Unit 6 forms May2007-draft3 - NC

BACT ANALYSIS

May 2007

1 May 2007

5. CONTROL TECHNOLOGY REVIEW

The proposed nominal 800 MW Unit 6 pulverized coal site expansion at Duke Energy’s Cliffside Steam Station is subject to PSD review and is required to demonstrate the application of Best Available Control Technology (BACT) for certain criteria air pollutants. An extensive survey and planning process has been conducted and technologies providing maximum reductions in emissions consistent with the definition of BACT have been evaluated and selected to enable the new unit to utilize a wide range of available coals. The flexibility to burn coal of a wide range of fuel specifications, from multiple sources including Central Appalachia, Northern Appalachia and Illinois Basin, is fundamental to the design of the unit as well as its control technology selection. This Section describes the evaluation of candidate control alternatives for this fuel-flexible, state-of-the-art coal-fired electricity generation unit.

The Clean Air Act established conditions for the approval of construction permit applications under the PSD program. One of these requirements is that a Best Available Control Technology (BACT) analysis be performed for all pollutants regulated under the act and emitted in significant amounts from new major sources or modifications unless contemporaneous reductions from existing sources result in a net decrease in emissions. The proposed addition of a new generating unit at Cliffside will be occurring contemporaneously with several other activities at the facility that will achieve emission reductions, and such reductions have been considered for purposes of determining net emissions increases and decreases (“netting”). Specifically, Duke Energy is undertaking a modernization and expansion plan that will include installation of flue gas desulfurization (FGD) for SO2 and acid gas removal on existing Unit 5, and retiring the less efficient and uncontrolled existing Units 1-4. Unit 5 is already equipped with high-efficiency controls for NOx (low NOx combustion and SCR) and particulate (electrostatic precipitator).

After accounting for contemporaneous reductions in emissions, the addition of the new generating unit at Cliffside will result in a net increase in emissions in quantities exceeding PSD significance thresholds for carbon monoxide (CO), particulate matter (PM), particulate matter smaller than 10-micrometer diameter (PM10), volatile organic compounds (VOCs), sulfuric acid mist (H2SO4), and metals including lead (Pb). PM10 is used as a surrogate for particulate matter smaller than 2.5-micrometer diameter (PM2.5). Therefore, the application of BACT is required for these pollutants. Since the project (including the retirement of existing Cliffside Units 1 – 4 and reductions to be achieved by retrofitting an SO2 scrubber and the addition of the SCR to existing Unit 5) will result in a net reduction in emissions of NOx and SO2, PSD review is not triggered, and analysis of BACT for NOx and SO2 is not required. In any event, proposed Units 6 will employ state-of-the-art SCR and flue gas desulfurization systems for the control of NOx, SO2 and acid gases.

Mercury is not a PSD pollutant and is not subject to PSD or BACT review. It is, however, the subject of New Source Performance Standards under the Clean Air Mercury Rule (CAMR).

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The same emission control systems that constitute BACT for the proposed Cliffside Unit 6 will also effectively control emissions of mercury, as discussed in Section 4.0 of this Application.

The new major sources proposed that are subject to the BACT requirements include the PC boiler, an auxiliary steam boiler, linear wet mechanical cooling towers, diesel engines, a distillate fuel oil storage tank and material handling point and fugitive emission sources. This section presents the PSD BACT analysis and proposed BACT limits for these proposed new emission sources.

This BACT evaluation has concluded that for the coal combustion unit, BACT will require the use of good combustion for control of CO and VOC, spray dryer lime injection upstream of a fabric filter for targeted control of H2SO4, and a fabric filter (baghouse) for particulate control, including lead. For the auxiliary boiler, BACT will consist of good combustion for CO and VOC, and the use of 0.05% sulfur No. 2 fuel oil to limit emissions of particulate and Pb as well as the use of operational limitations limiting annual hours of operation. BACT for the cooling towers (which only emit particulates) will require state-of-the-art drift eliminators. BACT for the distillate oil storage tank (which only emits VOC) will consist of bottom fill and sunlight reflective external coating. BACT for filterable particulate emissions from materials handling operations will require compliance with the NSPS applicable to coal preparation operations (Subpart Y) and applicable to limestone processing (non-metallic mineral processing, Subpart OOO), and the use of partially enclosed conveyors, dust suppression and dust collection (e.g. fabric filters). A summary of the proposed BACT emission limits for the proposed Unit 6 boiler is presented in Table 5-1.

Table 5-1 Proposed Emissions Control for a New Supercritical PC Boiler

Criteria Pollutant Proposed BACT Emission Level (lb/MMBtu)

Proposed BACT Technology

PM/PM10/PM2.5 (filterable) 0.015 Fabric Filter Baghouse

PM/PM10/PM2.5(filterable and condensable)

0.024 Spray Dryer Absorber followed by Fabric Filter Bag House

CO 0.15 Good Combustion Practice VOC 0.004 Good Combustion Practice H2SO4 0.005 Spray Dryer Absorber followed

by Fabric Filter Baghouse Pb and Trace Metals 0.000022 Fabric Filter Baghouse

5.1 BACT Framework

BACT requirements are intended to ensure that a proposed facility will incorporate control systems that reflect the latest demonstrated practicable techniques for a particular type of emission unit and do not result in the exceedance of a NAAQS, PSD increment, or other

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standard imposed at the State level. The top-down BACT evaluation requires documentation and ranking of performance levels achievable for each technically feasible pollutant control technology applicable to the Project.

BACT is an emission rate that reflects, on a case-by-case basis, the best level of emission control demonstrated to be technically, environmentally and economically feasible. While BACT is evaluated on a pollutant by pollutant basis, the simultaneous control of multiple emissions from a proposed source are inter-related, and can not be properly evaluated out of context. BACT is defined as;

“[A]n emissions limitation (including a visible emission standard) based on the maximum degree of reduction for each pollutant subject to regulation under 42 U.S.C. 7401 to 7671q (Clean Air Act), which would be emitted from a proposed major stationary source or major modification which the cabinet, on a case-by-case basis, taking into account energy, environmental, and economic impacts and other costs, determines is achievable for that source or modification through application of production processes or available methods, systems, and techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for control of that pollutant. … If the cabinet determines that technological or economic limitations on the application of measurement methodology to a particular emissions unit would make the imposition of an emissions standard infeasible, a design, equipment, work practice, or operational standard, or combination of design, equipment, work practice, or operational standard, may be prescribed instead to satisfy the requirement for the application of best available control technology.” [40 C.F.R. § 52.21(b)(12)]

US EPA has provided guidance suggesting use of a “top-down” BACT evaluation which provides a useful framework for evaluating BACT and providing documentation and ranking of performance levels achievable for each technically feasible pollutant control technology applicable to the Project.

The top-down approach to the BACT review process involves identification and ranking the available and technically feasible control techniques (from greatest to lowest control) for each relevant pollutant for an emissions source. The highest rated control technology is BACT unless environmental, energy or economic costs render it unacceptable on a case-by-case basis for the particular source under evaluation. If the highest control technique is rejected, the next most stringent level of control is evaluated. The process continues until an available and technically feasible control technology and associated emission level is determined which cannot be eliminated by any environmental, energy or economic impacts. The top-down BACT

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evaluation process is described in the EPA draft document "New Source Review Workshop Manual”. The five steps involved in a top-down BACT evaluation are;

• Identify all available control options with practical potential for application to the specific emission unit for the regulated pollutant under evaluation;

• Eliminate technically infeasible technology options;

• Rank remaining control technologies by control effectiveness;

• Evaluate most effective control alternative and document results; if top option is not selected as BACT, evaluate next most effective control option; and

• Select BACT, which will be the most effective practical option not rejected based on energy, environmental, and economic impacts.

The "top-down" approach was used as a framework in this analysis to evaluate available pollution controls for the proposed Cliffside expansion consistent with regulatory requirements.

5.2 Information Considered in the BACT Determination

5.2.1 Previous BACT/LAER Determinations for Pulverized Coal-fired Utility Boilers

EPA's RACT/BACT/LAER Clearinghouse (RBLC) is a listing of RACT, BACT, and LAER determinations by governmental agencies for many types of air emission sources. ENSR consulted this database as the first step in developing a list of the most recent BACT/LAER decisions for new pulverized coal electricity generation units. The results of the RACT/BACT/LAER Clearinghouse search and information from more recent permits are summarized on a pollutant specific basis in the following sections to identify and rank alternative technologies and potentially achievable levels of control. We note that the most applicable data in the RACT/BACT/LAER Clearinghouse for establishing candidate control alternatives are those that have actually been achieved in practice on similarly sized PC boilers burning eastern bituminous coals. Permits have been issued with limits that have not yet been achieved in practice and permitted projects have failed to receive financing because the limits can not be guaranteed by control technology suppliers and/or are unrealistic in practice.

5.2.2 Draft Permits

Draft Permits for similar PC boilers which will also utilize Eastern bituminous coals may also form a useful reference to the extent they are publicly available. As of this writing, we are not aware of any recent Draft Permits for similar projects pending in North Carolina. Draft permits obviously do not necessarily reflect limits achieved in practice.

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5.2.3 Permit Applications

PSD applications for similar PC boilers which will also utilize Eastern bituminous coals may also form a useful reference to the extent they are publicly available. We note that permit applications often represent theoretical or speculative projects which may or may not be built and which may or may not have achievable limits. As of this writing, we are not aware of any pending applications for similar projects in North Carolina. Santee Cooper was issued a PSD permit for a similar facility in South Carolina.

5.2.4 Vendor Data

Publicly available vendor data (for example from the internet) represents another potential source of information regarding the application of candidate control technologies to PC boilers. We note that there is often a discrepancy between what vendors state in their sales literature based on general assumptions and what they will guarantee (i.e. accept liability for achieving) based on site-specific conditions. As stated previously, performance data may only report short-term results based on ideal operating conditions rather than long-term worst-case performance.

5.3 BACT for Carbon Monoxide (CO) for the PC Boiler

5.3.1 Formation of CO Emissions

Carbon monoxide is formed as a result of incomplete combustion of a hydrocarbon fuel. Control of CO is accomplished by providing adequate fuel residence time, excess oxygen and high temperature in the combustion zone to ensure complete combustion. These control factors, however, also tend to result in increased emissions of NOx. Conversely, a low NOx emission rate achieved through combustion modification techniques such as staged combustion or gas reburn can result in higher levels of CO formation. Thus, a compromise is established to achieve the lowest NOx formation rate possible while keeping CO (and LOI) emission rates at acceptable levels.

5.3.2 Ranking of Available CO Control Technology Options

CO emissions from pulverized coal-fired boilers are a function of oxygen availability (excess air), combustion zone temperature, residence time at peak temperature, combustion zone design, and turbulence. All recent pulverized coal-fired boilers identified utilize front-end methods such as good combustion control, wherein CO formation is suppressed within the combustion zone of the boiler. All listings in EPA’s RACT/BACT/LAER Clearinghouse for pulverized coal-fired boilers utilize combustion control techniques for CO. While gas-fired combustion turbines have been widely equipped with oxidation catalyst control technology, this technology is not applicable to coal-fired boilers. This technology is not applicable since in addition to oxidizing CO, an oxidation catalyst would oxidize prodigious amounts of SO2 to SO3, which would form blue plume and excessive sulfuric acid mist emissions. In any event,

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for a CO catalyst to function it would have to be located in a higher temperature zone of the boiler, where it would be quickly damaged from abrasion and masking due to the presence of high quantities of high temperature coal ash and liquid and gaseous condensables. No PC boiler has ever been permitted with oxidation catalyst as BACT, nor has this technology ever been demonstrated in practice in a PC application.

A review of EPA's RACT/BACT/LAER Clearinghouse and ENSR's review of recent permit decisions indicates levels of CO control which may be achieved for pulverized coal-fired boilers. BACT for the recently permitted Big Cajun boiler was 0.135 lb/MMBtu, Comanche was 0.13 lb/MMBtu, Newmont Mining was 0.15 lb/MMBtu, Prairie State was 0.12 lb/MMBtu, Nebraska City was 0.16 lb/MMBtu Longview Power was 0.11 lb/MMBtu, Whelan was 0.15 lb/MMBtu and Plum Point was 0.16 lb/MMBtu. EPA’s RACT/BACT/LAER Clearinghouse lists more than 30 permits in this range and only one less than 0.10 lb/MMBtu.

Table 5-2 Ranking of CO Control Technology Options for Pulverized Coal-fired Boilers

Control Technology Option

Emission Level (lb/MMBtu)

Technically Feasibility for Pulverized Coal-fired

Boilers? Combustion controls 0.1 1 to 0.15 Yes Oxidation catalyst N/A No Thermal oxidation N/A No SCONOx N/A No

1. A 0.05 value is listed is for the original W. A. Parrish units. No other PC boiler since has been permitted below 0.1 lb CO / MMBtu.

5.3.3 CO Control Technology Discussion

5.3.3.1 Combustion Control

Combustion control refers to controlling emissions of CO through the design and operation of the boiler in a manner so as to limit CO formation. A properly designed and operated boiler effectively functions as a thermal oxidizer. In general, a combustion control system seeks to maintain the proper conditions to ensure complete combustion through one or more of the following operation design features: providing sufficient excess air, staged combustion to complete burn out of products of incomplete combustion, sufficient residence time, and good mixing. All of these factors also tend to reduce emissions of VOC as well as CO. However, this process must be optimized with the efforts to reduce NOx emissions, which tends to increase when steps to lower CO are taken. Boiler operators have an inherent disincentive for higher CO emissions because this represents incomplete combustion and loss of the heating value of the fuel (resulting in lower Unit efficiency, referred to as Heat Rate). However, the desire to tune a boiler for minimum CO must be traded off against other operating factors such as the volume of excess air and control of steam temperature as well as the environmental trade-off for reducing NOx formation.

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5.3.3.2 Catalytic Oxidation

Catalytic oxidation is the technology that has been used to obtain the most stringent control level for CO from natural gas-fired turbine combustion units. This technology has never been applied to a pulverized coal-fired unit. It is evaluated here to determine if it could be considered transferable technology for application to the proposed pulverized coal-fired boiler. In this hypothetical alternative, a catalyst would be situated in the flue gas stream to lower the activation energy required to convert products of incomplete combustion (CO and VOC) in the presence of oxygen (O2) to carbon dioxide and water. The catalyst permits combination of the reactant species at lower gas temperatures and residence times than would be required for un-catalyzed oxidation.

The catalyst would have to be located at a point where the gas temperature is within an acceptable range. The effective temperature range for CO oxidation is between 600 °F and about 1,000 °F. Catalyst non-selectivity is a problem for sulfur containing fuels such as coal. Catalysts promote oxidation of SO2 to SO3 as well as CO to CO2. The amount of SO2 conversion is a function of temperature and catalyst design. Under optimum conditions, formation of SO3 can be minimized to 5% of inlet SO2. This level of conversion would result in a large collateral increase in H2SO4 emissions which aside from the increased ambient air impacts could result in unacceptable amounts of corrosion to the particulate collector, air preheater, ductwork and stack.

Oxidation catalysts are known to be extremely sensitive to potential masking, blinding or poisoning due to trace elements such as metals in flue gas. While natural gas contains essentially no trace metals, coal contains many of trace compounds within the inert fraction referred to as ash. These trace compounds are highly variable in concentration even from coal taken within the same mine or seam. There is no empirical evidence available to show that oxidation catalyst technology would actually work with coal-fired boilers, or if so what the life of the catalyst might be.

ENSR contacted an oxidation catalyst system vendor to determine the technical feasibility of installing this technology within a pulverized coal-fired boiler. Due to the high particulate loading of the flue gas, variable trace element concentration in the flue gas and the SO2 loading before air pollution control systems, the vendor stated that they could not provide a catalyst system for coal-fired applications. Consequently, any type of oxidation catalyst systems are considered technically infeasible for application to the proposed coal-fired boiler.

5.3.3.3 Thermal Oxidizer

A PC boiler is inherently designed to oxidize fuel and products of incomplete combustion such as CO and VOC in a highly efficient manner (referred to as combustion control). A “thermal oxidizer” is an add-on control device designed to mimic the good combustion exhibited in a PC boiler, using heat and oxygen to convert CO to CO2. Because no catalyst is used in a thermal

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oxidizer, the temperature at which the conversion takes place is much higher. Temperatures above 1500o F are required to convert CO to CO2.

There are no known installations of add-on thermal oxidizers on coal-fired power plants. Most thermal oxidation technology for stationary sources is utilized for the control of concentrated volatile organic emissions. Because this technology is not applicable to a pulverized coal-fired boiler or any other stationary source applications of this magnitude, thermal oxidation is deemed technically infeasible.

5.3.3.4 SCONOx

SCONOx is a technology that has been widely discussed for application to many types of small emission units, however to date the only two known applications are on small gas turbine cogeneration systems. Like oxidation catalyst, this technology has never been applied or even tested for application to coal-fired boilers. In fact, SCONOx actually utilizes the same CO reduction technology as oxidation catalyst discussed previously. The SCONOx bed incorporates a coating of the same catalyst material, primarily to oxidize NO to NO2 but with the side benefit of also destroying CO. SCONOx therefore has all the limitations cited above for oxidation catalyst, but is even further from consideration as transferable technology.

5.3.4 Summary of BACT for CO

BACT for CO from boilers has always been determined to be good combustion achieved through good boiler design and operation; no pulverized coal unit has been permitted with post-combustion CO controls. On modern boilers, a certain emission of CO is unavoidable, due to the inverse relationship between CO and NOx formation, and the fact that no technically feasible post-combustion control options have been identified or demonstrated in practice for CO control. Combustion control, and the resulting optimized emission rate to minimize formation of CO while also minimizing NOx, therefore represents BACT for the proposed PC boiler. Duke Energy is proposing a limit of 0.15 lb/MMBtu based on an initial stack test and continued demonstration of good operation and maintenance practices as BACT for CO. This is within the range of previous BACT determinations in the Clearinghouse. Because there are no other feasible control technologies for a pulverized coal-fired boiler and because the level of CO emissions will be dictated by optimized combustion operation and maintenance practices including the need to simultaneously achieve low NOx emissions, Duke Energy is proposing that the CO emission limit be set at 0.15 lb/MMBtu. The project is proposing to use the only technically feasible option, and because the proposed CO emission rate is consistent with CO emission rates at comparable facilities, good combustion control and proper boiler design and operation represents BACT for CO. The environmental impacts associated with CO emissions at this level have been shown by air quality analysis to be inconsequential, while assuring operational flexibility to maintain NOx emissions as low as possible does have important consequences associated with ozone formation and other environmental issues.

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5.4 BACT for Particulate Matter from PC Boiler

5.4.1 Formation of Particulate Matter

The composition and amount of particulate matter emitted from coal-fired boilers are a function of firing configuration, boiler operation, coal properties and emission controls. Particulate matter will be emitted from the pulverized coal-fired boilers as a result of entrainment of incombustible inert matter (ash) and condensable substances such as acid gases. Particulate matter (PM) and particulate matter smaller than 10 microns (PM10) has historically been regulated from coal-fired boilers as the filterable, or front half catch only. Many permits contain filterable only limits, and/or require stack testing for filterable particulate only for demonstration of compliance. The US EPA has clarified that when considering the air quality impacts under the PSD review process, both filterable and condensable fractions of PM10 must be addressed and this air quality impact has been provided for this permit application. Particulate matter less than 2.5 microns in diameter (PM 2.5) is not yet subject to BACT limitations since PSD significance thresholds have yet to be established. The best technologies for controlling condensable PM10 are also effective for controlling PM2.5; therefore PM10 is used as a surrogate.

The constituents of condensable PM10 are primarily made up of pollutants which are regulated separately and typically addressed through use of control technologies for specific species of pollutants. These include sulfuric acid mist, VOC, Hg, HCL and HF. Measurement of condensables also presents the problem of collection of secondary particulates (sulfates and nitrates) which are technically not part of PM10 because they form artificially in Method 202 and would not form in the air pollution control train or stack.

5.4.2 Ranking of Available Particulate Control Technology Options

Previously permitted PM10 emission limits are difficult to assess as many permits do not specify test methods and some emission limits only reflect filterable PM10 while some others include condensable PM10. The permit for AES-PR (a CFB) addressed this issue in detail. AES’s permit limited filterable PM10 to 0.015 lb/MMBtu and allowed stack testing to determine an achievable total PM10 emission limit. Stack tests showed that filterable PM10 emissions were below 0.015 lb/MMBtu; however, based on stack test results, AES received an administrative change to their permit to set the total PM10 emission limit at 0.03 lb/MMBtu. Several recent coal-fired boiler projects are listed with emission rates in the range of 0.010 lb/MMBtu to 0.015 lb/MMBtu based on front half (filterable) PM only, and this level is representative of BACT for PM. In setting the permit limit, consideration should be given to the difficulty of measuring the very low concentrations of particulate emissions and the wet stack conditions where the tests will be conducted. The EPA reference methods require manual manipulations of test equipment and laboratory analysis which can introduce significant error. Finally, the most recent BACT limits, some of which include condensable PM10, have yet to be reliably demonstrated in practice.

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Table 5-3 Ranking of Particulate Control Technology Options for Pulverized Coal-fired Boilers



Technically Feasibility for Pulverized Coal-fired

Boilers? Fabric Filter 0.01 to 0.015 for

filterable PM, 0.03 for total PM10

Yes

Dry Electro-static Precipitator followed by

polishing Wet electro-static Precipitator

0.01 to 0.015 for filterable PM, 0.03 for

total PM10 Yes

Dry Electro-static Precipitator

0.015 to 0.03 for filterable PM Yes

High energy wet scrubber Not determined No applications in the last 15 years to large coal-fired boilers

Emission levels represent target steady-state values at base load, for front-half (filterable) only. Inclusion of the condensable fraction is thought to double the particulate emission rate for coal-fired boilers.

5.4.3 PM and PM10 Control Technology Discussion

5.4.3.1 Dry Electrostatic Precipitators (ESPs)

Electro-static precipitation technology is applicable to a variety of coal combustion sources. ESPs remove particulate matter from the flue gas stream by charging fly ash particulates with a high direct current (dc) voltage and attracting these particles to charged collection plates. A layer of collected particulate forms on the collecting plates (electrodes) and is removed by rapping the electrodes. The collected particulate drops into hoppers below the precipitator and is periodically removed from the fly ash handling system.

Because of their modular design, ESPs can be applied to a wide range of system sizes and should have no adverse effect on combustion system performance. The operating parameters that influence ESP performance includes 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. Data for ESPs applied to coal-fired sources show fractional collection efficiencies of approximately 95% for fine particles (less than 0.1 microns) and greater than 99% for coarse particles (greater than 10 microns).

ESPs are considered a technically feasible option for the proposed Cliffside boiler. Based on operating experience at other large bituminous coal-fired units, it is anticipated that the lowest post-control PM-10 emission rate that could be consistently achieved with ESP technology is 0.015 lb/MMBtu, as determined via periodic stack testing using Reference Method 5. We note

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that gaseous species that do not condense at ESP temperatures (but would in an ice bath of a Method 202 train) pass right through an ESP and are not collected well with this technology.

5.4.3.2 Fabric Filter

Fabric filters are widely used for particulate control from PC boilers and are capable of over 99% control efficiency. According to EPA’s Fabric Filter Fact sheet (US EPA, 2000), “flue gas is passed through a tightly woven or felted fabric, causing PM in the flue gas to be collected on the fabric by sieving and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with a number of the individual fabric filter units housed together in a group. Bags are most common type of fabric filter. The dust cake that forms on the filter from the collected PM can significantly increase collection efficiency. Fabric filters are frequently referred to as baghouses because the fabric is usually configured in cylindrical bags. Bags may be 6 to 9 m (20 to 30 ft) long and 13 to 31 centimeters (cm) (5 to 12 inches) in diameter. Groups of bags are placed in isolatable compartments to allow cleaning of the bags or replacement of some of the bags without shutting down the entire fabric filter. PC units with baghouses have also been permitted for filterable PM emissions in the range of 0.015 lb/MMBtu.

5.4.3.3 Fabric Filter With Spray Dryer Absorber

A fabric filter baghouse is the preferred particulate control device in applications involving use of a spray dry absorber (SDA) because flue gas passing through the filter cake enhances the utilization of the sorbent and removal of the gases pollutants. Emission rates of filterable PM10 are expected to be equivalent (in terms of lb/MMBtu) for a baghouse operating with or without SDA. However, operation of an SDA ahead of a fabric filter baghouse offers the advantage of reducing the flue gas temperature below the sulfuric acid gas dew point, and will therefore provide the opportunity to collect condensable PM10 emissions in the form of sulfuric acid. Hydrogen chloride (HCl) gas is also collected by the spray dryer/baghouse combination. Control of condensable emissions will be achieved by maintaining temperature below the acid dew point and providing sufficient sorbent to react with the acid gas species. Sulfuric acid emissions of 0.005 lb/MMBtu or less can be achieved with proper process control.

5.4.3.4 Wet Electrostatic Precipitator

There are no known applications where wet ESPs have been used as a primary particulate collection device on a coal-fired utility boiler. Wet ESPs have been proposed as a polishing device following a baghouse or dry precipitator and a wet SO2 scrubber to capture condensed fine particulate from coal-fired boilers. The primary purpose has been to address sulfuric acid mist that will form at the reduced temperature through the scrubber. Hydrochloric acid (HCl) and hydrofluoric acid (HF) are the other two “condensable” fraction species that are likely to condense at wet scrubber temperatures, but those are very soluble and are effectively captured within a wet scrubber system. If sulfuric acid is removed through other processes prior to passing through the wet scrubber, condensed sulfuric acid mist in the flue gas leaving

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the scrubber will be insignificant and there would be no basis for installation of a “polishing” device to remove condensed sulfuric acid.

In a WESP, the flue gas is saturated and liquid water is used to rinse the collected PM10 from the plates or tubes to a sump at the bottom. Here, conventional water treatment processes are used to remove the captured pollutants so that the water may be reused in the WESP. The use of a water flush rather than mechanical rapping in a dry ESP provides greater cleaning of the plates which promotes higher electric fields and thus greater collection of the fine particulate.

Disadvantages of WESP’s include a cooler plume (lower plume rise and dispersion), cost, and the evaporative use of greater quantities of water. The corrosive nature of the condensed acid gases would require use of high performance alloys and would require careful attention to operation and maintenance to avoid premature failure. WESP’s have been employed for years for primary control of aerosol and fine particulate emissions in industrial applications, but are a relative newcomer to the utility boiler sector. They are commercially available from multiple vendors and have been permitted for several new PC coal units as a secondary or polishing collector, but there is very limited actual operating experience.

5.4.4 Summary of BACT for PM10

Both ESP and fabric filters are proven filterable PM10 control systems, and either control system can be designed to achieve a controlled PM10 emission rate of 0.015 lb/MMBtu. WESP is a relatively new application to PC Boilers and is not well demonstrated in this application.

Duke Energy proposes spray dryer absorber followed by fabric filter technology, which represents the top level of control for fine particulate. Condensable emissions of sulfuric acid mist will be removed in gaseous state prior to the fabric filter, as discussed in the following sections. While these separate components are proven and reliable for use on a coal-fired boiler, this combination of technology is cutting edge for targeted removal of sulfuric acid upstream of the particulate collector, and Cliffside Steam Station is not aware of any long-term test data for total PM10 from similar PC boilers operating with lime injection for acid gas capture followed by a fabric filter, and utilizing the planned range of coals. The reliable measurement of PM10 from a saturated stack is also difficult. For these reasons, it is difficult to establish an enforceable emission limit for total PM10 that would apply to this combination of control technologies, even though they are considered to represent the greatest level of control available for fine particulate.

Duke Energy proposes a total PM10 limit of 0.024 lb/MMBtu for Cliffside Unit 6, which is consistent with the value used in PSD dispersion modeling (which indicated compliance with National Ambient Air Quality Standards and PSD increment requirements). This value is based on the proposed limit of 0.015 lb/MMBtu for filterable PM10, and adding 0.009 lb/MMbtu of non-otherwise regulated condensable PM10 (i.e. excluding H2SO4, HF, HCL, VOC). Compliance will be demonstrated through periodic testing for filterable emissions

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using EPA Reference Method 5 or 17 and Method 202, including any modifications necessary due to the saturated conditions in the stack. To determine compliance with the limit including condensable emissions, Duke Energy proposes to use Reference Method 202 with modifications and procedures to eliminate any “pseudo-condensable” particles which are known to cause interference. These limits provide a reasonable margin of compliance to allow for variation in calculated emissions due to the inherent problems of conducting a stack test under non-ideal conditions, and are within the range of BACT standards in recent permits.

However, Duke Energy will agree to accept a filterable PM10 emissions limit of 0.012 lb/MMBtu and a total PM10 emissions limit of 0.018 lb/MMBtu (including condensables) as DAQ has requested, provided the permit provides a mechanism to adjust the BACT limit if performance testing proves the limits are not achievable as a practical matter based on proper operation and maintenance of control equipment. Despite this acceptance, we continue to believe that the proposed emissions limits of 0.015 lb/MMBtu (filterable PM10) and 0.024 lb/MMBtu (total PM10) are defensible as a BACT limit for new coal-fired units. The ability to consistently meet a lower limit has not been adequately demonstrated in practice. We believe limits of 0.012 lb/MMBtu and 0.018 lb/MMBtu pose significant regulatory compliance risks that are unrelated to the installation and proper operation and maintenance of best available control technologies (either electrostatic precipitators or baghouses). The higher filterable and total particulate limits have been used as the basis for Duke Energy’s air quality modeling analyses, and these emission rates have been demonstrated not to have any significant impact on air quality.

US EPA recently adopted a Reference Method for continuous PM monitoring as under 40 CFR 60 Appendix A spec. 8. Duke Energy notes that implementation of CEM’s for PM10 is in its infancy, and there are few, if any, facilities to date that are required to base continuous compliance on such monitors. These monitors have not been shown to reliably represent the actual particulate emissions, and may not be capable of measuring PM10 emissions from a saturated stack. Duke Energy is not proposing the use of continuous particulate monitoring due to these concerns.

5.5 BACT for VOC from PC Boiler

5.5.1 Formation

Similar to CO, VOCs are also emitted from coal-fired boilers as a result of incomplete combustion of the fuel. Control of incomplete combustion is accomplished in the same way CO emissions are controlled: by providing adequate fuel residence time and high temperature in the combustion zone to ensure complete combustion. Combustion controls designed to reduce NOx emission, including low excess air, reduced residence time and lower temperatures tend to increase the generation of VOCs.

14 May 2007

5.5.2 Ranking of Available VOC Control Technology Options

The same combustion controls (good combustion) and post-combustion systems designed to reduce CO emission rates would also reduce VOC emission rates. VOC emissions from coal-fired boilers are a function of oxygen availability (excess air), flame temperature, residence time at flame temperature, combustion zone design, and turbulence. All coal-fired boilers identified utilize front-end methods such as combustion control wherein VOC formation is suppressed within the boiler. All listings in EPA’s RACT/BACT/LAER Clearinghouse for coal-fired boilers utilize combustion control techniques for VOC. While gas-fired combustion turbines have been widely equipped with oxidation catalyst control technology, this technology is not applicable to coal-fired boilers as previously discussed.

5.5.3 Recent Permit Limits

BACT for the recently permitted Comanche PC boiler was approved at 0.0035 lb/MMBtu. Prairie State and Longview Power were approved at 0.004 lb/MMBtu. Plum Point was approved as BACT at 0.02 lb/MMBtu. In summary, EPA’s RACT/BACT/LAER Clearinghouse lists 5 permits below 0.004 lb/MMBtu, 22 permits in the 0.005 lb/MMBtu to 0.01 lb/MMBtu range and several higher permit limits.

Table 5-4 Ranking of VOC Control Technology Options for Pulverized Coal-fired Boilers



Technically Feasibility for Pulverized Coal-fired Boilers?

Combustion controls 0.003 to 0.02 Yes Oxidation catalyst N/A No Thermal oxidation N/A No SCONOx N/A No

5.5.4 VOC Control Technology Discussion

5.5.4.1 Combustion Control

Combustion control refers to controlling emissions of VOC through the design and operation of the boiler in a manner to limit VOC formation. In general, a combustion control system seeks to maintain the proper conditions to ensure complete combustion through one or more of the following operation design features: providing sufficient excess air, staged combustion to complete burn out of products of incomplete combustion, sufficient residence time, and good mixing. All of these factors also have the by-product of reducing the emissions of CO. Pulverized coal-fired boilers are designed specifically for efficient fuel combustion with thorough mixing and residence time at temperature, plus staged combustion. This level of combustion control represents BACT for the proposed boilers.

15 May 2007

5.5.4.2 Add-On Emission Controls

Catalytic oxidation, thermal oxidation, and SCONOx are not applicable to coal-fired boilers as previously discussed.

5.5.5 Summary of BACT for VOC

The only practical or demonstrated in practice measures to control VOCs from coal-fired boilers is good combustion. Combustion control, and the resulting optimized emission rate to minimize formation of VOC while also minimizing NOx, therefore represents BACT for the proposed boilers. VOCs are only emitted in trace and variable quantities from large high efficiency coal-fired boilers. Cliffside Steam is proposing a VOC BACT limit of 0.004 lb/MMBtu, taking into account the use of low NOx combustion control technology and a wide range of potential coals. Compliance will be demonstrated with periodic stack testing and proper operation and maintenance of the boiler.

5.6 BACT Analysis for Sulfuric Acid Mist

5.6.1 Formation

Emissions of sulfuric acid mist are generated in fossil fuel-fired sources from the oxidation of sulfur in flue gas to sulfur trioxide (SO3), a portion of which reacts with water to form sulfuric acid vapor. At lower flue gas temperatures, this vapor may condense to sulfuric acid mist. The proposed boiler will generate SO3 during the combustion process, and the SCR catalyst will further oxidize a small percentage of the SO2 in the flue gas to SO3. The amounts of sulfur or SO2 that are oxidized to sulfuric acid mist may also be affected by trace metal catalysts in coal ash.

5.6.2 Sulfuric Acid Mist Control Technology Discussion

As the SO3 is sufficiently cooled, it combines with water to form H2SO4 aerosol (mist). It is collected in some form (i.e. NH4HSO4, H2SO4, SO3, Salts, PM10) particularly through the air pollution control system of a state-of-the-art PC boiler.

5.6.2.1 Sorbent Injection

An alkali sorbent can be injected into the flue gas duct upstream of a fabric filter to neutralize sulfuric acid in the flue gas. The sorbent is then collected downstream in the particulate control device. It has been reported that, depending on the particular equipment configuration, collection efficiencies of 10% to 50%% may be possible using this technique.

16 May 2007

5.6.2.2 Spray Dryer With Targeted Acid Gas Control

In the case of a spray dryer targeted for acid gas control, SO3 will condense and react with lime in the absorber. Because SO3 and HCL are much more reactive than SO2, approximately 90% of the SO3 and a large percentage of the HCL will be removed from the flue gas in the spray dry absorber and subsequent reactions in the fabric filter in a system designed primarily for capture of these acid gases.

In a typical spray dry absorber (SDA), the flue gas passes through a spray dryer vessel where it encounters a fine mist of lime slurry. The lime slurry is injected into the spray dryer absorber through either a rotary atomizer or fluid nozzles. The moisture in the droplets evaporates and the lime reacts with the acid gases in the flue gas to form calcium salts. A fabric filter then allows for further reaction of the lime with the acid gases in the flue gas. This is due to the layer of porous filter cake on the surface of the filter that contains the reagent that all flue gas must pass through. This allows for increased efficiency of control of sulfuric acid mist, hydrogen chloride and mercury as compared to wet scrubbers. In this targeted acid gas control application, preferential control of acid gases is achieved by controlling the amount of water based on the acid dew point of the flue gas. Little sulfur dioxide (SO2) will be removed as compared to a conventional spray dry FGD system because the spray dryer does not operate at the low approach to adiabatic saturation temperature and because the limited amount of lime injection will preferentially react with sulfuric acid.

5.6.2.3 Wet FGD

In the case of wet FGD, SO3 entering the wet scrubbers will react with water and create micron sized sulfuric acid droplets. Micron sized droplets can pass through the spray levels and the mist eliminator, and be emitted as sulfuric acid mist. Some of the sulfuric acid droplets will react with limestone in the wet scrubber, but because the droplets are so small, many of the droplets will not come into contact with limestone. Industry experience suggests that only approximately 40% of the potential sulfuric acid mist might be removed in a wet FGD.

5.6.2.4 Wet ESP

A wet ESP might also be used to control aerosol sulfuric acid mist once it has been condensed. It is projected that wet a WESP could reduce the potential sulfuric acid mist emissions by approximately 90%. However, because of the very minimal operating experience of wet ESPs on large utility boilers, the removal efficiency is not well documented for extended operating periods.

5.6.3 Summary of BACT for Sulfuric Acid Mist

The best level of control for sulfuric acid mist was determined to be through use of a spray dryer using lime slurry injection followed by a fabric filter. While a WESP may be capable of similar reductions, WESPs have not been well demonstrated on PC boilers. Duke Energy

17 May 2007

proposes to control sulfuric acid mist emissions through spray dryer lime injection system upstream of a fabric filter baghouse, and is proposing a sulfuric acid mist BACT emission rate (due to the case specific factors of using higher sulfur eastern bituminous coals, and subsequent oxidation of 1% to 2% of SO2 to SO3 across the SCR catalyst) of 0.005 lb/MMBtu, based on periodic stack testing using Reference Method 8. This emission rate is lower than the August 2003 permit of 0.0061 lb/MMBtu for the Plum Point Project in Arkansas, and the March 2004 permit of 0.075lb/MMBtu for the Longview Power Project in West Virginia, but is higher than the Thoroughbred Project in KY and Prairie State Project in Illinois which proposed WESP. Based on the minimal experience of using wet ESPs on large utility boilers, the 0.005 lb/MMBtu emission rate is deemed appropriate. We also note that the Roundup and Plum Point projects both use lower sulfur sub-bituminous coals as opposed to the range of eastern bituminous coals to be utilized at Cliffside.

We also note that the proposed BACT is an innovative use of technology that provides several environmental advantages. Use of the spray dryer system will allow the facility to recycle process wastewater from the wet scrubber systems installed on Unit 5 and Unit 6 for SO2 control. This will eliminate the need for a wastewater treatment system on Unit 6 and on Unit 5 when Unit 6 is operating. That will reduce or eliminate the need for a wastewater discharge to the environment. The recycled water will also provide flue gas cooling prior to the wet scrubber, which will reduce the overall water consumption needed to maintain scrubber operation.

US EPA is aware that Reference Method 8 has an inherent interference with NH3 (i.e. the results will bias high in the presence of slip ammonia). For this reason, Cliffside Steam requests a waiver to temporarily discontinue ammonia injection during performance of the Method 8 test for H2SO4, or some alternative strategy approved by NCDAQ to ensure accuracy of the results.

5.7 BACT Analysis for Lead and other Metals (other than Hg)

Emissions of lead and other metals are generated in coal-fired boilers due to the inherent presence of inert mineral matter in coal (ash). Certain of these metals, such as selenium and lead may be vaporized within the high temperature combustion zone of the boiler. All such metals, however, re-condense, typically nucleating onto other small particles of flyash at the low temperatures of the air pollution control train. At the temperatures of the proposed fabric filter, these metals exist as PM10 and are readily collected at similar efficiency as the generic category “filterable PM10”. Since the proposed units will employ BACT for PM10, they will also employ BACT for lead and other trace metals. Compliance with the filterable PM10 will be used to demonstrate compliance with BACT for non-mercury trace metals.

5.8 BACT for PC Boiler During Startup and Shut Down

The proposed PC boiler will be started up on low sulfur distillate oil up to a manufacturer’s defined partial load to heat up the equipment. The mass emissions (in lb/hr) from distillate oil

18 May 2007

firing at part load will always be less than allowable emissions from the boilers at full load firing coal. Once certain temperature and load parameters are met, coal is introduced into the boiler. The startup sequence will continue as equipment and operating parameters are brought to minimum stable operating conditions on coal (approximately 35 % load). Pollution control equipment will be brought into service throughout the startup sequence in accordance with manufacturer recommendations to assure proper safety and operating performance of the equipment. The dry scrubber and the fabric filter systems will be brought into service and will achieve substantial control once the coal is introduced to the boilers. However, these systems will not achieve optimum performance until steady state, stable load conditions are achieved. The SCR has a minimum operating temperature that corresponds closely with minimum load, and will not be brought into service until that load is reached. While individual emission rate factors will vary from limits established for normal operating conditions, all emissions from the proposed PC boilers will remain controlled to the extent feasible consistent with good design, operation, and maintenance. Startup emissions have been considered in the proposed BACT limits for each pollutant subject to continuous monitoring requirements by use of 30-day rolling average. Emissions are expected to fluctuate less during a planned shutdown sequence, as the boiler and APC train will start at steady state conditions and the production of pollutants will essentially cease when fuel is removed from the boiler.

For startup/shutdown operations, Duke Energy expects that the mass emissions occurring during the startup/shutdown period divided by the entire length of the startup/shutdown period will not exceed the mass emissions resulting from maximum heat input multiplied by proposed BACT emission limits. Duke Energy requests the right to confirm this expectation once the equipment supplier is chosen. BACT for startup and shut down of the PC boiler is therefore proposed to be the total mass resulting from the hours of startup/shutdown multiplied by the maximum allowable mass emission rate in lb/hr (and specifically not the proposed BACT limits for normal operation in units of lb/MMBtu) for each BACT pollutant. Air dispersion modeling performed for the combination of maximum allowable mass emissions with minimum stack flow rate has been performed to demonstrate that NAAQS will be protected during start up and shutdown events.

5.9 BACT Analysis for Auxiliary Boiler

In addition to the pulverized coal-fired boiler, the project will have one oil-fired auxiliary boiler to generate steam for start-up of the main boilers when the PC boiler is shut down. Generally, operation of the auxiliary boiler will not be necessary when the main boiler is operating.

The auxiliary boiler will be designed with a low NOx burner, and will be fired with low sulfur distillate fuel oil. Low sulfur distillate fuel oil is an inherently clean fuel, with a maximum sulfur content of 0.05%. Emissions from the auxiliary boiler will also be limited by limiting its annual hours of operation. As stated above, the primary function of the auxiliary boiler is to provide steam for start-up and plant heating when both of the main boilers are shut down. Each of the main boilers is expected to have a base load annual capacity factor; therefore, operation of the auxiliary boiler should be infrequent.

19 May 2007

In order to estimate maximum annual emissions from the auxiliary boiler, it was assumed that during some years the auxiliary boiler might need to operate as much as 2,500 hours. This assumption is considered conservative, because in most years the auxiliary boiler is expected to operate less than 800 hours/year.

5.9.1 BACT for CO from the Auxiliary Boiler

Based on distillate oil firing and limited use (maximum 2,500 hours per year) a BACT limit for CO emissions of 0.036 lb/MMBtu based on manufacturers guarantee is proposed for the auxiliary boiler based on the lowest emission limits listed in EPA’s RACT/BACT/LAER Clearinghouse.

5.9.2 BACT for VOC from the Auxiliary Boiler

The auxiliary boiler will fire distillate fuel oil, will accept restricted use limitations (i.e. 2,500 hrs/yr maximum) and will incorporate good combustion control to limit emissions of VOC. A BACT limit for VOC emissions of 0.0024 lb/MMBtu based on manufacturers guarantee is proposed for the auxiliary boiler based on limits for similar boilers in EPA’s RACT/BACT/LAER Clearinghouse.

5.9.3 BACT for PM10 from the Auxiliary Boiler

All distillate oil-fired boilers listed in EPA’s BACT/LAER Clearinghouse use low ash fuels to limit emissions of PM10. PM / PM10 from the proposed auxiliary boiler will be further limited with a proposed use restriction of up to 2,500 hrs/yr. The proposed BACT limits for PM and PM10 for the auxiliary boiler are based on EPA emission factors published in AP-42 and EPA’s RACT/BACT/LAER Clearinghouse for boilers utilizing low sulfur (.05%) distillate oil. For PM, a BACT emission limit of 0.014 lb/MMBtu is proposed based on the EPA emission factor of 2 lb/1000 gal. For total PM10 (front and back half) a BACT emission limit of 0.024 lb/MMBtu is proposed based on adding condensable PM10 emissions of 0.01 lb//MMBtu (1.3 lb/1,000 gal based on AP-42) to the filterable PM emission rate. These proposed emission rates are consistent with the data from EPA’s RACT/BACT/LAER Clearinghouse, since the Clearinghouse data generally do not include condensable PM10.

5.9.4 BACT for H2SO4 and Lead from the Auxiliary Boiler

BACT for the auxiliary boiler for sulfuric acid mist and lead is the use of low sulfur (0.05% S) distillate oil.

5.9.5 BACT for Startup and Shut Down of the Auxiliary Boiler

Unlike combustion turbines, emissions of all PSD pollutants are proportional to fuel input in a distillate oil-fired boiler, over a wide turndown range. In any event, BACT for emissions during

20 May 2007

startup and shutdown of the proposed auxiliary boiler is the maximum allowable mass emission rate (lb/hr) for each PSD pollutant.

5.10 BACT Analysis for Emergency Diesel Engines

The proposed project will be equipped with one1750 kW (2350 hp) diesel-fired emergency generators and one 430 hp diesel engine driven emergency fire water pump. The emergency generators will be used only during an interruption of the electrical power supply to the site and for short test periods. The emergency generators will be fired for a maximum of 100 hours per year (including for testing). The emergency fire pump engines will be also be operated only for short periods of testing or in the event of an actual fire emergency. The emergency fire pump will be limited to 100 hrs per yr excluding emergency use.

5.10.1 BACT for CO from Emergency Diesel Engines

CO from the emergency diesel engines will be limited by good engine design and annual use limitations. The emergency-use diesel engines will not be operated for more than 100 hours/year each. A BACT emission limit for these diesel engines of 0.5 g/hp-hr (same as comment above) based on vendor guarantees is proposed based on data from engine manufacturers.

5.10.2 BACT for VOC from Emergency Diesel Engines

VOC from the emergency diesel engines will be limited by good engine design and annual use limitations. The emergency-use diesel engines will not be operated for more than 100 hours/year each. A BACT emission limit for these diesel engines of 0.3 g/hp-hr is proposed based on EPA emission factors in AP-42.

5.10.3 BACT for PM / PM10 from Emergency Diesel Engines

PM and PM10 from the emergency diesel engines will be limited through the use of low sulfur, low ash fuel (0.05% distillate oil) and annual use limitations. The emergency-use diesel engines will not be operated for more than 100 hours/year each. BACT emission limits of 0.19 g/hp-hr and 0.22 g/hp-hr are proposed for PM and PM10, respectively, based on EPA emission factors in AP-42.

5.10.4 BACT for H2SO4 and Lead from Emergency Diesel Engines

Emergency diesel engines do not emit appreciable (or measurable) quantities of H2SO4 or lead. BACT for these pollutants is concluded to be the use of low sulfur (0.05% sulfur) distillate oil, and annual use limitations. The emergency-use diesel engines will not be operated for more than 100 hours/year each,

21 May 2007

5.10.5 BACT for Start up and Shutdown of Emergency Diesel Engines

Emergency diesel engines are designed to start up and go to rated load within minutes (a fundamental requirement for emergency backup conditions). Thus, they are not in start up long enough to affect emission limits that if tested, would be expressed on the basis of the average of three one-hour tests. Thus, the same BACT limits that apply during normal operation also apply during start up and shutdown.

5.11 BACT Analysis for Cooling Towers

Duke Energy has designed the new unit to use a mechanical draft wet cooling tower. Dry cooling was not employed because there is adequate water available and dry cooling requires unacceptably high parasitic load. Such a decrease in unit efficiency would result in collateral emission increases of PM10 as well as all other pollutants, as it would become necessary to combust more coal to produce the same electrical output. PM and PM10 emissions from cooling towers are emitted from the escape of water droplets containing dissolved solids. A certain fraction of these droplets will be of a size range such that upon evaporation in the atmosphere, a resulting particle of PM10 could be liberated as an air emission. PM / PM10 (which in this case is all filterable PM10) is controlled by drift eliminators, which limit the number and size distribution of liquid water droplets that escape the tower (called “drift”). Duke Power proposes to use state-of-the-art mist (drift) eliminators with a maximum drift rate equal to 0.0005% of the recirculated water flow to limit drift of water droplets that may contain dissolved solids (TDS) as BACT. There are no cooling towers identified in the RBLC with specified control other than drift eliminators.

5.12 BACT Analysis for Material Handling Sources

Material handling sources, including coal, limestone, gypsum and ash unloading, storage, reclaim, and loading, are a source of both fugitive (area) and point source particulate emissions. In this case, all PM / PM10 emissions are filterable only. In general, material handling system emissions will be controlled by wet or chemical dust suppression, enclosures or fabric filters as necessary. For example, water sprays, when needed, will be used to knock down fugitive dust at coal drops, conveyors will be partially enclosed in order to control dust emissions due to wind, and fabric filters will be used to evacuate and control enclosed sources such as silos. BACT for the fabric filters is proposed as a manufacturer’s guarantee of 0.01 gr/dscf and annual maintenance performed to OEM specifications. The proposed emission limit of 0.01 gr/dscf is the same as the BACT limit issued for the Roundup Power project in July 2003.

Section 3.0 and Appendix B include a list of material handling emission sources and the proposed BACT emission control strategy for each. While emissions are estimated for sources other than the fabric filters, BACT for these sources constitutes equipment design, operating practices and in certain cases use limitations on redundant equipment. No numerical PM / PM10 emission limits are proposed for these sources, although annual emissions will be

22 May 2007

calculated and reported based on the methodology used to estimate the materials handling emissions.

We note that the coal preparation area is subject to the Standards of 40 CFR 60 Subpart Y, which limit opacity to 20% (6-minute average). For purposes of consistency in monitoring approach and record keeping requirements, Duke Power proposes that compliance with BACT for sources other than the fabric filters be determined based on the same 20% opacity requirement as required under Subpart Y for the coal preparation areas. Maintaining the same limit on all materials handling operations at the facility will simplify compliance with Subpart Y and will streamline monitoring, record keeping and reporting for all of the bulk materials handling operations associated with Cliffside Unit 6. This is consistent with BACT determinations for similar PSD permits.

5.13 BACT for New Distillate Oil Storage Tank

As shown in Section 3 and Appendix B, the new distillate (No. 2) oil tank will emit small amounts of VOC due to filling and breathing losses. BACT for control of VOC emissions from the distillate oil storage tank is proposed as operational procedures during filling (to prevent spills or overfilling), submerged filling and utilizing a light color coating on the tanks (to minimize vaporization and breathing losses due to solar heat gain). This represents BACT for control of VOC from distillate oil storage, and is consistent with BACT determinations for similar PSD permits.

5.14 Summary of BACT Determinations for Cliffside Unit 6 Boiler

The emission limits and associated monitoring methods concluded to represent BACT for the Cliffside Unit 6 expansion are summarized in the following Table:

23 May 2007

Table 5-5 BACT Summary for Cliffside Unit 6 Boiler

Main Boiler Pollutant

Proposed Emission Limit (lb/MMBtu)

Averaging Period and Compliance Method

Proposed BACT Technology

PM / PM10 / PM2.5

0.015 filterable Three, 1-hour tests via Initial Reference Method 5 or 17 stack performance test, CAM

Spray Dry Absorber followed by Fabric Filter Baghouse

PM / PM10 / PM2.5

0.024 total filterable plus condensable

Initial Method 202 or other approved method, as modified to exclude non-condensable pseudo-particulates.


CO 0.15 Three, 1-hour tests via Initial Stack Testing

Good Combustion Practices

VOC 0.004 Three, 1-hr tests via Initial Stack Testing

Good Combustion Practices

H2SO4 0.005 Three, 1-hr tests via Initial Stack Testing


Pb and Trace Metals

0.000022 Same as PM10 Fabric Filter Baghouse

APPENDIX A: APPLICATION FORMS

May 2007

REVISED 12/01/01 A2

U6 Unit 6 Boiler CD19-22 SCR, SDA, Baghouse, and Wet FGDAux Auxiliary Boiler NACT1 Cooling Tower NAC19 Unit 6 Coal Reclaim HopperC27-30 Unit 6 Boilerhouse Coal Handling CD28 Baghouse

Ash Handling Point Source Unit 6 CD30 BaghouseA1, A12 Ash Handling Fugitive Source Unit 6 NAVF1 - VF32 Coal Reclaim FeedersLSSDA Lime for SDA CD32-3 Bin Vent Filter (on silo)EG6 Emergency GeneratorFWP Emergency Fire Water Pump

FVehicle Fugitive Vehicle EmissionsC1 Existing Coal UnloadingC2, C3, C4, C5, C7 Coal Handling Conveyors and Telescoping ChutesC9, C10 Coal Storage Pile Fugitive EmissionsC15 Unit 5 Crusher House C17 Existing Conveyor C4 to U5 Boiler BldgC18 Existing Tripper Conveyor TR1GS3, GS4 Gypsum Handling - Stockout ConveyorsGS5 Gypsum Storage PilesGS7 Gypsum Truck LoadingLS1 Limestone Rail Car UnloadingLS2 Limestone Stockout Conveyor LS6 Limestone Stockout ConveyorLS8 Limestone Storage PilesLS9, LS10 Limestone Bulldozing and Reclaim HoppersFLandfill Landfill Activities - Active Cell

U1 Unit 1 Boiler CD1 ESPU2 Unit 2 Boiler CD2 ESPU3 Unit 3 Boiler CD3 ESPU4 Unit 4 Boiler CD4 ESPC6 Stockout Conveyor SC3C8 Stockout Conveyor SC4C13 Reclaim Conveyor RC1 to Transfer houseC14 Reclaim Conveyor RC1 to U5 Crusher HouseC16 Reclaim Conveyor RC3 to Unit 5 Boiler HouseC20-23 Coal Reclaim ConveyorsC24-C26 Unit 6 & 7 Crusher House and Reclaim Conveyors CD27 BaghouseC31-34 Unit 7 Boilerhouse Coal Handling CD29 BaghouseLS3 Limestone Transfer House (existing)LS6, LS7 Limestone Stockout Conveyor and Radial StackerLS12 Limestone Reclaim ConveyorLS13-3 Limestone Silo No. 3LS15 Limeston Reclaim ConveyorGS9 Discharge from Belt Filter 3GS8 Gypsum Rail Car LoadingGS10 Gypsum - Belt Filter

Is your facility subject to 40 CFR Part 68 "Prevention of Accidental Releases" - Section 112(r) of the Federal Clean Air Act? Yes / NoIf No, please specify in detail how your facility avoided applicability:

If your facility is Subject to 112(r), please complete the following: A. Have you already submitted a Risk Management Plan (RMP) to EPA Pursuant to 40 CFR Part 68.10 or Part 68.150?

Yes No Specify required RMP submittal date: _____________ If submitted, RMP submittal date: __ 6/8/2004 B. Are you using administrative controls to subject your facility to a lesser 112(r) program standard?

Yes No If yes, please specify:

Facility Name: Duke Cliffside Steam StationMailing Address Line 1: 573 Duke Power Road Mailing Address Line 2:City: Cliffside State: NC Zip Code: 28114 County: Rutherford & ClevelandPhone No. (828) 657-2339 Fax No. (828) 657-2060 Email Address:

SO2 51,742,000 35,130,000 C19-U5 WFGDSO2 10,918,000 C19-U1-4 RetireNOx 2,816,000 C19-U1-4 RetirePM 698,000 C19-U1-4 RetireCO 130,000 C19-U1-4 Retire

Attach Additional Sheets As Necessary

For assistance with Section A4, please contact the North Carolina Division of Pollution Prevention and Environmental Assistance at 1-800-763-0136 or [email protected]

112(r) APPLICABILITY INFORMATION

SURVEY OF FACILITY REDUCTION & RECYCLING ACTIVITIES

Planned Source ReductionActivities (Enter Code)Activities (Enter Code) Reduction (lb/yr) Reduction (lb/yr)

Pollutant Ongoing Source Reduction Qty. Emitted Before Qty. Emitted After

Equipment To Be ADDED By This Application (New, Previously Unpermitted, or Replacement)

Existing Permitted Equipment To Be MODIFIED By This Application

Equipment To Be DELETED By This Application

ID NO. DESCRIPTION ID NO. DESCRIPTION

A3, A6, A8, A9

EMISSION SOURCE EMISSION SOURCE CONTROL DEVICE CONTROL DEVICE

FORMs A2, A3, A4

SURVEY OF FACILITY REDUCTION & RECYCLING ACTIVITIES - A4 NCDENR/Division of Air Quality - Application for Air Permit to Construct/Operate

EMISSION SOURCE LISTING: New, Modified, Previously Unpermitted, Replaced, Deleted

EMISSION SOURCE LISTING FOR THIS APPLICATION - A2112r APPLICABILITY INFORMATION - A3

A 3

A 4

REVISED 12/01/01 BEMISSION SOURCE ID NO: U6CONTROL DEVICE ID NO(S): CD 19-22EMISSION POINT (STACK) ID NO(S): EP-U6

DESCRIBE IN DETAILTHE EMISSION SOURCE PROCESS (ATTACH FLOW DIAGRAM):

X Coal,wood,oil, gas, other burner (Form B1) Woodworking (Form B4) Manufact. of chemicals/coatings/inks (Form B7)

Int.combustion engine/generator (Form B2 Coating/finishing/printing (Form B5 Incineration (Form B8) Liquid storage tanks (Form B3) Storage silos/bins (Form B6) Other (Form B9)

START CONSTRUCTION DATE June 2007 OPERATION DATE: 2011 DATE MANUFACTURED: 2007MANUFACTURER / MODEL NO.: TBDIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?): Da, HHHH NESHAP (SUBPART?):________ MACT (SUBPART?):__________

EXPECTED ANNUAL HOURS OF OPERATIO 8760

SOURCE OFEMISSION

AIR POLLUTANT EMITTED FACTOR lb/hr tons/yr lb/hr tons/yr lb/hr tons/yrPARTICULATE MATTER (PM) Vendor 117.8 515.7 2 2 117.8 515.7PARTICULATE MATTER<10 MICRONS (PM10) Vendor 188.4 825.2 2 2 188.4 825.2PARTICULATE MATTER<2.5 MICRONS (PM2.5) NA NA NA NA NA NASULFUR DIOXIDE (SO2) Vendor 1178 5157.5 2 2 1178 5157.5NITROGEN OXIDES (NOx) Regulatory 549.5 2406.81 2 2 549.5 2406.81CARBON MONOXIDE (CO) Vendor 1177.5 5157.5 2 2 1177.5 5157.5VOLATILE ORGANIC COMPOUNDS (VOC) Vendor 31.4 137.5 2 2 31.4 137.5

Vendor 0.2 0.8 2 2 0.2 0.8OTHER

SOURCE OFEMISSION

HAZARDOUS AIR POLLUTANT AND CAS NO. FACTOR lb/hr tons/yr lb/hr tons/yr lb/hr tons/yrHydrogen Chloride Mass Balance 6.53E+01 1.72E+02 - - 6.53E+01 1.72E+02Hydrogen Fluoride Mass Balance 1.16E+01 2.24E+01 - - 1.16E+01 2.24E+01Antimony AP-42 7.54E-03 3.30E-02 - - 7.54E-03 3.30E-02Arsenic AP-42 1.72E-01 7.52E-01 - - 1.72E-01 7.52E-01Beryllium AP-42 8.79E-03 3.85E-02 - - 8.79E-03 3.85E-02Cadmium AP-42 2.13E-02 9.35E-02 - - 2.13E-02 9.35E-02Chromium AP-42 1.09E-01 4.77E-01 - - 1.09E-01 4.77E-01Cobalt AP-42 4.19E-02 1.83E-01 - - 4.19E-02 1.83E-01Lead AP-42 1.76E-01 7.70E-01 - - 1.76E-01 7.70E-01Manganese AP-42 2.05E-01 8.98E-01 - - 2.05E-01 8.98E-01Mercury 1 NSPS Da 3.36E-02 1.47E-01 - - 3.36E-02 1.47E-01Nickel AP-42 1.17E-01 5.13E-01 - - 1.17E-01 5.13E-01Selenium AP-42 5.44E-01 2.38E+00 - - 5.44E-01 2.38E+00Acetaldehyde AP-42 2.39E-01 1.05E+00 - - 2.39E-01 1.05E+00Acetophenone AP-42 6.28E-03 2.75E-02 - - 6.28E-03 2.75E-02Acrolein AP-42 1.21E-01 5.32E-01 - - 1.21E-01 5.32E-01Anthracene AP-42 8.79E-05 3.85E-04 - - 8.79E-05 3.85E-04Benzene AP-42 5.44E-01 2.38E+00 - - 5.44E-01 2.38E+00Benzo(g,h,i)perylene AP-42 1.13E-05 4.95E-05 - - 1.13E-05 4.95E-05Benzyl Chloride AP-42 2.93E-01 1.28E+00 - - 2.93E-01 1.28E+00Biphenyl AP-42 7.12E-04 3.12E-03 - - 7.12E-04 3.12E-03Bis(2-ethylhexyl)phthalate AP-42 3.06E-02 1.34E-01 - - 3.06E-02 1.34E-01Bromoform AP-42 1.63E-02 7.15E-02 - - 1.63E-02 7.15E-02Carbon Disulfide AP-42 5.44E-02 2.38E-01 - - 5.44E-02 2.38E-012-Chloroacetophenone AP-42 2.93E-03 1.28E-02 - - 2.93E-03 1.28E-02Chlorobenzene AP-42 9.21E-03 4.03E-02 - - 9.21E-03 4.03E-02Chloroform AP-42 2.47E-02 1.08E-01 - - 2.47E-02 1.08E-01Cumene AP-42 2.22E-03 9.72E-03 - - 2.22E-03 9.72E-03Cyanide AP-42 1.05E+00 4.58E+00 - - 1.05E+00 4.58E+002,4-Dinitrotoluene AP-42 1.17E-04 5.13E-04 - - 1.17E-04 5.13E-04

EXPECTED OP. SCHEDULE: _24__ HR/DAY __7_ DAY/WK _52__ WK/YR

VISIBLE STACK EMISSIONS UNDER NORMAL OPERATION: _<20___ % OPACITYPERCENTAGE ANNUAL THROUGHPUT (%): DEC-FEB 25 MAR-MAY 25 JUN-AUG 25 SEP-NOV 25

FORM BSPECIFIC EMISSIONS SOURCE INFORMATION (REQUIRED FOR ALL SOURCES)

NCDENR/Division of Air Quality - Application for Air Permit to Construct/Operate

TYPE OF EMISSION SOURCE (CHECK AND COMPLETE APPROPRIATE FORM B1-B9 ON THE FOLLOWING PAGES):

EMISSION SOURCE DESCRIPTION: Unit 6 Boiler

Nominal 800 MW pulverized coal (PC) boiler fired with bituminous coal or a blend of bituminous and sub-bituminous coals. The boiler will be equipped with the following control devices to reduce air emissions during normal operations: low NOx burners, SCR, SDA, baghouse, and Wet FGD.

OPERATING SCENARIO ______1___________OF ________1__________

CRITERIA AIR POLLUTANT EMISSIONS INFORMATION FOR THIS SOURCE

(BEFORE CONTROLS / LIMITS)

POTENTIAL EMSSIONSEXPECTED ACTUAL(AFTER CONTROLS / LIMITS) (AFTER CONTROLS / LIMITS)

HAZARDOUS AIR POLLUTANT EMISSIONS INFORMATION FOR THIS SOURCE

(AFTER CONTROLS / LIMITS)

LEAD

EXPECTED ACTUAL POTENTIAL EMSSIONS(BEFORE CONTROLS / LIMITS) (AFTER CONTROLS / LIMITS)

Dimethyl Sulfate AP-42 2.01E-02 8.80E-02 - - 2.01E-02 8.80E-02Ethyl benzene AP-42 3.94E-02 1.72E-01 - - 3.94E-02 1.72E-01Ethyl Chloride (Chloroethane) AP-42 1.76E-02 7.70E-02 - - 1.76E-02 7.70E-02Ethylene Dichloride AP-42 1.67E-02 7.33E-02 - - 1.67E-02 7.33E-02Ethylene Dibromide AP-42 5.02E-04 2.20E-03 - - 5.02E-04 2.20E-03Formaldehyde AP-42 1.00E-01 4.40E-01 - - 1.00E-01 4.40E-01Hexane AP-42 2.80E-02 1.23E-01 - - 2.80E-02 1.23E-01Isophorone AP-42 2.43E-01 1.06E+00 - - 2.43E-01 1.06E+00Methyl Bromide (Bromomethane) AP-42 6.70E-02 2.93E-01 - - 6.70E-02 2.93E-01Methyl Chloride (Chloromethane) AP-42 2.22E-01 9.72E-01 - - 2.22E-01 9.72E-01Methyl Ethyl Ketone AP-42 1.63E-01 7.15E-01 - - 1.63E-01 7.15E-01Methyl Hydrazine AP-42 7.12E-02 3.12E-01 - - 7.12E-02 3.12E-01Methyl Methacrylate AP-42 8.37E-03 3.67E-02 - - 8.37E-03 3.67E-02Methyl tert-butyl ether AP-42 1.47E-02 6.42E-02 - - 1.47E-02 6.42E-02Methylene Chloride AP-42 1.21E-01 5.32E-01 - - 1.21E-01 5.32E-01Naphthalene AP-42 5.44E-03 2.38E-02 - - 5.44E-03 2.38E-02Phenanthrene AP-42 1.13E-03 4.95E-03 - - 1.13E-03 4.95E-03Phenol AP-42 6.70E-03 2.93E-02 - - 6.70E-03 2.93E-02Propionaldehyde AP-42 1.59E-01 6.97E-01 - - 1.59E-01 6.97E-01Styrene AP-42 1.05E-02 4.58E-02 - - 1.05E-02 4.58E-02Tetrachloroethylene AP-42 1.80E-02 7.88E-02 - - 1.80E-02 7.88E-02Toluene AP-42 1.00E-01 4.40E-01 - - 1.00E-01 4.40E-011,1,1-Trichloroethane AP-42 8.37E-03 3.67E-02 - - 8.37E-03 3.67E-02Vinyl Acetate AP-42 3.18E-03 1.39E-02 - - 3.18E-03 1.39E-02Xylene AP-42 1.55E-02 6.78E-02 - - 1.55E-02 6.78E-02Total PCDD/PCDF AP-42 7.37E-07 3.23E-06 - - 7.37E-07 3.23E-06

TOXIC AIR POLLUTANT AND CAS NO. EF SOURCEHydrogen Chloride Mass Balance 65.29 1566.85 571898.56Hydrogen Fluoride Mass Balance 11.63 279.20 101907.58Arsenic AP-42 0.17 4.12 1503.52Beryllium AP-42 0.01 0.21 77.01Cadmium AP-42 0.02 0.51 187.02Chromium AP-42 0.11 2.61 953.45Manganese AP-42 0.21 4.92 1796.89Mercury AP-42 0.03 0.81 294.34Nickel AP-42 0.12 2.81 1026.80Acetaldehyde AP-42 0.24 5.73 2090.26Acrolein AP-42 0.12 2.91 1063.47Benzene AP-42 0.54 13.06 4767.27Benzyl Chloride AP-42 0.29 7.03 2566.99Carbon Disulfide AP-42 0.05 1.31 476.73Chlorobenzene AP-42 0.01 0.22 80.68Chloroform AP-42 0.02 0.59 216.36Ethylene Dichloride AP-42 0.02 0.40 146.69Ethylene Dibromide AP-42 0.00 0.01 4.40Formaldehyde AP-42 0.10 2.41 880.11Hexane AP-42 0.03 0.67 245.70Methyl Ethyl Ketone AP-42 0.16 3.92 1430.18Methylene Chloride AP-42 0.22 5.32 1943.58Phenol AP-42 0.01 0.16 58.67Styrene AP-42 0.01 0.25 91.68Toluene AP-42 0.10 2.41 880.11Xylene AP-42 0.02 0.37 135.68Sulfuric Acid Vendor 47.10 1130.40 412596.00Ammonia Vendor 31.40 753.60 275064.00

1 Calculated based on NSPS Subpart Da, Sub-bituminous units w/ wet FGD - see emission calculation notes2 Emissions provided are based on preliminary design. Information based on final design will be provided to NC DAQ.

Attachments: (1) emissions calculations and supporting documentation; (2) indicate all requested state and federal enforceable permit limits (e.g. hours of operation, emissiorates) and describe how these are monitored and with what frequency; and (3) describe any monitoring devices, gauges, or test ports for this source.

lb/dayINDICATE EXPECTED ACTUAL EMISSIONS AFTER CONTROLS / LIMITATIONS

lb/yr

TOXIC AIR POLLUTANT EMISSIONS INFORMATION FOR THIS SOURCE

lb/hr

REVISED 12/01/01 B1EMISSION SOURCE DESCRIPTION: EMISSION SOURCE ID NO: U6

CONTROL DEVICE ID NO(S): CD 19-22

OPERATING SCENARIO: ______1________ OF ______1________ EMISSION POINT (STACK) ID NO(S): EP-U6

DESCRIBE USE: PROCESS HEAT SPACE HEAT X ELECTRICAL GENERATION

CONTINUOUS US STAND BY/EMERGENCY OTHER (DESCRIBE): _________

HEATING MECHANISM: X INDIRECT DIRECT

MAX. FIRING RATE (MMBTU/HOUR): 7850

BARK WOOD/BARK WET WOOD DRY WOOD OTHER (DESCRIBE): __________

PERCENT MOISTURE OF FUEL:_________________

UNCONTROLLED CONTROLLED WITH FLYASH REINJECTION CONTROLLED W/O REINJECTION

FUEL FEED METHOD: HEAT TRANSFER MEDIA: STEAM AIR OTHER

METHOD OF TUBE CLEANING: CLEANING SCHEDULE:

TYPE OF BOILER IF OTHER DESCRIBE:

PULVERIZED

WET BED UNCONTROLLED UNCONTROLLED UNCONTROLLED CIRCULATING

X DRY BED CONTROLLED CONTROLLED FLYASH REINJECTION RECIRCULATING

NO FLYASH REINJECTION

METHOD OF LOADING: CYCLONE HANDFIRED TRAVELING GRATE X OTHER (DESCRIBE): Supercritical PC Unit

METHOD OF TUBE CLEANING: TBD CLEANING SCHEDULE: As needed

TYPE OF BOILER: UTILITY INDUSTRIAL COMMERCIAL RESIDENTIAL

TYPE OF FIRING: NORMAL TANGENTIAL LOW NOX BURNERS NO LOW NOX BURNER


TYPE OF FUEL: ____________________________ PERCENT MOISTURE: _____________ TYPE OF BOILER: UTILITY INDUSTRIAL COMMERCIAL RESIDENTIAL

TYPE OF FIRING: _______________ TYPE OF CONTROL (IF ANY): ___________________________ FUEL FEED METHOD: ________


No. 2 Fuel Oil (Start-up) mmBTU 2747.5 NA

Coal mmBTU 7850 NA

No. 2 Fuel Oil (Start-up) 137000 BTU/gal 0.05 NA

Coal 9376 BTU/lb 3 11.29

COMMENTS:

SAMPLING PORTS, COMPLIANT WITH EPA METHOD 1 WILL BE INSTALLED ON THE STACKS: X YES NO


ASH CONTENT

(% BY WEIGHT)

SULFUR CONTENT

FUEL TYPE

SPECIFIC

BTU CONTENT (% BY WEIGHT)

Fuel oil will be combusted along with coal for start-up, up to 35% of maximum capacity, where the fuel will be switched to coal. Fuel oil may also be used when the pulverizer is brought into service. Coal will be a blend from various regions and coal specs.

LIMITATION (UNIT/HR)

FUEL CHARACTERISTICS (COMPLETE ALL THAT ARE APPLICABLE)

MAXIMUM DESIGN

CAPACITY (UNIT/HR)

REQUESTED CAPACITY

FUEL TYPE UNITS

COAL-FIRED BURNER

OIL/GAS-FIRED BURNER

WOOD TYPE:

FORM B1EMISSION SOURCE (WOOD, COAL, OIL, GAS, OTHER FUEL-FIRED BURNER)


WOOD-FIRED BURNER

Nominal 800 MW pulverized coal (PC) boiler fired with bituminous coal or a blend of bituminous and sub-bituminous coals. Boiler is controlled by SCR system, SDA, Baghouse, and a wet-flue gas desulfurization unit.

FUEL USAGE (INCLUDE STARTUP/BACKUP FUELS)

SPREADER STOKER FLUIDIZED BEDOVERFEED STOKER UNDERFEED STOKER

OTHER FUEL-FIRED BURNER

REVISED 12/01/01

CONTROL DEVICE ID NO: CD19 CONTROLS EMISSIONS FROM WHICH EMISSION SOURCE ID NO(S)U6

EMISSION POINT (STACK) ID NO(S) EP-U6 POSITION IN SERIES OF CONTROLS NO. 1 OF 4 UNITS

MANUFACTURER: TBD MODEL NO: TBD

MANUFACTURE DATE: TBD PROPOSED OPERATION DATE: 2011

PROPOSED CONSTRUCTION DATE: June 2007

TYPE: AFTERBURNER REGENERATIVE THERMAL OXIDATION RECUPERATIVE THERMAL OXIDATION

CATALYTIC OXIDATIONEXPECTED LIFE OF CATALYST (YRS): METHOD OF DETECTING WHEN CATALYST NEEDS REPLACMENT:CATALYST MASKING AGENT IN AIR STREAM: HALOGEN SILICONE PHOSPHOROUS COMPOUND HEAVY METAL

SULFUR COMPOUND OTHER_________________ NONE

TYPE OF CATALYST: Vanadium pentoxide CATALYST VOL (FT3): TBD VELOCITY THROUGH CATALYST (FPS): TDB

SCFM THROUGH CATALYST:

DESCRIBE CONTROL SYSTEM, INCLUDING RELATION TO OTHER CONTROL DEVICES AND SOURCES, AND ATTACH DIAGRAM OF SYSTEM:

POLLUTANT(S) COLLECTED: NOx

BEFORE CONTROL EMISSION RATE (LB/HR): 2355 lb/hr(to SCR; 0.30 lb/mmbtu)

CAPTURE EFFICIENCY: % % % %

CONTROL DEVICE EFFICIENCY: % % % %

OVERALL SYSTEM EFFICIENCY: % % % %

EFFICIENCY DETERMINATION CODE:

TOTAL EMISSION RATE (LB/HR) : 628 lb/hr (after SCR; 0.08 lb/mmbtu)

PRESSURE DROP (IN. H2O OUTLET TEMPERATURE (oF):

INLET TEMPERATURE (oF RESIDENCE TIME (SECONDS):

INLET AIR FLOW RATE (ACFM):4,500,000 to SCR COMBUSTION TEMPERATURE (oF):

COMBUSTION CHAMBER VOLUME (FT3): INLET MOISTURE CONTENT (%):

% EXCESS AIR: CONCENTRATION (ppmv) ______INLET ______OUTLET

AUXILIARY FUEL USED: No. 2 Fuel Oil TOTAL MAXIMUM FIRING RATE (MILLION BTU/HR): 7850 lb/mmbtu

MAXIMUM ANNUAL FUEL USE: UNITS: MAXIMUM HOURLY FUEL USE: UNITS:

ACTUAL ANNUAL FUEL USE: UNITS: ACTUAL HOURLY FUEL USE: 418.6 UNITS: ton/hr design coal

DESCRIBE METHOD USED TO INCREASE MIXING:

DESCRIBE METHOD TO INSURE ADEQUATE START-UP TEMPERATURE:

DESCRIBE TEMPERATURE MONITORING DEVICES AND PROCEDURES:

STACK TESTING PORTS: NO YES (INLET AND OUTLET)

DESCRIBE MAINTENANCE PROCEDURES:

DESCRIBE ANY AUXILIARY MATERIALS INTRODUCED INTO THE CONTROL SYSTEM:

ATTACH A DIAGRAM OF THE RELATIONSHIP OF THE CONTROL DEVICE TO ITS EMISSION SOURCE(S):

FORM C3 CONTROL DEVICE (THERMAL OR CATALYTIC)

NCDENR/Division of Air Quality - Application for Air Permit to Construct/Operate C3AS REQUIRED BY 15A NCAC 2Q .0112, THIS FORM MUST BE SEALED BY A PROFESSIONAL ENGINNER (P.E.) LICENSED IN NORTH CAROLINA.

OPERATING SCENARIO:

_____1__ OF __1_____

NOx emissions from the boiler will be controlled using a combination of low-NOx burners, over-fire air and a selective catalytic reduction (SCR) system. The combustion system applies air-staging in combination with low-NOx burners to minimize NOx formation in the furnace to minimze the amount of SCR catalyst required and reduce the consumption of reagent.

The Selective Catalytic Reduction (SCR) system catalytically reduces boiler flue gas nitrogen oxide (NOx) emissions to nitrogen and water using anydrous ammonia (NH3) as a reducing agent. Flue gas exiting the ecomonizer outlet flows through two flow paths prior to entering the ammonia / air injection zone. Each flue has a dedicated ammonia injection grid fed by a manifold valve station. Following the ammonia injection the gas enters the SCR reactor were the NOx reacts with the ammonia and is converted to nitrogen and water. The flue gas exiting the reactor is directed into the air heater.

MIN MAX AVE:4.3 across SCR MIN MAX 750 at SCR outlet


MIN 600 MAX 750 at econ. Outlet

The ammonia injection grid has multiple zones for injecting ammonia across the flue gas path. Each injection pipe has numerous injection orifices for optimim ammonia-flue gas mixing.

Steam coil air heaters are designed to preheat the combustion air during initial firing. Ammonia is injected once the catalst bed temperature has been elevated above the estimated minimum injection temperature of 600 F. Temp. to be confirmed by SCR supplier.

REVISED 12/01/01

CONTROL DEVICE ID NO: CD20 CONTROLS EMISSIONS FROM WHICH EMISSION SOURCE ID NO(S): U6

EMISSION POINT (STACK) ID NO(S)EP-U6 POSITION IN SERIES OF CONTROLSNO. 2 OF 4 UNITS

MANUFACTURER: ALSTOM MODEL NO: Custom

DATE MANUFACTURED: 2007 PROPOSED OPERATION DATE: 2011

PROPOSED START CONSTRUCTION DATE: Jun-07

DESCRIBE CONTROL SYSTEM: Two spray dryers are provided to condition flue gas before entering the fabric filter.The spray dryers work as a system with the fabric filter. Flue gas from the boiler exit air pre-heaters is conditioned using a well distributed spray ofa water/lime slurry to cool the gas to less than 260 F. The cooling together with the lime added removes and neutralizes SO3/H2SO4 in the combinedspray dryer/FF system.

POLLUTANT(S) COLLECTED: Collection is in Fabric Filter - see Fabric Filter formBEFORE CONTROL EMISSION RATE (LB/HR):CAPTURE EFFICIENCY: % % % %CONTROL DEVICE EFFICIENCY: % % % %CORRESPONDING OVERALL EFFICIENCY: % % % %EFFICIENCY DETERMINATION CODE:

TOTAL EMISSION RATE (LB/HR):

PRESSURE DROP (IN. H20): MIN 1 MAX 5 BULK PARTICLE DENSITY (LB/FT3) 40 - 45

INLET TEMPERATURE (oF): MIN 230 MAX 315

INLET AIR FLOW RATE (ACFM): 2,824,500 (total - full load) OUTLET AIR FLOW RATE (ACFM): 2,720,000 (typical total at full load)

INLET AIR FLOW VELOCITY (FT/SEC): 60 OUTLET AIR FLOW VELOCITY (FT/SEC): 50 - 55

INLET MOISTURE CONTENT (%): 8 to 11 FORCED AIR INDUCED AIRCOLLECTION SURFACE AREA (FT2): NA FUEL USAGE RATE:

DESCRIBE STARTUP PROCEDURES: Flue gas passes through spray dryers during boiler startup.

When gas temperature reaches certain temperature (preliminarily 230 F), water/lime slurry is added to multiple rotary atomizers at a controlled

DESCRIBE MAINTENANCE PROCEDURES: Each spray dryer has three normally operating rotary atomizers.

Periodically (one atomizer per day to one atomizer per week) an atomizer is stopped, removed, and replaced with the spare atomizer.

DESCRIBE ANY AUXILIARY MATERIALS INTRODUCED INTO THE CONTROL SYSTEM:

Water and lime slurry added to the flue gas in controlled manner using control valves. Water is added to maintain spray dryer exit temperature,

DESCRIBE ANY MONITORING DEVICES, GAUGES, TEST PORTS, ETC:


FORM C9

Approximately a one hour period for removal and replacement of atomizer. The removed atomizer is cleaned of any scale or pluggage due to the lime slurry.

C9CONTROL DEVICE (OTHER)


_______ OF _______

OUTLET TEMPERATURE (oF): MIN 160 MAX 260

Temperature at the exit of each spray dryer is monitored using thermocouples. Pressure drop across each spray dryer is monitored.

OPERATING SCENARIO:

FUEL USED: NA

rate to cool flue gas to setpoint (220 F anticipated normal operating temperature at spray dryer exit) and add lime to neutralize acid collected.

See attached "Cliffside Unit 6 Overal AQCS Process Flow Diagram."

Attach manufacturer's specifications, schematics, and all other drawings necessary to describe this control.

and an excess of lime slurry is added to neutralize any collected SO3/H2SO4.

P.E. SEAL REQUIRED (PER 2Q .0112)? X YES NO

REVISED 12/01/01 C1CONTROL DEVICE ID NO: CD21 CONTROLS EMISSIONS FROM WHICH EMISSION SOURCE ID NO(S): U6

EMISSION POINT (STACK) ID NO(S): EP-U6 POSITION IN SERIES OF CONTROLS NO. 3 OF 4 UNITS

MANUFACTURER: ALSTOM MODEL NO: Custom design

DATE MANUFACTURED: 2007 PROPOSED OPERATION DATE: 2011

PROPOSED START CONSTRUCTION DATE: June 2007

_______ OF _______

through multiple fabric bags. The fabric filter removes most of the filterable particulate. The gas temperature into the fabric filter of less than 260 F

(as conditioned by the spray dryers) together with the lime slurry addition in to the flue gas provides removal and neutralization of SO3/H2SO4 in the flue gas.

POLLUTANT(S) COLLECTED: Filterable Particulate SO3/H2SO4

BEFORE CONTROL EMISSION RATE (LB/HR): 20,000 to 170,000 200 to 1000

CAPTURE EFFICIENCY: >99 % % >80 % %

CONTROL DEVICE EFFICIENCY: >99 % % >80 % %

CORRESPONDING OVERALL EFFICIENCY: > 99 % % >80 % %

EFFICIENCY DETERMINATION CODE: EPA 5B in stack CCM in stack

TOTAL EMISSION RATE (LB/HR): 118 (0.015 lbs/MMBtu) 47 (0.006 lbs/MMBtu)

PRESSURE DROP (IN. H20): MIN: 4 MAX: 10 GAUGE?

BULK PARTICLE DENSITY (LB/FT3): 40 to 45 INLET TEMPERATURE (oF): MIN 160 MAX 260

POLLUTANT LOADING RATE: LB/HR GR/FT3 OUTLET TEMPERATURE (oF): MIN 160 MAX 260

INLET AIR FLOW RATE (ACFM): 2,720,000 (typical total at full load) FILTER MAX OPERATING TEMP. (oF): Design up to 340 F, Regular operation up to 260 F

NO. OF COMPARTMENTS: 24 NO. OF BAGS PER COMPARTMENT: 896 (preliminary) LENGTH OF BAG (IN.): 318

DIAMETER OF BAG (IN.): 5.125 DRAFT: INDUCED/NEG. FORCED/POS. FILTER SURFACE AREA (FT2): 726,800

AIR TO CLOTH RATIO:4 fpm FILTER MATERIAL: felted PPS with blend of additional fiber WOVEN FELTED

DESCRIBE CLEANING PROCEDURES:

AIR PULSE SONIC

REVERSE FLOW SIMPLE BAG COLLAPSE

MECHANICAL/SHAKER RING BAG COLLAPSE NA OTHER NA

DESCRIBE INCOMING AIR STREAM: Dried compressed air with pressure up to 50 psig NAis used for bag cleaning. NA

NANA

METHOD FOR DETERMINING WHEN TO CLEAN:

AUTOMATIC TIMED MANUAL Normal is auto based on pressure drop, timed cleaning is secondary if needed.

METHOD FOR DETERMINING WHEN TO REPLACE THE BAGS: Internal inspection for specific bag failures. ALARM INTERNAL INSPECTION VISIBLE EMISSION OTHER - Opacity meter after fabric filter.

SPECIAL CONDITIONS:

MOISTURE BLINDING CHEMICAL RESISTIVITY OTHER

EXPLAIN: Flue gas conditioned with moisture for cooling and lime to remove acid and protect bags.

>100

TOTAL = 100

1-10

10-25

25-50

PARTICLE SIZE DISTRIBUTION

CUMULATIVE

(MICRONS)

50-100

OF TOTAL %WEIGHT %

0-1

FORM C1CONTROL DEVICE (FABRIC FILTER)


OPERATING SCENARIO:

SIZE

P.E. SEAL REQUIRED (PER 2Q .0112)? X YES NO

YES NO WARNING ALARM? YES NO

DESCRIBE CONTROL SYSTEM: Conditioned flue gas leaving the spray dryers enters the fabric filter. Gas distributes to multiple compartments and is fltered

Attach Additional Sheets As NecessaryON A SEPARATE PAGE, ATTACH A DIAGRAM SHOWING THE RELATIONSHIP OF THE CONTROL DEVICE TO ITS EMISSION SOURCE(S):

DESCRIBE MAINTENANCE PROCEDURES: Individual bags are removed and replaced if failure is indicated. On aging, bleed through of fine particles will result in increased opacity and require replacement of bags.

REVISED 12/01/01 C8CONTROL DEVICE ID NO: CD22 CONTROLS EMISSIONS FROM WHICH EMISSION SOURCE ID NO(S): U6

EMISSION POINT ID NO(S): EP-U6 POSITION IN SERIES OF CONTROLS: NO. 4 OF 4 UNITS


DATE MANUFACTURED: PROPOSED OPERATION DATE: 2011

PROPOSED CONSTRUCTION DATE: June 2007

DESCRIBE CONTROL SYSTEM:

POLLUTANT(S) COLLECTED: SO2

BEFORE CONTROL EMISSION RATE (LB/HR): 39,238

CAPTURE EFFICIENCY: % % %

CONTROL DEVICE EFFICIENCY: % % %

CORRESPONDING EFFICIENCY: 99 % % %


TOTAL EMISSION RATE (LB/HR): 1178 lb/hr (0.15 lb/mmbtu - 30 day average)

PRESSURE DROP (IN. H20): MIN MAX AVE: 11 YES NO

INLET TEMPERATURE (oF): MIN MAX AVE: 300 OUTLET TEMPERATURE (oF): MIN MAX AVE: 120

INLET AIR FLOW RATE (ACFM): MOISTURE CONTENT : INLET % OUTLET %

THROAT VELOCITY (FT/SEC): THROAT TYPE: FIXED VARIABLE

TYPE OF SYSTEM: Wet Limestone, forced oxidation TYPE OF PACKING USED IF ANY: n/aADDITIVE LIQUID SCRUBBING MEDIUM: limestone slurry PERCENT RECIRCULATED:

MINIMUM LIQUID INJECTION RATE (GAL/MIN 313 FLOW RATE GAUGE INSTALLED? YES NO

MAKE UP RATE (GAL/MIN): FOR ADDITIVE (GAL/MIN):DESCRIBE MAINTENANCE PROCEDURES:

WEIGHT %OF TOTAL

DESCRIBE ANY MONITORING DEVICES, GAUGES, TEST PORTS, ETC:


TOTAL = 100


10-2525-50

50-100>100

(MICRONS) %

0-11-10

2,550,000

1300PARTICLE SIZE DISTRIBUTION

SIZE CUMULATIVE

_______ OF _______ P.E. SEAL NEEDED (PER 2Q .0112)? YES NO

The proposed flue gas desulfurization (FGD) system is a wet limestone, forced oxidation, system with a vertical, countercurrent, spray tower absorber. The flue gas enters the spray tower near the bottom through the absorber inlet nozzle. Once in the absorber, the hot flue gas is immediately quenched as it travels upward countercurrent to a continuous spray of process/recycle slurry produced by multiple spray banks. The recycle slurry extracts the sulfur dioxide from the flue gas and collects it in the bottom of the absorber where it is oxidized to calcium sulfate. The proposed system will treat 100% of the flue gas from the unit. The unit will be designed for 99% removal efficiency.

WARNING ALARM?

FORM C8CONTROL DEVICE (WET PARTICULATE SCRUBBER)NCDENR/Division of Air Quality - Application for Air Permit to Construct/Operate

OPERATING SCENARIO:

REVISED 12/01/01 BEMISSION SOURCE ID NO: Aux 6CONTROL DEVICE ID NO(S):EMISSION POINT (STACK) ID NO(S): Aux 6


X Coal,wood,oil, gas, other burner (Form B1) Woodworking (Form B4) Manufact. of chemicals/coatings/inks (Form B7)

Int.combustion engine/generator (Form B2 Coating/finishing/printing (Form B5) Incineration (Form B8) Liquid storage tanks (Form B3) Storage silos/bins (Form B6) Other (Form B9)

START CONSTRUCTION DATE June 2007 OPERATION DATE: 2011 DATE MANUFACTURED: 2007MANUFACTURER / MODEL NO.: TBDIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?): Db NESHAP (SUBPART?):________ MACT (SUBPART?):DDDDD_

EXPECTED ANNUAL HOURS OF OPERATIO ~876

SOURCE OFEMISSION

AIR POLLUTANT EMITTED FACTOR lb/hr tons/yr lb/hr tons/yr lb/hr tons/yrPARTICULATE MATTER (PM) BACT 1 2.66 1.17 2.66 11.70 2.66 1.17PARTICULATE MATTER<10 MICRONS (PM10) BACT 1 4.56 2.00 4.56 20.00 4.56 2.00PARTICULATE MATTER<2.5 MICRONS (PM2.5) NA NA NA NA NA NASULFUR DIOXIDE (SO2) AP-42 9.85 4.31 9.85 43.10 9.85 4.31NITROGEN OXIDES (NOx) BACT 1 19.00 8.32 19.00 83.20 19.00 8.32CARBON MONOXIDE (CO) BACT 1 6.84 3.00 6.84 30.00 6.84 3.00VOLATILE ORGANIC COMPOUNDS (VOC) BACT 1 0.46 0.20 0.46 2.00 0.46 0.20

AP-42 0.00 0.00 0.00 0.01 0.00 0.00SULURIC ACID AP-42 0.17 0.01 0.17 0.07 0.17 0.01

SOURCE OFEMISSION

HAZARDOUS AIR POLLUTANT AND CAS NO. FACTOR lb/hr tons/yr lb/hr tons/yr lb/hr tons/yrBenzene AP-42 2.97E-04 1.30E-04 2.97E-04 4.55E-04 2.97E-04 1.30E-04Ethylbenzene AP-42 8.82E-05 3.86E-05 8.82E-05 1.35E-04 8.82E-05 3.86E-05Formaldehyde AP-42 8.46E-02 3.71E-02 8.46E-02 1.30E-01 8.46E-02 3.71E-02Naphthalene AP-42 1.57E-03 6.86E-04 1.57E-03 2.41E-03 1.57E-03 6.86E-041,1,1-Trichloroethane AP-42 3.27E-04 1.43E-04 3.27E-04 5.02E-04 3.27E-04 1.43E-04Toluene AP-42 8.60E-03 3.77E-03 8.60E-03 1.32E-02 8.60E-03 3.77E-03o-Xylene AP-42 1.51E-04 6.62E-05 1.51E-04 2.32E-04 1.51E-04 6.62E-05Acenaphthene AP-42 2.93E-05 1.28E-05 2.93E-05 4.49E-05 2.93E-05 1.28E-05Acenaphthylene AP-42 3.51E-07 1.54E-07 3.51E-07 5.39E-07 3.51E-07 1.54E-07Anthracene AP-42 1.69E-06 7.41E-07 1.69E-06 2.60E-06 1.69E-06 7.41E-07Benz(a)anthracene AP-42 5.56E-06 2.44E-06 5.56E-06 8.54E-06 5.56E-06 2.44E-06Benzo(b.k)fluoranthene AP-42 2.05E-06 8.99E-07 2.05E-06 3.15E-06 2.05E-06 8.99E-07Benzo(g,h,i)perylene AP-42 3.13E-06 1.37E-06 3.13E-06 4.81E-06 3.13E-06 1.37E-06Chrysene AP-42 3.30E-06 1.45E-06 3.30E-06 5.07E-06 3.30E-06 1.45E-06Dibenzo(a,h)anthracene AP-42 2.32E-06 1.01E-06 2.32E-06 3.55E-06 2.32E-06 1.01E-06Fluoranthene AP-42 6.71E-06 2.94E-06 6.71E-06 1.03E-05 6.71E-06 2.94E-06Fluorene AP-42 6.20E-06 2.72E-06 6.20E-06 9.51E-06 6.20E-06 2.72E-06Indo(1,2,3-cd)pyrene AP-42 2.97E-06 1.30E-06 2.97E-06 4.55E-06 2.97E-06 1.30E-06Phenanthrene AP-42 1.46E-05 6.38E-06 1.46E-05 2.23E-05 1.46E-05 6.38E-06Pyrene AP-42 5.89E-06 2.58E-06 5.89E-06 9.05E-06 5.89E-06 2.58E-06OCDD AP-42 4.30E-09 1.88E-09 4.30E-09 6.60E-09 4.30E-09 1.88E-09

TOXIC AIR POLLUTANT AND CAS NO. EF SOURCEBenzene AP-42 2.97E-04 7.12E-03 2.60Formaldehyde AP-42 8.46E-02 2.03E+00 741.08Toluene AP-42 8.60E-03 2.06E-01 75.32Arsenic AP-42 7.60E-04 1.82E-02 6.66Beryllium AP-42 5.70E-04 1.37E-02 4.99Cadmium AP-42 5.70E-04 1.37E-02 4.99Chromium AP-42 5.70E-04 1.37E-02 4.99Lead AP-42 1.71E-03 4.10E-02 14.98Mercury AP-42 5.70E-04 1.37E-02 4.99Manganese AP-42 1.14E-03 2.74E-02 9.99Nickel AP-42 5.70E-04 1.37E-02 4.99Selenium AP-42 2.85E-03 6.84E-02 24.97

1 Emission factor based on the proposed BACT emission rates for distillate oil-fired boilers.



lb/hr






EMISSION SOURCE DESCRIPTION: Auxiliary Boiler

Distillate fuel oil-fired 190mmBTU/hr auxiliary steam boiler will meet the steam demand during start up of the main steam generator. Auxiliary Boiler will operate at a capacity factor of 10% or less.

OPERATING SCENARIO _______1__________OF ________1__________




Attachments: (1) emissions calculations and supporting documentation; (2) indicate all requested state and federal enforceable permit limits (e.g. hours of operation, emission rates) and describe how these are monitored and with what frequency; and (3) describe any monitoring devices, gauges, or test ports for this source.

lb/day

LEAD



POTENTIAL EMSSIONS(BEFORE CONTROLS / LIMITS)

EXPECTED ACTUAL

INDICATE EXPECTED ACTUAL EMISSIONS AFTER CONTROLS / LIMITATIONSlb/yr

REVISED 12/01/01 B1EMISSION SOURCE DESCRIPTION: EMISSION SOURCE ID NO: Aux 6

CONTROL DEVICE ID NO(S):

OPERATING SCENARIO: ______1________ OF ________1______ EMISSION POINT (STACK) ID NO(S): Aux 6

DESCRIBE USE: PROCESS HEAT SPACE HEAT ELECTRICAL GENERATION

CONTINUOUS US STAND BY/EMERGENCY X OTHER (DESCRIBE): _Process Steam__

HEATING MECHANISM: X INDIRECT DIRECT

MAX. FIRING RATE (MMBTU/HOUR): 190

BARK WOOD/BARK WET WOOD DRY WOOD OTHER (DESCRIBE): __________

PERCENT MOISTURE OF FUEL:_________________

UNCONTROLLED CONTROLLED WITH FLYASH REINJECTION CONTROLLED W/O REINJECTION

FUEL FEED METHOD: HEAT TRANSFER MEDIA: STEAM AIR OTHER


TYPE OF BOILER IF OTHER DESCRIBE:

PULVERIZED

WET BED UNCONTROLLED UNCONTROLLED UNCONTROLLED CIRCULATING

DRY BED CONTROLLED CONTROLLED FLYASH REINJECTION RECIRCULATING

NO FLYASH REINJECTION

METHOD OF LOADING: CYCLONE HANDFIRED TRAVELING GRATE OTHER (DESCRIBE): _________________


TYPE OF BOILER: UTILITY X INDUSTRIAL COMMERCIAL RESIDENTIAL

TYPE OF FIRING: NORMAL TANGENTIAL X LOW NOX BURNERS NO LOW NOX BURNER

METHOD OF TUBE CLEANING NA CLEANING SCHEDULE: NA

TYPE OF FUEL: ____________________________ PERCENT MOISTURE: _____________ TYPE OF BOILER: UTILITY INDUSTRIAL COMMERCIAL RESIDENTIAL

TYPE OF FIRING: _______________ TYPE OF CONTROL (IF ANY): ___________________________ FUEL FEED METHOD: ________


No. 2 Fuel Oil mmBTU 190 NA

No. 2 Fuel Oil (Start-up) 137000 BTU/gal 0.05 NA

COMMENTS:

FUEL USAGE (INCLUDE STARTUP/BACKUP FUELS)

SPREADER STOKER FLUIDIZED BEDOVERFEED STOKER UNDERFEED STOKER

OTHER FUEL-FIRED BURNER

COAL-FIRED BURNER

OIL/GAS-FIRED BURNER

WOOD TYPE:

FORM B1EMISSION SOURCE (WOOD, COAL, OIL, GAS, OTHER FUEL-FIRED BURNER)


WOOD-FIRED BURNER

Distillate fuel oil-fired 190mmBTU/hr auxiliary steam boiler will meet the steam demand during start up of the main steam generator.

LIMITATION (UNIT/HR)

FUEL CHARACTERISTICS (COMPLETE ALL THAT ARE APPLICABLE)

MAXIMUM DESIGN

CAPACITY (UNIT/HR)

REQUESTED CAPACITY

FUEL TYPE UNITS

SAMPLING PORTS, COMPLIANT WITH EPA METHOD 1 WILL BE INSTALLED ON THE STACKS: YES NO


ASH CONTENT

(% BY WEIGHT)

SULFUR CONTENT

FUEL TYPE

SPECIFIC

BTU CONTENT (% BY WEIGHT)

Emissions will be controlled by the following: only burning low sulfur (0.05 percent sulfur) distillate oil using low-NOx burners, good combustion, and limiting operation to 2500 hours/year. Propane used for initial light-off.

REVISED 12/01/01 BEMISSION SOURCE ID NO: CT1CONTROL DEVICE ID NO(S):EMISSION POINT (STACK) ID NO(S): CT1


Coal,wood,oil, gas, other burner (Form B1) Woodworking (Form B4) Manufact. of chemicals/coatings/inks (Form B7)

Int.combustion engine/generator (Form B2) Coating/finishing/printing (Form B5) Incineration (Form B8) Liquid storage tanks (Form B3) Storage silos/bins (Form B6) X Other (Form B9)

START CONSTRUCTION DATE June 2007 OPERATION DATE: 2011 DATE MANUFACTURED: 2007MANUFACTURER / MODEL NO.: TBDIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?): NESHAP (SUBPART?):________ MACT (SUBPART?):_


SOURCE OFEMISSION

AIR POLLUTANT EMITTED FACTOR lb/hr tons/yr lb/hr tons/yr lb/hr tons/yrPARTICULATE MATTER (PM) AP-42 2.95 12.94 2.95 12.94PARTICULATE MATTER<10 MICRONS (PM10) AP-42 2.95 12.94 2.95 12.94PARTICULATE MATTER<2.5 MICRONS (PM2.5)

SULFUR DIOXIDE (SO2)NITROGEN OXIDES (NOx)CARBON MONOXIDE (CO)VOLATILE ORGANIC COMPOUNDS (VOC)

OTHER

SOURCE OFEMISSION

HAZARDOUS AIR POLLUTANT AND CAS NO. FACTOR lb/hr tons/yr lb/hr tons/yr lb/hr tons/yr

TOXIC AIR POLLUTANT AND CAS NO. EF SOURCE

COMPLETE THIS FORM AND COMPLETE AND ATTACH APPROPRIATE B1 THROUGH B9 FORM FOR EACH SOURC

LEAD

EXPECTED ACTUAL



lb/day









EMISSION SOURCE DESCRIPTION: One Multi-Cell Cooling Tower

One multi-cell (up to 22 cells) mechanical draft cooling tower will be installed as part of a wet cooling system for proposed Unit 6.

OPERATING SCENARIO ______1___________OF _________1_________







lb/hr

REVISED: 12/01/01 B9EMISSION SOURCE DESCRIPTOne Multi-Cell Cooling Tower EMISSION SOURCE ID NO: CT1


EMISSION POINT (STACK) ID NO(S): CT1

DESCRIBE IN DETAIL THE PROCESS (ATTACH FLOW DIAGRAM):

One multi-cell (up to 22 cells) mechanical draft cooling tower will be installed as part of a wet cooling system for proposed Unit 6.

UNITS

Cooling Tower Water Gallons 393,414 NA

UNITS

MAXIMUM DESIGN (BATCHES / HOUR):

REQUESTED LIMITATION (BATCHES / HOUR): (BATCHES/YR):

FUEL USED: NA TOTAL MAXIMUM FIRING RATE (MILLION BTU/HR): NA

MAX. CAPACITY HOURLY FUEL USE: NA REQUESTED CAPACITY ANNUAL FUEL USE: NACOMMENTS:

FORM B9EMISSION SOURCE (OTHER)


LIMITATION(UNIT/HR)

MAX. DESIGN

TYPE CAPACITY (UNIT/HR)

OPERATING SCENARIO: ____1__________ OF _____1_________

MATERIALS ENTERING PROCESS - CONTINUOUS PROCESS

Attach Additional Sheets as Necessary

TYPE CAPACITY (UNIT/BATCH) LIMITATION (UNIT/BATCH)

MATERIALS ENTERING PROCESS - BATCH OPERATION

REQUESTED CAPACITY

The cooling towers will be equipped with specially designed drift eliminators that will act to remove droplets from the cooling tower plume, which will conserve water and reduce drift and resultant particulate emissions.

MAX. DESIGN REQUESTED CAPACITY

REVISED 12/01/0 BEMISSION SOURCE ID NO: C19CONTROL DEVICE ID NO(S):EMISSION POINT (STACK) ID NO(S): Fugitive


Coal,wood,oil, gas, other burner (Form B1 Woodworking (Form B4) Manufact. of chemicals/coatings/inks (Form B7)

Int.combustion engine/generator (Form B2 Coating/finishing/printing (Form Incineration (Form B8) Liquid storage tanks (Form B3) Storage silos/bins (Form B6) X Other (Form B9)

START CONSTRUCTION DATE: June 2007 OPERATION DATE: 2011 DATE MANUFACTURE 2007MANUFACTURER / MODEL NO. NAIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?):___Y____ NESHAP (SUBPART?):________ MACT (SUBPART?):_________

EXPECTED ANNUAL HOURS OF OPERATIO< 8760

SOURCE OFEMISSION

AIR POLLUTANT EMITTED FACTOR lb/hr tons/yr lb/hr tons/yr lb/hr tons/yrPARTICULATE MATTER (PM) AP-42 0.65 8.59 0.65 8.59PARTICULATE MATTER<10 MICRONS (PM10) AP-42 0.32 4.18 0.32 4.18PARTICULATE MATTER<2.5 MICRONS (PM2.5)SULFUR DIOXIDE (SO2)NITROGEN OXIDES (NOx)CARBON MONOXIDE (CO)VOLATILE ORGANIC COMPOUNDS (VOC)

OTHER

SOURCE OFEMISSION

HAZARDOUS AIR POLLUTANT AND CAS NO FACTOR lb/hr tons/yr lb/hr tons/yr lb/hr tons/yr


PLETE THIS FORM AND COMPLETE AND ATTACH APPROPRIATE B1 THROUGH B9 FORM FOR EACH SO

LEAD

EXPECTED ACTUAL


Attachments: (1) emissions calculations and supporting documentation; (2) indicate all requested state and federal enforceable permit limits (e.g. hours ofoperation, emission rates) and describe how these are monitored and with what frequency; and (3) describe any monitoring devices, gauges, or test ports for this source

lb/day


BEFORE CONTROLS / LIMITS


EXPECTED OP. SCHEDULE: __24__ HR/DAY __7_ DAY/WK ___52

VISIBLE STACK EMISSIONS UNDER NORMAL OPERATION: ___<20__ % OPAPERCENTAGE ANNUAL THROUGHPUT (%): DEC-FEB 25 MAR-MAY 25 JUN-AUG 25 SEP-NOV 25




EMISSION SOURCE DESCRIPTION: Fugitive Coal Handling - Unit 6 Reclaim Hopper Emission

Fugitive emissions include bulldozing coal to hoppers. (Emissions were already provided in Unit 5 Application for Bulldozing and Unit 5 Reclaim Hopper C11 and C12). Assumptions for coal bulldozing are as follows : 3 Bulldozers operating 24 hrs/day each and 365 days/yr. Dust suppression agents will be used to control fugitive emissions.

OPERATING SCENARIO __________1_______OF __________1________



POTENTIAL EMSSIONSBEFORE CONTROLS / LIMITS




lb/hr

REVISED: 12/01/01 B9EMISSION SOURCE ID NO: C19


EMISSION POINT (STACK) ID NO(S):


UNITS

tons

UNITS








OPERATING SCENARIO: _______1_______ OF ________1______



REQUESTED CAPACITY

Fugitive

Coal (Reclaim Hoppers) 400



LIMITATION(UNIT/HR)

MAX. DESIGN


Fugitive coal handling emissions include material handling from bulldozing. (Emissions were already provided in Unit 5 Application for Bulldozing and Unit 5 Reclaim Hopper). Assumptions for coal bulldozing are as follows : 3 Bulldozers operating 24 hrs/day each and 365 days/yr. Dust suppression agents will be used to control fugitive emissions.

EMISSION SOURCE DESCRIPTION: Fugitive Coal Handling - Reclaim Hopper Emissions

REVISED 12/01/01 BEMISSION SOURCE ID NO: C27-C30CONTROL DEVICE ID NO(S): C28EMISSION POINT (STACK) ID NO(S): EP-C27-C30




START CONSTRUCTION DATE June 2007 OPERATION DATE: 2011 DATE MANUFACTURED: 2007MANUFACTURER / MODEL NO.: NAIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?): Y NESHAP (SUBPART?):________ MACT (SUBPART?):_


SOURCE OFEMISSION

AIR POLLUTANT EMITTED FACTOR lb/hr tons/yr lb/hr tons/yr lb/hr tons/yrPARTICULATE MATTER (PM) 1 3.43 15.02 3.43 15.02PARTICULATE MATTER<10 MICRONS (PM10)

1 3.43 15.02 3.43 15.02PARTICULATE MATTER<2.5 MICRONS (PM2.5)


OTHER

SOURCE OFEMISSION



1 Emissions are based on control device outlet concentration design and exhaust fan parameters.

LEAD

EXPECTED ACTUAL



lb/day




EMISSION SOURCE DESCRIPTION: Unit 6 Boiler House Coal Handling: Reclaim Conveyors (2) & Tripper Conveyors (2)

Emissions represent the following coal reclaim conveyors controlled by partially enclosed hood/filter and tripper conveyors that are controlled by enclosed room/filter:C27: Reclaim Conveyor RC11 to Unit 6 Boiler Building (1600 ft)C28: Reclaim Conveyor RC12 to Unit 6 Boiler Building (1600 ft)Belt Widths are 36 inches. C29: Unit 6 Tripper Conveyor TR2 (200 ft)C30: Unit 6 Tripper Conveyor TR3 (200 ft)Belt Widths are 42 inches.




VISIBLE STACK EMISSIONS UNDER NORMAL OPERATION: _< 20___ % OPACITYPERCENTAGE ANNUAL THROUGHPUT (%): DEC-FEB 25 MAR-MAY 25 JUN-AUG 25 SEP-NOV 25






POTENTIAL EMSSIONS(BEFORE CONTROLS / LIMITS) (AFTER CONTROLS / LIMITS)

lb/hr

REVISED: 12/01/01 B9EMISSION SOURCE DESCRIPTION: EMISSION SOURCE ID NO: C27-C30

Unit 6 Boiler House Coal Handling: Reclaim Conveyors (2) & Tripper Conveyors (2) CONTROL DEVICE ID NO(S): C28

EMISSION POINT (STACK) ID NO(S): EP-C27-C30


UNITS

Coal tons 750 NA

UNITS






OPERATING SCENARIO: _______1_______ OF ______1________





REQUESTED CAPACITY



LIMITATION(UNIT/HR)

MAX. DESIGN


Emissions represent the following coal reclaim conveyors controlled by partially enclosed hood/filter and tripper conveyors that are controlled by enclosed room/filter:C27: Reclaim Conveyor RC11 to Unit 6 Boiler Building (1600 ft)C28: Reclaim Conveyor RC12 to Unit 6 Boiler Building (1600 ft)Belt Widths are 36 inches. C29: Unit 6 Tripper Conveyor TR2 (200 ft)C30: Unit 6 Tripper Conveyor TR3 (200 ft)Belt Widths are 42 inches.

REVISED 12/01/01 BEMISSION SOURCE ID NO: A3, A6, A8 & A9CONTROL DEVICE ID NO(S): C30EMISSION POINT (STACK) ID NO(S): EPA3, A6, A8 & A9



Int.combustion engine/generator (Form B2) Coating/finishing/printing (Form B5) Incineration (Form B8) Liquid storage tanks (Form B3) X Storage silos/bins (Form B6) Other (Form B9)

START CONSTRUCTION DATE June 2007 OPERATION DATE: 2011 DATE MANUFACTURED: 2007MANUFACTURER / MODEL NO.: NAIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?): NESHAP (SUBPART?):________ MACT (SUBPART?):_


SOURCE OFEMISSION




OTHER

SOURCE OFEMISSION


TOXIC AIR POLLUTANT AND CAS NO. EF SOURCE lb/hr






VISIBLE STACK EMISSIONS UNDER NORMAL OPERATION: _20___ % OPACITYPERCENTAGE ANNUAL THROUGHPUT (%): DEC-FEB 25 MAR-MAY 25 JUN-AUG 25 SEP-NOV 25







EMISSION SOURCE DESCRIPTION: Unit 6 Fly Ash Handling (Controlled)

Sources include the following:A3: Dry Fly Ash Pickup at Boiler Economizer - Fly ash pneumatically conveyed to silo A6: Fly Ash Silo (3 days total storage)A8: Dry Fly Ash Pickup at Boiler Economizer - Fly ash pneumatically conveyed to silo A9: Dry Fly Ash Pickup at Fabric Filter - Fly ash pneumatically conveyed to silo


1 Emissions are based on filter design, material charge rate and density of material charged.

LEAD

EXPECTED ACTUAL



lb/day

REVISED 12/01/01 B6EMISSION SOURCE DESCRIPTION: EMISSION SOURCE ID NO: A3, A6, A8, A9

Unit 6 Fly Ash Handling (Controlled) CONTROL DEVICE ID NO(S): C30

OPERATING SCENARIO: ________1______ OF ______1_________ EMISSION POINT(STACK) ID NO(S): EPA3, A6, A8 & A9


MATERIAL STORED: Fly Ash DENSITY OF MATERIAL (LB/FT3): 80

CUBIC FEET: TONS:

HEIGHT: 100 DIAMETER: 30 (OR) LENGTH: WIDTH: HEIGHT:

ACTUAL: ~284,000/each MAXIMUM DESIGN CAPACITY:

BLOWER SCREW CONVEYOR RAILCAR

COMPRESSOR BELT CONVEYOR TRUCK

OTHER: BUCKET ELEVATOR STORAGE PILE

OTHER: OTHER:

NO. FILL TUBES:

MAXIMUM ACFM:

MATERIAL IS FILLED TO:

BY WHAT METHOD IS MATERIAL UNLOADED FROM SILO?

Material is mixed with water and dropped into an open bed truck. The truck is then tarpped for transport.

Material can also be withdrawn through a dustless unloader into an enclosed pneumatic tank truck for shipment.

MAXIMUM DESIGN FILLING RATE OF MATERIAL (TONS/HR): 20

MAXIMUM DESIGN UNLOADING RATE OF MATERIAL (TONS/HR): 200

COMMENTS:

MOTOR HP:


FORM B6EMISSION SOURCE (STORAGE SILO/BINS)


FILLED FROMPNEUMATICALLY FILLED MECHANICALLY FILLEDANNUAL PRODUCT THROUGHPUT (TONS)

CAPACITY

DIMENSIONS (FEET)

Sources include the following:A3: Dry Fly Ash Pickup at Boiler Economizer - Fly ash pneumatically conveyed to silo A6: Fly Ash Silo (3 days total storage)A8: Dry Fly Ash Pickup at Boiler Economizer - Fly ash pneumatically conveyed to silo A9: Dry Fly Ash Pickup at Fabric Filter - Fly ash pneumatically conveyed to silo

REVISED 12/01/01 C1CONTROL DEVICE ID NO: C30 CONTROLS EMISSIONS FROM WHICH EMISSION SOURCE ID NO(S): A6

EMISSION POINT (STACK) ID NO(S): EPA6 POSITION IN SERIES OF CONTROLS NO. 1 OF 1 UNITS


DATE MANUFACTURED: TBD PROPOSED OPERATION DATE: 2011


___1____ OF ___1____

Bin Vent fabric filter to control emissions from the Unit #6 fly ash silo

POLLUTANT(S) COLLECTED: Particulates

BEFORE CONTROL EMISSION RATE (LB/HR): 1.3



CORRESPONDING OVERALL EFFICIENCY: 99.9 % % % %


TOTAL EMISSION RATE (LB/HR): 0.0013


BULK PARTICLE DENSITY (LB/FT3): 50 - 60 INLET TEMPERATURE (oF): MIN MAX ambient

POLLUTANT LOADING RATE: 10 LB/HR GR/FT3 OUTLET TEMPERATURE (oF): MIN MAX ambientINLET AIR FLOW RATE (ACFM): N/A FILTER MAX OPERATING TEMP. (oF): 275

NO. OF COMPARTMENTS: 1 NO. OF BAGS PER COMPARTMENT: 124 LENGTH OF BAG (IN.): 144

DIAMETER OF BAG (IN.): 3"x6" oval DRAFT: INDUCED/NEG. FORCED/POS. FILTER SURFACE AREA (FT2): 1911

AIR TO CLOTH RATIO: 5.2 : 1 FILTER MATERIAL: 16 oz polyester felt WOVEN FELTED

DESCRIBE CLEANING PROCEDURES: Either Air Pulse or Reverse Flow AIR PULSE SONIC


MECHANICAL/SHAKER RING BAG COLLAPSE - OTHER 20

DESCRIBE INCOMING AIR STREAM: 25Pnumatic transfer to cyclone seperator that drops the ash out of the air stream 25and into the silo. Air is displaced from the silo throught the filter as it fills with ash. 30Air is drawn into the silo through the filter as ash is removed from the silo. -

METHOD FOR DETERMINING WHEN TO CLEAN: Ether Automatic or Timed

AUTOMATIC TIMED MANUAL

METHOD FOR DETERMINING WHEN TO REPLACE THE BAGS:

ALARM INTERNAL INSPECTION VISIBLE EMISSION OTHER

SPECIAL CONDITIONS: MOISTURE BLINDING CHEMICAL RESISTIVITY OTHER

EXPLAIN: N/A

>100

TOTAL = 100

1-10

10-25

25-50


CUMULATIVE

(MICRONS)

50-100

OF TOTAL %WEIGHT %

0-1

ON A SEPARATE PAGE, ATTACH A DIAGRAM SHOWING THE RELATIONSHIP OF THE CONTROL DEVICE TO ITS EMISSION SOURCE(S):



OPERATING SCENARIO:

SIZE

P.E. SEAL REQUIRED (PER 2Q .0112)? YES NO


DESCRIBE MAINTENANCE PROCEDURES: Check Filter Bag, Bag Cage and Housing Condition. Replace worn or teared bags. Replace and repair defective components.


REVISED 12/01/01 BEMISSION SOURCE ID NO: A1, A12CONTROL DEVICE ID NO(S):EMISSION POINT (STACK) ID NO(S): Fugitive




START CONSTRUCTION DATE June 2007 OPERATION DATE: 2011 DATE MANUFACTURED: TBDMANUFACTURER / MODEL NO.: NAIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?): NESHAP (SUBPART?):________ MACT (SUBPART?):_


SOURCE OFEMISSION



OTHER

SOURCE OFEMISSION



LEAD

EXPECTED ACTUAL



lb/day




EMISSION SOURCE DESCRIPTION: Fugitive Fly Ash Sources

Sources include the following:A1: Wet Botton Ash Transfer and Pickup - Botton ash has consistency of wet sand - no emissions expected.A12: Flyash Dishcarge to Truck











lb/hr

REVISED: 12/01/01 B9EMISSION SOURCE DESCRIPTION: EMISSION SOURCE ID NO: A1, A12

Fugitive Fly Ash Sources CONTROL DEVICE ID NO(S):

EMISSION POINT (STACK) ID NO(S): Fugitive

DESCRIBE IN DETAIL THE PROCESS (ATTACH FLOW DIAGRAM):Sources include the following:A1: Wet Botton Ash Transfer and Pickup - Botton ash has consistency of wet sand - no emissions expected.A12: Fly Ash Discharge to Truck

UNITS

Fly Ash tons 200 NA

UNITS











REQUESTED CAPACITY



LIMITATION(UNIT/HR)

MAX. DESIGN


REVISED 12/01/01 BEMISSION SOURCE ID NO: VF1-VF8CONTROL DEVICE ID NO(S):EMISSION POINT (STACK) ID NO(S): NA




START CONSTRUCTION DATE June 2007 OPERATION DATE: 2011 DATE MANUFACTURED: 2007MANUFACTURER / MODEL NO.: NAIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?): Y NESHAP (SUBPART?):________ MACT (SUBPART?):_


SOURCE OFEMISSION

AIR POLLUTANT EMITTED FACTOR lb/hr tons/yr lb/hr tons/yr lb/hr tons/yrPARTICULATE MATTER (PM) NA NA NA NAPARTICULATE MATTER<10 MICRONS (PM10) NA NA NA NAPARTICULATE MATTER<2.5 MICRONS (PM2.5)


OTHER

SOURCE OFEMISSION



LEAD

EXPECTED ACTUAL



lb/day




EMISSION SOURCE DESCRIPTION: Coal Reclaim Feeders for Coal Stacking Tubes

No emissions are expected from the reclaim feeders as they are enclosed devices that discharge to a belt that is enclosed underground in a tunnel. The following feeders service the following stacking tubes:VF1-VF8: Reclaim Feeder for Stacking Tube 1 (ST1)











lb/hr

REVISED: 12/01/01 B9EMISSION SOURCE DESCRIPTION: EMISSION SOURCE ID NO: VF1-VF8

Coal Reclaim Feeders for Coal Stacking Tubes CONTROL DEVICE ID NO(S):

EMISSION POINT (STACK) ID NO(S): NA


UNITS

Coal tons NA

UNITS











REQUESTED CAPACITY

400



LIMITATION(UNIT/HR)

MAX. DESIGN


No emissions are expected from the reclaim feeders as they are enclosed devices that discharge to a belt that is enclosed underground in a tunnel. The following feeders service the following stacking tubes:VF1-VF8: Reclaim Feeder for Stacking Tube 1 (ST1)

REVISED 12/01/01 BEMISSION SOURCE ID NO: LSSDACONTROL DEVICE ID NO(S): CD32-3EMISSION POINT (STACK) ID NO(S): LSSDA



Int.combustion engine/generator (Form B2) Coating/finishing/printing (Form B5) Incineration (Form B8) Liquid storage tanks (Form B3) X Storage silos/bins (Form B6) Other (Form B9)

START CONSTRUCTION DATE June 2007 OPERATION DATE: 2011 DATE MANUFACTURED: 2007MANUFACTURER / MODEL NO NAIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?):_OOO______ NESHAP (SUBPART?):________ MACT (SUBPART?):__________


SOURCE OFEMISSION




OTHER

SOURCE OFEMISSION



OMPLETE THIS FORM AND COMPLETE AND ATTACH APPROPRIATE B1 THROUGH B9 FORM FOR EACH SOURC

LEAD

EXPECTED ACTUAL



lb/day




EXPECTED OP. SCHEDULE: __24__ HR/DAY __7_ DAY/WK ___52__ WK/Y

VISIBLE STACK EMISSIONS UNDER NORMAL OPERATION: ___<7__ % OPACITYPERCENTAGE ANNUAL THROUGHPUT (%): DEC-FEB 25 MAR-MAY 25 JUN-AUG 25 SEP-NOV 25




EMISSION SOURCE DESCRIPTION: Fugitive Lime Handling - Lime Silo for SDA

Emissions from one lime silo equiped with a bin vent filter.





1 Emissions are based on material charge rate and density of material charged.Attach Additional Sheets As Necessary



lb/hr

REVISED 12/01/01 B6EMISSION SOURCE ID NO: LSSDA

CONTROL DEVICE ID NO(S): CD32-3

OPERATING SCENARIO: _______1_______ OF ______1_________ EMISSION POINT(STACK) ID NO(S): LSSDA


MATERIAL STORED: Lime DENSITY OF MATERIAL (LB/FT3): 85

CUBIC FEET: 24450 TONS: 672

HEIGHT: 65 DIAMETER: 22 (OR) LENGTH: WIDTH: HEIGHT:

ACTUAL: 213,398 MAXIMUM DESIGN CAPACIT 4 tons/hr

BLOWER SCREW CONVEYOR RAILCAR

COMPRESSOR X BELT CONVEYOR X TRUCK

X OTHER: BUCKET ELEVATOR STORAGE PILE

Blower is onboard delivery truck OTHER: OTHER:

NO. FILL TUBES: One 4" diameter

MAXIMUM ACFM: ~ 850

MATERIAL IS FILLED TO: Limestone SDA System

BY WHAT METHOD IS MATERIAL UNLOADED FROM SILO?

Gravity, with live bottom bin activator assist, to volumetric rotary feeder. Feed is to slaker.

MAXIMUM DESIGN FILLING RATE OF MATERIAL (TONS/HR): from truck is approxiamtely 24 tons / hr

MAXIMUM DESIGN UNLOADING RATE OF MATERIAL (TONSsingle volumetric feeder operating - 4 tons / hr

COMMENTS:

Normal operation is expected @ 2 tph, maximum design capacity is 4 tph for worst case fuel firing.

Redundant / spare equipment is not expected (required) to operate simultaneously.

DIMENSIONS (FEET)

MOTOR HP:

FORM B6EMISSION SOURCE (STORAGE SILO/BINS)


FILLED FROMPNEUMATICALLY FILLED MECHANICALLY FILLEDANNUAL PRODUCT THROUGHPUT (TONS)

EMISSION SOURCE DESCRIPTION: Fugitive Lime Handling - Lime Silo for SDA

CAPACITY

Hydrated lime is delivered by truck and filled to storage silo. Vent filter is for displacement during the fill process.

REVISED 12/01/01 C1CONTROL DEVICE ID NO: CD32-3 CONTROLS EMISSIONS FROM WHICH EMISSION SOURCE ID NO(S): LSSDA

EMISSION POINT (STACK) ID NO(S): LSSDA POSITION IN SERIES OF CONTROLS NO. 1 OF 1 UNITS


DATE MANUFACTURED 2007 PROPOSED OPERATION DATE: 2011


___1___ OF ____1___

One bin vent fabric filter to control emissions from the lime silo.

POLLUTANT(S) COLLECTED: Particulates

BEFORE CONTROL EMISSION RATE (LB/HR): 0.1



CORRESPONDING OVERALL EFFICIENCY: 99.9 % % % %


TOTAL EMISSION RATE (LB/HR): 0.01


BULK PARTICLE DENSITY (LB/FT3): 50 - 60 INLET TEMPERATURE (oF): MIN MAX ambient

POLLUTANT LOADING RATE: 10 LB/HR GR/FT3 OUTLET TEMPERATURE (oF): MIN MAX ambientINLET AIR FLOW RATE (ACFM): 10,000 FILTER MAX OPERATING TEMP. (oF): 275

NO. OF COMPARTMENTS: 1 NO. OF BAGS PER COMPARTMENT: 124 LENGTH OF BAG (IN.): 144

DIAMETER OF BAG (IN.): 3"x6" oval DRAFT: INDUCED/NEG. FORCED/POS. FILTER SURFACE AREA (FT2): 1911

AIR TO CLOTH RATIO: 5.2 : 1 FILTER MATERIAL: 16 oz polyester felt WOVEN FELTED

DESCRIBE CLEANING PROCEDURES:

AIR PULSE OR SONIC


MECHANICAL/SHAKER RING BAG COLLAPSE - OTHER 20

DESCRIBE INCOMING AIR STREAM: 25

Remove particles from LS Prep Bldg prior to exhausting building air to atmosphere. 25

30

-

METHOD FOR DETERMINING WHEN TO CLEAN: Ether Automatic or Timed

AUTOMATIC OR TIMED MANUAL

METHOD FOR DETERMINING WHEN TO REPLACE THE BAGS:

ALARM INTERNAL INSPECTION VISIBLE EMISSION OTHER

SPECIAL CONDITIONS:

MOISTURE BLINDING CHEMICAL RESISTIVITY OTHER

EXPLAIN: N/A

>100

TOTAL = 100

1-10

10-25

25-50


CUMULATIVE

(MICRONS)

50-100

OF TOTAL %WEIGHT %

0-1

ON A SEPARATE PAGE, ATTACH A DIAGRAM SHOWING THE RELATIONSHIP OF THE CONTROL DEVICE TO ITS EMISSION SOURCE(S):



OPERATING SCENARIO:

SIZE

P.E. SEAL REQUIRED (PER 2Q .0112)? YES NO


DESCRIBE MAINTENANCE PROCEDURES: Check Filter Bag, Bag Cage and Housing Condition. Replace worn or teared bags. Replace and repair defective components.


REVISED 12/01/01 BEMISSION SOURCE ID NO: FvehicleCONTROL DEVICE ID NO(S): NAEMISSION POINT (STACK) ID NO(S): Fugitive

DESCRIBE IN DETAILTHE EMISSION SOURCE PROCESS (ATTACH FLOW DIAGRAM):All roads are currently assumed to be paved. Facility is assumed to have a road washing/cleaning program.Coal and limestone are provided via rail. Fugitive dust emissions from these deliveries are assumed insignificant.Delivery vehicles include those of fuel oil, acid/caustic, and ammonia.



START CONSTRUCTION DATE NA OPERATION DATE: NA DATE MANUFACTURED: NAMANUFACTURER / MODEL NO.: NAIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?): NESHAP (SUBPART?):________ MACT (SUBPART?):______

EXPECTED ANNUAL HOURS OF OPERATION 8760

SOURCE OFEMISSION



OTHER

SOURCE OFEMISSION


TOXIC AIR POLLUTANT AND CAS NO. EF SOURCE lb/hr













EMISSION SOURCE DESCRIPTION: Fugitive Vehicle Emissions


LEAD

EXPECTED ACTUAL



lb/day

REVISED: 12/01/01 B9EMISSION SOURCE DESCRIPTION: EMISSION SOURCE ID NO: Fvehicle

Fugitive Vehicle Emissions CONTROL DEVICE ID NO(S): NA


DESCRIBE IN DETAIL THE PROCESS (ATTACH FLOW DIAGRAM):All roads are currently assumed to be paved. Facility is assumed to have a road washing/cleaning program.Coal and limestone are provided via rail. Fugitive dust emissions from these deliveries are assumed insignificant.Delivery vehicles include those of fuel oil, acid/caustic, and ammonia.

UNITS

UNITS



FUEL USED: TOTAL MAXIMUM FIRING RATE (MILLION BTU/HR):

MAX. CAPACITY HOURLY FUEL USE: REQUESTED CAPACITY ANNUAL FUEL USE:COMMENTS:



LIMITATION(UNIT/HR)

MAX. DESIGN








REQUESTED CAPACITY




Int.combustion engine/generator (Form B2) Coating/finishing/printing (Form Incineration (Form B8) Liquid storage tanks (Form B3) Storage silos/bins (Form B6) X Other (Form B9)

START CONSTRUCTION DATE: NA OPERATION DATE: NA DATE MANUFACTURE NAMANUFACTURER / MODEL NO.: NAIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?):___Y____ NESHAP (SUBPART?):________ MACT (SUBPART?):__________

EXPECTED ANNUAL HOURS OF OPERATION< 8760

SOURCE OFEMISSION


OTHER

SOURCE OFEMISSION






lb/hr









EMISSION SOURCE DESCRIPTION: Existing Fugitive Coal Handling - Unloading Emissions

Fugitive emissions from existing rail car unloading. Existing rotary dump unloader will be replaced with a bottom dump unloader using the existing building and uloading hopper.





MPLETE THIS FORM AND COMPLETE AND ATTACH APPROPRIATE B1 THROUGH B9 FORM FOR EACH SOU

LEAD

EXPECTED ACTUAL



lb/day

REVISED: 12/01/01 B9EMISSION SOURCE DESCRIPTI Fugitive Coal Handling - Unloading EmissionsEMISSION SOURCE ID NO: C1




UNITS

tons

UNITS



FUEL USED: NA TOTAL MAXIMUM FIRING RATE (MILLION BTU/HR)NA




LIMITATION(UNIT/HR)

MAX. DESIGN


Fugitive emissions from existing rail car unloading. Existing rotary dump unloader will be replaced with a bottom dump unloader using the existing building and uloading hopper.





REQUESTED CAPACITY

Coal 3000



REVISED 12/01/0 BEMISSION SOURCE ID NO: C2, C3, C4, C5, C7CONTROL DEVICE ID NO(S):EMISSION POINT (STACK) ID NOFugitive




START CONSTRUCTION DATE: June 2007 OPERATION DATE: 2011 DATE MANUFACTURE 2007MANUFACTURER / MODEL NO.: NAIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?):___Y____ NESHAP (SUBPART?):________ MACT (SUBPART?):__________


SOURCE OFEMISSION


OTHER

SOURCE OFEMISSION




LEAD

EXPECTED ACTUAL



lb/day









EMISSION SOURCE DESCRIPTION: Fugitive Coal Handling - Conveyor and Telescoping Chute Emissions

Fugitive emissions from coal handling conveyors and stacking tube. The length of each of the conveyor is as follows: C2 : Stockout conveyor - 250 ft C3: Stockout conveyor - 400 ftC4: Stockout conveyor - 420 ft C5: Telescoping ChuteC7: Telescoping Chute








lb/hr

REVISED: 12/01/01 B9EMISSION SOURCE DESCRIPTI Fugitive Coal Handling - Conveyor and TelescEMISSION SOURCE ID NO: C2, C3, C4, C5, C




UNITS

tons

UNITS











REQUESTED CAPACITY

Fugitive

Coal 3000



LIMITATION(UNIT/HR)

MAX. DESIGN


Fugitive emissions from coal handling conveyors and stacking tube. The length of each of the conveyor is as follows: C2 : Stockout conveyor - 250 ft C3: Stockout conveyor - 400 ftC4: Stockout conveyor - 420 ft C5: Telescoping ChuteC7: Telescoping Chute

REVISED 12/01/01 BEMISSION SOURCE ID NO: C9, C10CONTROL DEVICE ID NO(S):EMISSION POINT (STACK) ID NO(S): Fugitive




START CONSTRUCTION DATE: January 2007 OPERATION DATE: April 2010 DATE MANUFACTURED: 2007MANUFACTURER / MODEL NO.: NAIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?):___Y____ NESHAP (SUBPART?):________ MACT (SUBPART?):__________

EXPECTED ANNUAL HOURS OF OPERATION< 8760

SOURCE OFEMISSION



OTHER

SOURCE OFEMISSION






lb/hr









EMISSION SOURCE DESCRIPTION: Fugitive Coal Handling - Storage Pile Emissions

Fugitive emissions from coal storage piles. Unit 5 and Unit 6 45 day active coal storage piles. Storage pile size is estimated to be 25 acres. Dust suppression agents will be used to reduce fugitive emissions.





COMPLETE THIS FORM AND COMPLETE AND ATTACH APPROPRIATE B1 THROUGH B9 FORM FOR EACH SOURCE

LEAD

EXPECTED ACTUAL



lb/day

REVISED: 12/01/01 B9EMISSION SOURCE DESCRIPTI Fugitive Coal Handling - Storage Pile EmissionsEMISSION SOURCE ID NO: C9, C10




UNITS

UNITS







LIMITATION(UNIT/HR)

MAX. DESIGN






REQUESTED CAPACITY

Fugitive

Fugitive emissions from coal storage piles. Unit 5 and Unit 6 45 day active coal storage piles. Storage pile size is estimated to be 25 acres. Dust suppression agents will be used to reduce fugitive emissions.

Coal NA



REVISED 12/01/0 BEMISSION SOURCE ID NO: C15CONTROL DEVICE ID NO(S):EMISSION POINT (STACK) ID NO(S): EP-C15



Int.combustion engine/generator (Form B2) Coating/finishing/printing (Form Incineration (Form B8) Liquid storage tanks (Form B3) Storage silos/bins (Form B6) X Other (Form B9)

START CONSTRUCTION DA January 2007 OPERATION DATE: April 2010 DATE MANUFACTURED: 2007MANUFACTURER / MODEL NO.: NAIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?): Y NESHAP (SUBPART?):________ MACT (SUBPART?):_

EXPECTED ANNUAL HOURS OF OPERATION 8760

SOURCE OFEMISSION




OTHER

SOURCE OFEMISSION





lb/hr




EXPECTED OP. SCHEDULE: _24__ HR/DAY __7_ DAY/WK _52__ W

VISIBLE STACK EMISSIONS UNDER NORMAL OPERATION: _<20___ % OPACIPERCENTAGE ANNUAL THROUGHPUT (%): DEC-FEB 25 MAR-MAY 25 JUN-AUG 25 SEP-NOV 25




EMISSION SOURCE DESCRIPTION: Unit 5 Crusher House

Emissions include Unit 5 Crusher House which is controlled by water sprayers and enclosure.

OPERATING SCENARIO _________1________OF ________1__________




1 Emissions are based on control device outlet concentration design and exhaust fan parameters.

LEAD

EXPECTED ACTUAL


Attachments: (1) emissions calculations and supporting documentation; (2) indicate all requested state and federal enforceable permit limits (e.g. hours of operation, emission rates) and describe how these are monitored and with what frequency; and (3) de

lb/day

REVISED: 12/01/01 B9EMISSION SOURCE DESCRIPTION: EMISSION SOURCE ID NO: C15

Unit 5 Crusher House CONTROL DEVICE ID NO(S):

EMISSION POINT (STACK) ID NO(S): EP-C15


UNITS

Coal tons 3000 NA

UNITS







LIMITATION(UNIT/HR)

MAX. DESIGN


Emissions include Unit 5 Crusher House which is controlled by water sprayers and enclosure.







REQUESTED CAPACITY





START CONSTRUCTION DATE: NA OPERATION DATE: NA DATE MANUFACTURE NAMANUFACTURER / MODEL NO. NAIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?):___Y____ NESHAP (SUBPART?):________ MACT (SUBPART?):_________

EXPECTED ANNUAL HOURS OF OPERATI < 8760

SOURCE OFEMISSION


OTHER

SOURCE OFEMISSION




LEAD

EXPECTED ACTUAL



lb/day









EMISSION SOURCE DESCRIPTION: Fugitive Coal Handling - Existing Conveyor Emissions

Fugitive handling emissions from existing coal conveyor C4 to U5 Boiler House. Conveyor is 600 ft long and 42 inches wide.








lb/hr


Fugitive Coal Handling - Existing Conveyor Emissions CONTROL DEVICE ID NO(S):



UNITS

tons

UNITS











REQUESTED CAPACITY

Fugitive

Fugitive handling emissions from existing coal conveyor C4 to U5 Boiler House. Conveyor is 600 ft long and 42 inches wide.

Coal 3000



LIMITATION(UNIT/HR)

MAX. DESIGN






START CONSTRUCTION DATE: NA OPERATION DATE: NA DATE MANUFACTURE NAMANUFACTURER / MODEL NO. NAIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?):___Y____ NESHAP (SUBPART?):________ MACT (SUBPART?):_________

EXPECTED ANNUAL HOURS OF OPERATI < 8760

SOURCE OFEMISSION


OTHER

SOURCE OFEMISSION






lb/hr









EMISSION SOURCE DESCRIPTION: Fugitive Coal Handling - Existing Tripper Conveyor Emissions

Fugitive handling emissions from existing Unit 5 Tripper Conveyor TR1.






LEAD

EXPECTED ACTUAL



lb/day


Fugitive Coal Handling - Existing Tripper Conveyor Emissions CONTROL DEVICE ID NO(S):



UNITS

tons

UNITS







LIMITATION(UNIT/HR)

MAX. DESIGN






REQUESTED CAPACITY

Fugitive

Fugitive handling emissions from existing Unit 5 Tripper Conveyor TR1.

Coal 3000



REVISED 12/01/01 BEMISSION SOURCE ID NO: GS3, GS4CONTROL DEVICE ID NO(S):EMISSION POINT (STACK) ID NO(S): Fugitive




START CONSTRUCTION DATE June 2007 OPERATION DATE: 2011 DATE MANUFACTURED: 2007MANUFACTURER / MODEL NO NAIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?):_______ NESHAP (SUBPART?):________ MACT (SUBPART?):__________


SOURCE OFEMISSION



OTHER

SOURCE OFEMISSION




LEAD

EXPECTED ACTUAL



lb/day









EMISSION SOURCE DESCRIPTION: Fugitive Gypsum Handling - Stockout Conveyors

Fugitive emissions from gypsum stockout conveyors. Stockout conveyors GS3 (GSC1) & GS4 (GSC2) are 400 ft in length. Belt width is 30 inches.








lb/hr

REVISED: 12/01/01 B9EMISSION SOURCE ID NO: GS3, GS4




UNITS

tons

UNITS











REQUESTED CAPACITY

Gypsum 300



LIMITATION(UNIT/HR)

MAX. DESIGN


EMISSION SOURCE DESCRIPTION: Fugitive Gypsum Handling - Stockout Conveyors

Fugitive emissions from gypsum stockout conveyors. Stockout conveyors GS3 (GSC1) & GS4 (GSC2) are 400 ft in length. Belt width is 30 inches.

REVISED 12/01/01 BEMISSION SOURCE ID NO: GS5CONTROL DEVICE ID NO(S):EMISSION POINT (STACK) ID NO(S): Fugitive




START CONSTRUCTION DATEJanuary 2007 OPERATION DATE: April 2010 DATE MANUFACTURED: 2007MANUFACTURER / MODEL NO NAIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?):_______ NESHAP (SUBPART?):________ MACT (SUBPART?):__________

EXPECTED ANNUAL HOURS OF OPERATIO < 8760

SOURCE OFEMISSION



OTHER

SOURCE OFEMISSION






lb/hr




EXPECTED OP. SCHEDULE: __24__ HR/DAY __7_ DAY/WK ___52__ WK/YR





EMISSION SOURCE DESCRIPTION: Fugitive Gypsum Handling - Storage Pile Emissions

Fugitive emissions from gypsum storage piles. Nine day supply stockpile with approximately 25,000 tons. Total gypsum storage pile area is 0.45 acres.





COMPLETE THIS FORM AND COMPLETE AND ATTACH APPROPRIATE B1 THROUGH B9 FORM FOR EACH SOURCE

LEAD

EXPECTED ACTUAL


Attachments: (1) emissions calculations and supporting documentation; (2) indicate all requested state and federal enforceable permit limits (e.g. hours of operation, emission rates) and describe how these are monitored and with what frequency; and (3) de

lb/day

REVISED: 12/01/01 B9EMISSION SOURCE ID NO: GS5




UNITS

NA

UNITS







LIMITATION(UNIT/HR)

MAX. DESIGN


Fugitive emissions from gypsum storage piles. Nine day supply stockpile with approximately 25,000 tons. Total gypsum storage pile area is 0.45 acre

EMISSION SOURCE DESCRIPTION: Fugitive Gypsum Handling - Storage Pile Emissions





REQUESTED CAPACITY

Fugitive

Gypsum NA







START CONSTRUCTION DATE June 2007 OPERATION DATE: 2011 DATE MANUFACTURED: 2007MANUFACTURER / MODEL NO NAIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?):_______ NESHAP (SUBPART?):________ MACT (SUBPART?):__________


SOURCE OFEMISSION



OTHER

SOURCE OFEMISSION






lb/hr









EMISSION SOURCE DESCRIPTION: Fugitive Gypsum Handling - Truck Loading Emissions

Fugitive emissions from gypsum truck loading.






LEAD

EXPECTED ACTUAL



lb/day





UNITS

tons

UNITS







LIMITATION(UNIT/HR)

MAX. DESIGN


EMISSION SOURCE DESCRIPTION:Fugitive Gypsum Handling - Truck Loading Emissions





REQUESTED CAPACITY

Fugitive

Fugitive emissions from gypsum truck loading.

Gypsum 300







START CONSTRUCTION DATE June 2007 OPERATION DATE: 2011 DATE MANUFACTURED: 2007MANUFACTURER / MODEL NO NAIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?):___Y____ NESHAP (SUBPART?):________ MACT (SUBPART?):__________


SOURCE OFEMISSION



OTHER

SOURCE OFEMISSION




LEAD

EXPECTED ACTUAL



lb/day




EXPECTED OP. SCHEDULE: __24__ HR/DAY __7_ DAY/WK ___52__ WK/YR





EMISSION SOURCE DESCRIPTION: Fugitive Gypsum Handling - Gypsum to Rail Car Emissions

Fugitive emissions from gypsum loading to rail car.








lb/hr





UNITS

tons

UNITS











REQUESTED CAPACITY

Fugitive

Gypsum 300



LIMITATION(UNIT/HR)

MAX. DESIGN


Fugitive emissions from gypsum loading to rail car.

EMISSION SOURCE DESCRIPTION: Fugitive Gypsum Handling - Gypsum to Rail Car Emissions

REVISED 12/01/01 BEMISSION SOURCE ID NO: LS1CONTROL DEVICE ID NO(S):EMISSION POINT (STACK) ID NO(S): Fugitive






SOURCE OFEMISSION



OTHER

SOURCE OFEMISSION




LEAD

EXPECTED ACTUAL



lb/day









EMISSION SOURCE DESCRIPTION: Fugitive Limestone Handling - Rail Car Unloading Emissions

Fugitive emissions from limestone rail car unloading.








lb/hr

REVISED: 12/01/01 B9EMISSION SOURCE ID NO: LS1




UNITS

tons

UNITS











REQUESTED CAPACITY

Fugitive

Fugitive emissions from limestone rail car unloading.

Limestone 2800



LIMITATION(UNIT/HR)

MAX. DESIGN


EMISSION SOURCE DESCRIPTION: Fugitive Limestone Handling - Rail Car Unloading Emissions







SOURCE OFEMISSION



OTHER

SOURCE OFEMISSION






lb/hr









EMISSION SOURCE DESCRIPTION: Fugitive Limestone Handling - Stockout Conveyor

Fugitive emissions from limestone stockout conveyor.The stockout conveyor LSC1 is 250 ft in length. Belt width is 54 inches.






LEAD

EXPECTED ACTUAL



lb/day





UNITS

tons

UNITS







LIMITATION(UNIT/HR)

MAX. DESIGN


EMISSION SOURCE DESCRIPTION: Fugitive Limestone Handling - Stockout Conveyor

Fugitive emissions from limestone stockout conveyor. The stockout conveyor LSC1 is 250 ft in length. Belt width is 54 inches.





REQUESTED CAPACITY

Limestone 2800







START CONSTRUCTION DATE June 2007 OPERATION DATE: 2011 DATE MANUFACTURE 2007MANUFACTURER / MODEL NO NAIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?):_OOO______ NESHAP (SUBPART?):________ MACT (SUBPART?):______

EXPECTED ANNUAL HOURS OF OPERAT < 8760

SOURCE OFEMISSION


OTHER

SOURCE OFEMISSION




LEAD

EXPECTED ACTUAL



lb/day









EMISSION SOURCE DESCRIPTION: Fugitive Limestone Handling - Stockout Conveyor Emissions

Fugitive emissions from limestone stockout conveyor. The stockout conveyor LSC2 is 780 ft in length and 54 inches wide.








lb/hr





UNITS

tons

UNITS











REQUESTED CAPACITY

Fugitive

Limestone 2800



LIMITATION(UNIT/HR)

MAX. DESIGN


Fugitive emissions from limestone stockout conveyor. The stockout conveyor LSC2 is 780 ft in length and 54 inches wide.

EMISSION SOURCE DESCRIPTION: Fugitive Limestone Handling - Stockout Conveyor Emissions





START CONSTRUCTION DATEJanuary 2007 OPERATION DATE: April 2010 DATE MANUFACTURED: 2007MANUFACTURER / MODEL NO NAIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?):_OOO______ NESHAP (SUBPART?):________ MACT (SUBPART?):__________


SOURCE OFEMISSION



OTHER

SOURCE OFEMISSION




LEAD

EXPECTED ACTUAL



lb/day









EMISSION SOURCE DESCRIPTION: Fugitive Limestone Handling - Storage Pile Emissions

Fugitive emissions from limestone storage pile. The stock pile will contain a 30 day supply - approximately 20,000 tons. The area of the limestone storage pile is approximately 0.7 acres.








lb/hr





UNITS

NA

UNITS











REQUESTED CAPACITY

Fugitive

Fugitive emissions from limestone storage pile. The stock pile will contain a 30 day supply - approximately 20,000 tons. The area of the limestone stopile is approximately 0.7 acres.

Limestone NA



LIMITATION(UNIT/HR)

MAX. DESIGN


EMISSION SOURCE DESCRIPTION:Fugitive Limestone Handling - Storage Pile Emissions

REVISED 12/01/0 BEMISSION SOURCE ID NO: LS9, LS10CONTROL DEVICE ID NO(S):EMISSION POINT (STACK) ID NO(S): Fugitive




START CONSTRUCTION DA January 2007 OPERATION DATE: April 2010 DATE MANUFACTURE 2007MANUFACTURER / MODEL NAIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?):_OOO______ NESHAP (SUBPART?):________ MACT (SUBPART?):______

EXPECTED ANNUAL HOURS OF OPERATI< 8760

SOURCE OFEMISSION


OTHER

SOURCE OFEMISSION






lb/hr









EMISSION SOURCE DESCRIPTION: Fugitive Limestone Handling - Bulldozing and Reclaim Hopper Emissions

Fugitive emissions from limestone bulldozing and reclaim hopper. For bulldozing operations, it is assumed that the emissions are conservatively based on 1 bulldozer operating 24 hrs/day and 365 days/yr.






LEAD

EXPECTED ACTUAL


Attachments: (1) emissions calculations and supporting documentation; (2) indicate all requested state and federal enforceable permit limits (e.g. hours ofoperation, emission rates) and describe how these are monitored and with what frequency; and (3) describe any monitoring devices, gauges, or test ports for this source

lb/day

REVISED: 12/01/01 B9EMISSION SOURCE ID NO: LS9, LS10




UNITS

tons

UNITS







LIMITATION(UNIT/HR)

MAX. DESIGN


Fugitive emissions from limestone bulldozing and reclaim hopper. For bulldozing operations, it is assumed that the emissions are conservatively based on 1 bulldozer operating 24 hrs/day and 365 days/yr.

EMISSION SOURCE DESCRIPTION: Fugitive Limestone Handling - Bulldozing and Reclaim Hopper Emissions





REQUESTED CAPACITY

Fugitive

Limestone 300







START CONSTRUCTION DATEJanuary 2007 OPERATION DATE: April 2010 DATE MANUFACTURED: 2007MANUFACTURER / MODEL NO NAIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?):_OOO______ NESHAP (SUBPART?):________ MACT (SUBPART?):__________


SOURCE OFEMISSION

AIR POLLUTANT EMITTED FACTOR lb/hr tons/yr lb/hr tons/yr lb/hr tons/yrPARTICULATE MATTER (PM) AP-42 Conveyor emissions are included in with Limestone Silo emissionsPARTICULATE MATTER<10 MICRONS (PM10) AP-42 Conveyor emissions are included in with Limestone Silo emissionsPARTICULATE MATTER<2.5 MICRONS (PM2.5)


OTHER

SOURCE OFEMISSION






lb/hr









EMISSION SOURCE DESCRIPTION: Fugitive Limestone Handling - Limestone Reclaim Conveyor Emissions

Fugitive emissions from two limestone reclaim conveyors. The reclaim conveyor LRC1 is 450 ft in length.






LEAD

EXPECTED ACTUAL



lb/day





UNITS

tons

UNITS











REQUESTED CAPACITY

Fugitive

Limestone 300



LIMITATION(UNIT/HR)

MAX. DESIGN


Fugitive emissions from two limestone reclaim conveyors. The reclaim conveyor LRC1 is 450 ft in length.

EMISSION SOURCE DESCRIPTION: Fugitive Limestone Handling - Reclaim Conveyor Emissions

REVISED 12/01/01 BEMISSION SOURCE ID NO: FLandfillCONTROL DEVICE ID NO(S):

EMISSION POINT (STACK) ID NO(S):DESCRIBE IN DETAILTHE EMISSION SOURCE PROCESS (ATTACH FLOW DIAGRAM):



START CONSTRUCTION DATE NA OPERATION DATE: NA DATE MANUFACTURED: NAMANUFACTURER / MODEL NO.: NAIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?): NESHAP (SUBPART?):________ MACT (SUBPART?):


SOURCE OFEMISSION



OTHER

SOURCE OFEMISSION



LEAD

EXPECTED ACTUAL



lb/day




EMISSION SOURCE DESCRIPTION: Landfill Emissions

Increased fugitive emissions are expected from the addition of Unit 6. Landfill emissions include dumping of material from delivery vehicle to active landfill cell and active cell storage.

OPERATING SCENARIO ______1___________OF ________1__________Fugitive










lb/hr

REVISED: 12/01/01 B9EMISSION SOURCE DESCRIPTION: EMISSION SOURCE ID NO: FLandfill

Landfill Emissions CONTROL DEVICE ID NO(S):EMISSION POINT (STACK) ID NO(S):


UNITS

Coal Combustion Products acres 4

UNITS











REQUESTED CAPACITY



LIMITATION(UNIT/HR)

MAX. DESIGN


Increased fugitive emissions are expected from the addition of Unit 6. Landfill emissions include dumping of material from delivery vehicle to active landfill cell and active cell storage.

Fugitive

REVISED 12/01/01 BEMISSION SOURCE ID NO: EG6CONTROL DEVICE ID NO(S):EMISSION POINT (STACK) ID NO(S): EP-EG6



X Int.combustion engine/generator (Form B2) Coating/finishing/printing (Form B5) Incineration (Form B8) Liquid storage tanks (Form B3) Storage silos/bins (Form B6) Other (Form B9)

START CONSTRUCTION DATE June 2007 OPERATION DATE: 2011 DATE MANUFACTURED: 2007MANUFACTURER / MODEL NO.: TBDIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?): IIII NESHAP (SUBPART?):________ MACT (SUBPART?):__________


SOURCE OFEMISSION

AIR POLLUTANT EMITTED FACTOR lb/hr tons/yr lb/hr tons/yr lb/hr tons/yrPARTICULATE MATTER (PM) NSPS 0.78 0.04 - - 0.78 0.04PARTICULATE MATTER<10 MICRONS (PM10) 2 3.89 0.19 - - 3.89 0.19PARTICULATE MATTER<2.5 MICRONS (PM2.5) NA NA NA NA NA NASULFUR DIOXIDE (SO2) 8 0.03 1.00E-03 - - 0.03 1.00E-03NITROGEN OXIDES (NOx) NSPS 24.87 1.24 - - 24.87 1.24CARBON MONOXIDE (CO) NSPS 13.47 0.67 - - 13.47 0.67VOLATILE ORGANIC COMPOUNDS (VOC) NSPS 24.87 1.24 - - 24.87 1.24

OTHER

SOURCE OFEMISSION


TOXIC AIR POLLUTANT AND CAS NO. EF SOURCEDuke Power is not proposing changes to previously permitted TAP emission due to this modification.

EXPECTED OP. SCHEDULE: ___ HR/DAY ___ DAY/WK ___ WK/YR



lb/day



POTENTIAL EMSSIONSEXPECTED ACTUAL




EMISSION SOURCE DESCRIPTION: Emergency Diesel Fired Generator

A new 2350 hp (1750 kW) emergency diesel fired generator will be used for emergency power at the facility.


(AFTER CONTROLS / LIMITS) (AFTER CONTROLS / LIMITS)



LEAD

EXPECTED ACTUAL




lb/hr

REVISED 12/01/01 B2EMISSION SOURCE DESCRIPTIONEmergency Diesel Fired Generator EMISSION SOURCE ID NO: EG6


OPERATING SCENARIO: ______1________ OF _____1_________ EMISSION POINT (STACK) ID NO(S): EP-EG6

CHECK ALL THAT APPLY X EMERGENCY SPACE HEAT X ELECTRICAL GENERATION

PEAK SHAVER OTHER (DESCRIBE): ___________________

GENERATOR OUTPUT (KW): ANTICIPATED ACTUAL HOURS OF OPERATION AS PEAK SHAVER (HRS/YR):

ENGINE OUTPUT (HP): 2350

TYPE ICE: GASOLINE ENGINE DIESEL ENGINE UP TO 600 HP X DIESEL ENGINE GREATER THAN 600 HP DUAL FUEL ENGINE

OTHER (DESCRIBE): _________________________________________ (complete below)

ENGINE TYPE RICH BURN LEAN BURN

EMISSION REDUCTION MODIFICATIONS INJECTION TIMING RETAR PREIGNITION CHAMBER COMBUSTION OTHER _________

OR STATIONARY GAS TURBINE (complete below) NATURAL GAS PIPELINE COMPRESSOR OR TURBINE (complete below)

FUEL NATURAL GAS OIL ENGINE TYPE: 2-CYCLE LEAN BURN 4-CYCLE LEAN TURBINE

OTHER (DESCRIBE):____________ 4-CYCLE RICH BURN OTHER (DESCRIBE): _______________

CYCLE: COGENERATION SIMPLE CONTROLS: COMBUSTION MODIFICATIONS (DESCRIBE): __________________

REGENERATIVE COMBINED NONSELECTIVE CATALYTIC REDUCTION SELECTIVE CATALYTIC REDUCTION

CONTROLS: WATER-STEAM INJECTION CLEAN BURN AND PRECOMBUSTION CHAMBER UNCONTROLLED

UNCONTROLLED LEAN-PREMIX

No 2 Fuel Oil Gallons 120 NA

No. 2 Fuel Oil 137,000 Gallon 0.0015

- - - - -

DESCRIBE METHODS TO MINIMIZE VISIBLE EMISSIONS DURING IDLING, OR LOW LOAD OPERATIONS:

COMMENTS:


FORM B2EMISSION SOURCE (INTERNAL COMBUSTION ENGINES/GENERATORS)

FUEL TYPE UNITSBTU/UNIT

FUEL USAGE (INCLUDE STARTUP/BACKUP FUEL)REQUESTED CAPACITY

FUEL TYPE UNITSMAXIMUM DESIGN

CAPACITY (UNIT/HR) LIMITATION (UNIT/HR)


CO PM PM10 VOCPOLLUTANT

EMISSION FACTOR LB/UNIT

FUEL CHARACTERISTICS (COMPLETE ALL THAT ARE APPLICABLE) SULFUR CONTENT

(% BY WEIGHT)

UNIT

NOX OTHER

MANUFACTURER'S SPECIFIC EMISSION FACTORS (IF AVAILABLE)

REVISED 12/01/01 BEMISSION SOURCE ID NO: FWPCONTROL DEVICE ID NO(S):EMISSION POINT (STACK) ID NO(S): EP-FWP



X Int.combustion engine/generator (Form B2) Coating/finishing/printing (Form B5) Incineration (Form B8) Liquid storage tanks (Form B3) Storage silos/bins (Form B6) Other (Form B9)

START CONSTRUCTION DATE June 2007 OPERATION DATE: 2011 DATE MANUFACTURED: 2007MANUFACTURER / MODEL NO.: TBDIS THIS SOURCE SUBJECT TO? NSPS (SUBPART?): IIII NESHAP (SUBPART?):________ MACT (SUBPART?):__________


SOURCE OFEMISSION

AIR POLLUTANT EMITTED FACTOR lb/hr tons/yr lb/hr tons/yr lb/hr tons/yrPARTICULATE MATTER (PM) NSPS 0.14 0.01 - - 0.14 0.01PARTICULATE MATTER<10 MICRONS (PM10) 2 0.71 0.04 - - 0.71 0.04PARTICULATE MATTER<2.5 MICRONS (PM2.5) NA NA NA NA NA NASULFUR DIOXIDE (SO2) 8 0.01 3.00E-04 - - 0.01 3.00E-04NITROGEN OXIDES (NOx) NSPS 2.84 0.14 - - 2.84 0.14CARBON MONOXIDE (CO) NSPS 2.46 0.12 - - 2.46 0.12VOLATILE ORGANIC COMPOUNDS (VOC) NSPS 2.84 0.14 - - 2.84 0.14

OTHER

SOURCE OFEMISSION


TOXIC AIR POLLUTANT AND CAS NO. EF SOURCEDuke Power is not proposing changes to previously permitted TAP emission due to this modification.

EXPECTED OP. SCHEDULE: ___ HR/DAY ___ DAY/WK ___ WK/YR



lb/day



POTENTIAL EMSSIONSEXPECTED ACTUAL




EMISSION SOURCE DESCRIPTION: Emergency Diesel Fired Fire Water Pump

A new 430 hp emergency diesel fired fire water pump. Duke requests an annual operation limit of 100 hours.


(AFTER CONTROLS / LIMITS) (AFTER CONTROLS / LIMITS)



LEAD

EXPECTED ACTUAL




lb/hr

REVISED 12/01/01 B2EMISSION SOURCE DESCRIPTIONEmergency Diesel Fired Fire Water Pump EMISSION SOURCE ID NO: FWP


OPERATING SCENARIO: ______1________ OF _____1_________ EMISSION POINT (STACK) ID NO(S): EP-FWP

CHECK ALL THAT APPLY X EMERGENCY SPACE HEAT ELECTRICAL GENERATION

PEAK SHAVER OTHER (DESCRIBE): ___________________

GENERATOR OUTPUT (KW): ANTICIPATED ACTUAL HOURS OF OPERATION AS PEAK SHAVER (HRS/YR):

ENGINE OUTPUT (HP): 430

TYPE ICE: GASOLINE ENGINE DIESEL ENGINE UP TO 600 HP X DIESEL ENGINE GREATER THAN 600 HP DUAL FUEL ENGINE

OTHER (DESCRIBE): _________________________________________ (complete below)

ENGINE TYPE RICH BURN LEAN BURN

EMISSION REDUCTION MODIFICATIONS INJECTION TIMING RETAR PREIGNITION CHAMBER COMBUSTION OTHER _________

OR STATIONARY GAS TURBINE (complete below) NATURAL GAS PIPELINE COMPRESSOR OR TURBINE (complete below)

FUEL NATURAL GAS OIL ENGINE TYPE: 2-CYCLE LEAN BURN 4-CYCLE LEAN TURBINE

OTHER (DESCRIBE):____________ 4-CYCLE RICH BURN OTHER (DESCRIBE): _______________

CYCLE: COGENERATION SIMPLE CONTROLS: COMBUSTION MODIFICATIONS (DESCRIBE): __________________

REGENERATIVE COMBINED NONSELECTIVE CATALYTIC REDUCTION SELECTIVE CATALYTIC REDUCTION

CONTROLS: WATER-STEAM INJECTION CLEAN BURN AND PRECOMBUSTION CHAMBER UNCONTROLLED

UNCONTROLLED LEAN-PREMIX

No 2 Fuel Oil Gallons 21.9 NA

No. 2 Fuel Oil 137,000 Gallon 0.0015

- - - - -

DESCRIBE METHODS TO MINIMIZE VISIBLE EMISSIONS DURING IDLING, OR LOW LOAD OPERATIONS:

COMMENTS:


FORM B2EMISSION SOURCE (INTERNAL COMBUSTION ENGINES/GENERATORS)

FUEL TYPE UNITSBTU/UNIT

FUEL USAGE (INCLUDE STARTUP/BACKUP FUEL)REQUESTED CAPACITY

FUEL TYPE UNITSMAXIMUM DESIGN

CAPACITY (UNIT/HR) LIMITATION (UNIT/HR)


CO PM PM10 VOCPOLLUTANT

EMISSION FACTOR LB/UNIT

FUEL CHARACTERISTICS (COMPLETE ALL THAT ARE APPLICABLE) SULFUR CONTENT

(% BY WEIGHT)

UNIT

NOX OTHER

MANUFACTURER'S SPECIFIC EMISSION FACTORS (IF AVAILABLE)

REVISED 12/01/01 D1

AIR POLLUTANT EMITTED

HAZARDOUS AIR POLLUTANT EMITTED CAS NO.

Hydrogen Chloride 1.72E+02 - 1.72E+02

Hydrogen Fluoride 2.24E+01 - 2.24E+01

Antimony 3.30E-02 - 3.30E-02

Arsenic 7.53E-01 - 7.53E-01

Beryllium 3.91E-02 - 3.91E-02

Cadmium 9.40E-02 - 9.40E-02

Chromium 4.77E-01 - 4.77E-01

Cobalt 1.83E-01 - 1.83E-01

Lead 7.70E-01 - 7.70E-01

Manganese 8.99E-01 - 8.99E-01Mercury 1.48E-01 - 1.48E-01

Nickel 5.14E-01 - 5.14E-01

Selenium 2.39E+00 - 2.39E+00

Acenapthene 3.05E-05 - 3.05E-05

Acenapththylene 1.41E-05 - 1.41E-05

Acetaldehyde 1.05E+00 - 1.05E+00

Acetophenone 2.75E-02 - 2.75E-02

Acrolein 5.32E-01 - 5.32E-01

Aldehydes 2.10E-01 - 2.10E-01

Ammonia 2.24E+02 - 2.24E+02

Anthracene 3.92E-04 - 3.92E-04

Benzene 2.39E+00 - 2.39E+00

Benz(a)Anthracene 9.65E-06 - 9.65E-06

Benz(A)Pyrene 5.20E-07 - 5.20E-07

Benzo(b)Fluoranthene 4.17E-06 - 4.17E-06

Benzo(g,h,i)perylene 5.37E-05 - 5.37E-05

Benzo(k)Fluoranthene 4.25E-07 - 4.25E-07

Benzyl Chloride 1.28E+00 - 1.28E+00

Biphenyl 3.12E-03 - 3.12E-03

Bis(2-ethylhexyl)phthalate 1.34E-01 - 1.34E-01

Bromoform 7.15E-02 - 7.15E-02

Carbon Disulfide 2.38E-01 - 2.38E-01

2-Chloroacetophenone 1.28E-02 - 1.28E-02

Chlorobenzene 4.03E-02 - 4.03E-02

Chloroform 1.08E-01 - 1.08E-01

(AFTER CONTROLS / LIMITATIONS)

HAZARDOUS AIR POLLUTANT EMISSIONS INFORMATION - FACILITY-WIDE

CRITERIA AIR POLLUTANT EMISSIONS INFORMATION - FACILITY-WIDE

FORM D1

tons/yr

1,770.51

tons/yr tons/yr

- 1,770.51PARTICULATE MATTER (PM)

FACILITY-WIDE EMISSIONS SUMMARY

36,680.60

10,329.45 to 10887.45

36,680.60 -

-

-

SULFUR DIOXIDE (SO2)

NITROGEN OXIDES (NOx)1

CARBON MONOXIDE (CO) 6,111.97

VOLATILE ORGANIC COMPOUNDS (VOC)

0.77LEAD

1,659.54

NA

PARTICULATE MATTER < 10 MICRONS (PM10)

PARTICULATE MATTER < 2.5 MICRONS (PM2.5)

1,659.54

NA -

(BEFORE CONTROLS / LIMITATIONS)

(AFTER CONTROLS /LIMITATIONS)

tons/yrtons/yrtons/yr


EXPECTED ACTUAL EMISSIONS POTENTIAL EMISSIONS POTENTIAL EMISSIONS

EXPECTED ACTUAL EMISSIONS POTENTIAL EMISSIONS POTENTIAL EMISSIONS(AFTER CONTROLS /

LIMITATIONS)

10,329.45 to 10887.45

206.75-

0.77-

206.75

6,111.97

-

(BEFORE CONTROLS / LIMITATIONS)

(AFTER CONTROLS /LIMITATIONS)

Cumene 9.72E-03 - 9.72E-03

Cyanide 4.58E+00 - 4.58E+00

2,4-Dinitrotoluene 5.13E-04 - 5.13E-04

Dimethyl Sulfate 8.80E-02 - 8.80E-02

Ethyl benzene 1.72E-01 - 1.72E-01

Ethyl Chloride (Chloroethane) 7.70E-02 - 7.70E-02

Ethylene Dichloride 7.33E-02 - 7.33E-02

Ethylene Dibromide 2.20E-03 - 2.20E-03

Formaldehyde 5.17E-01 - 5.17E-01

Hexane 1.23E-01 - 1.23E-01

Isophorone 1.06E+00 - 1.06E+00

Methyl Bromide (Bromomethane) 2.93E-01 - 2.93E-01

Methyl Chloride (Chloromethane) 9.72E-01 - 9.72E-01

Methyl Ethyl Ketone 7.15E-01 - 7.15E-01

Methyl Hydrazine 3.12E-01 - 3.12E-01

Methyl Methacrylate 3.67E-02 - 3.67E-02

Methyl tert-butyl ether 6.42E-02 - 6.42E-02

Methylene Chloride 5.32E-01 - 5.32E-01

Naphthalene 2.53E-02 - 2.53E-02

Phenanthrene 4.96E-03 - 4.96E-03

Phenol 2.93E-02 - 2.93E-02

Propionaldehyde 6.97E-01 - 6.97E-01

Styrene 4.58E-02 - 4.58E-02

Tetrachloroethylene 7.88E-02 - 7.88E-02

Toluene 4.48E-01 - 4.48E-01

1,1,1-Trichloroethane 3.70E-02 - 3.70E-02

Vinyl Acetate 1.39E-02 - 1.39E-02

Xylene 6.78E-02 - 6.78E-02

Total PCDD/PCDF 3.23E-06 - 3.23E-06

TOXIC AIR POLLUTANT EMITTED CAS NO. lb/hr lb/day lb/year Yes No

Hydrogen Chloride 39.25 942.09 343863.06 No

Hydrogen Fluoride 5.11 122.68 44777.57 No

Arsenic 0.17 4.12 1505.09 No

Beryllium 0.01 0.21 78.14 No

Cadmium 0.02 0.52 188.06 No

Chromium 0.11 2.62 954.49 No

Manganese 0.21 4.93 1798.96 No

Mercury 0.03 0.81 295.37 No

Nickel 0.12 2.82 1027.83 No

Acetaldehyde 0.24 5.74 2094.48 No

Acrolein 0.12 2.92 1063.98 No

Benzene 0.54 13.08 4773.11 No

Benzyl Chloride 0.29 7.03 2566.99 No

Carbon Disulfide 0.05 1.31 476.73 No

Chlorobenzene 0.01 0.22 80.68 No

Chloroform 0.02 0.59 216.36 No

Ethylene Dichloride 0.02 0.40 146.69 No

Ethylene Dibromide 0.00 0.01 4.40 No

Formaldehyde 0.12 2.83 1033.81 No

Hexane 0.03 0.67 245.70 No

Methyl Ethyl Ketone 0.16 3.92 1430.18 No

Methylene Chloride 0.22 5.32 1943.58 No

INDICATE REQUESTED ACTUAL EMISSIONS AFTER CONTROLS / LIMITATIONS. EMISSIONS ABOVE THE TOXIC PERMIT EMISSION RATE (TPER) IN 15A NCAC 2Q .0711 MAY REQUIRE AIR DISPERSION MODELING. USE NETTING FORM D2 IF NECESSARY.

Modeling Required ?

TOXIC AIR POLLUTANT EMISSIONS INFORMATION - FACILITY-WIDE

Phenol 0.01 0.16 58.67 No

Styrene 0.01 0.25 91.68 No

Toluene 0.10 2.45 895.73 No

Xylene 0.02 0.37 135.68 No

Sulfuric Acid 0.02 0.52 189.81 Yes

Ammonia 62.80 1507.20 550128.00 Yes


1 Nox emissions are provided as a range reflecting operation of Unit 5 during the 5 month ozone season.

COMMENTS:

Revised:12/01/01 NCDENR/Division of Air Quality - Application for Air Permit to Construct/Operate D2

AIR POLLUTANT: Sulfuric Acid

EMISSION SOURCE ID NOS.: U6

LB/YEAR LB/DAY

MODIFICATION 0.52 0.02

INCREASE

- MINUS - - MINUS - - MINUS - - MINUS -

MODIFICATION

DECREASE

= EQUALS = = EQUALS = = EQUALS = = EQUALS =

NET CHANGE

FROM MODIFICATION

CREDITABLE

INCREASE



NET CREDITABLE

CHANGE

TOTAL FACILITY

0.52 0.02

TPER LEVELS (2Q .0711) 0.25 0.025

CHECK HERE IF AN AIR DISPERSION MODELING ANALYSIS IS REQUIRED

CAS NO.:

PURPOSE OF NETTING: AIR TOXICS PSD (100/250 tons per year) PSD SIGNIFICANT LEVELS

EMISSIONS


LB/HR

COMMENTS:

FORM D2AIR POLLUTANT NETTING WORKSHEET

SECTION C - FACILITY-WIDE EMISSIONS

Summarize in this sectionusing the B forms

CREDITABLE

DECREASE

EMISSIONS - USE APPROPRIATE COLUMNS ONLY

SECTION A - EMISSION OFFSETTING ANALYSIS FOR MODIFIED/NEW SOURCES

SECTION B - FACILITY-WIDE EMISSION NETTING ANALYSIS

Revised:12/01/01 NCDENR/Division of Air Quality - Application for Air Permit to Construct/Operate D2

AIR POLLUTANT: ammonia

EMISSION SOURCE ID NOS.: U6

LB/YEAR LB/DAY

MODIFICATION

INCREASE 62.8


MODIFICATION

DECREASE


NET CHANGE

FROM MODIFICATION

CREDITABLE

INCREASE



NET CREDITABLE

CHANGE

TOTAL FACILITY

62.8

TPER LEVELS (2Q .0711) 0.68

CHECK HERE IF AN AIR DISPERSION MODELING ANALYSIS IS REQUIRED

FORM D2AIR POLLUTANT NETTING WORKSHEET

SECTION C - FACILITY-WIDE EMISSIONS

Summarize in this sectionusing the B forms

CREDITABLE

DECREASE

EMISSIONS - USE APPROPRIATE COLUMNS ONLY

SECTION A - EMISSION OFFSETTING ANALYSIS FOR MODIFIED/NEW SOURCES

SECTION B - FACILITY-WIDE EMISSION NETTING ANALYSIS

CAS NO.:

PURPOSE OF NETTING: AIR TOXICS PSD (100/250 tons per year) PSD SIGNIFICANT LEVELS

EMISSIONS


LB/HR

COMMENTS:

REVISED: 12/01/0

1. Unit 6 Start-Up/Aux. Boiler Fuel Oil Tank 168,000 gallons 2Q.0503(8)

2. One Emergency Diesel Generator Fuel Oil Tank 1,640 gallons each 2Q.0503(8)

3. Emergency Fire Water Pump Fuel Oil Tank 350 gallons 2Q.0503(8)

4.

5.

6.

7.

8.

9.

10.


DESCRIPTION OF EMISSION SOURCEBASIS FOR EXEMPTION OR

INSIGNIFICANT ACTIVITY

SIZE OR PRODUCTION

RATE

FORM D4

INSIGNIFICANT ACTIVITIES PER 2Q .0503 FOR TITLE V SOURCESACTIVITIES EXEMPTED PER 2Q .0102 OR

EXEMPT AND INSIGNIFICANT ACTIVITIES SUMMARY NCDENR/Division of Air Quality - Application for Air Permit to Construct/Operate D4

APPENDIX B: EMISSION CALCULATIONS

May 2007

Duke Energy Carloinas - Cliffside ExpansionAssumptions for Emission Calculations in Appendix B

Potential to Emit SummaryParticulate matter (PM) emissions and TSP emissions (i.e., filterable particulates) are equal.

Main Boiler (Unit #6)Emission rates and boiler capacity (7850 MMBtu/hr) provided by Duke Power.

Auxiliary BoilerBoiler capacity and operating hours (876 hr/yr) provided by Duke Power.Emission rates for NOx, CO, VOC are based on BACT emission rates. Emission rates for TSP, PM10, SO2, and H2SO4 are based on BACT/AP-42 emission rates and a fuel sulfur content of 0.05% S by weight.

Emergency Generator, Diesel Fire-Water Pump & Emergency Quench Water PumpGenerator capacity and operating hours (100 hr/yr) provided by Duke Power.Emission rates for NOx, CO, VOC, and TSP are based on the limitations in NSPS Subpart IIIII for Stationary Compression Ignition Internal Combustion Engines.Emission rates for SO2 are based on the NSPS Subpart IIIII fuel sulfur content limitation of 0.0015% S by weight.

Particulate Emissions - PointThroughput data for coal, bottom ash, fly ash, limestone and gypsum provided by Duke Power.Outlet concentration from fabric filter stacks estimated at 0.01 gr/scf by ENSR.For emission calculation purposes, point sources are equipped with fabric filters and forced air exhaust.

The Unit 5 Crusher House and Unit 6 Tripper Room exhausts are point sources.

CoalEmissions from C27, C28, C29 & C30 are included with the U6 Tripper House emissions.

Particulate Emissions - FugitivesThroughput data for coal, bottom ash, fly ash, limestone and gypsum provided by Duke Power.Average surface moisture content for coal, bottom ash, fly ash, limestone and gypsum estimated by ENSR.The particle size multiplier value of 0.74 is based on information from AP-42 Chapter 13.2.4.The mean wind speed value of 7.3 miles per hour was obtained from historical wind speed data from Asheville, NC maintained on the NOAA website.

Conservative estimates for control efficiencies (based on engineering judgment):75% for conveyors with partially enclosed hood & for stacking tubes75% for building & dust suppression (as needed) for rail car unloading 90% for underground conveyors90% for fly ash enclosed hoppers & pneumatic system30% for truck loading of wetted materials

Rail car unloading:Rotary unloading for coal and limestone Since a fabric filter is currently not specified as a control device, emissions will be calculated using fugitive methodology.Duke Power proposes water and dust suppression for controls on an as-needed basis..

For coal handling operations, coal will be treated with dust suppression agents (water, surfactants) at the base of the conveyor leading to the stacking tubes.Stacking tubes are to be equipped with water sprays for dust suppressionSince stacking tubes are currently not equipped with fabric filters, emissions are calculated using fugitive methodology.

Since AP-42 does not have an emission factor for PM10, the PM10 emission factor was estimated by multiplying the AP-42 emission rate for TSP by a factor of 5 to conservatively estimate the contribution of condensables.

HCl and HF emissions are based on a mass balance, which includes the chloride and fluoride concentrations of coal (provided by Duke) and the scrubber control efficiency (provided by B&W) for each pollutant.

For point sources without exhaust fans, short-term emissions are based on the material charge rate and the density of the material charged. Annual emissions are based on annual throughput rather than on operating hours. Annual emissions are estimated an annual capacity factor (the ratio of the annual throguhput to the year-round throughput at the maximum charge rate).

The exhaust fans from the point sources are assumed to operate 24 hours/day. Although the material handling operations may operate less than 24 hours per day, recordkeeping would likely be required to justify reduced emission estimates based on operating hour restrictions.

Emission estimates from fugitive emission sources are based on the maximum short-term limit and 24 operating hours per day. Although the material handling operations may operate less than 24 hours per day, recordkeeping would likely be required to justify reduced emission estimates based on operating hour Emissions from the coal and limestone hoppers (located underground) are accounted for in the bulldozing emission estimates.

For conveyors that transfer materials to emission sources equipped with control devices, the emissions from the conveyor are assumed to be included in the point source emissions. This methodology was utilized for the following sources:

Appendix B Page 1 of 63 5/29/2007

Duke Energy Carloinas - Cliffside ExpansionAssumptions for Emission Calculations in Appendix B

Particulate Emissions - Limestone FugitivesEmissions are based on AP-42 Section 11.19.2 for Crushed Stone Processing operations.

Control Efficiencies:50% for partial enclosure & dust suppression (as needed) for rotary unloading75% for conveyors with partially enclosed hood

Particulate Emissions - Storage PilesAcreage of storage piles based on facility diagram provided by Duke Power (16.9 acres for coal, 0.7 acres for limestone, 0.45 acres for gypsum).

These storage pile acreages were permitted in the PSD permit application for the Unit 5 modernization project.Moisture content estimates for each material reviewed and confirmed by Duke Power. Estimate of windy days based on 1987-1991 data from Douglas/Charlotte Airport

Particulate Emissions - Landfill Active CellsParticulate emissions from the truck vehicle miles to transport materials to the on-site active landfill cells are accounted for in the "Vehicle Miles" calculations.

The maximum delivery rate (per hour) of materials to the active landfill cells is estimated at ten 15-ton deliveries for fly ash and ten 15-ton deliveries for limestone.

Particulate emissions from the non-active landfill cells are assumed to be zero because this area is seeded and has vegetation.

BulldozingBulldozing emissions are based on the methodology described in the Mojave AQMD Emission Inventory guidance document. For coal bulldozing operations, emissions are conservatively based on 3 bulldozers operating 8760 hr/yr.For limestone bulldozing operations, emissions are conservatively based on 1 bulldozer operating 8760 hr/yr.

Cooling TowerLiquid circulation rate and TDS concentration data provided by Duke Power.The total liquid drift (%) is estimated based on BACT levels.

Vehicle MilesAll roads are currently assumed to be paved. Facility is assumed to have a road washing/cleaning program.Coal and limestone are provided via rail. Fugitive dust emissions from these deliveries are assumed insignificant.For delivery vehicles of fuel oil, acid/caustic, and ammonia, the number of deliveries (per substance) was estimated at 2 deliveries per day.

LocomotivesEmission estimates from locomotives are currently not included in the facility-wide emission estimates.

Particulate emissions from the dumping of the materials from the delivery vehicle into the active landfill cells are estimated based on the same methodology used for the calculation of fugitive emissions from particulate handling.

The particulate emissions from the storage of materials in the active landfill cells are estimated using the same methodology as that used for the estimation of fugitive particulate emissions for storage piles. However, a control factor of 80% was applied to the methodology to account for the reduction in particulate emissions due to the wet compaction of materials added to the landfill.

Since conveyors LS11 and LS12 originate underground and deposit material within LS13, which is equipped with a fabric filter, emissions from LS11 and LS12 are assumed to be included with the point source emissions from LS13.

Since AP-42 Section 11.19.2-2 does not list a TSP emission factor for unloading, the TSP emission factor for rail car unloading was estimated by multiplying the PM10 emission factor by a factor of 3. This factor is consistent with the difference in the TSP and PM 10 emission rate for the conveyor transfer point LS7.


Duke Energy Carolinas - Cliffside ExpansionPotential Emissions Summary

NOx SO2 PM (TSP) PM10 CO VOC H2SO4

(TPY) (TPY) (TPY) (TPY) (TPY) (TPY) (TPY)

Main Boilers

Unit 6 Main Boiler - Unit 6 2,406.8 5,157.5 515.7 825.2 5,157.5 137.5 206.3

Ancillary Combustion Sources

Aux Auxiliary Boiler 8.3 4.3 1.2 2.0 3.0 0.2 0.1

Gen 1 Emergency Generator 1 1.2 0.0 0.0 0.2 0.7 1.2

Pump 1 Diesel Fire-Water Pump 0.1 0.0 0.0 0.0 0.1 0.1

Coal Handling

C27-C30 U6 Tripper Conv. TR2/TR3 15.0 15.0

Fugitives - Material Handling 10.8 2.8

C9, C10 Fugitives - Storage Piles 3.3 1.6

C11 Fugitives - Bulldozing 8.6 4.2

Ash Handling

A6 Fly Ash Silo (3 days total storage) 0.01 0.01


Limestone Handling

LS13 - 1 Limestone Silo #1 0.00 0.00


LS (SDA) Limestone Silo for SDA 0.00 0.00


LS8 Fugitives - Storage Piles 0.2 0.1

LS9 Fugitives - Bulldozing 1.7 0.8

Gypsum Handling


GS5 Fugitives - Storage Piles 0.6 0.3

Landfill - Active Cell


Fugitives - Storage Piles 10.4 5.2

Fugitive Vehicle Emissions

Paved Roads 26.5 5.0

Cooling Tower

CT1 Cooling Tower 12.9 12.9

Fuel Oil Storage Tanks

Fuel Oil Storage Tanks (Combined) 0.1

Total Project Emissions: 2,416.5 5,161.8 607.9 875.9 5,161.2 139.2 206.4

Unit ID Emission Source Description


Duke Energy Carolinas - Cliffside ExpansionMain Boilers - Potential Emissions of PSD Pollutants

Main Boiler Heat Input Rate = 7850 MMBtu/hrMain Boiler Hours of Operation = 8760 Hours/Year

Heat Content of Coal, HHV (design basis) = 9,376 Btu/lb

NOx CO SO2 TSP PM10 VOC H2SO4 HF LeadMain Boiler Emission Factors (lb/MMBtu) = 0.07 0.15 0.150 24-hr, annual 0.015 0.024 0.004 0.006 0.0015 max 2.24E-05

0.150 3-hr 0.0007 avg

(lb/hr) (TPY) (lb/hr) (TPY) (lb/hr) (TPY) (lb/hr) (TPY) (lb/hr) (TPY) (lb/hr) (TPY) (lb/hr) (TPY) (lb/hr) (TPY) (lb/hr) (TPY)Unit 6 Main Boiler - Unit 6 549.5 2406.8 1177.5 5157.5 1177.5 5157.5 117.8 515.7 188.4 825.2 31.4 137.5 47.1 206.3 11.6 22.4 0.2 0.8

549.5 2406.8 1177.5 5157.5 1177.5 5157.5 117.8 515.7 188.4 825.2 31.4 137.5 47.1 206.3 11.6 22.4 0.2 0.8

Notes:Annual hours of operation based on "Annual Pollutant Factor" provided by Duke Power.

HF LeadTSP

Emissions from normal operations are more conservative for short-term and annual emission estimates, since normal operations combust coal versus start-up operations that combust fuel oil. Consequently, start-up and shutdown emissions are not listedseparately.

H2SO4PM10 VOCSO2

Unit IDEmission Source

DescriptionNOx CO

Appendix B 4 of 63 5/29/2007

CALCULATIONS AND COMPUTATIONS

Project Duke Power - CliffsideProject Number:02355-134 Computed by: C. Fleck Date: 9/15/2005Subject Auxiliary Boiler - Emission Calculations Checked by: Bob Hall Date: 10/1/2005

Emission Source: Auxiliary BoilerSource Type: Distillate Oil-Fired BoilerHeat Input (mmBtu/hr): 190.0Maximum Fuel Usage (gal/hr) 1387Number of Units: 1Fuel Oil Heating Value (BTU/gal) 137000Sulfur Content of Fuel (wt. %): 0.05Operating Hours per Year: (e) 876 approximately

Emission Emission Rate - per UnitCompound Factor Hourly (c) Annual (d)

(lbs/MMBtu) (Lbs/Hr) (Tons/Year)Criteria Pollutants

Nitrogen Oxides (a) 0.1 19.00 8.32Carbon Monoxide (a) 0.036 6.84 3.00NMTOC (a) 0.0024 0.46 0.20Sulfur Oxides (b) 0.052 9.85 4.31TSP (a) 0.014 2.66 1.17PM-10 (a) 0.024 4.56 2.00Sulfuric Acid (b) 0.0009 0.17 0.07Lead (b) 9.0E-06 1.7E-03 7.5E-04

Notes:(a) Emission factors (lb/MMBtu) are based on the proposed BACT emission rates for distillate oil-fired boilers. (b) Emission factors based on USEPA AP-42, Section 1.3, Table 1.3-1, dated September 1998 and the sulfur content in fuel listed above.(c) Hourly Emission Rate (Lbs/Hr) = (Heat Input * Emission Factor)(d) Annual Emission Rate (Tons/Yr) = (Hourly Emission Rate, Lbs/Hr) * (Hour of Operation Per Year, Hr/Yr) / (2,000 Lbs/Ton)(e) Operation limited to 10% annual capacity factor

Stack ParametersStack Height 260.0 ftStack Diameter 4.3 ftStack Exit Velocity 59 ft/secExhaust Flow 51,638 ACFMExhaust Temp 324 F

Appendix B 7 of 63 5/29/2007

Calculations and ComputationsHAP Emissions from Duke Power Cliffside Facility

Project: Duke Power CliffsideProject Number: 02355-134 Computed By: C. Hawk Date: 11/29/2005Subject: Fuel Oil-Fired Auxiliary Boiler Checked By: Date:

Non-Criteria Regulated Pollutant Emissions

Distillate Fuel Oil CombustionDistillate Oil-Fired Boiler

EmissionsEmission Emission Rate, Major

Pollutant Type(a) Factor One Boiler Source

AP-42 Section 1.3 9/98 - Fuel Oil Combustion Hourly(e) Annual(f)

(lb/103gal) (d) (lb/1012Btu)(d) Rating (lb/hr) (tpy) (Y/N)

Benzene 2.14E-04 C 190.0 2.97E-04 1.30E-04 NoEthylbenzene 6.36E-05 E 190.0 8.82E-05 3.86E-05 NoFormaldehyde 6.10E-02 C 190.0 8.46E-02 3.71E-02 NoNaphthalene 1.13E-03 C 190.0 1.57E-03 6.86E-04 No1,1,1-Trichloroethane 2.36E-04 E 190.0 3.27E-04 1.43E-04 NoToluene 6.20E-03 D 190.0 8.60E-03 3.77E-03 Noo-Xylene 1.09E-04 E 190.0 1.51E-04 6.62E-05 NoAcenaphthene 2.11E-05 C 190.0 2.93E-05 1.28E-05 NoAcenaphthylene 2.53E-07 D 190.0 3.51E-07 1.54E-07 NoAnthracene 1.22E-06 C 190.0 1.69E-06 7.41E-07 NoBenz(a)anthracene 4.01E-06 C 190.0 5.56E-06 2.44E-06 NoBenzo(b.k)fluoranthene 1.48E-06 C 190.0 2.05E-06 8.99E-07 NoBenzo(g,h,i)perylene 2.26E-06 C 190.0 3.13E-06 1.37E-06 NoChrysene 2.38E-06 C 190.0 3.30E-06 1.45E-06 NoDibenzo(a,h)anthracene 1.67E-06 D 190.0 2.32E-06 1.01E-06 NoFluoranthene 4.84E-06 C 190.0 6.71E-06 2.94E-06 NoFluorene 4.47E-06 C 190.0 6.20E-06 2.72E-06 NoIndo(1,2,3-cd)pyrene 2.14E-06 C 190.0 2.97E-06 1.30E-06 NoPhenanthrene 1.05E-05 C 190.0 1.46E-05 6.38E-06 NoPyrene 4.25E-06 C 190.0 5.89E-06 2.58E-06 NoOCDD 3.10E-09 E 190.0 4.30E-09 1.88E-09 NoArsenic 4.00E-12 E 190.0 7.60E-04 3.33E-04 NoBeryllium 3.00E-12 E 190.0 5.70E-04 2.50E-04 NoCadmium 3.00E-12 E 190.0 5.70E-04 2.50E-04 NoChromium 3.00E-12 E 190.0 5.70E-04 2.50E-04 NoLead 9.00E-12 E 190.0 1.71E-03 7.49E-04 NoMercury 3.00E-12 E 190.0 5.70E-04 2.50E-04 NoManganese 6.00E-12 E 190.0 1.14E-03 4.99E-04 NoNickel 3.00E-12 E 190.0 5.70E-04 2.50E-04 NoSelenium 1.50E-11 E 190.0 2.85E-03 1.25E-03 No

1.05E-01Hours of

OperationDistillate Oil-Fired Boiler 876

Number of Boilers 1Boiler Total HAPs 4.60E-02 No

Maximum Individual HAP 3.71E-02 No

Distillate Oil Heating Value 137,000 Btu/gal (HHV)

Notes:(a) Type = NC for Non-Criteria Pollutants, HAP/POM for compounds included as polycyclic organic matter or HAP for Hazardous Air Pollutant.(b) Maximum heat input rate for the boiler is based on an assumption of a 429.4 MMBtu/hr boiler(d) Emission factors from AP-42, Section 1.3, Tables 1.3-8, 1.3-9 and 1.3-10.(e) Hourly Emission Rate (lb/hr) = [Heat Input Rate (MMBtu/Hr) * Emission Factor (lb/MMBtu)](f) Annual Emission Rate (tpy) = (Maximum Hourly Emission Rate, lb/hr) * (hours/yr) / (2,000 lb/ton)

One Boiler

MaximumHeat Input,

(MMBtu/Hr)(b)

Duke Cliffside - Unit 6 Appendices B and C_052907.xlsAuxiliary Boiler HAPs - U6 8 of 63 5/29/2007


Project: Duke Power - CliffsideProject Number: 02355-134 Computed by: C. Fleck Date: 5/17/2007Subject: Diesel Generator Calculations Checked by: Date:

Emission Source: Emergency GeneratorSource Type: Diesel GeneratorEngine Power (bhp): 2350Heat Input (mmBtu/hr): 16.4Maximum Fuel Usage (gal/hr) 120Number of Units: 1Fuel Oil Heating Value (BTU/gal) 137000Sulfur Content of Fuel (wt. %): 0.0015 (a)Operating Hours per Year: 100

Emission Emission RateCompound Factor Hourly (d) Annual (e)

(g/hp-hr) (Lbs/Hr) (Tons/Year)Nitrogen Oxides (a) 4.80 24.87 1.24Carbon Monoxide (a) 2.60 13.47 0.67TOC (a) 4.80 24.87 1.24Sulfur Oxides (b) 0.0055 0.029 0.001TSP (a) 0.15 0.78 0.04PM-10 (c) 0.75 3.89 0.19

Notes:(a) Emission factors (g/hp-hr) are based on the NSPS Subpart IIIII limits for Stationary Compression Ignition Internal Combustion Engines(b) Emission factors based on USEPA AP-42, Section 3.4, Table 3.4-1, dated October 1996

(d) Hourly Emission Rate (Lbs/Hr) = (Emission Factor, g/hp-hr) * (Engine Power, hp) * (1 lb / 453.6 g)(e) Annual Emission Rate (Tons/Yr) = (Hourly Emission Rate, Lbs/Hr) * (Hour of Operation Per Year, Hr/Yr) / (2,000 Lbs/Ton)

Stack Parameters (Each)Stack Height 22.0 ftStack Diameter 0.8 ftStack Exit Velocity 190 ft/secExhaust Flow 6,200 ACFMExhaust Temp 893 F

(c) Since AP-42 does not provide an emission factor for PM-10, the TSP emission rate was arbitrarily multiplied by a factor of 5 to conservatively estimate the contribution of condensables.

Appendix B 9 of 63 5/29/2007


Project: Duke Power - CliffsideProject Number: 02355-134 Computed by: C. Fleck Date: 5/17/2007Subject: Diesel Fire-Water Pump Engine Calculations Checked by: Date:

Emission Source: Emergency Fire-Water Pump EngineSource Type: Diesel Fueled IC Reciprocating EngineEngine Power (bhp): 430Heat Input (mmBtu/hr): 3.0Maximum Fuel Usage (gal/hr) 21.9Number of Units: 1Fuel Oil Heating Value (BTU/gal) 137000Sulfur Content of Fuel (wt. %): 0.0015 (a)Operating Hours per Year: 100



Notes:(a) Emission factors (g/hp-hr) are based on the NSPS Subpart IIIII limits for Stationary Compression Ignition Internal Combustion Engines(b) Emission factors based on USEPA AP-42, Section 3.4, Table 3.4-1, dated October 1996


Stack ParametersStack Height 22.0 ftStack Diameter 0.8 ftStack Exit Velocity 220 ft/secExhaust Flow 7,440 ACFMExhaust Temp 860 F


Appendix B 10 of 63 5/29/2007

Duke Energy Carolinas - Cliffside ExpansionMaterials Handling - Point Sources

Unit Unit DescriptionC27-C30 U6 Tripper Conv. TR2/TR3 0.01 gr/scf 40,000 acfm (1) 40,000 scfm 3.43 lb/hour

A6 Fly Ash Silo (3 days total storage) 0.01 gr/scf 14.6 acfm (2) 15 scfm 0.00 lb/hourLS13 - 1 Limestone Silo #1 0.01 gr/scf 117.6 acfm (2) 118 scfm 0.01 lb/hourLS13 - 2 Limestone Silo #2 0.01 gr/scf 117.6 acfm (2) 118 scfm 0.01 lb/hourLS (SDA) Limestone Silo for SDA 0.01 gr/scf 117.6 acfm (2) 118 scfm 0.01 lb/hour

Notes:1. Point source is equpped with an exhaust fan. Exhaust flow rate based on fan capacity.2. Point source not equipped with an exhaust fan. Exhaust flow rate based on the material charge rate and density of material charged.

Fly Ash Silo A6: 35 ton/hr charge rate (each) 80 lb/ft3 densityLimestone Silos: 300 ton/hr charge rate (each) 85 lb/ft3 density

Elb/hour = (gr/scf) * (scfm) * (60 min/hour) / (7000 grains/pound)

Unit Unit DescriptionC27-C30 U6 Tripper Conv. TR2/TR3 3.43 lb/hour 24 hrs/day 82.29 lbs/day

A6 Fly Ash Silo (3 days total storage) 0.00 lb/hour 24 hrs/day 0.03 lbs/dayLS13 - 1 Limestone Silo #1 0.01 lb/hour 24 hrs/day 0.24 lbs/dayLS13 - 2 Limestone Silo #2 0.01 lb/hour 24 hrs/day 0.24 lbs/dayLS (SDA) Limestone Silo for SDA 0.01 lb/hour 24 hrs/day 0.24 lbs/day

Note:Elb/day = (lb/hour) * (hrs/day) / (24 hours/day)

Unit Unit DescriptionC27-C30 U6 Tripper Conv. TR2/TR3 3.43 lb/hour 8,760 hrs/year 15.02 tons/year

A6 Fly Ash Silo (3 days total storage) 0.00 lb/hour 8,760 hrs/year 194% 0.01 tons/yearLS13 - 1 Limestone Silo #1 0.01 lb/hour 8,760 hrs/year 8% 0.004 tons/yearLS13 - 2 Limestone Silo #2 0.01 lb/hour 8,760 hrs/year 8% 0.004 tons/yearLS (SDA) Limestone Silo for SDA 0.01 lb/hour 8,760 hrs/year 8% 0.004 tons/year

Notes:Annual emission rates are based on the annual exhaust flow rate and the design outlet concentration of particulates from the fabric filter.For point sources equpped with exhaust fans, annual emissions are based on the exhaust fan operating 8760 hours per year using the following equation

Etons/year = (lb/hour) * (hrs/year) / (2000 lbs/ton)

Etons/year = (lb/hour) * (hrs/year) * Annual Capacity Factor / (2000 lbs/ton)The annual capacity factors are based on the following information:

Fly Ash Silo A6: 35 ton/hr charge rate (each) 594,651 ton/yr annual throughput (each)Limestone Silos: 300 ton/hr charge rate (each) 213,398 ton/yr annual throughput (each)

Capacity FactorAnnual Operating Rate

For point sources without exhaust fans, annual emissions are based on annual throughput rather than operating hours, even though the sources contain material year-round. Annual emissions are estimated using the following equation, which includes an annual capacity factor (the ratio of the annual throguhput to the year-round throughput at the maximum charge rate).

Emission RateEmission Rate

Design Flow Rates Emission Rate

Emission Rate Daily Operating Rate Emission Rate

Appendix B 11 of 63 5/29/2007

Duke Energy Carolinas - Cliffside ExpansionParticulate Emission Sources - Fugitive

PM10 Emission Estimates

Unit Unit Description Process Rate (TPH)

Process Rate (TPY)

Uncontrolled Emission Factor

(lb/ton)

Particle Size Multiplier

Mean Wind Speed (mph)

Material Moisture

Content (%)

Control Efficiency

(%)

Emission Rate (lb/hr)

Emission Rate (lb/day)

Emission Rate (ton/yr)

Coal Handling

C1 Existing Rail Car Unloading 3000 5,422,440 5.89E-04 0.35 7.3 4.5 75 0.44 10.59 0.40

C2 Existing Stockout Conveyor C1 (750 ft) 3,000 5,422,440 5.89E-04 0.35 7.3 4.5 75 0.44 10.59 0.40


C4 Stockout Conveyor SC2 (420 ft) 3,000 5,422,440 5.89E-04 0.35 7.3 4.5 75 0.44 10.59 0.40

C5 Telescopic Chute to Unit 6 Coal Pile (130 feet high) 3,000 5,422,440 5.89E-04 0.35 7.3 4.5 75 0.44 10.59 0.40

C7 Telescopic Chute to Unit 5 Coal Pile (130 feet high)

C12 Existing U5 Reclaim Hoppers

C15 Existing U5 Crusher House 3,000 5,422,440 1.00E-04 0.35 7.3 4.5 90 0.03 0.72 0.03

C17 Existing Conv C4 to U5 Boiler Bldg. (600 ft) 3,000 5,422,440 5.89E-04 0.35 7.3 4.5 75 0.44 10.59 0.40

C18 Existing U5 Tripper Conv. TR1 3,000 5,422,440 5.89E-04 0.35 7.3 4.5 75 0.44 10.59 0.40

C19 U6 Reclaim Hoppers

C27 Reclaim Conv. RC11 to U6 Boiler Bldg. (600 ft)


C29 U6 Tripper Conv. TR2 (200 ft)

C30 U6 Tripper Conv. TR3 (200 ft)Ash Handling

A1 Wet Bottom Ash Bunker

A3 Dry Fly Ash Pickup at Boiler Economizer


A9 Dry Fly Ash Pickup at Precipitator

A12 Fly Ash Discharge to Truck 200 796,651 1.68E-04 0.35 7.3 11.0 30 0.02 0.57 0.05Gypsum Handling

GS1 Discharge from Belt Filter 1


GS3 Stockout Conveyor GSC1 (400 ft) 300 913,445 1.92E-04 0.35 7.3 10.0 75 0.01 0.35 0.02


GS7 Truck Loading 300 913,445 1.92E-04 0.35 7.3 10.0 0 0.06 1.39 0.09

Notes:The particle size multiplier value of 0.35 is based on information from AP-42 Chapter 13.2.4.The mean wind speed value of 7.3 miles per hour was obtained from historical wind speed data from Asheville, NC maintained on the NOAA website.The material moisture contents for coal, bottom ash, fly ash, and limestone are based on engineering estimates.Ash not processed through either A7 or A12, will be processed through A14.

From AP-42, Chapter 13.2.4 - Aggregate Handling & Storage Piles

EF (lb/ton) = k * (0.0032) * [((u/5)^1.3) / ((M/2)^1.4)]

where, EF = Emission Factork = Particle Size Multiplier (dimensionless)U = Mean Wind Speed, [mph]M = Material Moisture Content (%)

Sample Calculation: Unloading Conveyork = 0.35 for PM10

Mean Wind Speed = 7.3 mph (estimated)Material Moisture Content = 4.5 % (based on worst-case coal)

Control Efficiency (Wet Suppression) = 75 %

EF = 5.89E-04 lb/ton PM10Maximum Hourly Stackout Rate = 3,000 TPH E = 0.44 lb/hr PM10

Maximum Daily Stackout Rate = 72,000 TPD E = 10.59 lb/24 hrs PM10Maximum Annual Stackout Throughput = 5,422,440 TPY E = 0.40 TPY

Emissions included with Fugitive Source C5

Emissions included with Point Source C11 (Bulldozing)


Bottom ash has consistency of wet sand. No emissions.

Fly ash pneumatically conveyed to silo. Emissions included with A6 (Fly ash silo)

Gypsum transferred using a screw conveyor. No emissions.




Emissions included with Point Source for U6 Building

For the Unit 5 Crusher (C15), the secondary crushing emission factor ( 0.001 lb PM10/ton coal) was referenced from Section VI - F of the Emissions Inventory Guidance, Mineral Handling and Processing Industries, Mojave Desert AQMD (dated April 2000).

Appendix B 12 of 63 5/29/2007


TSP Emission Estimates


Process Rate (TPY)


(lb/ton)



Material Moisture

Content (%)

Control Efficiency

(%)




Coal Handling

C1 Existing Rail Car Unloading 3,000 5,422,440 1.24E-03 0.74 7.3 4.5 75 0.93 22.40 0.84



C4 Stockout Conveyor SC2 (420 ft) 3,000 5,422,440 1.24E-03 0.74 7.3 4.5 75 0.93 22.40 0.84

C5 Telescopic Chute to Unit 6 Coal Pile (130 feet high) 3,000 5,422,440 1.24E-03 0.74 7.3 4.5 75 0.93 22.40 0.84

C7 Telescopic Chute to Unit 5 Coal Pile (130 feet high)

C12 Existing U5 Reclaim Hoppers

C15 Existing U5 Crusher House 3,000 5,422,440 1.80E-02 0.74 7.3 4.5 90 5.40 129.60 4.88

C17 Existing Conv C4 to U5 Boiler Bldg. (600 ft) 3,000 5,422,440 1.24E-03 0.74 7.3 4.5 75 0.93 22.40 0.84

C18 Existing U5 Tripper Conv. TR1 3,000 5,422,440 1.24E-03 0.74 7.3 4.5 75 0.93 22.40 0.84

C19 U6 Reclaim Hoppers





Ash Handling

A1 Wet Bottom Ash Bunker



A9 Dry Fly Ash Pickup at Precipitator

A12 Fly Ash Discharge to Truck 200 796,651 3.56E-04 0.74 7.3 11.0 30 0.05 1.20 0.10

Gypsum Handling





GS7 Truck Loading 300 913,445 4.07E-04 0.74 7.3 10.0 0 0.12 2.93 0.19

Notes:The particle size multiplier value of 0.74 is based on information from AP-42 Chapter 13.2.4.The mean wind speed value of 7.3 miles per hour was obtained from historical wind speed data from Asheville, NC maintained on the NOAA website.The material moisture contents for coal, bottom ash, fly ash, and limestone are based on engineering estimates.

For the Unit 5 Crusher (C15), the secondary crushing emission factor ( 0.018 lb TSP/ton coal) was referenced from Section VI - F of the Emissions Inventory Guidance, Mineral Handling and Processing Industries, Mojave Desert AQMD (dated April 2000).

Emissions included with Fugitive Source C5


Bottom ash has consistency of wet sand. No emissions.

Emissions included with Point Source for U6 Building



For gypsum handling operations, gypsum can be loaded in trucks or railcars. To avoid double-counting annual TSP and PM10 emissions, emission from truck loading were used in the annual estimates because truck loading represents the wort-case loading scenario from an emissions standpoint.





Appendix B 13 of 63 5/29/2007

Duke Energy Carolinas - Cliffside ExpansionParticulate Emission Sources - Limestone Handling Fugitive

From AP-42, Chapter 11.19.2 - Crushed Stone ProcessingPM10 Emission Estimates


Process Rate (TPY)


(lb/ton)



Material Moisture

Content (%)

Control Efficiency

(%)




Limestone Handling

LS1 Rail Car Unloading 1,800 426,796 0.0001 50 0.09 2.16 0.01

LS2 Stockout Conveyor LSC1 (250 ft) 1,800 426,796 0.0011 75 0.50 11.88 0.06


LS10 Reclaim Hoppers

LS11 Reclaim Conv. LRC1 (450 ft)

LS14 Hydraulic Conveyor to FGD Areas



Process Rate (TPY)


(lb/ton)



Material Moisture

Content (%)

Control Efficiency

(%)




Limestone Handling

LS1 Rail Car Unloading 1,800 426,796 0.0003 50 0.27 6.48 0.03



LS10 Reclaim Hoppers

LS11 Reclaim Conv. LRC1 (450 ft)

LS14 Hydraulic Conveyor to FGD AreasNote:Since AP-42 Section 11.19.2-2 does not list a TSP emission factor for unloading, the TSP emission factor for rail car unloading was estimated by multiplying the PM10 emission factor by a factor of 3. This factor is consistent with the difference in the TSP and PM10 emission rate for the conveyor transfer points (LS7).

Emissions included with Point Source LS13

Emissions included with Point Source LS13

Emissions included with Point Source LS9 (Bulldozing)

Emissions included with Point Source LS9 (Bulldozing)

Limestone Transferred in a Slurry

Limestone Transferred in a Slurry

Appendix B 14 of 63 5/29/2007


PM10 Emission Estimates


Process Rate (TPY)


(lb/ton)



Material Moisture

Content (%)

Control Efficiency

(%)




Ash Handling

Fly Ash Discharge to Active Cells 90 796,651 7.29E-05 0.35 7.3 20.0 0 0.01 0.16 0.03

Gypsum Handling

Gypsum Discharge to Active Cells 90 913,445 1.92E-04 0.35 7.3 10.0 0 0.02 0.42 0.09

Notes:

The process rate for material delivery is estimated as 90 TPH per material, which is equivalent to 10 x 15 ton truck deliveries per hour.The particle size multiplier value of 0.35 is based on information from AP-42 Chapter 13.2.4.The mean wind speed value of 7.3 miles per hour was obtained from historical wind speed data from Asheville, NC maintained on the NOAA website.The material moisture contents for fly ash and gypsum are estimated at 25% based on engineering estimates.

From AP-42, Chapter 13.2.4 - Aggregate Handling & Storage Piles

EF (lb/ton) = k * (0.0032) * [((u/5)^1.3) / ((M/2)^1.4)]

where, EF = Emission Factork = Particle Size Multiplier (dimensionless)U = Mean Wind Speed, [mph]M = Material Moisture Content (%)

Sample Calculation: Material Deliveryk = 0.35 for PM10

Mean Wind Speed = 7.3 mph (estimated)Material Moisture Content = 20.0 % (based on worst-case coal)

Control Efficiency (Wet Suppression) = 0 %

EF = 7.29E-05 lb/ton PM10Maximum Hourly Rate = 90 TPH

Maximum Daily Rate = 2,160 TPDMaximum Annual Throughput = 796,651 TPY

E = 0.01 lb/hr PM10E = 0.16 lb/24 hrs PM10E = 0.03 TPY

Appendix B 15 of 63 5/29/2007




Process Rate (TPY)


(lb/ton)



Material Moisture

Content (%)

Control Efficiency

(%)




Ash Handling

Fly Ash Discharge to Active Cells 90 796,651 1.54E-04 0.74 7.3 20.0 0 0.01 0.33 0.06

Gypsum Handling

Gypsum Discharge to Active Cells 90 913,445 4.07E-04 0.74 7.3 10.0 0 0.04 0.88 0.19

Notes:The particle size multiplier value of 0.74 is based on information from AP-42 Chapter 13.2.4.The mean wind speed value of 7.3 miles per hour was obtained from historical wind speed data from Asheville, NC maintained on the NOAA website.The material moisture contents for coal, bottom ash, fly ash, and limestone are based on engineering estimates.

Appendix B 16 of 63 5/29/2007


Project: Duke Power - Cliffside ExpansionProject Number: 02355-134 Computed by: Chris Fleck Date: 5/16/2005Subject: Preliminary Cooling Tower Emissions Checked by: Bob Hall Date: 10/1/2005

Water Circulation Rate (a) all cells (GPM) 393,414No of Cells 22

Total Liquid Drift (b) (%) 0.0005

Expected TDS/TSS of Circulated Water (c) (ppmw) 3000

Emission Rate - Total Cooling TowerTotal Suspended Particulate (d) (Lbs/Hr) 2.95

(Tons/Yr) 12.94PM-10 (e) (Lbs/Hr) 2.95

(Tons/Yr) 12.94Emission Rate - Per Cell (f)

Total Suspended Particulate (Lbs/Hr) 0.13(Tons/Yr) 0.59

PM-10 (Lbs/Hr) 0.13(Tons/Yr) 0.59

Notes: (a) Design Water Circulation Rate, Gallons/Minute (GPM)(b) Design Total Liquid Drift, Percent (%)(c) Process Design Data of 3000 ppmw in circulating water(d) Based on USEPA AP-42 Section 13.4 Wet Cooling Towers, Table 13.4-1 dated 1/95. Modified to Cooling Tower Design Lbs/Hr = (Water Circulation Rate,GPM)*60*(Drift,%) / 100 * (8.3453 Lbs/Gal) * (TDS, Lbs PM/1,000,000 Lbs Water) Tons/Yr = (Lbs/Hr) * (8,760 Hrs/Yr) / (2,000 Lbs/Ton) (e) PM-10 based on 100% of TSP. Assumed that PM-10 generated by water droplets with a diameter of less than 100 microns which account for 100% of emitted from typical cooling tower.(f) Cooling tower has 24 cells. Each emits 1/24 of total tower emissions.

Stack Parameters (Each Cooling Tower)Number of Stacks 18 - 24Stack Height 57.0 ftStack Diameter 32.8 ftStack Exit Velocity 26 ft/secExhaust Flow 1,310,685 ACFMExhaust Temp 90 F

Stack parameters provided by Duke Power.

Appendix B 17 of 63 5/29/2007

Duke Energy Carolinas - Cliffside ExpansionCoal Handling - Coal Pile Wind Erosion

From Emissions Inventory Guidance, Mineral Handling and Processing Industries , Mojave Desert AQMD

E = Ef * AEf = J * 1.7 * ((sL)/1.5) * ((365-P) / 235) * (I/15) * (365/2000)

Where,

E = Particulate matter emission rate in tons/yrEf = Emission Factor in tons/acre-yrA = Exposed surface area of stockpile (acres)J = Particulate aerodynamic factor

J (TSP) = 1.0J (PM10) = 0.5J (PM2.5) = 0.2

sL = Average silt loading of storage pile (%)P = Average number of days/yr with at least 0.01 inch of precipitationI = Percent of time with unobstructed wind speed > 12 mph (%)

Coal Pile Wind Erosion Assumptions

Silt Loading = 4.8 % (AP-42 Section 13.2.4, Table 13.2.4-1) Conservative Days with Precipitation = 120 days (AP-42 Section 13.2.2)

Conservative Windy Hours = 11.28 % (Wind data from Charlotte/Douglas Airport, 1987-1991)Acreage of Coal Pile = 16.9 acres (Provided by Duke Power)

Active Coal Pile

Control Efficiency (Dust Suppression) = 75 %

PM10 Emissions: Ef = 3.89E-01 tons/acre-yr (uncontrolled)

E = 0.38 lb/hrE = 9.01 lb/24 hrE = 1.64 TPY

TSP Emissions: Ef = 7.78E-01 tons/acre-yr (uncontrolled)

E = 0.75 lb/hrE = 18.02 lb/24 hrE = 3.29 TPY

Appendix B 18 of 63 5/29/2007

Duke Energy Carolinas - Cliffside ExpansionLimestone Storage Pile Wind Erosion


E = Ef * AEf = J * 1.7 * ((sL)/1.5) * ((365-P) / 235) * (I/15) * (365/2000)

Where,


J (TSP) = 1.0J (PM10) = 0.5J (PM2.5) = 0.2


Limestone Pile Wind Erosion Assumptions

Silt Loading = 1.5 % (from table 2 for "crushed limestone" as stockpile material)Conservative Days with Precipitation = 120 days (AP-42 Section 13.2.2)

Conservative Windy Hours = 11.28 % (Wind data from Charlotte/Douglas Airport, 1987-1991)Acreage of Limestone Pile = 0.7 acres (Provided by Duke Power)

ACTIVE LIMESTONE PILEControl Efficiency = 0 %

PM10 Emissions: Ef = 1.22E-01 tons/acre-yr (uncontrolled)

E = 0.02 lb/hrE = 0.47 lb/24 hrE = 0.09 TPY

TSP Emissions: Ef = 2.43E-01 tons/acre-yr (uncontrolled)

E = 0.04 lb/hrE = 0.93 lb/24 hrE = 0.17 TPY

Appendix B 19 of 63 5/29/2007

Duke Energy Carolinas - Cliffside ExpansionGypsum Storage Pile Wind Erosion


E = Ef * A

Ef = J * 1.7 * ((sL)/1.5) * ((365-P) / 235) * (I/15) * (365/2000)

Where,


J (TSP) = 1.0J (PM10) = 0.5J (PM2.5) = 0.2


Gypsum Pile Wind Erosion Assumptions

Silt Loading = 80 % (estimate)Conservative Days with Precipitation = 120 days (AP-42 Section 13.2.2)

Conservative Windy Hours = 11.28 % (Wind data from Charlotte/Douglas Airport, 1987-1991)Acreage of Gypsum Pile = 0.45 acres (Provided by Duke Power)

GYPSUM PILEControl Efficiency (Eng. Judgment) = 90 % (Wet Material - High Moisture Content - Crusting)

PM10 Emissions: Ef = 6.49E+00 tons/acre-yr (uncontrolled)

E = 0.07 lb/hrE = 1.60 lb/24 hrE = 0.29 TPY

TSP Emissions: Ef = 1.30E+01 tons/acre-yr (uncontrolled)

E = 0.13 lb/hrE = 3.20 lb/24 hrE = 0.58 TPY

Appendix B 20 of 63 5/29/2007

Duke Energy Carolinas - Cliffside ExpansionLandfill Active Cell Wind Erosion


E = Ef * A

Ef = J * 1.7 * ((sL)/1.5) * ((365-P) / 235) * (I/15) * (365/2000)

Where,


J (TSP) = 1.0J (PM10) = 0.5

J (PM2.5) = 0.2sL = Average silt loading of storage pile (%)P = Average number of days/yr with at least 0.01 inch of precipitationI = Percent of time with unobstructed wind speed > 12 mph (%)

Landfill Active Cell Wind Erosion Assumptions

Type of Material Landfilled Gypsum Fly Ash Bottom Ash Totals

Silt Loading 80 80 0

Conservative Days with Precipitation 120 120 120

Conservative Windy Hours (% of annual) 11.28 11.28 11.28

Acreage of Active Cells (acres) 2 2 0 4Control Factor (%) 80 80 80

PM10 EmissionsPM10 Emissions, Ef (ton/acre-yr) 1.30 1.30 0.00

PM10 Emissions (lb/hr) 0.59 0.59 0.00 1.18PM10 Emissions (lb/24-hr day) 14.22 14.22 0.00 28.43

PM10 Emissions (ton/yr) 2.59 2.59 0.00 5.19

TSP EmissionsTSP Emissions, Ef (ton/acre-yr) 2.59 2.59 0.00

TSP Emissions (lb/hr) 1.18 1.18 0.00 2.37

TSP Emissions (lb/24-hr day) 28.43 28.43 0.00 56.87TSP Emissions (ton/yr) 5.19 5.19 0.00 10.38

Notes:The silt loading values are based on typical values for the type of material landfilled.The number of conservative days with precipitation is based on the information contained in AP-42 Section 13.2.2.The percentage of windy hours per year is based on historical wind data (1987-1991) from Charlotte/Douglas Airport.The acreage of active cells is based on engineering judgment.The particulate emissions from the storage of materials in the active landfill cells are estimated using the same methodology as that used for the estimation of fugitive particulate emissions for storage piles. However, a control factor of 80% was applied to the methodology to account for the reduction in particulate emissions due to the wet compaction of materials added to the landfill.

Appendix B 21 of 63 5/29/2007

Duke Energy Carolinas - Cliffside ExpansionBulldozing of Coal Pile

From Mojave Desert AQMD Emissions Inventory Guidance for Bulldozing, Scraping and Grading of Materi(Methdology Derived From AP-42, Chapter 11.9 - Western Surface Coal Mining)

EPM10 (lb/hr) = [2.76 * k(PM10) * s1.5] / M1.4

ETSP (lb/hr) = [2.76 * k(TSP) * s1.5] / M1.4

Where,

EPM10 = Emissions for PM10 (lb/hr)

ETSP = Emissions for TSP (lb/hr)kPM10 = 0.36 (dimensionless)kTSP = 0.74 (dimensionless)

s = Material silt content (%)M = Material Moisture Content (%)

Coal Bulldozing Assumptions

Material Silt Content = 4.8 % Material Moisture Content = 4.5 % (based on moisture content for material handling source

Size of Active Coal Pile = 16.9 Acres (consistent with storage pile acreage)Control Efficiency (Wet Suppression) = 75 % (consistent with storage pile information)

Maximum Hours/Day of Bulldozing = 72 Hours/Day (Based on 3 bulldozers operating 24 hr/day)Maximum Hours/Year of Bulldozing = 26,280 Hours/Year (Based on 2 bulldozers operating 365 day/yr

PM10 Emissions: E = 0.32 lb/hrE = 22.90 lb/24 hrsE = 4.18 TPY

TSP Emissions: E = 0.65 lb/hr E = 47.07 lb/24 hrsE = 8.59 TPY

Appendix B 22 of 63 5/29/2007

Duke Energy Carolinas - Cliffside ExpansionBulldozing of Limestone Pile

From Mojave Desert AQMD Emissions Inventory Guidance for Bulldozing, Scraping and Grading of Materials (Methdology Derived From AP-42, Chapter 11.9 - Western Surface Coal Mining)

EPM10 (lb/hr) = [2.76 * k(PM10) * s1.5] / M1.4

ETSP (lb/hr) = [2.76 * k(TSP) * s1.5] / M1.4

Where,

EPM10 = Emissions for PM10 (lb/hr)ETSP = Emissions for TSP (lb/hr)

kPM10 = 0.36 (dimensionless)kTSP = 0.74 (dimensionless)

s = Material silt content (%)M = Material Moisture Content (%)

Limestone Bulldozing Assumptions

Material Silt Content = 1.5 % Material Moisture Content = 5 % (based on Duke estimate for moisture content at storage pile)

Size of Active Limestone Pile = 0.7 Acres (consistent with storage pile acreage)Control Efficiency (Partial Enclosure) = 0 % (consistent with storage pile information)

Maximum Hours/Day of Bulldozing = 24 Hours/Day (Based on 1 bulldozer operating 24 hr/day)Maximum Hours/Year of Bulldozing = 8,760 Hours/Year (Based on 1 dozer operating 365 day/yr)

PM10 Emissions: E = 0.19 lb/hrE = 4.60 lb/24 hrsE = 0.84 TPY

TSP Emissions: E = 0.39 lb/hr E = 9.46 lb/24 hrsE = 1.73 TPY

Appendix B 23 of 63 5/29/2007

Duke Energy Carolinas - Cliffside ExpansionCalculation of Paved Roadway EmissionsCurrent AP-42 Program Emission Factors

Equation from AP-42 Chapter 13.2.1, December 2003

Equation 2 - Annual EmissionsE(lb PM10/VMT) = [k(sL/2)0.65 * (W/3)1.5 - C] * [1-P/4N] * [1-CE]

Equation 3 - Daily/Hourly EmissionsE(lb PM10/VMT) = [k(sL/2)0.65 * (W/3)1.5 - C] * [1-CE]

Input VariablesDescription Variable ValueParticle size multiplier for PM10 (lb/VMT) k 0.016Particle size multiplier for TSP (lb/VMT) k 0.084

Road surface silt loading (g/m2) sL 1.2Mean vehicle weight (tons) W Varies1

Exhaust, Brake Wear & Tire Wear for PM10 (lb/VMT) C 0.00047

Number of days in the averaging period N (days) 365Number of hours in the averaging period N (hrs) 8760

Number of days with at least 0.254mm (0.01in) of precipitation during the averaging period. P (days) 120Number of hours with at least 0.254mm (0.01in) of precipitation during the averaging period. P (hours) 2880Control Efficiency (water washing, cleaning) CE 90%

Notes:1Mean vehicle weight (W) varies depending on the vehicles using the road as highlighted below

One-way distance for delivery trucks RT miles miles/day miles/year tons/trip ton/yr trip/yrDaily / Annual truck hauling trips of Ammonia (Unit 5) 1.6 1.6 584 15 5,475 365Daily / Annual truck hauling trips of Ammonia (Unit 6 ) 1 1.0 365 15 5,475 365Daily / Annual truck hauling trips of Acid/Caustic (Unit 5) 1.6 1.6 584 15 5,475 365Daily / Annual truck hauling trips of Acid/Caustic (Unit 6 ) 1 1.0 365 15 5,475 365Daily / Annual truck hauling trips of Fuel Oil (Unit 5) 1.6 1.6 584 15 5,475 365Daily / Annual truck hauling trips of Fuel Oil (Unit 6) 1 1.0 365 15 5,475 365Number of trips Daily 8 Annual 2847 Assumes 22 ton/truck

One-way distance for disposal trucks RT miles miles/day miles/year tons/trip ton/yr trip/yrDaily / Annual truck hauling trips Bottom Ash (Unit 5) 2.9 27.0 9,860 15 51,000 3,400Daily / Annual truck hauling trips Bottom Ash (Unit 6) 2.2 49.6 18,117 15 123,520 8,235Daily / Annual truck hauling trips of Fly Ash (Unit 5) 2.9 107.0 39,054 15 202,000 13,467Daily / Annual truck hauling trips of Fly Ash (Unit 6) 2.2 238.9 87,215 15 594,651 39,643Daily / Annual truck hauling trips of Lime (Unit 6) 1.3 3.1 1,139 15 13,140 876Daily / Annual truck hauling trips of Gypsum (Unit 5) 2.5 175.4 64,015 15 384,087 25,606Daily / Annual truck hauling trips of Gypsum (Unit 6 ) 2.5 241.7 88,228 15 529,358 35,291Number of trips Daily 842.8 Annual 307,627

Vehicle Information

Vehicle Type

Empty Weight (tons)

Loaded Weight (tons) VMT/day VMT/yr

Average Vehicle Weight (tons)

Delivery Trucks 22 37 7.80 2,847 30Disposal Trucks 22 37 842.81 307,627 30

850.61 310,474

Controlled Paved Roadway EmissionsE(lb/VMT)

(daily)E(lb/VMT)

(annual)PM10

(lb/hr)1PM10 (TPY)

Delivery Trucks 0.035 0.03 0.01 0.05

Disposal Trucks 0.035 0.03 1.24 4.99Total Controlled Paved Roadway Emissions 1.25 5.04

Controlled Paved Roadway EmissionsE(lb/VMT)

(daily)E(lb/VMT)

(annual)TSP

(lb/hr)1TSP

(TPY)

Delivery Trucks 0.186 0.17 0.06 0.24

Disposal Trucks 0.186 0.17 6.52 26.23Total Controlled Paved Roadway Emissions 6.58 26.47Notes:1Assume VMTs occur equally over a 24 hour period

(assumes range of 'quarry' industry as representative to flyash hauling)

Number of wet days assumed 60 based on map in figure 13.2.2-1. Based on 0 for worst-case hourly assumption

Appendix B 24 of 63 5/29/2007

Duke Energy Carolinas - Cliffside ExpansionFuel Oil Storage Tanks

Emission calculations were performed using EPA TANKS Version 4.0 software.

Units 6

Tank Description Capacity Orientation Tank Diameter

Tank Height

Annual Throughput

Number of Turnovers

Turnover Factor

Kn:

Breathing Losses

Working Losses

Total Losses

Total Losses

(Gallons) (Feet) (Feet) (gallons) (lb/yr) (lb/yr) (lb/yr) (TPY)Unit 6 Start-Up/Aux. Boiler Fuel Oil Tank #1 168,000 Vertical 31 30 10,841,168 64.5 0.63 24.60 124.87 149.47 0.07Emergency Diesel Generator #1 Fuel Oil Tank 1,640 Horizontal 5 12 11,985 7.3 1.00 0.30 0.22 0.52 0.00Fire Water Pump Fuel Oil Tank 350 Horizontal 3 6.5 2,193 6.3 1.00 0.06 0.04 0.10 0.00Quench Pump Fuel Oil Tank 350 Horizontal 3 6.5 7,344 21.0 1.00 0.06 0.13 0.19 0.00Totals 10,862,690 150.28 0.08Notes:The annual throughput for Unit 6 Start-Up/Aux Boiler tank is based on the following assumptions: The throughput will be based on each unit having 40 start-ups per year. Each start-up will last for 6 hours (on fuel oil) with the boiler operating at 35% of maximum capacity. The annual throughput for the auxiliary boiler is split is included in the total tank throughput. The annual throughputs for the diesel generator and water pump tank are based on the fuel consumption rate for the combustion units associated with the tanks.

APPENDIX C: NETTING ANALYSIS

May 2007

Duke Energy Carolinas - Cliffside ExpansionPSD Applicability Determination and Netting Analysis for Proposed Project

PSD Applicability Determination Summary

NOx SO2 PM (TSP) PM10 CO VOC H2SO4 HF Lead

(TPY) (TPY) (TPY) (TPY) (TPY) (TPY) (TPY) (TPY) (TPY)

1504 423 243 558 5096 131 173 4 0.7

-1466 -5842 22 7 0 1 0 -4 0.0

39 -5,419 265 564 5,097 132 173 0 0.7

40 40 25 15 100 40 7 3 0.6

No No Yes Yes Yes Yes Yes No YesNotes:Total Net Impact = Emissions Increases + Other Contemporaneous Emissions Increases / DecreasesEmission decreases are specified with a negative value.

Potential Emissions Increases - Proposed Project



Unit 6 Main Boilers - Units 6 2,406.8 5,157.5 515.7 825.2 5,157.5 137.5 206.3 22.4 0.8

Ancillary Sources - Combustion (Unit 6) 9.7 4.3 9.2 2.2 3.8 1.6 0.1 0.0 0.0

Ancillary Sources - Combustion (Unit 5) 45.9 720.6

Ancillary Sources - Non-Combustion 67.4 41.2 0.0

Creditable Decreases - Retiring Units 1-4 -958.3 -5,459.2 -349.0 -311.1 -65.0 -7.8 -33.4 -18.5 -0.1

Potential Emissions Increase 1,504.2 423.1 243.3 557.6 5,096.2 131.3 173.0 3.9 0.7Notes:Unit 6 boiler is a new sources. Potential emissions from main boilers are based on operating at full capacity year-round.

Creditable Emission Decreases (Retire Units #1-4)



1,197

720

6,794 451 401 81 10 42 23 0.1

4,124 248 221 49 6 25 14 0.1

958 5,459 349 311 65 8 33 19 0.1

Other Contemporaneous Increases / Decreases (Unit 5 Scrubber Project)



1 0 22 7 0 1 0 0 0.0

-1466 -5842 0 0 0 0 0 -4 0.0

-1466 -5842 22 7 0 1 0 -4 0.0Notes:The proposed project is scheduled to commence operation in calendar year 2011. For netting purposes, the contemporaneous period is calendar years 2004-2011.The potential emissions increase is due to the installation of materials handling equipment in support of Unit #5.Creditable emission decreases for SO 2, HF, and H2SO4 are available due to the installation of a wet flue gas desulfurization (FGD) unit on Unit 5.

PSD Avoidance ConditionHF

(ton/yr)Historical HF Emissions: 95.7 ton/yr Baseline Actual Emissions: 95.7

Future HF Emissions: 91.8 ton/yr Offsets for Unit 6 & Ancillary Combustion Sources: -3.9HF Emission Credits Used for Netting: 3.9 ton/yr PSD Limit for Unit 5 after Unit 6 Installed: 92

Duke Energy will offset SO2 emissions increases from the addition of Unit 6 using credit for reductions on Unit 5 based on future operation of the flue gas desulfurization system. While Units 1 -4 will be retired, those reductions are not being used to offset increased emissions, and Duke Energy requests that those reductions be reserved as net reductions for any future projects that may fall within the contemporaneous period. Duke Energy will assure compliance by taking a limit on annual emissions less than or equal to the current baseline emissions of 25,871 tons plus the allowable PSD increase of 40 tons per year.

Duke Energy will offset NOx emissions from the addition of Unit 6 by taking credit for retiring Units 1-4 and credit for reductions on Unit 5 as a result of additional operation of the installed SCR system. Duke Energy will assure compliance by taking a limit of annual emissions less than or equal to the current baseline of 6,386 tons per year plus the allowable PSD increase of 40 tons per year.

The creditable emissions reductions for HF are based on the following:

Proposed Project Subject to PSD?

Creditable Emissions Used (from Unit 5)

For Unit #5, there are no creditable emissions for NO x, CO, VOC, PM, PM10, and lead due to the installation of the wet flue gas desulfurization (FGD) unit. For determining the net increases of these pollutants, the future actual throughput (heat input) is assumed equal to the historical actual throughput as allowed by the WEPCO rule. Since the emission rates of these pollutants are unchanged, the net increase for each pollutant is zero.

Total Contemporaneous Increases/Decreases

The ancillary combustion sources are new installations. Potential emissions from ancillary combustion sources are based on unit-specific emissions factors and annual fuel consumption limitations, which are specified in Appendix B.

The ancillary non-combustion sources consist of new installations, existing sources with emission increases due to increased annual throughput, and existing sources with potential emissions that are unaffected by the proposed changes.

Description of Emissions Increase/Decrease

Potential Emissions Increase

To ensure expected reductions in emissions from Unit 5 are creditable, the facility is proposing to take a Federally enforceable limit on future SO 2 and HF emissions from Unit #5. Emission credits will be requested only to the extent necessary to offset the potential emissions increase from the proposed project. No emission reduction credits are requested for H 2SO4 because there are not sufficient emission reduction credits available to offset the new emissions from the proposed project.


Units #1 -4 Actual Emissions - 2004

Creditable Emissions (2-Year Average)



Per NC DENR's request, both existing and new ancillary combustion sources are included in the netting analysis. Existing ancillary combustion sources are the Unit 5 Auxiliary Boiler (ES-6) and the Emergency Generator (ES-12).


Potential Emissions Increases - Proposed Project

Other Contemporaneous Increases/Decreases

Total Net Impact

PSD Threshold

Units #1 - 4 will be retired as part of the proposed project.



Appendix C 26 of 63 5/29/2007

Duke Energy Carolinas - Cliffside ExpansionPotential Emission Increases Due to Proposed Project



Main Boilers

Unit 6 Main Boiler - Unit 6 2,406.8 5,157.5 515.7 825.2 5,157.5 137.5 206.3


Aux Auxiliary Boiler 8.3 4.3 4.6 2.0 3.0 0.2 0.1

Gen 1 Emergency Generator 1 1.2 0.0 3.9 0.2 0.7 1.2

Pump 1 Diesel Fire-Water Pump 0.1 0.0 0.7 0.0 0.1 0.1

Coal Handling

C27-C30 U6 Tripper Conv. TR2/TR3 15.0 15.0

Fugitives - Material Handling (2) 9.5 2.2

Fugitives - Storage Piles (3) 0.0 0.0

Fugitives - Bulldozing (3) 5.7 2.8

Ash Handling

A6 Fly Ash Silo (3 days total storage) 0.01 0.01


Limestone Handling

LS13 - 1 Limestone Silo #1 (1) 0.0 0.0

LS13 - 2 Limestone Silo #2 (1) 0.0 0.0



Fugitives - Bulldozing 0.2 0.1

Gypsum Handling


Fugitives - Storage Piles (3) 0.6 0.3





Paved Roads (4) 12.2 2.3

Cooling Tower

CT1 Cooling Tower 12.9 12.9

Fuel Oil Storage Tanks

Fuel Oil Storage Tanks (Combined) 0.1

Total Project Emissions: 2,416.5 5,161.8 592.3 868.6 5,161.2 139.2 206.4Notes:

3) Potential emissions from coal storage piles are unchanged due to the proposed project because the potential acreage of the coal storage piles does not increase. For coal bulldozing operations, the number of coal bulldozers (operating annually) changes from 1 to 3. 4) Potential emissions from fugitive vehicle emissions increases due to the increased truck traffic required to transport additional raw materials on-site and to transport additional coacombustion products to the on-site landfill. The net increase in potential emissions due to the increased truck traffic is provided in the table above.


1) Emission source is located at the facility prior to the proposed modification. The net emission increase for this source is zero because the source is currently under construction and potentiaemissions from this source do not increase due to proposed project.2) Emission source is located at the facility prior to the proposed modification. However, the potential annual throughput for these sources increase due to the proposed project, resulting in an annual emissions increase. The net emission increase for these sources is provided in the table above.

Appendix C Page 27 of 63 5/29/2007

Duke Energy Carolinas - Cliffside ExpansionPotential Emissions from Sources Installed in Unit 5 Scrubber Project




Unit 5 Pump Unit 5 Quench Water Pump 0.3 0.0 0.1 0.1 0.2 0.3

Pump 1 Unit 5 Diesel Fire-Water Pump 0.4 0.0 0.0 0.1 0.1 0.4

Coal Handling



Fugitives - Bulldozing 2.9 1.4

Limestone Handling




LS8 Fugitives - Storage Piles 0.00 0.00

LS9 Fugitives - Bulldozing 0.00 0.00

Gypsum Handling


GS5 Fugitives - Storage Piles 0.00 0.00





Paved Roads 14.3 2.7

Total Project Emissions: 0.6 0.0 21.9 6.6 0.4 0.6 0.0Notes:

For coal bulldozing emissions for Unit 5, it is assumed that only 1 bulldozer was operated year-round.Although limestone handling, gypsum handling and landfill operations were included in the Unit 5 scrubber project, this equipment has not Emissions from the vehicle traffic are based on the existing truck deliveries for the Unit 5 boiler. Potential emissions from coal storage piles are unchanged due to the proposed project because the potential acreage of the coal storage piles does not increase.


The ancillary combustion sources were permitted in the Unit 5 Scrubber project and are considered as contemporaneous increase for the Unit 6 netting analysis.Emissions from the coal handling operations are based on the annual throughput and existing coal conveyors used for the Unit 5 boiler.

Appendix C Page 28 of 63 5/29/2007

Duke Power - Cliffside ExpansionActual to Future Emissions for Project

Baseline EmissionsNOx SO2

(ton/yr) (ton/yr)

Units 1 - 4 (2001-2002 Average) 958

Unit 5 (2001-2002 Average) 5,428

Units 1 - 4 (2003-2004 Average) 5,459

Unit 5 (2003-2004 Average) 25,871

Ancillary Sources (Assumed at Zero - No Credit Taken For Baseline Emissions) 0 0

Total Baseline Emissions 6,386 31,330

Project Future EmissionsNOx SO2

(ton/yr) (ton/yr)

Units 1 - 4 Projected Actual Emissions 0 0

Unit 5 - Future Emissions for Netting 3,964 20,028

Existing and New Ancillary Combustion Sources - Potential to Emit (1) 56 725

Unit 6 Boiler (New) - Potential to Emit 2,407 5,157

Total Future Potential Emissions 6,426 25,911

Net Project Emissions

Proposed NOx Rate for Unit 6 = 0.07 lb NOx/MMBtu (annual avg.)Proposed SO2 Rate for Unit 6 = 0.15 lb SO2/MMBtu (annual avg.)

NOx SO2

(ton/yr) (ton/yr)

Unit 6 Boiler (New) 2,407 5,157

Ancillary Combustion Sources (1) 56 725

Creditable Decrease (Units 1-4) (2) -958 -5,459

Creditable Decrease (Unit 5) (2) -1,466 -5,842

Total Project Emissions Increase: 40 -5,419

Notes

Key Parameters

Unit 6 Boiler Unit 1 - 4 BoilersHeat Input Rate = 7850 MMBtu/hr Past Actual NOx Emissions = 958 ton/yr

Operating Hours = 8760 hr/yr Past Actual SO2 Emissions = 5,459 ton/yr

Unit 5 Boiler

Past Actual NOx Emissions = 5,428 ton/yrFuture Projected NOx Emissions = 3,962 ton/yr

Net Decrease (Creditable) = -1,466 ton/yr

Past Actual SO2 Emissions = 25,871 ton/yr

Future Projected SO2 Emissions = 20,028 ton/yr


2) Duke Energy will offset SO2 emissions increases from the addition of Unit 6 using credit for reductions on Unit 5 based on future operation of the flue gas desulfurization system. While Units 1 -4 will be retired, those reductions are not being used to offset increased emissions, and Duke Energy requests that those reductions be reserved as net reductions for any future projects that may fall within the contemporaneous period. Duke Energy will assure compliance by taking a limit on annual emissions less than or equal to the current baseline emissions of 25,871 tons plus the allowable PSD increase of 40 tons per year.

3) Duke Energy will offset NOx emissions from the addition of Unit 6 by taking credit for retiring Units 1-4 and credit for reductions on Unit 5 as a result of additional operation of the installed SCR system. Duke Energy will assure compliance by taking a limit of annual emissions less than or equal to the current baseline of 6,386 tons per year plus the allowable PSD increase of 40 tons per year.

Emission Source Description - Project Future Emissions

Emission Source Description - Baseline Emissions

Emission Source Description - Project Net Emissions

1) Per NC DENR's request, both existing and new ancillary combustion sources are included in the netting analysis. Existing ancillary combustion sources are the Unit5 Auxiliary Boiler (ES-6) and the Emergency Generator (ES-12).

Duke Cliffside - Unit 6 Appendices B and C_052907.xlsProject Actual to Future Page 29 of 63 5/29/2007

Duke Power - Cliffside ExpansionNetting Analysis

Netting Analysis Summary

Proposed NOx Rate for Unit 6 = 0.07 lb NOx/MMBtu (annual avg.)Proposed SO2 Rate for Unit 6 = 0.15 lb SO2/MMBtu (annual avg.)

NOx SO2

(ton/yr) (ton/yr)

Unit 6 Boiler (New) 2,407 5,157

Ancillary Combustion Sources (1) 56 725

Creditable Decrease (Units 1-4) (2) -958 -5,459

Creditable Decrease (Unit 5) (2) -1,466 -5,842

Total Project Emissions Increase: 38 -5,419

Notes

Key Parameters

Unit 6 BoilerHeat Input Rate = 7850 MMBtu/hr

Operating Hours = 8760 hr/yr

Unit 1 - 4 BoilersPast Actual NOx Emissions = 958 ton/yr


Unit 5 Boiler

Past Actual NOx Emissions = 5,428 ton/yr

Future Projected NOx Emissions = 3,962 ton/yr



Future Projected SO2 Emissions = 20,028 ton/yr


Emission Source Description - Project Net Emissions

1) Per NC DENR's request, both existing and new ancillary combustion sources are included in the netting analysis. Existing ancillary combustion sources are the Unit 5 Auxiliary Boiler (ES-6) and the Emergency Generator (ES-12).

2) Duke Energy will offset SO2 emissions increases from the addition of Unit 6 using credit for reductions on Unit 5 based on future operation of the flue gas desulfurization system. While Units 1 -4 will be retired, those reductions are not being used to offset increased emissions, and Duke Energy requests that those reductions be reserved as net reductions for any future projects that may fall within the contemporaneous period. Duke Energy will assure compliance by taking a limit on annual emissions less than or equal to the current baseline emissions of 25,871 tons plus the allowable PSD increase of 40 tons per year.

3) Duke Energy will offset NOx emissions from the addition of Unit 6 by taking credit for retiring Units 1-4 and credit for reductions on Unit 5 as a result of additional operation of the installed SCR system. Duke Energy will assure compliance by taking a limit of annual emissions less than or equal to the current baseline of 6,386 tons per year plus the allowable PSD increase of 40 tons per year.

Duke Cliffside - Unit 6 Appendices B and C_052907.xlsNOx SO2 Netting Analysis Page 30 of 63 5/29/2007

Duke Power - Cliffside StationPermitting Strategy: PSD Netting

Historical Actual Emissions Data

Unit 1-4 Unit 1-4 Unit 5 Unit 5 Unit 1-5 Unit 1-5 Unit 1-4 Unit 5

Year SO2 (TPY) NOx (TPY) SO2 (TPY) NOx (TPY) SO2 (TPY) NOx (TPY) (MMBtu/yr) (MMBtu/yr)

2000 5,193 1,471 7,365 29,139 8,836 7,439,937 33,175,658

2001 4,003 1,197 25,556 7,943 29,559 9,139 5,842,785 33,623,388

2002 2,667 720 19,429 2,913 22,096 3,633 3,479,216 24,218,041

2003 6,794 1,798 28,183 4,041 34,977 5,840 8,857,771 35,402,456

2004 4,124 1,077 23,558 2,748 27,683 3,825 5,333,731 30,166,012

PSD: Avg. 2001-2002 958 5,428 4,661,001 28,920,715

PSD: Avg. 2003-2004 5,459 25,871 7,095,751 32,784,234

Notes:

Calendar year 2002 may be not representative of typical operations due to the bad drought and associated operational problems that year. Use of 2002 is conservative.

Possible NOx Emission Reductions from Unit 5 for Operating SCR Year-Round:

Actual Heat Input Rate

SCR NOx Rate

Actual NOx Emissions

NOx Emissions at

SCR Rate

Creditable Emissions Available

Year (MMBtu/yr) (lb/MMBtu) (TPY) (TPY) (TPY)

2001 33,623,388 0.08 7,943 1,345 6,598

2002 24,218,041 0.08 2,913 969 1,944

Avg. 2001-2002 28,920,715 5,428 1,157 4,271

The period 2001-2005 is used as the 5-year window for determining the 24-month annual average baseline emissions, based on the application submittal date of December 21, 2005.

Duke Cliffside - Unit 6 Appendices B and C_052907.xlsHistorical 31 of 63 5/29/2007

Duke CliffsidePotential Emission Rates for Cliffside Title V Sources

Height Temp Velocity DiameterSource ID Source Description Capacity Units Factor Units lb/hr g/s Factor Units lb/hr g/s m K m/s mES-1 U1 Boiler 647 MMBtu/hr 0.45 lb/MMBtu 291 36.68 1.7 lb/MMBtu 1,100 139 55.93 480 18.35 3.2ES-2 U2 Boiler 647 MMBtu/hr 0.45 lb/MMBtu 291 36.68 1.7 lb/MMBtu 1,100 139 55.93 480 18.35 3.2ES-3 U3 Boiler 810 MMBtu/hr 0.45 lb/MMBtu 365 45.93 1.7 lb/MMBtu 1,377 174 57.45 462 19.541 3.2ES-4 U4 Boiler 810 MMBtu/hr 0.45 lb/MMBtu 365 45.93 1.7 lb/MMBtu 1,377 174 57.45 462 19.541 3.2ES-5 U5 Boiler 6080 MMBtu/hr 0.45 lb/MMBtu 2,736 344.74 1.6 lb/MMBtu 9,728 1225.73 150.55 322.04 18.17 7.62ES-6 AuxB 71.5 MMBtu/hr 0.14 lb/MMBtu 10.01 1.26 2.3 lb/MMBtu 164.45 20.72 83.82 366.48 126.42 1.22ES-7 AuxB 4 MMBtu/hr 0.14 lb/MMBtu 0.56 0.07 2.3 lb/MMBtu 9.20 1.16 29.25 435.93 58.09 0.43ES-12 Emerg. Gen. 1000 kW 29.85 lb NOx/hr 29.85 3.76 2.3 lb/MMBtu 4.84 0.61 6.71 733.15 67.05 0.24

Notes:NOx emission rates for ES-1 through ES-5 were based on the Phase II Acid Rain Permit Limit (0.45 lb/MMBtu per 15A NCAC 2Q.0402, 40 CFR Part 72).SO2 emission rates for ES-1 through ES-5 were based on proposed interim limits prior to retirement of Units 1-4 and with the Unit 5 FGD system.NOx emission rates for ES-6 and ES-7 were based on AP-42 emission factors for distillate fuel oil firing and a heat content of 138,455 Btu/gal from the Title V application for this source. SO2 emission rates for ES-6 and ES-7 were based on the NC SIP for combustion sources (2.3 lb/MMBtu per 15A NCAC 2D.0516).NOx and SO2 emission rates for ES-12 were based on the information submitted in the Title V application for this source.

NOx SO2

Duke Power - Cliffside ExpansionNOx Netting Analysis

Netting Analysis Summary - Ancillary Sources

NOx SO2

(ton/yr) (ton/yr)

Unit 6 Auxiliary Boiler (New) 8.32 4.3 Operating Hours = 876 hr/yr

Unit 5 Auxiliary Boiler (Existing: ES-6) 43.84 720.3 See Below

Unit 6 Emergency Generator (New) 1.24 0.0014 Operating Hours = 100 hr/yr

Emergency Generator (Existing: ES-12) 1.49 0.242 See Below

Unit 6 Fire-Water Pump (New) 0.14 0.0003 Operating Hours = 100 hr/yr

Unit 5 Fire-Water Pump (Existing) 0.36 0.043 Operating Hours = 100 hr/yr

Unit 5 Quench Water Pump (Existing) 0.23 0.0004 Operating Hours = 100 hr/yr

Total Emissions: 55.6 725

Key Parameters

Unit 5 Aux. Boiler (ES-6)Heat Input Rate = 71.5 MMBtu/hr


NOx Emission Rate = 0.14 lb/MMBtu

SO2 Emission Rate = 2.3 lb/MMBtu

Unit 5 Emergency Generator (ES-12)Operating Hours = 100 hr/yr

Hourly NOx Emission Rate = 29.85 lb/hr

Hourly SO2 Emission Rate = 4.84 lb/hr

Based on the information submitted in the Title V application for this source

Based on the information submitted in the Title V application for this source

New Ancillary Source Description Key Parameter

Based on AP-42 emission factors for distillate fuel oil firing and a heat content of 138,455 Btu/gal. Based on the NC SIP for combustion sources (2.3 lb/MMBtu per 15A NCAC 2D.0516).


Project: Duke Power - CliffsideProject Number: 02355-134 Computed by: C. Hawk Date: 1/2/2007Subject: Diesel Fire-Water Pump Engine Calculations Checked by: W. C. Campbell Date: 1/18/2007

Emission Source: Emergency Fire-Water Pump EngineSource Type: Diesel Fueled IC Reciprocating EngineEngine Power (bhp): 420Heat Input (mmBtu/hr): 3.014Maximum Fuel Usage (gal/hr) 22.0Number of Units: 1Fuel Oil Heating Value (BTU/gal) 137000Sulfur Content of Fuel (wt. %): 0.05 (a)Operating Hours per Year: 100



Notes:(a) Emission factors (g/hp-hr) are based on the NSPS Subpart IIII limits for Stationary Compression Ignition Internal Combustion Engines(b) Emission factors based on USEPA AP-42, Section 3.3, Table 3.3-1, dated October 1996


Stack ParametersStack Height 10.0 ftStack Diameter 0.7 ftExhaust Flow 2,064 ACFMExhaust Temp 907 F


Appendix B 34 of 63 5/29/2007

ENSR 2 Technology Park Drive, Westford, Massachusetts 01886-3140 T 978.589.3000 F 978.589.3100 www.ensr.aecom.com

A Trusted Global Environmental, Health and Safety Partner

Cliffside Unit 6 Project –Class I Modeling Addendum May 2007

Memorandum

Date: May 29, 2007

To: Rick Roper (Duke Energy Carolinas)

From: Jeffrey Connors (ENSR)

Subject: Addendum to Class I Modeling:

Cliffside Unit 6 Project – PSD Permit Application (NOX Netting Analysis and Updated Class I Modeling)

Distribution: Duke Energy Kris Knudsen Harry Lancaster

ENSR William Campbell

NC DAQ Don van der Vaart Chuck Buckler Tom Anderson Ed Martin

ENSR has performed additional netting and subsequent Class I modeling analyses in support of Duke Energy Carolina’s “Unit 6&7 Project” located at the Cliffside Steam Station (Cliffside) in Rutherford County, NC. These additional analyses examine the impact of PSD applicability for criteria pollutants and the related Class I area impacts by permitting just one (Unit 6) of the new 800 MW boilers at the Cliffside Steam Station.

Netting Analysis

Duke Energy Carolinas has revised its netting analysis to incorporate the permitting of just the new Unit 6 (800 MW) boiler. The focus of this netting analysis will be NOX. The project still nets out of SO2 as previously demonstrated even with construction of both of the originally proposed units. Therefore the netting analysis presented within this memo addresses NOX only. Table 1 shows a list of historical NOX emissions data for Unit 1-4 and Unit 5 that will be used in the netting analysis.

The data in Table 1 has been incorporated into Table 2 which presents the netting analysis for NOX. As shown in Table 1 the emission offsets from a combination of retiring Units 1-4 and taking an annual NOX emission limit of 3,962 tons/year for Unit 5 is enough to offset the new emissions from Unit 6 below the PSD significance threshold of 40 TPY. For purposes of this netting analysis, ancillary sources (existing and new) are not included in the baseline calculation and are included at the maximum potential for future emissions. This is conservative because it does not provide any credit for existing ancillary sources in the baseline emissions. However, the overall impact on the reduction required from Unit 5 is minimal.




Class I Modeling Update

Additional Class I area modeling has also been conducted to reflect that the project has now netted out of PSD review for SO2 and NOX. Like for previous modeling iterations that did not include SO2 because the projected netted out of PSD review for SO2, these additional analysis do not account for NOX since the project now nets out of PSD review for NOX. The modeling was conducted for just project emissions of primary PM10 from the new Unit 6 boiler.

There are five PSD Class I areas within 300-km of Cliffside (see Figure 1). As summarized in Section 10 of the December 2005 PSD Application, CALPUFF was run with two different grid resolutions for specific areas: (1) a 1-km resolution for more distant Class I areas – Cohutta, Great Smoky Mountains, and Joyce Kilmer-Slickrock; (2) a 500-m resolution for the nearest Class I areas – Linville Gorge and Shining Rock.

Since the project is not a significant source of SO2 or NOX, only a PSD increment analysis for PM10 and a regional haze analysis (that only considers emissions of PM10) were performed. The sulfur and nitrogen deposition analyses were excluded from this analysis because the source is no longer a significant source of either SO2 or NOX.

Tables 3 and 4 present an updated set of modeling results for PM10 increment and regional haze based on primary PM10 emissions from the Unit 6 boiler alone. Like in previous analyses, the proposed project does not exceed the significance thresholds for PM10 or regional haze. Therefore the proposed project does not have an adverse impact on air quality.

Table 1: Historical NOX Emissions Data for Units 1-5

Unit 1-4 Unit 5 Unit 1-4 Unit 5 Year NOX

(TPY) NOX

(TPY) (MMBtu/yr) (MMBtu/yr)

2000 1,471 7,365 7,439,937 33,175,658

2001 1,128 7,380 5,842,787 33,623,389

2002 664 2,930 3,479,216 24,218,041

2003 1,801 4,017 8,857,771 35,402,456

2004 1,016 2,941 5,333,731 30,166,012

PSD: Avg. 2001-2002 958 5,428 4,661,001 28,920,715

Note: Calendar years 2001 and 2002 are used as the baseline for NOx emission reductions.




Table 2: Netting Analysis for NOX

Proposed NOX Rate for Unit 6 = 0.07 lb NOx/MMBtu

NOX with Unit 6 Only

Emission Source Description (ton/yr)

Main Boilers 2,406.8

All Ancillary Combustion Sources on Site 55.6

Creditable Decreases (Units 1 -4) -958.3

Creditable Decrease (Unit 5) -1,466.2

Total Project Emissions: 39.0

Key Parameters Unit 6 Boiler

Heat Input Rate = 7,850 MMBtu/hr

Operating Hours = 8,760 hr/yr

Unit 1 - 4 Boilers

Past Actual NOX Emissions = 958.3 Ton/yr

Unit 5 Boiler

Past Actual NOX Emissions = 5,428.0 Ton/yr

Future Allowable NOX Emissions = 3,962.0 Ton/yr

Net Decrease (Creditable) = 1,466.0 Ton/yr

Auxiliary Combustion Sources

NOx Emission Source Description Ton/YrAux Boiler (876 Hr) Unit 6 Auxiliary Boiler 8.32EMR_GEN1 (100 Hr) Unit 6 Emergency Generator 1.24FWP_5 (100 hr) Unit 5 Fire Water Pump 0.36FWP_6 (100 Hr) Unit 6 Fire Water Pump 0.14EQWP_5 (100 Hr) Unit 6 Quench Pump 0.23ES_6 (PTE) Unit 5 Auxiliary Boiler 43.84ES_12 (100 Hr) Emergency Generator (1000 kw) 1.49 Total 55.6




Emission Basis for Unit 5 Existing Sources Unit 5 Auxiliary Boiler

Heat Input Rate = 71.5 MMBtu/hr

Operating Hours = 8,760 hr/yr

NOx Emission Rate = 0.14 lb/MMBtu

Unit 5 Emergency Generator

Capacity = 1,340 bHp


NOx Emission Factor = 29.85 lb/hr




Table 3 Maximum Concentrations at the PSD Class I Areas

CALPUFF Modeled Concentration (μg/m3)

Class I Significant

Impact Level

Pollutant Class I Area Averaging Period

2001 2002 2003 (μg/m3)

24-hour 0.0392 0.0739 0.0535 0.32 Cohutta

Annual 0.0011 0.0026 0.0015 0.16

24-hour 0.1329 0.0652 0.1371 0.32 Great Smoky Mountain

Annual 0.0023 0.0026 0.0019 0.16

24-hour 0.0700 0.0494 0.0995 0.32 Joyce Kilmer Slickrock

Annual 0.0017 0.0022 0.0017 0.16

24-hour 0.1215 0.1196 0.1208 0.32 Linville Gorge

Annual 0.0068 0.0061 0.0054 0.16

24-hour 0.1434 0.0902 0.0617 0.32

PM10

Shinning Rock Annual 0.0031 0.0040 0.0023 0.16

Table 4 Visibility Impacts at the PSD Class I Areas

2001 2002 2003 Days > than Days > than Days > than

Class I Area 5% Δ BBext

10% Δ BBext

MAX % Change in Bext

5% Δ BBext

10% Δ BBext


5% Δ BBext

10% Δ BBext


Cohutta 0 0 0.17 0 0 0.20 0 0 0.15

Great Smoky Mountains 0 0 0.43 0 0 0.22 0 0 0.40

Joyce Kilmer-Slickrock 0 0 0.26 0 0 0.15 0 0 0.29

Linville Gorge 0 0 0.41 0 0 0.56 0 0 0.67

Shining Rock 0 0 0.53 0 0 0.30 0 0 0.21




Figure 1 Location of Nearby Class I Areas in Relation to the Cliffside Steam Station

May 2007

APPENDIX G: FIGURES AND DRAWINGS

Unit 6 forms May2007-draft3 - NC

Documents

Transcript of Unit 6 forms May2007-draft3 - NC