sixth Edition EPA-452/B , January Over the past several years, prices on air pollution control equipment have increased significantly. Several trends have contributed to the rapid escalation in costs, including the greater demand for equipment and materials, significant increases in commodity prices, and greater demand for skilled labor and construction contractors. Over the past 4-year period the demand for electric utility steam generating emission control equipment, including FGD and SCR control systems, increased significantly in response to the Clean Air Interstate Rule (CAIR). CAIR, published May 12, 2005, mandates specific emission caps on SO 2 and NOx emissions from power plants located in 28 eastern and midwestern states. CAIR emission caps will be imposed in two phases, with the first phase beginning in 2009 for NOx and 2010 for SO 2. The second phase of emission reductions are required in 2015 for both pollutants. CAIR is projected to result in the installation of an additional 64 GW of flue gas desulfurization and an additional 34 GW of selective catalytic reduction technology on existing coal-fired generation capacity. 29 This increase in demand for retrofit emission control systems created a sellers market in the U.S. Pollution control equipment vendors, their fabricators and material suppliers currently have significant backlogs and are able to charge higher margins, contributing to the recent escalation in retrofit control technology costs. Construction contractors and construction labor are currently in high demand in the U.S., not only in the electric power generating industry but also in the petroleum refining, chemical processing, and ethanol industries. All of these industries pull from the same labor force. Due to increased demand, construction contractors are more selective with the projects that they bid, and are able to demand higher margins. Similarly, the labor force is able to demand more lucrative contracts in order to be attracted to an area that is short of labor. Per diems and mandatory overtime are often needed to attract sufficient labor to support major construction projects. During the same period, commodity prices have also increased significantly. Commodity price data available from the U.S. Department of Labor s Bureau of Labor Statistics show a sharp upturn in metals prices since For example, steel increased 47% from January 2004 to January Prices for copper wire doubled between 2003 and Pollution control projects require large quantities of basic commodities, including steel, concrete, and copper. Increased commodity prices have a significant impact on the cost of large emission control retrofit projects. 29 Regulatory Impact Analysis for the Final Clean Air Interstate Rule, U.S. EPA Office of Air and Radiation, EPA-452/R , March Page A-2

69 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No BART Economic Evaluation Average and incremental cost effectiveness were the two economic criteria considered in the BART analysis. Effectiveness of a control option is measured in terms of tons of pollutant emissions removed per year (E annual ). Cost is measured in terms of the total annualized cost (TAC) associated with the control system. The annual cost effectiveness of a particular control system (expressed in $/ton) is calculated using the following equation: Capital Recovery Cost Average Cost Effectiveness = E annual / TAC One important component of the TAC is the annualized cost to recover the initial capital investment, termed the Capital Recovery Cost (CRC). CRC is a function of the total capital investment, an assumed interest rate, and the estimated economic life of the control equipment. Total Capital Investment Total Capital Investment (TCI) includes all costs required to purchase equipment needed for the control system, and includes the purchased equipment cost plus direct installation costs (such as foundations and supports, erection, electrical, and piping), and indirect capital costs (such as engineering, contractor fees, performance testing and contingencies). To calculate the CRC, the equivalent uniform annual cash flow (EUAC) method was used to annualize the total capital investment. Using the EUAC method, the CRC is determined by multiplying the TCI by a capital recovery factor (CRF), as shown in the following equation: CRC = Capital Recovery Factor (CRF) x TCI The product of the TCI and CRF gives a uniform end-of-year payment necessary to repay the initial capital investment in "n" years at an interest rate of "i". The CRF is calculated using the following equation: n i * (1 + i) CRF = n (1 + i) 1 Where: i = interest rate; and n = economic life of the emission control system Total Annual Cost The Total Annual Cost (TAC) is comprised of the following elements: capital recovery costs (CRC), direct O&M costs (DC), indirect operating costs (IC), and recovery credits (RC) as follows: TAC = CRC + DC + IC - RC Page A-3

70 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No Direct O&M costs are those costs that tend to be proportional to the quantity of exhaust gas processed by the control system. These may include costs for catalysts, utilities (steam, electricity, and water), waste treatment and disposal, maintenance materials, replacement parts, and operating and maintenance labor. Of these direct O&M costs, costs for catalysts, utilities, waste treatment, and disposal are variable. Emission allowance costs associated with certain regulatory programs may also be represented as a variable O&M costs, but have not been included in this cost estimate. Labor costs, maintenance materials and replacement parts are semi-variable direct costs as they are only partly dependent upon the exhaust flow rate. Indirect or Fixed" annual costs are those whose values are totally independent of the exhaust flow rate and, in fact, would be incurred even if the control system were shut down. They include such categories as administrative charges, property taxes, and insurance, and include the capital recovery cost. The direct and indirect annual costs are offset by recovery credits, taken for materials or energy recovered by the control system, which may be sold, recycled to the process, or reused elsewhere at the site. Summary In summary, the following methodology was used to calculate the cost effectiveness of various pollution control systems. 1. The effectiveness of each control system, in terms of annual reduction of pollutant emissions, was calculated. 2. The Total Capital Investment required for each control system was estimated. 3. The Capital Recovery Cost of each control system was calculated based on an assumed interest rate and estimated economic life of 20 years for the control equipment. 4. The Total Annualized Cost of each control system was calculated based on the Capital Recovery Cost and Annual Operating Costs. 5. The Annual Control Effectiveness, in terms of Total Annualized Costs divided by annual emission reductions, was calculated for each control system. BART economic evaluations were prepared for the following control systems: NOx Control Cost Summary - Combustion Controls (LNB/OFA) - Combustion Controls plus Selective Catalytic Reduction (SCR) SO 2 Control Cost Summary - Dry FGD (Spray Dry Absorber) - Wet FGD Page A-4

71 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No BART Economic Evaluation NOx Summary SOONER STATION UNIT 1 OR 2 NOx CONTROL SUMMARY Pollutant: Sooner 1 - NOx Sooner 2 - NOx Unit Design Heat Input: 5,116 5,116 mmbtu/hr Net Capacity: MW Capacity Factor 90% 90% Maximum Hours/year: 7,884 7,884 hours Notes Assuming 90% capacity factor for cost evaluations. Based on 90% capacity factor for cost evaluations. Control Technology Sooner Unit 1 Expected Emissions Reduction Expected Emission Expected Total Capital Annual Capital Recovery Total Annual Average Control Rate Emissions Requirement Cost Operating Costs Total Annual Costs Efficiency (lb/mmbtu) (ton/year) (ton/year) ($) ($/year) ($/year) ($) ($/ton) ($/ton) Baseline Emissions ,121 NA Incremental Control Efficiency Alternative 1: LNB / OFA ,025 9,096 $14,055,900 $1,206,100 $877,100 $2,083,200 $ Alternative 2: LNB/OFA + SCR ,412 10,709 $192,018,500 $16,477,200 $14,487,400 $30,964,600 $2,891 17,905 Note: Costs for Alternative 2 include the costs of the combustion controls (Alternative 1) plus the costs of SCR. Control Technology Sooner Unit 2 Expected Emission Rate Expected Emissions Expected Emissions Reduction Total Capital Requirement Annual Capital Recovery Cost Total Annual Operating Costs Total Annual Costs Average Control Efficiency Incremental Control Efficiency (lb/mmbtu) (ton/year) (ton/year) ($) ($/year) ($/year) ($) ($/ton) ($/ton) Baseline Emissions ,778 NA Alternative 1: LNB / OFA ,025 8,753 $14,055,900 $1,206,100 $877,100 $2,083,200 $ Alternative 2: LNB/OFA + SCR ,412 10,366 $192,018,500 $16,477,200 $14,487,400 $30,964,600 $2,987 17,905 Note 1: Costs for Alternative 2 include the costs of the combustion controls (Alternative 1) plus the costs of SCR. Note 2: Baseline NOx emissions used in this BART analysis were based on the highest 24-hour block emissions reported by each unit during the baseline period. Baseline NOx emission rates (lb/mmbtu) were calculated by dividing the maximum hourly mass emission rate (lb/hr) by the full load heat input to each boiler. The relatively high short-term baseline emission rates were used to predict maximum potential visibility impacts, and to provide a conservative estimate of the cost effectiveness of potentially feasible retrofit control technologies. The short-term baseline emission rates should in no way be interpreted as a potential violation of the facility s permitted emission limits, which are averaged over a longer period of time. Page A-5

72 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No BART Economic Evaluation NOx Retrofit Control Technologies Capital Cost Summary Case 1 x 569 MW-gross PC Boiler 1 x 569 MW-gross PC Boiler Gross Plant Output (MW-gross) MW-gross Net Plant Output (MW-net) MW-net Maximum Heat Input (mmbtu/hr) mmbtu/hr 5,116 5,116 Uncontrolled NOx Emission Rate (lb/mmbtu) lb/mmbtu Capacity Factor Used for Cost Estimates (%) % 90% 90% Capital Cost Recovery Factor Equipment Life years Capital Cost Estimates were based on detailed cost estimates recently prepared for similar projects. Capital costs were compared to U.S.EPA's Coal Utility Environmental Cost (CUECost) Workbook, modified to account for recent increases in purchased equipment costs and commodity costs. Estimates were also compared to vendor quotes provided on recent similar projects. Low NOX Burner Technology Capital Costs Sooner 1 Sooner 2 Cost Basis (Year) Total Capital Requirement with Retrofit (TCR) $ $14,055,900 $14,055,900 SCR Capital Costs Sooner 1 Sooner 2 Cost Basis (Year) SCR Area $2,011,000 $2,011,000 Civil/Site Work $617,000 $617,000 Flue Gas System/Ductwork $32,150,000 $32,150,000 Modifications $5,243,000 $5,243,000 Pipe Rack $7,708,000 $7,708,000 Miscellaneous Mechanical Items $1,095,000 $1,095,000 Urea to Ammonia System $4,877,000 $4,877,000 Booster Fans $5,299,000 $5,299,000 Allowance for Additional Cranes $868,000 $868,000 Electrical Modifications $11,273,000 $11,273,000 Equipment Capital Cost Subtotal $ $71,141,000 $71,141,000 Instruments & Controls $ $1,422,800 $1,422,800 Taxes $ $4,268,500 $4,268,500 Freight $ $3,557,100 $3,557,100 Total Direct Cost $80,389,400 $80,389,400 Other Costs Total Direct Cost with Retrofit Factor $ $96,467,300 $96,467,300 General Facilities $ $4,823,400 $4,823,400 Engineering Fees $ $9,646,700 $9,646,700 Contingency $ $19,293,500 $19,293,500 EPC Fee (20% of total Cost) $19,293,500 $19,293,500 Total Plant Cost (TPC) $ $149,524,400 $149,524,400 Total Plant Cost (TPC) w/ Prime Contractor's Markup $ $154,010,000 $154,010,000 Allow. for Funds During Constr. (AFDC) $ $12,536,000 $12,536,000 Preproduction Costs $ $3,326,600 $3,326,600 Inventory Capital Initial Ammonia (60 days) $ $87,000 $87,000 Initial Catalyst $ $8,003,000 $8,003,000 Total Capital Requirement (TCR) $ $177,962,600 $177,962,600 Total Capital Requirement ($/kw-gross) $/kw-gross $313 $313 Total Capital Requirement ($/kw-net) $/kw-net $336 $336 Page A-6

73 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No BART Economic Evaluation NOx LNB/OFA Combustion Details CAPITAL COSTS SOONER 1 SOONER 2 Basis Total Capital Requirement (TCR) $14,055,900 $14,055,900 Total Capital Investment ($/kw - net) $27 $27 Capital Recovery Factor = i(1+ i) n / (1 + i) n EPA Air Pollution Control Cost Manual 6th Ed., page Annualized Capital Costs (Capital Recover Factor x Total Capital Investment) $1,206,100 $1,206,100 7% Assumed pretax marginal rate of return on private investment. OPERATING & MAINTENANCE COSTS Basis Variable O&M Costs Ammonia Reagent Cost $0 $0 Assumed no variable O&M costs with the LNB/OFA retrofit control system. Catalyst Replacement Cost $0 $0 Auxiliary Power Cost $0 $0 Total Variable O&M Cost $0 $0 Fixed O&M Costs Additional Operators per shift Assumed no additional operators needed for the LNB/OFA retrofit control system. Operating Labor Maintenance Labor $112,400 $112, % CUECost Maintenance Labor Default for emission control systems (0.8%/yr * Total Plant Cost) Maintenance Materials $168,700 $168, % CUECost Maintenance Default Factor for control systems (1.2% of installed cost). Control, Administration, Overhead $33,700 $33,700 30% of Maintenance Labor Cost (CUECost Default of control systems) Total Fixed O&M Costs $314,800 $314,800 Indirect Operating Cost Property Taxes $140,600 $140,600 1% of total capital investment (TCR). EPA Air Pollution Control Cost Manual 6th Ed., page Insurance $140,600 $140,600 1% of total capital investment (TCR). EPA Air Pollution Control Cost Manual 6th Ed., page Administration $281,100 $281,100 2% of total capital investment (TCR). EPA Air Pollution Control Cost Manual 6th Ed., page Total Indirect Operating Cost $562,300 $562,300 Total Annual Operating Cost $877,100 $877,100 TOTAL ANNUAL COST Annualized Capital Cost $1,206,100 $1,206,100 Annual Operating Cost $877,100 $877,100 Total Annual Cost $2,083,200 $2,083,200 See, Input Sheet. TCR includes all costs required to purchase and install control equipment, including materials, labor, site preparation, engineering, contingencies, and retrofit costs. Page A-7

74 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No BART Economic Evaluation NOx SCR Details Sooner 1 Sooner 2 CAPITAL COSTS [$] [$] Basis Total Capital Requirement (TCR) $ 177,962,600 $ 177,962,600 Total Capital Investment ($/kw-net) $336 $ 336 Capital Recovery Factor = i(1+ i) n / (1 + i) n EPA Air Pollution Control Cost Manual 6th Ed., page Annualized Capital Costs (Capital Recover Factor x Total Capital Investment) $15,271,100 $15,271,100 7% Assumed pretax marginal rate of return on private investment. OPERATING COSTS Operating & Maintenance Costs (based on 90% capacity factor) Variable O&M Costs Ammonia Reagent Cost $254,800 $254,800 $ 370 Catalyst Replacement Cost $1,692,200 $1,692,200 7,000 Auxiliary Power Cost $1,215,000 $1,215,000 $ 45 Total Variable O&M Cost $3,162,000 $3,162,000 See, Input Sheet. TCR includes all costs required to purchase and install control equipment, including materials, labor, site preparation, engineering, contingencies, and retrofit costs. Basis Based on maximum heat input, NOx removal rate (lb/hr), NH2/N2 ratio of approximately 1.1, 90% capacity factor, and $370/ton reagent cost. $ Based on 1.7 M 3 catalyst per MW-gross, 4 year catalyst life, and $7,000/M 3 catalyst cost. Based on 9" pressure drop across the SCR, MWh/inch auxiliary power requirement, and $45/MWh. Fixed O&M Costs Additional Operators per shift Based on S&L O&M estimate for SCR control system. Operating Labor $293,500 $293,500 3 shifts/day, 365 $33.50/hour (salary + benefits) which is equal to an annual operator salary of $70,000/year. Supervisory Labor $44,000 $44, % of operating labor. EPA Air Pollution Control Cost Manual 6th Ed., page Maintenance Materials $2,669,400 $2,669, % CUECost Maintenance Default Factor for SCR (1.5% of installed cost). Maintenance Labor $322,900 $322, % of operating labor. EPA Air Pollution Control Cost Manual 6th Ed., page Total Fixed O&M Cost $3,329,800 $3,329,800 Indirect Operating Cost Property Taxes $1,779,600 $1,779,600 1% of total capital investment (TCR). EPA Air Pollution Control Cost Manual 6th Ed., page Insurance $1,779,600 $1,779,600 1% of total capital investment (TCR). EPA Air Pollution Control Cost Manual 6th Ed., page Administration $3,559,300 $3,559,300 2% of total capital investment (TCR). EPA Air Pollution Control Cost Manual 6th Ed., page Total Indirect Operating Cost $7,118,500 $7,118,500 Total Annual Operating Cost $13,610,300 $13,610,300 TOTAL ANNUAL COST Annualized Capital Cost $15,271,100 $15,271,100 Annual Operating Cost $13,610,300 $13,610,300 Total Annual Cost $28,881,400 $28,881,400 Page A-8

75 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No BART Economic Evaluation SO 2 Summary SOONER STATION UNIT 1 OR 2 SO2 CONTROL SUMMARY (per boiler) Pollutant: SO2 Unit Design Heat Input: 5,116 mmbtu/hr Capacity Factor 90% % Maximum Hours/year: 7,884 hours Notes Design heat input was held constant for both FGD control technologies. Net plant output will decrease with the wet FGD system due to increased auxiliary power requirements. Assumed 90% capacity factor for cost evaluations. Control Technology Expected Emission Rate Expected Emissions Expected Emissions Reduction (lb/mmbtu) (ton/year) (ton/year) Baseline Emissions ,344 0 Alternative 1: DFGD-SDA ,017 15,327 Alternative 2: WFGD ,613 15,731 Baseline Emissions Control Technology Alternative 1: DFGD-SDA Tons of SO2 Total Capital Annual Capital Total Annual Average Control Incremental Emissions Removed Requirement Recovery Cost Operating Costs Total Annual Costs Efficiency Control Efficiency (tpy) (tpy) ($) ($/year) ($/year) ($) ($/ton) ($/ton) 17,344 2,017 15,327 $390,406,000 $33,500,900 $40,021,700 $73,522,600 $4,797 Alternative 2: WFGD 1,613 15,731 $441,658,000 $37,898,900 $42,998,900 $80,897,800 $5,143 $ 18,255 Page A-9

76 Oklahoma Gas & Electric May 27, 2008 Sooner Generating Station BART Determination Project No BART Economic Evaluation SO 2 Retrofit Control Technology Capital Cost Summary Page A-10