APPENDIX 10 

BACT ANALYSIS
10784-004-400 July, 2007 10-1

APPENDIX 10 

CONTROL TECHNOLOGY EVALUATION REPORT 

10.1 Control Technology Overview 

The Toquop Energy, LLC (Toquop Energy) Toquop Energy Project (TEP) is subject to Best 

Available Control Technology (BACT) for oxides of nitrogen (NOX), sulfur dioxide (SO2), carbon 

monoxide (CO), particulate matter (PM), particulate matter with an aerodynamic diameter of 

10 microns or less (PM10), volatile organic compounds (VOCs), lead (Pb), hydrogen fluoride (HF), 

and sulfuric acid mist (H2SO4). The TEP also will be subject to New Source Performance 

Standards (NSPS) for Mercury (Hg) under the Clean Air Mercury Rule (CAMR). While not a 

pollutant subject to BACT, Hg control to meet CAMR requirements also has been addressed in 

this appendix. Each project emission source of the listed pollutants (except for Hg) is required to 

employ BACT, as determined on a “top-down”, case-by-case basis. This appendix presents the 

top-down BACT analysis for the proposed TEP emission sources. 

10.1.1 Top-Down BACT 

BACT requirements are intended to ensure that a proposed facility will incorporate control 

systems that reflect the latest demonstrated practical techniques for a particular type of emission 

unit and do not result in the exceedance of National Ambient Air Quality Standards, Prevention of 

Significant Deterioration (PSD) increment, or other 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 TEP. 

The top-down approach to the BACT review process involves determining the most stringent 

control technique available, referred to as Lowest Achievable Emission Rate (LAER) for a similar 

or identical emission source. If it can be shown that the LAER is technically, environmentally, or 

economically impractical on a case-by-case basis for the particular source under evaluation, then 

the next most stringent level of control is determined and similarly evaluated. This process 

continues until a control technology and associated emission level is determined that can not be 

eliminated by any technical, environmental, or economic objections. The top-down BACT 

evaluation process is described in the U.S. Environmental Protection Agency (USEPA) draft 

document "New Source Review Workshop Manual.” The five steps involved in a top-down BACT 

evaluation are: 

y Identify all available control options with practical potential for application to the specific 

emission unit for the regulated pollutant under evaluation; 
10784-004-400 July, 2007 10-2

y Eliminate technically infeasible technology options; 

y Rank remaining control technologies by control effectiveness; 

y Evaluate the most effective control alternative and document results; if the top option is not 

selected as BACT, evaluate the next most effective control option; and 

y Select BACT, which will be the most effective practical option not rejected based on energy, 

environmental, or economic impacts. 

The top-down approach was used in this analysis to evaluate available pollution controls for the 

proposed TEP. 

10.1.2 Lowest Achievable Emission Rate 

While the proposed project is not subject to the Non-attainment New Source Review requirement 

to install LAER levels of control for any pollutant, in a top-down control technology analysis LAER 

is used as the starting point since it establishes the lowest emission level that has been 

demonstrated in practice for a similar pulverized coal- (PC-) fired power plant. LAER, as defined in 

the "New Source Review Workshop Manual" (USEPA 1990), is derived from the following 

definition: 

"The most stringent emission limitation contained in the implementation plan of any State 

for such class or category of source; or the most stringent emission limitation achieved in 

practice by such class or category of source." 

The LAER standard is more stringent than BACT since it considers only technological applicability 

of the best level of control that has been achieved in practice on another similar unit, without 

consideration of potential adverse economic, environmental, or energy impacts. It does, however, 

represent a useful starting point in the evaluation of potentially achievable levels of control. To 

determine the applicable emission limitations that would be representative of LAER, several 

sources were consulted including USEPA's Reasonably Available Control Technology 

(RACT)/BACT/LAER Clearinghouse (RBLC), recent permit applications and PSD permits issued 

for other recent coal-fired power plants not yet listed in the USEPA RBLC. The RBLC for coal-fired 

boilers is included as Attachment 10-B. 

10.1.3 Previous BACT/LAER Determinations for Pulverized Coal-fired Boilers 

USEPA's RACT/BACT/LAER RBLC is a listing of RACT, BACT, and LAER determinations by 

governmental agencies for many types of air emission sources. ENSR Corporation (ENSR) 
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consulted this database as the first step in developing a list of the most recent BACT/LAER 

decisions for similar sources, including PC boilers and support facilities. The results of the RBLC 

search and information from known permit applications (in particular the Desert Rock Energy 

project also being proposed by Sithe Global) are summarized on a pollutant-specific basis in the 

following sections to identify and rank alternative technologies and achievable levels of control. 

The National Coal Fired Power Plant Spreadsheet maintained by USEPA Region VII also was 

reviewed. It has not been updated since March of 2005, so the relevant facilities were already 

covered by the RBLC; however, it is included as Attachment 10-C. 

10.1.4 Cost Determination Methodology 

Economic analyses of certain BACT alternatives were performed to compare capital and annual 

costs in terms of cost effectiveness (i.e., dollars per ton of pollutant removed). Capital costs 

include the initial cost of components intrinsic to the complete control system (selective catalytic 

reduction [SCR], for example, includes catalyst, support frame, ductwork, ammonia storage tanks, 

piping, rotating equipment, instrumentation, monitoring equipment, and installation costs). Annual 

operating costs consist of the financial requirements to operate the control system on an annual 

basis and include impacts to heat rate (efficiency losses), overhead, maintenance, outages, labor, 

raw materials, and utilities. 

10.1.4.1 Capital Costs 

The capital cost estimating technique used in this analysis is based on a combination of cost data 

from the Coal Utility Environmental Cost (CUECost) Workbook, version 1.0 (USEPA 2000) and 

the factored cost estimating technique presented in the latest USEPA guidance manual for 

estimating control technology costs Office of Air Quality Planning and Standards (OAQPS) Control 

Cost Manual (USEPA 1996). Capital cost estimates generated from CUECost were inserted into 

the factored cost estimate format presented in the OAQPS manual as shown in Table 10-1

through Table 10-3. Line item costs included in the OAQPS Control Cost Manual estimating 

method that were not provided in the CUECost workbook were factored from Total Capital Cost 

using the appropriate Control Cost Manual factor. Due to variations in the output format of 

CUECost, merging of the cost estimating data into OAQPS Control Cost Manual format were 

each slightly different for the wet scrubber, fabric filter, and selective catalytic reduction cases, 

depending on the form that the estimates were reported in CUECost. The input and output from 

the CUECost workbook are included in Attachment 10-A. 

Purchased equipment costs represent the delivered cost of the control equipment, auxiliary 

equipment, and instrumentation. Auxiliary equipment consists of all structural, mechanical, and 

electrical components required for efficient operation of the device. These include such items as 
10784-004-400 July, 2007 10-4

reagent storage and supply piping and distributed controls. Auxiliary equipment costs are taken as 

a straight percentage of the basic equipment cost, the percentage being based on the average 

requirements of typical systems, and their auxiliary equipment (USEPA 1996). 

Direct installation costs consist of the direct expenditures for materials and labor for site 

preparation, foundations, structural steel, erection, piping, electrical, painting, and facilities. 

Indirect installation costs include engineering and supervision of contractors, construction and field 

expenses, construction fees, and contingencies. Other indirect costs include equipment startup 

and performance testing, working capital, interest during construction, and allowance for funds 

during construction. 

Table 10-1 

Capital Cost Estimating Methodology for a Wet Scrubber 

Equipment Basis 

Direct Costs 

PURCHASED EQUIPMENT 

 (a) Basic Equipment (BE) Back Calculate PE / 1.2175 

 (b) Auxiliaries included 

 (c) Instrumentation and Controls 10% of BE 

 (d) Tax and Freight 11.75% of BE 

TOTAL PURCHASED EQUIPMENT (PE) Back Calculate TDC / 1.85 

DIRECT INSTALLATION 

 (a) Foundations and Support 12% of PE 

 (b) Handling and Erection 40% of PE 

 (c) Electrical 1% of PE 

 (d) Piping 30% of PE 

 (e) Insulation for Ductwork 1% of PE 

 (f) Painting 1% of PE 

TOTAL DIRECT INSTALLATION (DI) Sum of (a) through (f) 

TOTAL DIRECT COST (TDC) CUECost (Total Capital Cost – Chimney) 

Indirect Costs 

INDIRECT INSTALLATION 

 (a) Engineering and Supervision CUECost (Engineering Fees – Chimney) 

 (b) Construction and Field Expenses CUECost (General Facilities – Chimney) 

 (c) Contractor Fees CUECost Prime Contractor’s Markup 

 (d) Contingencies CUECost Total Contingency 

OTHER INDIRECT COSTS 

 (a) Startup and Performance Tests CUECost Preproduction Costs 

 (b) Working Capital 30 Days O&M + CUECost Inventory Capital 

 (c) Allowance for Funds During Construction CUECost AFDC 

TOTAL INDIRECT COST (TIC) Sum of All Indirect Costs 

TOTAL CAPITAL COST TDC + TIC 
10784-004-400 July, 2007 10-5

Table 10-2 

Capital Cost Estimating Methodology for a Fabric Filter 

Equipment Basis 

Direct Costs 

PURCHASED EQUIPMENT 

 (a) Basic Equipment (BE) CUECost Equipment Cost Subtotal 

 (b) Auxiliaries Included 

 (c) Instrumentation and Controls CUECost Instrumentation and Controls 

 (d) Tax and Freight CUECost (Taxes + Freight) 

TOTAL PURCHASED EQUIPMENT (PE) Sum of (a) through (d) 

DIRECT INSTALLATION 

 (a) Foundations and Support Included 

 (b) Handling and Erection Included 

 (c) Electrical Included 

 (d) Piping Included 

 (e) Insulation for Ductwork Included 

 (f) Painting Included 

TOTAL DIRECT INSTALLATION (DI) CUECost Installation 

TOTAL DIRECT COST (TDC) PE + DI 

Indirect Costs 

INDIRECT INSTALLATION 

 (a) Engineering and Supervision CUECost Engineering Fees 

 (b) Construction and Field Expenses CUECost General Facilities 

 (c) Contractor Fees CUECost Prime Contractor’s Markup 

 (d) Contingencies CUECost Total Contingency 

OTHER INDIRECT COSTS 

 (a) Startup and Performance Tests CUECost Preproduction Costs 

 (b) Working Capital 30 Days O&M 

 (c) Allowance for Funds During Construction CUECost AFDC 

TOTAL INDIRECT COST (TIC) Sum of All Indirect Costs 

TOTAL CAPITAL COST TDC + TIC 
10784-004-400 July, 2007 10-6

Table 10-3 

Capital Cost Estimating Methodology for Selective Catalytic Reduction 

Equipment Basis 

Direct Costs 

PURCHASED EQUIPMENT 

 (a) Basic Equipment (BE) Back Calculate CUECost TDC / (1.2175 * 1.3) 

 (b) Auxiliaries Included 

 (c) Instrumentation and Controls 10% of BE 

 (d) Initial Ammonia and Catalyst CUECost Initial Ammonia and Catalyst 

 (e) Tax and Freight 11.75% of BE 

TOTAL PURCHASED EQUIPMENT (PE) Sum of (a) through (e) 

DIRECT INSTALLATION 

 (a) Foundations and Support 8% of PE 

 (b) Handling and Erection 14% of PE 

 (c) Electrical 4% of PE 

 (d) Piping 2% of PE 

 (e) Insulation for Ductwork 1% of PE 

 (f) Painting 1% of PE 

TOTAL DIRECT INSTALLATION (DI) Sum of (a) through (f) 

TOTAL DIRECT COST (TDC) PE + DI 

Indirect Costs 

INDIRECT INSTALLATION 

 (a) Engineering and Supervision CUECost Engineering Fees 

 (b) Construction and Field Expenses CUECost General Facilities 

 (c) Contractor Fees CUECost Prime Contractor’s Markup 

 (d) Contingencies CUECost Total Contingency 

OTHER INDIRECT COSTS 

 (a) Startup and Performance Tests CUECost Preproduction Costs 

 (b) Working Capital 30 Days O&M 

 (c) Allowance for Funds During Construction CUECost AFDC 

TOTAL INDIRECT COST (TIC) Sum of All Indirect Costs 

TOTAL CAPITAL COST TDC + TIC 

10.1.4.2 Annualized Costs 

Annualized costs are comprised of direct and indirect operating costs. Direct costs include labor, 

maintenance, replacement parts, raw materials, utilities, and waste disposal. Indirect operating 

costs include plant overhead, taxes, insurance, general administration, and capital charges. Like 

the capital costs, the annualized costs were obtained from both CUECost and the OAQPS 

Manual. The estimates reported by CUECost were used as the primary source, and the USEPA 

factors were used to fill in remaining information. The basis for the annualized cost data for the 

wet scrubber, fabric filter, and SCR equipment are reported in Tables 10-4 through 10-6. 

Direct annual operating costs include the costs of labor, maintenance, materials, utilities, and 

replacement components necessary for the operation of the control equipment. Indirect costs 

consist of funds allocated for overhead, property taxes, and administration. 
10784-004-400 July, 2007 10-7

Table 10-4 

Annualized Operating Cost Estimation Methodology for a Wet Scrubber 

Cost Basis 

Direct Operating Costs 

Direct Labor CUECost Operating Labor 

Maintenance CUECost Maintenance Labor and Materials 

Operating Materials CUECost Reagent Costs 

Disposal CUECost Disposal Costs 

Steam CUECost Steam Costs 

Electricity CUECost Power Costs 

Indirect Operating Costs 

Overhead 44% of Operating Labor + 12% of Maintenance Labor 

Property Tax 1% of Total Capital Cost 

Insurance 1% of Total Capital Cost 

Administration CUECost Administration and Support Labor 

Capital Recovery Assume 30 year life, 7% interest rate 

Total Annualized Cost Sum of All Annual Costs 

Table 10-5 

Annualized Operating Cost Estimation Methodology for a Fabric Filter 

Cost Basis 

Direct Operating Costs 

Direct Labor 2920 hours at $35/hour (Assumes 0.3 Operators per Shift) 

Maintenance CUECost Maintenance 

Replacement Parts, Bags CUECost Periodic Replacement Items 

Electricity CUECost Power Cost 

Indirect Operating Costs 

Overhead 44% of Operating Labor + 12% of Maintenance Labor 

Property Tax 1% of Total Capital Cost 

Insurance 1% of Total Capital Cost 

Administration 2% of Total Capital Cost 

Capital Recovery Assume 30 year life, 7% interest rate 

Total Annualized Cost Sum of All Annual Costs 
10784-004-400 July, 2007 10-8

Table 10-6 

Annualized Operating Cost Estimation Methodology for Selective Catalytic Reduction 

Cost Basis 

Direct Operating Costs 

Direct Labor CUECost Operating Labor 

Maintenance CUECost Maintenance 

Utilities 

 (a) Aqueous Ammonia CUECost Ammonia 

 (b) Catalyst CUECost Catalyst Replacement 

 (c) Electricity CUECost Electricity 

 (d) High-Dust SCR Steam CUECost High Dust SCR Steam 

Catalyst Disposal CUECost Catalyst Disposal 

Indirect Operating Costs 

Overhead 44% of Operating Labor + 12% of Maintenance Labor 

Property Tax 1% of Total Capital Cost 

Insurance 1% of Total Capital Cost 

Administration 2% of Total Capital Cost 

Capital Recovery Assume 30 year life, 7% interest rate 

Total Annualized Cost Sum of All Annual Costs 

To determine the total annualized cost, it also was necessary to calculate the capital recovery 

factor (CRF). The CRF is defined as: 

(1 ) 1

(1 )

+ −

+ = n

n

i

i i CRF

Where i is the annual interest rate and n is the equipment economic life (years). The lifetime was 

assumed to be 30 years, which is the default project lifetime included in the CUECost workbook. 

The average interest rate was assumed to be 7 percent (USEPA 1996). CRF is therefore 

calculated to be 0.08. 

10.1.4.3 Cost-Effectiveness 

The cost-effectiveness of an available control technology is based on the annualized cost of the 

available control technology and its potential annual pollutant emission reduction. Cost 

effectiveness is calculated by dividing the annualized cost of the available control technology by 

the theoretical tons of pollutant removed by that control technology each year. The basis for 

determining the percent reduction of a given technology was based on information contained in 

USEPA literature, from recent permits, and from engineering estimates. The cost effectiveness of 

each control system in units of dollars per ton of pollutant removed is described within each 

section of the BACT determination. 
10784-004-400 July, 2007 10-9

10.2 BACT for NOX

10.2.1 Formation 

NOX is formed during the combustion of fossil fuels, including coal, and is generally classified as 

either thermal NOX or fuel NOX. Thermal NOX is formed when elemental nitrogen reacts with 

oxygen (O2) in the combustion air within the high temperature environment of the furnace. The 

rate of formation of thermal NOX is a function of residence time and free O2, and is exponential 

with peak flame temperature. Fuel NOX is generated when nitrogen contained in the fuel itself is 

oxidized. The rate of formation of fuel NOX is primarily a function of fuel bound nitrogen content of 

the coal but also is affected by fuel:air mixing. 

NOX emissions can be reduced using either combustion controls (i.e., staged combustion 

techniques such as Low-NOX burners (LNB), flue gas recirculation (FGR), over fire air (OFA), 

natural gas reburn, or flue gas treatment including selective non-catalytic reduction (SNCR) or 

SCR. SCONOX is a proprietary catalytic control technology that has been applied to several small 

gas turbines; however, it has never been applied to a coal fired application and therefore was not 

considered further in this analysis. Most PC boilers being permitted today incorporate a 

combination of both combustion controls and add-on control to achieve very low NOX emission 

levels. 

10.2.2 Pulverized Coal-fired Boilers 

10.2.2.1 Ranking of Available Control Techniques 

A review of USEPA's RBLC for coal-fired boilers (see Attachment 10-B) and recent permits and 

applications indicates general levels of NOX control that may be achieved with various 

combinations of control technology. Emission levels and control technologies for PC combustion 

have been identified and ranked as shown in Table 10-7. 

10.2.2.2 Recent Permit Limits 

The three most recent permits identified for new PC-fired units with supercritical boilers are the 

Big Cajun II Power Plant in Louisiana, issued 8/22/2005; Comanche Station in Colorado, issued 

7/5/2005; and the Wisconsin Public Service Weston Plant, issued 10/19/2004. Each of these 

projects was subject to top-down BACT, and the emission limits contained in those BACT 

approvals are representative of the current state-of-the-art for new PC power plants. All three of 

these facilities proposed to utilize sub-bituminous coal. Both the Weston Plant and Comanche 
10784-004-400 July, 2007 10-10

Table 10-7 

Ranking of NOX Control Technologies for PC Boilers 

PC 

Control Technologies 

Typical Control 

Efficiency Range

(% Removal) 

Typical Emission 

Level1

(lb/MMBtu) 

Technically Feasible for 

PC Boilers 

SCR and LNB 80-90 0.06-0.15 lb/MMBtu2 Yes 

SNCR 40-60 0.2-0.3 lb/MMBtu Yes 

Staged Combustion Techniques 

Including Low-NOX Burners 

30-50 0.15-0.5 lb/MMBtu3 Yes 

SCONOX

TM N/A N/A No 

Gas Reburn 40-60 0.15-0.3 lb/MMBtu 

Requires natural gas on 

site 

1

 Emission levels represent target steady state values at base load, long-term averages. All known projects also incorporate staged combustion 

techniques such as LNB. 

2

 The lowest value in this range comes from the Desert Fox Application. The W. A. Parish facility in Texas has reportedly tested NOX emissions to 

~ 0.04 lb/MMBtu with Alstom LNB and SCR using PRB coal. However, there are spikes in daily readings that are above 0.06 lb/MMBtu. BACT 

limits are based on continuous emission limits – one-time test results are by definition lower than allowable limits. 3

 The lower end of this range is only achievable using PRB coal in tangentially or corner fired boilers. 

N/A – Not available (no known installations of this technology on utility scale coal-fired boilers) 

Station specifically propose to burn Powder River Basin (PRB) coal from Wyoming. Both Big 

Cajun II and the Weston Plant will employ LNB and SCR to achieve NOX emission limits of 0.07 

and 0.06 lb/million British thermal unit (MMBtu), respectively. Comanche Station was able to net 

out of PSD review for NOX through retrofit of controls to pre-existing sources. The Weston Plant 

currently has the lowest NOX emission limit of any coal burning facility in the USEPA RBLC at 

0.06 lb/MMBtu (12-month average). The Sithe Global Desert Rock PSD permit application 

(pending) also proposed 0.06 lb/MMBtu as BACT. 

Based on these recent BACT determinations, ENSR concludes that SCR in the range of 0.06 to 

0.08 lb NOX/MMBtu is representative of state-of-the-art emission control for new PC units burning 

sub-bituminous coal. 

Alternative control technologies with potential for application to the TEP are reviewed below. 

10.2.2.3 NOX Control Technology Discussion 

Selective Catalytic Reduction

SCR is a process that involves post-combustion removal of NOX from flue gas with a catalytic 

reactor. In the SCR process, ammonia injected into the exhaust gas reacts with NOX and O2 to 
10784-004-400 July, 2007 10-11

form nitrogen and water. SCR converts NOX to nitrogen and water by the following reactions 

(Cho 1994): 

4NO + 4NH3 +O2 → 4N2 + 6H2O 

6NO + 4NH3 → 5N2 + 6H2O 

2NO2 + 4NH3 + O2 → 3N2 + 6H2O 

6NO2 + 8NH3 → 7N2 + 12H2O 

NO + NO2 + 2NH3 → 2N2 + 3H2O 

The reactions take place on the surface of a catalyst. The function of the catalyst is to effectively 

lower the activation energy of the NOX decomposition reaction. Technical factors related to this 

technology include the catalyst reactor design, optimum operating temperature, sulfur content of 

the fuel, catalyst de-activation due to aging or poisoning, ammonia slip emissions, and design of 

the ammonia injection system. 

The SCR system is comprised of a number of subsystems. These include the SCR reactor and 

flues, ammonia injection system, and ammonia storage and delivery system. The SCR reactor 

with necessary inlet and outlet duct work will be located downstream of the economizer and 

upstream of the air heater and the particulate control system. 

From the economizer outlet, the flue gas will first pass through a low-pressure ammonia/air 

injection grid designed to provide optimal mixing of ammonia with flue gas. The ammonia treated 

flue gas will then flow through the catalyst bed and exit to the air heater. 

The SCR system for a PC boiler typically utilizes a fixed bed catalyst in a vertical down-flow multistage reactor. The reactor will include a seal system to prevent gas from bypassing the catalyst 

bed. Access openings for catalyst loading/removal and periodic internal inspection will be 

provided. The reactor will contain multiple stages of catalyst with room for loading a future stage. 

For each stage, a soot blowing system will be provided. Each stage will be equipped with a 

platform with monorails and hoists to accommodate catalyst loading and unloading. 

Reduction catalysts are divided into two groups: base metal (lower temperature, primarily 

vanadium, platinum, or titanium) and zeolite (higher temperature). Both groups exhibit advantages 

and disadvantages in terms of operating temperature, reducing agent/NOX ratio, and optimum O2

concentration. A disadvantage common to base metal catalysts is the narrow range of 

temperatures in which the reactions will proceed. Platinum group catalysts have the advantage of 

requiring lower ignition temperature, but have been shown to also have a lower maximum 

operating temperature. Operating above the maximum temperature results in oxidation of 

ammonia to either NOX (thereby actually increasing NOX emissions) or ammonium nitrate. 
10784-004-400 July, 2007 10-12

Optimum operating temperature for a vanadium-titanium catalyst system has been shown to be in 

the range of 550 degrees Fahrenheit (°F) to 800°F, which is significantly higher than for platinum 

catalyst systems. However, the vanadium-titanium catalyst systems begin to break down when 

continuously operating at temperatures above this range. Consequently, operating above the 

maximum temperature for the catalyst system again results in the oxidation of ammonia to either 

NOX (increasing NOX emissions) or ammonium nitrate. 

Sulfur content of the fuel can be a concern for systems that employ SCR. Catalyst systems 

promote partial oxidation of SO2 to sulfur trioxide (SO3), which combines with water to form 

sulfuric acid. At typical SCR operating temperatures, SO3 and sulfuric acid react with excess 

ammonia to form ammonium salts. These ammonium salts may condense as the flue gases are 

cooled and can lead to increased uncontrolled emissions of PM10 entering the particulate 

collector. Fouling may eventually lead to decreased NOX reduction performance, increased 

system pressure drop over time, and decreased heat transfer efficiencies. 

The SCR process is subject to catalyst deactivation over time. Catalyst deactivation occurs 

through two primary mechanisms: physical deactivation and chemical poisoning. Physical 

deactivation is generally the result either of prolonged exposure to excessive temperatures or 

masking of the catalyst due to entrainment of particulate from ambient air or internal 

contaminants. Chemical poisoning is caused by the irreversible reaction of the catalyst with a 

contaminant in the gas stream and is a permanent condition. Catalyst suppliers typically only 

guarantee a limited lifetime to very low emission level, high performance catalyst systems. 

SCR manufacturers typically estimate 10 parts per million (ppm) volume dry of unreacted 

ammonia emissions (ammonia slip) when making guarantees at very high efficiency levels. To 

achieve high NOX reduction rates, SCR vendors suggest a higher ammonia injection rate than 

stoichiometrically required, which conversely results in ammonia slip. Thus, an emissions trade-off 

between NOX and ammonia may occur in high NOX reduction applications. 

The potential environmental impacts associated with the use of SCR are summarized below: 

• Unreacted ammonia would be emitted to the atmosphere (ammonia slip). 

• Ammonium salts would increase loading to the particulate collection stage as PM10 (and PM 

with an aerodynamic diameter of 2.5 microns or less [PM2.5]). 

• Safety issues and Risk Management Planning may be required relative to the transportation, 

handling, and storage of ammonia (aqueous or anhydrous). 
10784-004-400 July, 2007 10-13

Selective Non-Catalytic Reduction

SNCR has been applied to a number of different types of combustion sources, including 

petroleum heaters, utility and industrial boilers fired with natural gas and oil, as well as PC boilers 

and coal-fired Circulating Fluidized Bed (CFB) boilers. 

The SNCR process is based on a gas-phase homogeneous reaction, within a specified 

temperature range, between NOX in the flue gas and either injected NH3 or urea to produce 

gaseous nitrogen and water vapor. SNCR systems do not employ a catalyst; the NOX reduction 

reactions are driven by the thermal decomposition of ammonia and the subsequent reduction of 

NOX. Consequently, the SNCR process operates at higher temperatures than the SCR process. 

Critical to the successful reduction of NOX with SNCR is the temperature of the flue gas at the 

point where the reagent is injected. For the ammonia injection process, the necessary 

temperature range is 1,700 to 1,900°F; for the urea injection process the nominal temperature 

range is 1,600 to 2,100°F. Also critical to effective application of these processes are gas mixing, 

residence time at temperature, and ammonia slip. 

Theoretically, one mole of ammonia (or one-half mole of urea) will react with one mole of NOX, 

forming elemental nitrogen and water. In reality, not all the injected reagent will react due to 

imperfect mixing, uneven temperature distribution, and insufficient residence time. These physical 

limitations may be compensated for by injecting a large amount of excess reagent and essentially 

achieving low NOX emissions at the expense of emissions of unreacted reagent, referred to as 

ammonia "slip." These emissions represent an adverse environmental impact and can lead to 

formation of ammonium salts and may contribute to regional haze as a precursor to PM2.5. Thus, 

for a given boiler configuration, there is a limit on the degree of NOX reduction that can be 

achieved with SNCR while maintaining acceptable levels of ammonia slip. 

A number of CFB boilers have been equipped with SNCR for NOX control as BACT according to 

the listings in the RBLC. The CFB design is described as the ideal application for SNCR in the 

literature. CFB boilers are constant temperature, variable heat transfer devices. The bed 

temperature and downstream flue gas temperature can be set and maintained by the operator to 

within a few degrees. The typical temperature of CFB flue gas leaving the bed and entering the 

hot cyclone is at the ideal temperature for SNCR. Additionally, the reduction reagent is injected at 

the inlet to the hot cyclone, where all of the flue gas is swirled at 50 to 75 feet/second, and forced 

to change direction many times. This cyclonic action homogenizes the reagent and flue gas NOX

concentration, thus maximizing gas to gas mixing. PC-fired units have a much more limited 

furnace temperature window and poor lateral mixing, conditions that render SNCR less effective in 

these applications. SNCR has been applied to PC boilers more often to achieve 30 to 50 percent 

reductions in response to RACT since the technology can be retrofit more readily than add-on 
10784-004-400 July, 2007 10-14

control. Due to mixing limitations and a brief temperature window in which to react, SNCR is 

fundamentally less effective at controlling NOX from PCs compared with CFBs. 

Staged Combustion

A number of techniques have been employed to reduce the formation of NOX by reducing peak 

flame temperature and/or starving the hottest parts of the flame for O2. By staging the combustion 

process, a longer, cooler flame results that forms less NOX. Staged combustion techniques 

include LNB, flue gas recirculation, OFA, burners out of service, and combinations of these. A 

collateral impact of staged combustion is an increase in emissions of products of incomplete 

combustion including CO, VOC, and carbon in ash (referred to as Loss on Ignition). 

Gas Reburn

Natural gas reburn is a control technique that has shown promise as a potential retrofit to existing 

boilers, and may be capable of reducing emissions of NOX to 0.15 lb/MMBtu simply by starving 

the coal burners for excess O2 and completing combustion with 12 to 15 percent gas in the upper 

furnace. Application of this technology assumes that natural gas in substantial quantity is already 

available on site – otherwise, it is technically infeasible. In any event, the level of NOX control that 

may be achieved is less than for the other add-on control technologies and therefore it is not 

considered further in this analysis. 

10.2.2.4 Summary of PC-fired Boiler BACT for NOX

Based on a review of available control technologies for emissions of NOX from a PC-fired boiler, 

as well as 20+ years of Sithe Global field experience and expertise in the application of SCR to 

coal-fired boilers, we conclude that the lowest NOX emission rate that has been permitted or 

continuously demonstrated in practice is 0.06 lb/MMBtu as a 24-hour average. This emission rate 

reflects the best emissions control technology available (LNB + SCR) for the proposed PC-fired 

boiler, and also represents the lowest emission rate permitted for a similar PC boiler. Therefore, 

0.06 lb/MMBtu of NOX represents the LAER as well as a top-down BACT. 

 

As shown in Table 10-8, at this level of control, the application of SCR to the proposed boiler was 

determined to have a total capital cost of about $35,000,000 and a total annualized cost of about 

$8,800,000. An estimated 2,100 tons per year (tpy) of NOX will be removed based on reduction 

from approximately 0.15 lb/MMBtu with LNB and PRB coal to 0.06 lb/MMBtu. Therefore, the cost 

effectiveness of SCR is estimated to be about $4,300 per ton of NOX removed in this particular 

application. No adverse cost, energy, or environmental impacts have been identified that would 

prevent the proposed project from continuously achieving 0.06 lb/MMBtu as a 24-hour average. 
10784-004-400 July, 2007 10-15

Table 10-8 

Estimated Cost of SCR for NOX Control 

Equipment Cost Basis 

Direct Capital Costs 

PURCHASED EQUIPMENT 

 (a) Basic Equipment (BE) 8,926,659 Back Calculate CUECost TDC / (1.2175 * 1.3) 

 (b) Auxiliaries Included Included 

 (c) Instrumentation and Controls 892,666 10% of BE 

 (d) Initial Ammonia and Catalyst 9,492,748 CUECost Initial Ammonia and Catalyst 

 (e) Tax and Freight 1,048,882 11.75% of BE 

TOTAL PURCHASED EQUIPMENT (PE) $20,360,955 Sum of (a) through (e) 

DIRECT INSTALLATION 

 (a) Foundations and Support 1,628,876 8% of PE 

 (b) Handling and Erection 2,850,534 14% of PE 

 (c) Electrical 814,438 4% of PE 

 (d) Piping 407,219 2% of PE 

 (e) Insulation for Ductwork 230,610 1% of PE 

 (f) Painting 230,610 1% of PE 

TOTAL DIRECT INSTALLATION (DI) $6,108,286 Sum of (a) through (f) 

TOTAL DIRECT COST (TDC) $26,469,241 PE + DI 

Indirect Capital Costs 

INDIRECT INSTALLATION 

 (a) Engineering and Supervision 1,412,867 CUECost Engineering Fees 

 (b) Construction and Field Expenses 706,433 CUECost General Facilities 

 (c) Contractor Fees 572,211 CUECost Prime Contractor’s Markup 

 (d) Contingencies 2,825,734 CUECost Total Contingency 

OTHER INDIRECT COSTS 

 (a) Startup and Performance Tests 501,260 CUECost Preproduction Costs 

 (b) Working Capital 370,100 30 Days O&M 

 (c) Allowance for Funds During Construction 2,091,959 CUECost AFDC 

TOTAL INDIRECT COST (TIC) $8,480,564 Sum of All Indirect Costs 

TOTAL CAPITAL COST $34,949,800 TDC + TIC 

Annual Direct Operating Costs 

DIRECT LABOR 200,157 CUECost Operating Labor 

MAINTENANCE 286,106 CUECost Maintenance 

UTILITIES 

 (a) Aqueous Ammonia 400,306 CUECost Ammonia 

 (b) Catalyst 3,142,315 CUECost Catalyst Replacement 

 (c) Electricity 441,316 CUECost Electricity 

 (d) High-Dust SCR Steam 30,373 CUECost High Dust SCR Steam 

CATALYST DISPOSAL 2,430 CUECost Catalyst Disposal 

Annual Indirect Operating Costs 

OVERHEAD 122,402 44% of Operating Labor + 12% of Maintenance Labor

PROPERTY TAX 349,500 1% of Total Capital Cost 

INSURANCE 349,500 1% of Total Capital Cost 

ADMINISTRATION 699,000 2% of Total Capital Cost 

CAPITAL RECOVERY 2,816,500 Assume 30 year life, 7% interest rate 

Total Annualized Cost $8,839,905 Sum of All Annual Costs 

TONS/YEAR CONTROLLED 2059

COST EFFECTIVENESS ($/TON) 4,300
10784-004-400 July, 2007 10-16

BACT for NOX for the TEP is concluded to be the emission rate of 0.06 lb/MMBtu as a 24-hour 

average using LNB and SCR. 

10.2.3 Auxiliary Boilers 

The TEP will include two small distillate oil-fired auxiliary boilers with heat input capacities of 

approximately 86.4 MMBtu/hour each. They will exclusively fire No. 2 distillate fuel oil with a 

maximum sulfur content of 0.0015 weight percent. These boilers will be subject to NSPS 40 Code 

of Federal Regulations (CFR) 60 Subpart Dc. Total annual fuel use in the two boilers will be 

limited to 95,040 MMBtu/year, which is equivalent to an average of only 550 hours of operation 

per year per boiler at full load (capacity factor of 6 percent). 

USEPA’s RBLC did not identify application of any emission controls to distillate oil-fired auxiliary 

package boilers other than “combustion control” for NOX. Industrial package boilers are 

pre-assembled units that are delivered to the site as a prefabricated unit. Due to shipping size 

constraints, package boilers are very compact, and utilize a “down and back” horizontal gas path. 

The small furnace volumes and high heat release rates of package boilers preclude application of 

a number of control alternatives that may be applied to field erected boilers, which typically are 

constructed with large furnace volumes and lower velocity, vertical gas paths. 

While ENSR did not identify any distillate oil-fired package boilers using SCR for NOX control, we 

believe that a new boiler could, in theory, be designed to accommodate SCR technology, and 

made the presumption that SCR might represent transferable technology for this application. If so, 

at a potential reduction of up to 90 percent, SCR would represent the hypothetical “top” control 

case (even though it could not be cost effective to a boiler that will only operate at most the 

equivalent of 23 days per year). As will be discussed in the following sections, SNCR, natural gas 

reburn, separated OFA (SOFA), and Burners Out of Service (BOOS) were determined to be not 

technically feasible for application to package boilers. The next best level of control in the topdown BACT analysis was therefore determined to be LNB to achieve an emission level of 0.10 lb 

NOX/MMBtu. 

10.2.3.1 SCR 

Due to advances in technology, package boilers that burn low sulfur distillate are routinely 

supplied with LNB design, and that utilize internal FGR, with resulting NOX emissions of around 

0.10 lb NOX/MMBtu. This proposed emission limit provides a maximum allowable NOX emission 

rate from each proposed auxiliary boiler of 0.10 lb/MMBtu x 86.4 MMBtu/hr x 550 hrs/yr x 

1 ton/2000lb = 2.4 tons NOX/year. SCR requires flue gas temperatures in the range of 600°F. 

Package boilers are manufactured to be both compact and efficient; flue gas temperatures exiting 

a package boiler are typically less than 300°F. Thus, the application of SCR to a package boiler 
10784-004-400 July, 2007 10-17

would either require flue gas re-heat, or a re-definition of the source from a package boiler to a 

custom design, split within the heat transfer tubes to provide sufficient volume for NH3:flue gas 

mixing at the correct temperature window for SCR. SCR is not, therefore, technically feasible for 

application to package design boilers. Even if a custom installation could be designed, SCR would 

not be well suited to operations of auxiliary units with frequent starts and stops (no NOX control is 

experienced at all until the catalyst bed achieves full operating temperature, negating any NOX

control during the first few hours after startup). 

In any event, such an installation would not be cost effective. For this hypothetical analysis, we 

conservatively assume that a hypothetical SCR could remove 90 percent of the proposed 

potential annual NOX emissions, or 2.1 tpy per boiler. ENSR obtained a budgetary cost estimate 

to apply SCR to a similarly sized heat recovery steam generators (HRSG) from Binder, Moss & 

Richter, Inc. The cost estimate was scaled from 99.7 to 86.4 MMBtu/hr and adjusted for consumer 

price index (CPI). As shown in Table 10-9, the basic SCR system and boiler modifications would 

have a capital cost of about $580,000 per boiler. Using a factored cost estimating approach, as 

outlined in USEPA’s Control Cost Manual, yields a total (installed) capital cost of $754,000 per 

boiler. The annualized cost to operate SCR for 550 hours per year, including capital recovery 

based on 7 percent interest for a 30-year lifetime, would exceed $200,000/yr per boiler. The 

interest rate and lifetime were chosen to be consistent with the values used for the cost 

effectiveness analysis of control options for the PC boiler. The cost effectiveness of application of 

SCR to each proposed auxiliary package boiler, therefore, would be about $93,000/ton of NOX

controlled, which is clearly not cost effective for this particular application. 

10.2.3.2 SNCR 

SNCR, a less effective but also less costly control technique, was reviewed for potential 

application to the proposed auxiliary package boilers. SNCR also requires a flue gas temperature 

zone of about 1,000°F, and requires excellent ammonia:flue gas mixing, which necessitates large 

furnace volumes and residence time within a precise and stable temperature window in the 

furnace at which to inject the ammonia or urea. As stated previously, the proposed auxiliary 

packaged boilers are designed for high heat release rates in a very compact space, and are not 

able to accommodate SNCR technology. Further, the proposed auxiliary boilers will only operate 

the equivalent of 550 hours per year, and then will serve a range of startup and space heating 

duties. This sporadic operation with load following over a turndown range of as much as 10:1, will 

create wide firing and temperature distribution variations within a furnace volume that is inherently 

too small for ammonia and NOX to effectively contact, which precludes the ability to utilize SNCR 

for NOX control. The USEPA document, “Alternative Control Techniques Document – NOX

Emissions from Industrial/Commercial/Institutional (ICI) Boilers” (ACT), states “... SNCR is not 
10784-004-400 July, 2007 10-18

Table 10-9 

Estimated Cost of SCR for the Auxiliary Boilers 

Equipment Cost Basis 

Direct Capital Costs 

PURCHASED EQUIPMENT 

 (a) Basic Equipment (BE) $488,158 Vendor Quote Binder, Moss & Richter 

 (b) Auxiliaries included 

 (c) Instrumentation & Controls 48,800 10% of BE 

 (d) Tax & Freight 43,000 8% of (1a) -> (1c) 

TOTAL PURCHASED EQUIPMENT (PE): $579,958 

DIRECT INSTALLATION 

 (a) Foundations and Support 46,397 8% of PE 

 (b) Handling and Erection 81,194 14% of PE 

 (c) Electrical 23,198 4% of PE 

 (d) Piping 11,599 2% of PE 

 (e) Insulation for Ductwork 5,800 1% of PE 

 (f) Painting 5,800 1% of PE 

TOTAL DIRECT INSTALLATION (DI): $173,987 

TOTAL DIRECT COST (TDC): $753,945 

Indirect Capital Costs 

INDIRECT INSTALLATION 

 (a) Engineering & Supervision 58,000 10% of PE 

 (b) Construction & Field Expenses 29,000 5% of PE 

 (c) Contractor Fees 58,000 10% of PE 

 (d) Contingencies 17,400 3% of PE 

OTHER INDIRECT COSTS 

 (a) Startup & Performance Tests 17,400 3% of PE 

 (b) Working Capital 6,600 30 days O&M cost 

TOTAL INDIRECT COST: $186,400 Sum of All Indirect Costs 

TOTAL CAPITAL COST: $940,300 TDC + TIC 

Annual Direct Operating Costs 

DIRECT LABOR (DL) 

 (a) Operators 1,200 0.5 hour/shift @$35/hr 

 (b) Supervisors 200 15% of operating labor 

MAINTENANCE 

 (a) Labor 1,600 0.5 hour/shift @$45/hr 

 (b) Material 1,600 100% of maintenance labor 

MEDIA REPLACEMENT 81,360 1/6 of BE assuming 3 year life and total catalyst cost 

equal to half of equipment cost 

UTILITIES 

 (a) Electricity 206 $0.05 per kWh 

 (a) Aqueous Ammonia 19.3% 756 $350 per ton ENSR Estimate 

Annual Indirect Operating Costs 

OVERHEAD 800 44% of Operating Labor + 12% of Maintenance Labor

PROPERTY TAX 9,400 1% of Total Capital Cost 

INSURANCE 9,400 1% of Total Capital Cost 

ADMINISTRATION 18,800 2% of Total Capital Cost 

CAPITAL RECOVERY 75,800 Assume 30 year life, 7% interest rate 

Total Annualized Cost $201,122 Sum of All Annual Costs 

TONS/YEAR CONTROLLED 2.16

COST EFFECTIVENESS ($/TON) $93,100 
10784-004-400 July, 2007 10-19

considered applicable to small packaged watertube and firetube boilers and units with large 

fluctuations in steam load” (USEPA 1994). SNCR is determined to be not technically feasible for 

application to the proposed distillate-fired auxiliary package boilers. 

10.2.3.3 Burners Out of Service, Separated Over-fire Air, and Gas Reburn 

Various staged combustion techniques have been applied to vertically oriented, field erected 

boilers, including BOOS, SOFA, and Natural Gas Reburn. All of these technologies seek to limit 

the formation of NOX by vertical combustion staging in the furnace of a field-erected boiler, where 

sufficient volume and residence time exists to starve the high temperature combustion zone of O2, 

then adding the O2 back to complete combustion in the upper section of the furnace. Industrial 

package boilers are simply not configured with the volume, residence time, or temperature 

windows to employ such combustion macro-staging. No listings of distillate oil-fired auxiliary 

package boilers were found in the RBLC that employ BOOS, SOFA, or gas reburn technologies 

for control of NOX, nor were any of these technologies discussed in the USEPA’s ATC document 

as applicable to this type of boiler. None of these methods of NOX control are determined to be 

technically feasible for application to the proposed auxiliary package boiler. 

10.2.3.4 Low NOX Burners with Flue Gas Recirculation 

All identified top-down BACT decisions for similar auxiliary package boilers conclude that LNB 

with internal FGR represent the best practical and cost effective alternative for this particular 

source type. Most LNBs sold by the major manufacturers utilize internal “micro combustion 

staging,” whereby flue gas is internally recirculated into the highest temperature portion of the 

flame, and additional air is added downstream to complete burn out of products of incomplete 

combustion. The lowest emission rate that can be achieved when burning distillate oil with this 

technology is 0.10 lb NOX/MMBtu. 

10.2.3.5 Selection of BACT for NOX for the Proposed Auxiliary Package 

Boilers 

Although a custom auxiliary boiler could, in theory, be designed to allow application of an SCR to 

a boiler for removal of NOX, it has been determined that even just based on the cost of the SCR 

system itself, it would not be cost-effective for an auxiliary boiler limited to 6 percent capacity. The 

550 hour per year operating limit results in the cost per ton of NOX to $93,000, which is not cost 

effective and eliminates it from consideration as BACT. SNCR, BOOS, OFA, and Gas reburn are 

all eliminated from consideration for BACT due to technical infeasibility. Therefore BACT for the 

proposed auxiliary boilers is determined to be LNB. 
10784-004-400 July, 2007 10-20

All but one of the permit limits for similar boilers listed in the USEPA RBLC from January of 1996 

through September of 2006 received BACT decisions between 0.09 and 0.19 lb/MMBtu. The 

Auxiliary Boiler at the Faribault Energy Park in Minnesota (7/15/2004) is listed with a limit of 

0.058 lb/MMBtu using low sulfur distillate oil, LNB and FGR. As of September 2006, this unit has 

not been constructed, and the limit has not been demonstrated in practice. Toquop Energy 

proposes to use LNB and low sulfur fuel to limit NOX emissions to 0.10 lb/MMBtu, the 

demonstrated capability of these BACT control technologies. 

10.2.4 Emergency Diesel Engines 

The TEP includes one 1,482 horsepower (hp) emergency diesel generator and one 284 hp 

diesel-fired firewater pump. These emergency diesel engines will not operate for more than 

100 hours/year each for readiness testing purposes, unless they should be called upon to operate 

in an emergency situation. NOX emissions during operation will be controlled by limiting fuel 

supply to these units to ultra low sulfur distillate oil, with ignition timing retard with turbocharging 

and aftercooling. These engines also will be subject to new requirements under the NSPS for 

Stationary Compression Ignition Internal Combustion Engines (40 CFR Parts 60, 85, 89, 94, 1039, 

1065, and 1068) published on July 11, 2006. Toquop Energy proposes that the NSPS 

requirements are equivalent to BACT for the proposed emergency diesel generator and the 

firewater pump, engine since the NSPS requirements establish new maximum limits and are still 

being phased in for these source categories. Selection of the appropriate emission limits for the 

emergency generator were based on the specifications for a 2007 model year 1,482 hp standby 

generator manufactured by Caterpillar (or equivalent), which have a displacement of about 8 liters 

per cylinder. Therefore, emissions from the emergency generator will be limited to 6.4 g/kWh for 

combined NOX and non-methane hydrocarbons (NMHC), as specified for generator engines with 

a displacement less than 10 liters per cylinder. The limit for the firewater pump engine also is for 

the combined emissions of NOX and NMHC of no more than 4.0 g/kWh. 

10.3 BACT for Sulfur Dioxide 

10.3.1 Formation 

Emissions of SO2 are generated in fossil fuel-fired sources from the oxidation of sulfur present in 

the fuel. Approximately 98 percent of sulfur in solid fuels is emitted upon combustion as gaseous 

sulfur oxides. Uncontrolled emissions of SO2 are thus affected by fuel sulfur content alone, and 

not by source category, mechanism, size, or operation. Many coal-fired boilers in the U.S. limit 

emissions of SO2 through the use of low sulfur western coals, including PRB coal. Compared with 

a high-sulfur eastern bituminous coal that may contain as much as 4 percent sulfur, burning 

western coal can avoid SO2 emissions by approximately 70 to 90 percent. The selection of coal 

type and sulfur content is therefore an important aspect of the determination of BACT and needs 
10784-004-400 July, 2007 10-21

to be considered in conjunction with add-on control alternatives when performing the top-down 

analysis. 

10.3.2 PC-fired Boilers 

10.3.2.1 Ranking of Available Add-On Control Techniques 

Generally, there are two types of add-on control applicable to a coal-fired boiler: in-situ 

combustion control (sorbent injection) and post-combustion control (flue gas desulfurization 

[FGD]). In-situ control is used effectively in CFB boilers, and may be used in a PC boiler by dry 

injection of sorbents such as limestone or trona; however, the level of control that is achievable is 

not comparable to post-combustion SO2 control systems. Post-combustion controls applicable to 

PC boilers include wet scrubbing or spray dryer absorber (SDA) technology using reagents such 

as limestone, lime, quicklime, sodium bicarbonate, or magnesium oxide. 

A comparative ranking of available SO2 control technologies (Table 10-10) must take into 

consideration multiple variables including coal sulfur content and variability, percent removal 

capability (which varies depending on the amount of uncontrolled SO2 entering the control device), 

and the resulting composite emission rate (lb/MMBtu) in addition to collateral impacts on other 

pollutants, energy impacts, and other environmental impacts. 

Table 10-10 

Ranking SO2 Technologies for PC Boilers 

Control Technology 

Typical Level 

of Control1 Typical Emission Level1 

(lb/MMBtu) 

Technically Feasible 

for PC Boilers? 

Wet Scrubber 80 to 98% Depends on coal sulfur content (lower end of range 

with western coal) 

Yes 

Limestone Injection 25 to 35% Depends on coal sulfur content (lower end of range 

with western coal) 

Yes 

SDA 60 to 92% Depends on coal sulfur content (lower end of range 

with western coal) 

Yes 

Use of Low Sulfur 

Coal 

30 to 90% Western coals represent a 70 to 90% reduction 

compared with high sulfur eastern coals, lower 

reduction compared to other eastern coals 

Yes 

1

 Emission levels represent steady state values. EPA AP-42 notes limestone wet scrubbers at the high range of control efficiency are applicable to high 

sulfur fuels. 

10.3.2.2 Recent Permit Limits 

SO2 emission limits for the permits listed in USEPA’s RBLC (see Attachment 10-B) since 2004 for 

PC boilers range between 0.09 to 0.13 lb/MMBtu. 
10784-004-400 July, 2007 10-22

AES Puerto Rico and the proposed application for the Nevco Sevier project have SO2 limits in the 

range of 0.023 lb/MMBtu; however, both are CFB boilers with polishing scrubbers. CFB boilers 

are fundamentally different emission sources than PC-fired boilers. CFB boilers are limited in size 

to about 250 MMBtu/hr and could not meet the single unit generation capacity of the proposed 

TEP unit. Further, CFB boilers have yet to be demonstrated in supercritical operation, meaning 

they are fundamentally less fuel efficient than a supercritical PC boiler. Burning more fuel to 

produce the same electrical output would result in collateral increases in emissions of the other 

pollutants (on a lb/kW produced basis), would emit more carbon dioxide (CO2), and would be 

wasteful of both fuel resources and the cost to produce electricity. No supercritical PC-fired boilers 

have been permitted at SO2 emission levels less than 0.09 lb/MMBtu. 

The permit limits for Big Cajun II in Louisiana and the Weston Plant in Wisconsin were 0.10 and 

0.09 lb/MMBtu, respectively. According to the USEPA RBLC, Big Cajun II could utilize either a 

semi-dry lime scrubber or wet FGD. The sulfur controls needed to be 90 percent efficient to reach 

their design goal of 0.10 lb/MMBtu. The Weston Plant proposed to use 92 percent efficient dry 

FGD to achieve the design goal of 0.09 lb/MMBtu. Comanche Station was able to net out of PSD 

review for SO2 by controlling existing equipment. Toquop Energy has proposed very low emission 

rates for the TEP: 483.8 lb/hr and 1351 tpy. These emission rates are equivalent to about 0.08 

lb/MMBtu on an hourly basis and 0.06 lb/MMBtu on an annual basis, and are considered to 

represent the top level of control for SO2 from a supercritical PC-fired boiler. 

10.3.2.3 SO2 Control Technology Review 

Wet Flue Gas Desulfurization

The most frequently utilized wet FGD technology is the wet quicklime spray tower system. 

Typically, flue gas enters at the bottom of the absorber tower, continues vertically through the 

quicklime/water spray, passes through a mist eliminator to control the re-entrained slurry drops, 

and then exits the tower. Quicklime (calcium carbonate) reacts with the SO2 to form calcium 

sulfite. The calcium sulfite may then be oxidized to form calcium sulfate, since it is easier to 

de-water than calcium sulfite. This can be achieved by blowing compressed air into the slurry in 

the retention tank in the base of the tower or in an external oxidation tank. 

To fully utilize the quicklime, the slurry is re-circulated through the tower and a bleed stream is 

taken off for de-watering. The bleed stream can be de-watered using a variety of techniques, 

including thickeners, centrifuges and vacuum filters. The final slurry may contain 10 to 40 percent 

water by weight. 
10784-004-400 July, 2007 10-23

Wet scrubbers also can utilize limestone rather than lime. Some of the lime (calcium oxide) 

becomes calcium hydroxide in water. The slurry of calcium hydroxide and lime is fed to the spray 

tower. Since the cost of limestone is much less than lime, the limestone alternative is much more 

common. This is especially the case for medium to high sulfur coals. 

Spray Dryer Absorber

The SDA is located upstream of the particulate collection system, typically fabric filters. 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 SDA through either a rotary atomizer or fluid nozzles. The moisture in the 

droplets evaporates and reacts with the SO2 in the flue gas to form insoluble calcium salts. The 

flue gas is cooled to approximately 18 to 30°F above the adiabatic saturation of the flue gas. The 

calcium salts have a moisture content of approximately 2 to 3 percent, which falls to 1 percent 

before reaching the particulate control device. When a fabric filter is used as the particulate control 

device, it allows for further reaction of the lime with the sulfur (and other 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 

H2SO4, hydrogen chloride, and Hg as compared to wet scrubbers. 

Use of Low Sulfur Coal

Any discussion of the relative effectiveness of add on SO2 control also must take into account the 

level of uncontrolled SO2 to be handled, which is highly dependent on the sulfur content of the 

coal to be burned. Higher removal efficiencies tend to be more practical when there is a high 

concentration of SO2 in the flue gas, and vice versa. This is reflected in a comparison of the 

resulting emission rate in units of lb of SO2 per MMBtu of fuel burned (or lb of SO2 per kW 

produced). For example, a proposed project with a BACT limit of 0.16 lb/MMBtu using an 

80 percent removal control system is environmentally superior to another project with a BACT limit 

of 0.32 lb/MMBtu and 95 percent removal. For a project located in the Western U.S., BACT limits 

are generally based on the use of low sulfur western coal as a part of a strategy to limit SO2 to 

BACT levels in combination with add-on control. 

10.3.2.4 Summary of PC-fired Boiler BACT for SO2

Toquop Energy is proposing to limit SO2 emissions to 483.6 lb/hr and 1351 tpy by burning low 

sulfur western coal and using a wet quicklime flue gas desulfurization system. These emission 

rates are equivalent to about 0.08 and 0.06 lb/MMBtu, and are lower than any other PC project 

listed in USEPA’s RBLC. TEP’s proposed emission limits are lower than the two most recent 

similar permits – Big Cajun II Power Plant in Montana (08/22/05) and the Weston Plant in 

Wisconsin (10/19/04). These projects have SO2 permit limits of 0.10 and 0.09 lb/MMBtu 
10784-004-400 July, 2007 10-24

respectively. The permit for Sithe Global’s proposed Desert Rock Energy Facility is pending, with 

a proposed BACT emission limit for SO2 of 0.06 lb/MMBtu. Toquop Energy is proposing the same 

“Top” level of control for the TEP, and has proposed the same level of control from the proposed 

PC boilers on an annual basis. 

As shown in Table 10-11, wet FGD (lime slurry, forced oxidation) total capital equipment was 

estimated at about $74,000,000 with a total annualized cost of $22,000,000. This system would 

reduce SO2 emissions by 6,544 tpy based on the assumption that without the scrubber present all 

of the sulfur in the design fuel would be emitted as SO2. Therefore, the cost effectiveness of the 

wet FGD system is about $3,300 per ton of SO2 removed. 

The cost effectiveness is significantly higher than the typical cost effectiveness to control SO2

(SO2 allowances trade in the range of $500/ton). The high cost effectiveness calculated for this 

project is due to a combination of very low sulfur in coal to begin with, and Toquop Energy’s 

proposal to over-control SO2 compared with similar PC boiler permits. While the cost effectiveness 

is high enough to eliminate the proposed level of SO2 control as BACT, Toquop Energy has 

elected to propose a level of control that goes beyond BACT, in order to proactively limit 

emissions of H2SO4 and SO2 as potential precursors to the formation of regional haze. No adverse 

energy or environmental impacts have been identified that would prevent the proposed project 

from continuously achieving 483.8 lb/hr and 1351 tpy. 

10.3.3 Auxiliary Boilers 

The TEP also includes two small distillate oil-fired auxiliary boilers with heat input capacities of 

86.4 MMBtu/hour each. Total annual fuel use in the two boilers will be limited to 

95,040 MMBtu/year, which is equivalent to an average of 550 hours/year per boiler at full load. 

SO2 emissions will be controlled by only burning ultra low sulfur distillate oil with a maximum sulfur 

content of 0.0015 weight percent. No add-on SO2 controls have ever been applied to similar 

sources. The use of very low sulfur fuel is the only available SO2 control option. On-road 

transportation distillate oil is currently becoming available with very low sulfur contents. It is not 

expected to be commercially available in bulk for several more years in distant locations such as 

at the TEP location. However, since operation of the TEP is not expected until late 2012, ultra low 

sulfur distillate oil is expected to be available at the project site. The TEP proposes to burn ultra 

low sulfur transportation diesel oil (0.0015 wt percent sulfur) and by limiting total annual fuel 

consumption to 95,040 MMBtu/year, resulting in an SO2 emission rate of 0.002 lb/MMBTU as 

BACT for the proposed auxiliary boilers, based on AP-42 emission factors including the 

summation of both SO2 and SO3. 
10784-004-400 July, 2007 10-25

Table 10-11 

Estimated Cost of Wet FGD System 

Equipment Cost Basis 

Direct Capital Costs 

PURCHASED EQUIPMENT 

 (a) Basic Equipment (BE) 19,235,499 Back Calculate PE / 1.2175 

 (b) Auxiliaries included

 (c) Instrumentation and Controls 1,923,550 10% of BE 

 (d) Tax and Freight 2,260,171 11.75% of BE 

TOTAL PURCHASED EQUIPMENT (PE) $23,419,220 Back Calculate TDC / 1.85 

DIRECT INSTALLATION 

 (a) Foundations and Support 2,810,306 12% of PE 

 (b) Handling and Erection 9,367,688 40% of PE 

 (c) Electrical 234,192 1% of PE 

 (d) Piping 7,025,766 30% of PE 

 (e) Insulation for Ductwork 234,192 1% of PE 

 (f) Painting 234,192 1% of PE 

TOTAL DIRECT INSTALLATION (DI) $19,906,337 Sum of (a) through (f) 

TOTAL DIRECT COST (TDC) $43,325,558 CUECost (Total Capital Cost – Chimney) 

Indirect Capital Costs 

INDIRECT INSTALLATION 

 (a) Engineering and Supervision 4,332,556 CUECost (Engineering Fees – Chimney) 

 (b) Construction and Field Expenses 4,332,556 CUECost (General Facilities – Chimney) 

 (c) Contractor Fees 2,022,610 CUECost Prime Contractor’s Markup 

 (d) Contingencies 8,665,112 CUECost (Contingency – Chimney) 

OTHER INDIRECT COSTS 

 (a) Startup and Performance Tests 2,609,645 CUECost Preproduction Costs 

 (b) Working Capital 1,017,625 30 Days O&M + CUECost Inventory Capital 

 (c) Allowance for Funds During Construction 7,394,505 CUECost AFDC 

TOTAL INDIRECT COST (TIC) $30,374,609 Sum of all Indirect Costs 

TOTAL CAPITAL COST $73,700,200 TDC + TIC 

Annual Direct Operating Costs 

DIRECT LABOR 2,890,857 CUECost Operating Labor 

MAINTENANCE 3,467,331 CUECost Maintenance Labor and Materials 

OPERATING MATERIALS 408,849 CUECost Reagent Costs 

DISPOSAL 270,694 CUECost Disposal Costs 

STEAM 1,754,288 CUECost Steam Costs 

ELECTRICITY 2,674,437 CUECost Power Costs 

Annual Indirect Operating Costs 

OVERHEAD 1,688,057 44% of Operating Labor + 12% of Maintenance Labor 

PROPERTY TAX 737,000 1% of Total Capital Cost 

INSURANCE 737,000 1% of Total Capital Cost 

ADMINISTRATION 1,283,337 2% of Total Capital Cost 

CAPITAL RECOVERY 5,939,200 Assume 30 year life, 7% interest rate 

Total Annualized Cost $21,851,049 Sum of All Annual Costs 

TONS/YEAR CONTROLLED 6,544

COST EFFECTIVENESS ($/TON) $3,300 
10784-004-400 July, 2007 10-26

10.3.4 Emergency Diesel Engines 

The TEP includes one 1,482 hp emergency diesel generator and one 284 hp diesel powered 

emergency firewater pump engine. These emergency diesel engines will not be operated for more 

than 100 hours/year each for readiness testing purposes, unless they should be called upon to 

operate in an emergency situation. No add-on SO2 controls have ever been applied to similar 

sources. The July 2006 NSPS for Stationary Compression Ignition Internal Combustion Engines 

does not specify emission limits for SO2, but does specify that future emissions be reduced 

through the use of ultra low sulfur diesel fuel. 

The use of low sulfur fuels such as ultra low sulfur distillate oil is the only available SO2 control 

option and represents the top level of control. Toquop Energy proposes an SO2 limit of 0.15 

g/kWh for the emergency generator and 0.01 g/kWh for the firewater pump engine while utilizing 

the same ultra low sulfur distillate oil (0.0015 wt percent sulfur) for the proposed emergency diesel 

engines as for the auxiliary boilers, and to restrict operation to 100 hours per year each. 

10.4 BACT for CO 

10.4.1 Formation of CO Emissions 

CO is formed as a result of incomplete combustion of a hydrocarbon fuel. Control of CO is 

accomplished by providing adequate fuel residence time, excess O2, 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 LNB can result in higher levels of CO formation. 

Thus, a compromise is established to achieve the lowest NOX formation rate possible while 

keeping CO emission rates at acceptable levels. 

10.4.2 PC-fired Boilers 

10.4.2.1 Ranking of Available CO Control Technology Options 

CO emissions from PC-fired boilers are a function of O2 availability (excess air), flame 

temperature, residence time at flame temperature, combustion zone design, and turbulence. All 

PC-fired boilers identified utilize front-end methods such as good combustion control wherein CO 

formation is suppressed within the boiler. All listings in USEPA’s RBLC for PC-fired boilers utilize 

combustion control techniques for CO (see Attachment 10-B). While gas-fired combustion 

turbines have been widely equipped with oxidation catalyst control technology, this technology is 

not applicable to coal-fired boilers. In addition to oxidizing CO, an oxidation catalyst would oxidize 

SO2 to produce SO3, which would exacerbate H2SO4 emissions. The SO2 oxidation rate would be 
10784-004-400 July, 2007 10-27

in the range of 5 percent or more resulting in very high sulfuric acid mist emissions if an oxidation 

catalyst were to be attempted on a coal-fired boiler. 

A review of the USEPA’s RBLC from 2004 to September of 2006 indicates that the CO permit 

limits for PC boilers are all between 0.11 and 0.16 lb/MMBtu. All of these facilities plan to use 

combustion controls to achieve their emission limit. One permit in the RBLC for W. A. Parish 

Unit 8, has a CO limit of 0.05 lb/MMBtu; however, the corresponding NOX limit is 0.43 lb/MMBtu. 

Since the TEP is proposing a very stringent NOX limit of 0.06 lb/MMBtu, a CO limit similar to W. A. 

Parrish would not be technically feasible. 

Emission levels and control technologies have been identified and ranked in Table 10-12. 

Table 10-12 

Ranking of CO Control Technology Options for PC-Fired Boilers 

Control Technology Option 

Emission Level 

(lb/MMBtu) 

Technically Feasibility 

for PC-fired Boilers? 

Combustion controls 0.101 to 0.16 Yes 

Oxidation catalyst Not determined No 

SCONOX Not determined No 

1

 Lowest level achievable for PC boilers with aggressive NOX limits. 

10.4.2.2 CO Control Technology Discussion 

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. 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 may increase when 

steps to lower CO are taken. 

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 
10784-004-400 July, 2007 10-28

a coal-fired unit. It is evaluated here to determine if it could be considered transferable technology 

for application to the proposed PC-fired boilers. In this 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 O2 to CO2 and water. The catalyst permits 

combination of the reactant species at lower gas temperatures and residence times than would be 

required for uncatalyzed 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 

approximately 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 percent of inlet SO2. This level of conversion would result in a large 

collateral increase in H2SO4 emissions that, aside from the increased ambient air impacts, could 

result in unacceptable amounts of corrosion to the fabric filter 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 system on a 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, oxidation catalyst systems are considered technically infeasible for 

application to the proposed coal-fired boiler. 

SCONOX

SCONOX is a technology that has been widely discussed for application to many types of sources; 

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 nitric oxide to nitrogen dioxide but with the side benefit of 
10784-004-400 July, 2007 10-29

also reducing emissions of CO. SCONOX therefore has all the limitations cited above for oxidation 

catalyst, but is even further from consideration as transferable technology. 

10.4.2.3 Summary of PC-fired Boiler BACT for CO 

The only practical or demonstrated-in-practice measure to control CO from PC-fired boilers is 

good combustion. Combustion control, and the resulting optimized emission rate to minimize 

formation of CO while simultaneously minimizing NOX, therefore represents the BACT control 

technology for the proposed PC boiler. BACT for CO from the proposed PC boiler is therefore 

concluded to be 0.10 lb/MMBtu on a 24-hour average. This level is lower than all recent permits 

for new PC fired boilers.

10.4.3 Auxiliary Boilers 

10.4.3.1 Identification and Ranking of Control Technologies for CO 

As with the coal-fired boilers, emissions of CO from auxiliary package boilers are the product of 

incomplete combustion (PICs) of the fuel. All CO control techniques seek to more fully burn out 

these PICs with excess oxygen typically present. Oxidation catalysts have been routinely applied 

to combustion turbines (which exhibit much higher levels of PICs than steam boilers), however 

oxidation catalyst technology is not applicable to auxiliary package boilers. In order to function, the 

oxidation catalyst must be placed within the first boiler pass where flue gas temperature is 

consistently 800 to 1,000°F. Further, the catalyst bed requires a large surface area (as in the 

full-height HRSG of a combined cycle turbine) to limit space velocity of the flue gases across the 

catalyst bed and to limit adverse pressure drop. The cross sectional area of package boilers is too 

small to accommodate these design features. Finally, the placement of a catalyst barrier within the 

furnace of a package boiler would increase risk of explosion or “puff” in the event of flame out. The 

application of oxidation catalyst technology within a compact, high heat release, load-following 

package boilers is concluded to not be technically feasible. The next best level of control is 

achieved with good combustion control via time, temperature and turbulence. Today’s generation 

of LNB’s seek to provide low NOX profiles through staged combustion, while simultaneously 

adding back oxygen to effectively burn out CO. This represents the top level of control for 

products of incomplete combustion from this source type. 

10.4.3.2 Selection of BACT for CO for the Proposed Auxiliary Package 

Boilers 

The top level of control for these particular emission units was determined to be the use of 

combustion controls to avoid incomplete combustion of CO. What little CO is emitted is a 

necessary side effect of simultaneously controlling NOX to very low levels. The use of LNB 
10784-004-400 July, 2007 10-30

designed for good combustion control for the proposed backup auxiliary boiler is therefore 

determined to represent BACT for CO for distillate oil-fired auxiliary package boilers. Total annual 

fuel use in the boilers will be limited to 95,040 MMBtu/year, which is equivalent to an average of 

550 hours/year per boiler at full load. A BACT limit for CO emissions of 0.036 lb/MMBtu and the 

annual total fuel restriction of 95,050 MMBtu/year are proposed for these boilers, which reflect the 

lowest emission limits listed in USEPA’s RBLC (see Attachment 10-D). 

10.4.4 Emergency Diesel Engines 

The TEP includes one 1,482 hp emergency diesel generator and one 284 hp diesel powered 

emergency firewater pump. The diesel engines will not be operated for more than 100 hours/year 

each (except as called upon to operate in an emergency). The July 2006 NSPS for Stationary 

Compression Ignition Internal Compression Engines specifies a limit of 3.5 g/kWh of CO for 

engines greater than 900 kWh with a displacement less than 10 liters per cylinder and a limit of 

3.5 g/kWh of CO for firewater pump engines. Selection of the appropriate emission limits for the 

emergency generator were based on the specifications for the 1,482 hp emergency generator 

manufactured by Caterpillar (or equivalent), which have a displacement of about 8 liters per 

cylinder. Toquop Energy proposes these limits as BACT for the emergency diesel generator and 

firewater pump, together with an operation limit of 100 hours per year. 

10.5 BACT for VOC 

10.5.1 Formation of VOC Emissions 

Similar to CO, VOCs also are emitted from combustion units 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. 

10.5.2 PC-fired Boilers 

10.5.2.1 Ranking of Available VOC Control Technology Options 

VOC emissions from coal-fired boilers are a function of fuel rank and heating value (Btu/lb), 

oxygen availability (excess air), flame temperature, residence time at peak 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 

USEPA’s RBLC (see Attachment 10-B) 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. 
10784-004-400 July, 2007 10-31

10.5.2.2 Recent Permit Limits 

The VOC permit limits for the PC units listed in USEPA’s RBLC from 2004 through 

September 2006 range between 0.0024 and 0.01 lb/MMBtu. The lower values of this range were 

all permitted for units that will utilize higher rank bituminous coals. The limits for the most recently 

permitted facilities using PRB (sub-bituminous) coal, Big Cajun II, Comanche Station, and the 

Weston Plant, were 0.015, 0.0035, and 0.0036 lb/MMBtu respectively. Emission levels and control 

technologies have been identified and ranked in Table 10-13. 

Table 10-13 

Ranking of VOC Control Technology Options for PC-Fired Boilers 

Control Technology Option 

Emission Level 

(lb/MMBtu) 

Technically Feasibility 

for PC-fired Boilers? 

Combustion control 0.00241 to 0.01 Yes 

Oxidation catalyst Not determined No 

 

1

 Lowest values for PC boilers burning sub-bituminous coal are 0.0035 lb/MMbtu. 

10.5.2.3 VOC Control Technology Discussion 

Combustion Control

Combustion control refers to controlling emissions of VOC through the design and operation of the 

boiler in a manner so as 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. PC-fired 

boilers are designed specifically for efficient fuel combustion with thorough mixing and residence 

time at temperature, and typically employ staged combustion. This level of combustion control 

represents BACT for the proposed PC boilers. 

Add-On Emission Controls

Catalytic oxidation and SCONOX are not applicable to coal-fired boilers as previously discussed in 

Section 10.4.4.2. 
10784-004-400 July, 2007 10-32

Summary of PC-fired Boiler BACT for VOC

The only practical or demonstrated in practice measures to control VOC emissions 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 PC boilers. Toquop Energy proposes a VOC BACT limit of 0.003 lb/MMBtu, which is 

lower than any recently permitted PC boiler burning sub-bituminous PRB coal. 

10.5.3 Auxiliary Boilers 

Like CO emissions, VOCs are products of incomplete combustion. The same control techniques 

that are BACT for CO for the auxiliary boilers also represent BACT for VOCs. Therefore, the use 

of LNB designed for good combustion control is determined to represent BACT for VOC for the 

distillate oil-fired auxiliary package boilers. Total annual fuel use in the boilers will be limited to 

95,040 MMBtu/year, which is equivalent to an average of 550 hours/year per boiler at full load. 

BACT for VOC emissions is concluded to be an emission limit of 0.003 lb/MMBtu and a total fuel 

restriction of 95,040 MMBtu/year for the two boilers based on USEPA’s RBLC (see 

Attachment 10-B). 

10.5.4 Emergency Diesel Engines 

The TEP includes one 1,482 hp emergency diesel generator and one 284 hp diesel powered 

emergency firewater pump. The diesel engines will be limited to no more than 100 hours/year 

each (except for operation during an emergency). The July 2006 NSPS for Stationary 

Compression Ignition Internal Combustion Engines regulates NMHC, which is essentially the 

same as VOC (methane is not regulated as a VOC). Selection of the appropriate emission limits 

for the emergency generator were based on the specifications for a 1,482 standby generator 

manufactured by Caterpillar (or equivalent), which have a displacement of about 8 liters per 

cylinder. The emission limits for both the emergency generator and the firewater pump are for 

combined NMHC and NOX as described in Section 10.2.4. 

Toquop Energy proposes that the combined NMHC and NOX emission limits are BACT for VOC 

for the emergency engines. The proposed emission limit is 6.4 g/kWh of NMHC and NOX for the 

emergency generator and 4.0 g/kWh for the firewater pump. Both emergency generators will have 

an operational limit of 100 hours per year, except during operation in an emergency situation. 
10784-004-400 July, 2007 10-33

10.6 BACT for Particulate Matter 

10.6.1 Formation of Particulate Matter 

The composition and amount of PM emitted from coal-fired boilers are a function of coal ash 

content (rank), firing configuration, boiler operation, and emission controls. PM will be emitted 

from the PC-fired boilers as a result of entrainment of incombustible inert matter (ash) and 

condensable substances such as acid gases. Sub-bituminous coals such as PRB are of low 

heating value primarily due to their relatively higher ash content compared with higher rank 

bituminous coal; this elevated ash content results in higher uncontrolled particulate emissions 

when burning PRB coal. PM and PM10 (PM2.5 is a subset of PM10) require the application of BACT 

under the federal PSD program. PM is total filterable PM as determined by USEPA Method 5 

or 17. PM10 includes filterable PM10 as determined by USEPA Method 201 or 201A plus 

condensable PM as determined by USEPA Method 202. 

10.6.2 PC-fired Boilers 

10.6.2.1 Ranking of Available Particulate Control Technology Options 

PM10 emission limits are often difficult to assess as many older listings in the RBLC and even in 

issued permits do not specify test methods. Consequently, ENSR has determined that many 

emission limits only reflect filterable PM or PM10 and do not include condensable PM10. The permit 

for AES-Puerto Rico addressed this issue in detail. AES’s permit limits filterable PM10 to 

0.015 lb/MMBtu and allowed for 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, USEPA has approved an administrative change to their permit to set the 

total PM10 emission limit at 0.03 lb/MMBtu to account for the condensable fraction of PM10. 

Several other recent coal-fired boiler projects are listed in the RBLC 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 and LAER for PM. BACT and LAER for PM10 must account for 

additional emissions attributable to the condensable fraction of PM10. 

A review of USEPA's RBLC indicates several levels of particulate control that may be achieved for 

pulverized boilers. Emission levels and control technologies have been identified and ranked in 

Table 10-14. 
10784-004-400 July, 2007 10-34

Table 10-14 

Ranking of Particulate Control Technology Options for PC-Fired Boilers 

Control Technology Option 

Emission Level 

(lb/MMBtu) 

Technically Feasibility 

for PC-fired Boilers? 

Fabric Filter 0.01 to 0.02 for filterable PM Yes 

Electrostatic precipitator 0.015 to 0.025 for filterable PM Yes 

High energy wet scrubber Not determined No applications in the last 15 years 

to large coal-fired boilers 

Note: Emission levels represent target steady-state values at base load, for front-half (filterable) only. Inclusion of the condensable fraction is anticipated to 

double the particulate emission rate for coal-fired boilers. 

There are a large number of coal-fired boilers listed in the USEPA's RBLC with emission limits for 

filterable PM that are less than or equal to 0.02 lb/MMBtu. All but one of these listings report that a 

fabric filter is utilized (the AES Puerto Rico facility is the only exception). The control of PM using 

fabric filtration is clearly demonstrated for coal-fired boilers. The recently permitted PC boilers 

have emission limits for PM10 varying from 0.012 to 0.018 lb/MMBtu; however, the USEPA RBLC 

specified whether these limits included condensable PM10 in only a few cases. Fabric filter 

represents the technology of choice to achieve the lowest PM10 limits in the RBLC. 

Wet control techniques (venturi or other high-energy scrubbers), on the other hand, do not 

represent a recently applied or demonstrated control technique for coal-fired boilers and do not 

offer more stringent levels of control of particulate matter than fabric filters. 

10.6.2.2 PM and PM10 Control Technology Discussion 

Fabric Filter

Fabric filters are widely used for particulate control from PC boilers and are capable of over 

99 percent control efficiency. According to USEPA’s Fabric Filter Fact sheet (USEPA 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 meters (20 to 30 feet) long and 13 to 31 centimeters (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. 
10784-004-400 July, 2007 10-35

The advantages of fabric filters include: 

1. High collection efficiency for a broad range of particle sizes; 

2. Flexibility in design (various methods of cleaning methods and filter media); 

3. Wide range of volumetric capacities; 

4. Reasonable pressure drops and power requirements; and 

5. Handles a wide range of solid materials. 

Some disadvantages of fabric filters are as follows: 

1. Danger of explosion in the presence of a spark; or catastrophic bag damage due to fire; and 

2. Wet particles can agglomerate on a filter cloth if the waste gases are at a temperature close to 

their dew point. 

Summary of PC Boiler BACT for Particulate Matter

Based on numerous projects using fabric filters, Toquop Energy proposes fabric filter technology 

as BACT to limit PM and filterable PM10 emissions to 0.010 lb/MMBtu. As shown in Table 10-15, 

at this level of control the total capital cost of fabric filters was determined to be about $35,000,000 

with a total annualized cost of about $8,000,000. The total pollutant removed was calculated to be 

about 23,000 tons of filterable PM based on the assumption that the filter has a collection 

efficiency of at least 99 percent. The actual percent collection (inlet to outlet) is difficult to 

document with current testing methods, but is expected to be in the range of 99.9 percent. The 

cost effectiveness of this option is estimated to be about $400 per ton of PM removed. 

Very little data are available on condensable PM10 emissions from western coal (or any) coal-fired 

boilers, and none of the supercritical PC boilers firing sub-bituminous PRB coal listed with lower 

PM limits in the RBLC have demonstrated total PM10 levels less than 0.03 lb/MMbtu. For this 

reason, Toquop Energy proposes to limit total PM10 (including condensable PM10) emissions to no 

more than 0.03 lb/MMBtu. 

10.6.3 Auxiliary Boilers 

10.6.3.1 Identification and Ranking of PM/PM10 Control Technologies 

No add-on particulate controls have been identified that would be technically feasible or applicable 

to distillate oil-fired boilers. One boiler in the RBLC, which is owned by the Toyota Motor 

Manufacturing in Kentucky, reports the use of a fabric filter for particulate control. However, this 

unit has an emission rate of 0.1 lb/MMBtu, which would not represent BACT. We believe that the 

RBLC listing in this case is either incomplete or incorrect. All other listings in the RBLC cite the 
10784-004-400 July, 2007 10-36

Table 10-15 

Estimated Cost of Fabric Filter 

Equipment Cost Basis 

Direct Capital Costs 

PURCHASED EQUIPMENT 11,792,965 CUECost Equipment Cost Subtotal 

 (a) Basic Equipment (BE) Included 

 (b) Auxiliaries 235,859 CUECost Instrumentation and Controls 

 (c) Instrumentation and Controls 1,385,673 CUECost (Taxes + Freight) 

 (d) Tax and Freight 1,385,673 Sum of (a) through (d) 

TOTAL PURCHASED EQUIPMENT (PE) $13,414,497 

DIRECT INSTALLATION 

 (a) Foundations and Support Included 

 (b) Handling and Erection Included 

 (c) Electrical Included 

 (d) Piping Included 

 (e) Insulation for Ductwork Included 

 (f) Painting Included 

TOTAL DIRECT INSTALLATION (DI) $8,987,713 CUECost Installation 

TOTAL DIRECT COST (TDC) $22,402,210 PE + DI 

Indirect Capital Costs 

INDIRECT INSTALLATION 

 (a) Engineering and Supervision 2,240,221 CUECost Engineering Fees 

 (b) Construction and Field Expenses 2,240,221 CUECost General Facilities 

 (c) Contractor Fees 940,892 CUECost Prime Contractor’s Markup 

 (d) Contingencies 4,480,442 CUECost Total Contingency 

OTHER INDIRECT COSTS 

 (a) Startup and Performance Tests 670,543 CUECost Preproduction Costs 

 (b) Working Capital 276,900 30 Days O&M 

 (c) Allowance for Funds During Construction 1,693,607 CUECost AFDC 

TOTAL INDIRECT COST (TIC) $12,722,826 Sum of All Indirect Costs 

TOTAL CAPITAL COST $35,125,000 TDC + TIC 

Annual Direct Operating Costs 

DIRECT LABOR 102,200 2920 hours at $35/hour (Assumes 0.3 Operators per Shift) 

MAINTENANCE 1,568,155 CUECost Maintenance 

REPLACEMENT PARTS, BAGS 1,175,962 CUECost Periodic Replacement Items 

ELECTRICITY 624,491 CUECost Power Cost 

Annual Indirect Operating Costs 

OVERHEAD 233,147 44% of Operating Labor + 12% of Maintenance Labor 

PROPERTY TAX 351,300 1% of Total Capital Cost 

INSURANCE 351,300 1% of Total Capital Cost 

ADMINISTRATION 702,500 2% of Total Capital Cost 

CAPITAL RECOVERY 2,830,600 Assume 30 year life, 7% interest rate 

Total Annualized Cost $7,939,655 Sum of All Annual Costs 

TONS/YEAR CONTROLLED 22,654

COST EFFECTIVENESS ($/TON) 400

use of clean fuels. The facility will not have natural gas service. Back up units such as the 

proposed auxiliary boilers require on-site fuel storage (pipeline natural gas is an interruptible fuel 

supply); the cleanest fuel available for this service, therefore, is distillate oil (which contains 

essentially no ash). 

The use of distillate oil for the proposed backup auxiliary boilers is therefore determined to 

represent the top level of control for PM and PM10. 
10784-004-400 July, 2007 10-37

10.6.3.2 Selection of BACT for PM10 for the Proposed Auxiliary Package 

Boiler 

The top level of control for this particular source type was determined to be the use of clean fuels 

to avoid emitting particulate. The use of ultra low sulfur (0.0015 percent sulfur) distillate oil for the 

proposed auxiliary boilers is therefore determined to represent BACT for PM as well as PM10 for 

this particular emission source. 

Total annual fuel use in the boilers will be limited to 95,040 MMBtu/year, which is equivalent to an 

average of 550 hours/year per boiler at full load. Proposed BACT limits for PM and PM10 are 

based on the use of very low sulfur distillate oil, the total annual fuel limitation of 

95,040 MMBtu/year, USEPA emission factors published in AP-42, and USEPA’s RBLC (see 

Attachment 10-B), which vary from 0.001 to 0.14 lb/MMBtu. For PM, BACT for the auxiliary boilers 

is the annual fuel limitation, the use of 0.0015 weight percent sulfur distillate oil, and an emission 

limit of 0.018 lb/MMBtu based on the USEPA emission factor of 2.4 lb/1000 gal. For PM10, BACT 

includes an emission limit of 0.024 lb/MMBtu based on adding the condensable PM10 emissions of 

1.3 lb/1,000 gal based on AP-42 to the PM emission rate. 

10.6.4 Emergency Diesel Engines 

The TEP includes one 1,482 hp emergency diesel generator and one 284 hp diesel powered 

emergency firewater pump. The diesel engines will not be operated for more than 100 hours/year 

each (except in the event of emergency). The July 2006 NSPS for Stationary Compression 

Ignition Internal Combustion Engines specifies a limit of 0.20 g/kWh for PM and PM10 emissions 

for both engines greater than 1,000 kW with displacements less than 10 liters per cylinder and 

firewater pump engines. Selection of the appropriate emission limits for the emergency generator 

were based on the specifications for a 1,482 hp emergency generator manufactured by Caterpillar 

(or equivalent), which have a displacement of about 8 liters per cylinder. Toquop Energy proposes 

the USEPA Tier II emission limits as BACT along with an operational limit of 100 hours per year. 

10.6.5 Material Handling Sources 

10.6.5.1 Formation of PM/PM10 Emissions 

PM and filterable PM10 will be emitted from the coal, ash, quicklime, gypsum, and activated 

carbon handling and storage operations as either fugitive dust (i.e., outside storage) or point 

source (i.e., exhaust from enclosed conveyors or silos via bin vent filters). 

Coal will arrive in bottom dump type rail cars. The unloading facility will be able to dump coal from 

two railcars simultaneously. Hoppers and two feeder belts (2,500 tons per hour each) with 
10784-004-400 July, 2007 10-38

variable frequency drives will load to below grade coal conveyor belts taking the coal to the linear 

stack-out and reclaim equipment. The active coal pile will be a 30-day supply of coal live storage, 

which can be stacked and reclaimed without the use of mobile equipment (bulldozers). A second 

inactive storage pile will be built using both the automatic stock out system and mobile equipment. 

The inactive storage will contain a 90-day supply of coal with the ability to expand to a 180-day 

supply of coal adjacent to the active storage pile. The reclaim system will be a rail mounted 

scraper type, which will transfer coal at a rate of 2,000 tons per hour to two redundant coal reclaim 

systems, with enclosed conveyors to transfer the coal to the coal crushers. Coal will be conveyed 

from either coal crusher on one of two redundant enclosed conveyors to a transfer tower where it 

will be transferred to one of two tripper conveyors for loading into the coal silos. 

Quicklime will be transferred pneumatically from trucks or railcars to one of two enclosed storage 

silos. From the quicklime storage silos, the quicklime is fed to a slaker to make a slurry, which 

feeds the wet FGD system. 

Activated carbon will be transferred pneumatically from delivery trucks to an enclosed storage silo. 

The activated carbon will then be conveyed to the injection system via enclosed system. There is 

no exposure of the activated carbon to the atmosphere during this process. 

Fly ash will be collected from the baghouses and transferred via pneumatic system to fly ash silos. 

If the fly ash is sent to the landfill, it will be transferred pneumatically to a fully enclosed waste 

disposal area where it will be combined with excess bottom ash and gypsum, wetted to form a 

cake and transferred to trucks or railcars. Alternatively, if the fly ash is being shipped to 

purchasers, it will be loaded to trucks or railcars through a fully enclosed unloading system. 

Bottom ash will be handled through a submerged bed conveyor that conveys the bottom ash 

through a trough to a storage silo. If the bottom ash is sent to the landfill, it will be transferred 

pneumatically to a fully enclosed waste disposal area where it will be combined with excess fly 

ash and gypsum, wetted to form a cake and transferred to trucks or railcars. Alternatively, if the 

bottom ash is being shipped to purchasers, it will be loaded to trucks or railcars through a fully 

enclosed unloading system. 

Gypsum will be produced as a by-product of the facility’s wet FGD system and facility operations 

will include temporary and/or long-term on-site storage of gypsum. The gypsum will be de-watered 

to about 90 percent solids, transferred pneumatically to a silo where it will be stored until being 

loaded into trucks for transport to off-site recycling. Excess gypsum will be transferred 

pneumatically to a fully enclosed waste disposal area where it will be combined with excess fly 

ash and bottom ash, wetted to form a cake and transferred to trucks to be taken to the landfill. 
10784-004-400 July, 2007 10-39

10.6.5.2 Identification of PM/PM10 Control Technologies 

Potential PM/PM10 control technology options for the systems are: 

Coal handling

• Use of enclosed conveyors; 

• Partial enclosure with wet dust suppression for unloading coal from railcars; 

• Partial enclosures, lowering well or telescoping chute, water sprays and/or chemical dust 

suppression for unloading coal onto the coal pile; and 

• Partial enclosures for conveyors and in-line crushing operations vented to fabric filters. 

Fly ash, bottom ash, gypsum, activated carbon, and quicklime storage and handling

• Fly ash, bottom ash, gypsum, activated carbon, and quicklime storage silos with installed bin 

vent filters; 

• Partial enclosure with wet dust suppression for unloading coal from railcars; 

• Fly ash unloaded into opened trucks is thoroughly mixed with water; 

• Material unloading storage silos that also are controlled by the bin vent filters. 

Storage Piles 

• Application of surfactants, cover, wet suppression, and/or stabilizers to exposed surfaces; and 

• Minimize handling of storage pile materials. 

Material Transport

• Paved roadways; 

• Enclosed trucks; and 

• Water sprays and/or application of a dust suppression chemical. 

Attachment 10-F provides the USEPA RBLC data for PM and PM10 controls for materials handling 

and storage operations. The results are provided separately for PM and PM10; however, it is 

evident that the range of technologies cited above has been used as BACT for the various 

material handling operations. The reviewed sources particularly focus on power plants, and do not 

include other major particulate emitting sources, such as grain handling, aggregate handling, etc. 
10784-004-400 July, 2007 10-40

10.6.5.3 Discussion of PM/PM10 Control Technologies for Material Handling 

Dust Sources 

All of the above options are technically feasible and are widely utilized for PRB coal. 

Coal handling

As discussed in Appendix 3 of this application, Section 3.4, coal handling systems will be subject 

to NSPS Subpart Y. A review of the USEPA RBLC (see Attachment 10-F) gives a range of control 

efficiencies for fugitive emissions from coal handling in recent permits for coal-fired power plants. 

Western Greenbrier, Newmont Nevada Energy Investment, Bull Mountain, and Roundup Power 

determined that BACT was 0.01 gr/dscf for all material handling sources. The TEP proposes to 

specify a filterable PM/PM10 emission limit of 0.005 gr/dscf for coal handling operations. Other 

comparable sources, such as Mid-American Power and Desert Rock have proposed baghouse 

control effectiveness of 0.005 gr/dscf for coal handling operations. The Richardton, North Dakota, 

baghouse emission rate is 0.004 gr/dscf, however, which is only slightly lower than the proposed 

level, and is on a much smaller unit. 

Silos

As discussed in Appendix 3 of this application, Section 3.4, quicklime handling systems will be 

subject to NSPS Subpart OOO. The review of the USEPA RBLC (see Attachment 10-F) gives a 

range of control efficiencies from silos and bin vents for quicklime storage. CLM Superior and the 

Gascoyne Generating Station have limits of 0.005 gr/dscf. Other recent permits for coal fired 

power plants, including Western Greenbrier, Newmont Nevada Energy Investment, Bull Mountain, 

and Roundup Power Projects, determined that BACT was 0.01 gr/dscf for all material handling 

sources. Desert Rock has proposed a control effectiveness of 0.01 gr/dscf for non-coal material 

handling operations. 

Exposed Materials

In a coal-fired power plant, there are numerous locations where materials are exposed to the 

atmosphere as part of the handling and transport processes. Exposed handling and storage areas 

include the coal unloading, coal pile storage, ash unloading, and roadway emissions from traffic. 

These are areas where an enclosure is not practical, and water sprays and/or chemical dust 

suppression is the most effective means to control emissions. 
10784-004-400 July, 2007 10-41

10.6.5.4 Selection of BACT for Material Handling Sources 

Coal conveyors will be fully enclosed. The associated unloading, reclaiming, crushing, and 

transfer points will be either located below grade inside full enclosures for dustless transfer, or will 

be exhausted through bin vent filters. The entire coal handling system will be equipped with an 

automatic wash-down system to remove coal dust from all surfaces within the handling areas. 

Bin vent filters are being proposed for the coal, gypsum, fly ash, bottom ash, activated carbon, 

and quicklime silos and transfer towers. Toquop Energy proposes an outlet grain loading of 

0.005 gr/dscf for coal handling and 0.01 gr/dscf for other materials. 

Fugitive PM/PM10 emissions will be controlled by a variety of operations. Toquop Energy proposes 

to use dry fogging in an enclosed three-sided building at the rail car coal unloading point, which is 

expected to have a control efficiency of 85 percent. The active coal pile will be treated with water 

sprays, and the inactive pile will be both wetted and compacted, to reduce fugitive emissions. 

Control efficiencies of 75 and 85 percent are expected for the active and inactive piles, 

respectively. A surfactant may be applied at the head end of the unload/stack-out conveyor to 

reduce emissions at the lowering well stack-out as needed. 

All haul roads will be paved to control fugitive dust. Silt loading will be limited to low levels via 

periodic washing of the roadways with a water truck. 

A summary of material handling PM/PM10 sources and the various proposed control strategies is 

provided in Table 10-16. 

Coal preparation operations are subject to the Standards of 40 CFR 60 Subpart Y, which limit 

opacity to 20 percent (6-minute average). For purposes of consistency in monitoring approach 

and recordkeeping requirements, the facility proposes that compliance with BACT for sources 

other than the fabric filters and bin vent filters be determined based on the same 20 percent 

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 and will 

streamline monitoring, recordkeeping, and reporting for all of the bulk materials handling 

operations associated with the TEP. 
10784-004-400 July, 2007 10-42

Table 10-16 

Description of Material Handling System 

Fugitive Dust Source Material Throughput Control Method 

Control 

Efficiency 

Coal Handling 

Coal Transfer Building Coal 530,000 dscfh Baghouse 0.005 gr/dscf 

Coal Crusher Building Coal 530,000 dscfh Baghouse 0.005 gr/dscf 

Coal Transfer House/Tripper Deck Coal 700,000 dscfh Baghouse 0.005 gr/dscf 

Rail Car Unloading Coal 5000 TPH Fogging Water Sprays 85% 

Active Coal Pile Coal 21.52 aces exposed Wet Suppression 75% 

Inactive Coal Pile Coal 9.34 acres exposed Wet Suppression and 

Compaction 

87.5% 

Coal Pile Bulldozing Coal 12 hr / day Wet Suppression 75% 

Coal Yard Conveyer Coal 5000 TPH Wet Suppression 75% 

Gull Wing Stacker/Telescoping Chute to Coal Pile Coal 5000 TPH Wet Suppression 75% 

Ash Handling 

Silo Vent Filter Bottom Ash 210,000 dscfh Baghouse 0.01 gr/dscf 

Silo Vent Filter Discharge Bottom Ash 210,000 dscfh Baghouse 0.01 gr/dscf 

Silo Filter Vent Flyash 210,000 dscfh Baghouse 0.01 gr/dscf 

Silo Vent Filter Discharge Flyash 210,000 dscfh Baghouse 0.01 gr/dscf 

Gypsum Handling 

Silo Filter Vent Gypsum 210,000 dscfh Baghouse 0.01 gr/dscf 

Silo Vent Filter Discharge Gypsum 210,000 dscfh Baghouse 0.01 gr/dscf 

Quicklime Handling 

Silo Vent Quicklime 240,000 dscfh Baghouse 0.01 gr/dscf 

Quicklime Silo Quicklime 240,000 dscfh Baghouse 0.01 gr/dscf 

Other Sources 

Activated Carbon Silo Activated Carbon 240,000 dscfh Baghouse 0.01 gr/dscf 

CCP Bulldozing at Landfill CCP 12 hr / day Wet Suppression 75% 

CCP Truck Unloading CCP 44 TPH Wet Suppression 75% 

Active CCP Pile CCP 21 aces exposed Wet Suppression 75% 

Paved Road Emissions Silt 126 VMT/day Water 75% 

10.7 BACT for Sulfuric Acid Mist 

10.7.1 Formation 

H2SO4 is formed in coal fired boilers due to oxidation of SO2 to SO3, and subsequent reaction with 

water vapor to form H2SO4. The formation of H2SO4 is therefore highly dependent on coal sulfur 

content and the presence of oxidizing catalysts. H2SO4 may be emitted from coal-fired boilers 

since wet FGD systems are expected to capture in the range of only 30 to 50 percent of 

condensed H2SO4 aerosols. 

10.7.2 PC-fired Boilers 

The use of the lowest sulfur available coal (PRB) and “low oxidation” SCR catalysts will minimize 

formation of H2SO4 proportionately to SO2. The Thoroughbred Project in Kentucky also agreed to 

install a wet electrostatic precipitator (WESP) downstream of a wet scrubber, primarily for 

additional control of high levels of uncontrolled H2SO4. This project exhibits high uncontrolled 
10784-004-400 July, 2007 10-43

H2SO4 emission levels because it will utilize a relatively high sulfur eastern coal. The proposed 

TEP, by comparison, will have uncontrolled H2SO4 levels that are only a fraction of 

Thoroughbred’s levels. 

Toquop Energy recognizes, however, that H2SO4 is a precursor to the formation of regional haze 

and also has included active control of H2SO4 in the design of the TEP. Dry sorbent injection has 

been proposed upstream of the fabric filter to selectively scrub H2SO4 before it ever enters the wet 

scrubber. The application of this technology will result in emission levels lower than those 

permitted for Thoroughbred (with an add-on WESP), and represents BACT at a H2SO4 emission 

rate of 0.005 lb/MMBtu. One recently permitted PC facility listed in the USEPA RBLC, the Santee 

Cooper Cross Generating Station in South Carolina (02/05/2004), is listed with an H2SO4 limit of 

0.0014 lb/MMBtu on a 365-day average with higher sulfur bituminous coal and without dry sorbent 

injection. This facility has yet to operate or be tested, and hence this H2SO4 limit is not considered 

demonstrated in practice. The Nevada Division of Environmental Protection has defined BACT for 

this project as 0.005 lb/MMBtu. 

10.7.3 Auxiliary Boilers and Diesel Generators 

No control alternatives beside the use of very low sulfur fuels have been identified for industrial 

boilers or emergency diesel generators. BACT for H2SO4 for the proposed auxiliary boilers is 

therefore the use of ultra low sulfur (0.0015 percent sulfur) distillate oil. The facility proposes a limit 

of 0.0004 lb/MMBtu for the auxiliary boilers with an operational equivalent to about 550 hours per 

year at full load. 

No limits are described in the 2006 NSPS for Stationary Compression Ignition Internal 

Combustion Engines. BACT for H2SO4 for the proposed auxiliary boilers and emergency diesel 

engines is the use of ultra low sulfur (0.0015 percent sulfur) distillate oil. 

10.8 BACT for Hydrogen Fluoride 

Emissions of HF are generated in fossil fuel-fired sources from the oxidation of fluorine present in 

the fuel. For the PC boilers, the same dry sorbent injection acid gas pre-control technology 

designed to scrub H2SO4 also will control HF emissions through injection of hydrated lime before 

the fabric filter, with additional removal expected from the wet quicklime scrubbing. The TEP is 

proposing a HF emission rate of 0.00024 lb/MMBtu based on an assumed concentration of 

fluorine in the coal of 100 ppm (estimated 98 percent control) as BACT. These emission rates are 

consistent with, or lower than, all but one recent BACT decision. The Maidsville Plant in West 

Virginia has an HF limit of 0.0001 lb/MMBtu using dry sorbent injection with a baghouse as HF 

control. This unit does not burn PRB coal and its emission level of HF is not comparable to the 

proposed TEP. 
10784-004-400 July, 2007 10-44

No appreciable HF is emitted from distillate oil-fired industrial auxiliary boilers or emergency diesel 

engines, and no limits are described in the 2006 NSPS for Stationary Compression Ignition 

Internal Combustion Engines. The use of low fluorine bearing fuel (very low sulfur distillate oil) 

represents BACT for HF for these emission sources. 

10.9 BACT for Lead 

Emissions of Pb are generated in fossil fuel-fired sources from trace amounts of Pb present in the 

fuel ash. Since Pb is emitted as solid particulate from coal-fired boilers, it is already included in the 

PM and PM10 emission selected as BACT. BACT for Pb emissions from the proposed PC boilers 

is the control of PM emissions using fabric filtration (baghouse), and the emission limits 

determined to represent BACT for PM10. 

For distillate oil-fired industrial auxiliary boilers and emergency diesel engines, the use of low ash 

fuel such as distillate oil represents BACT. No limits are described in the 2006 NSPS for 

Stationary Compression Ignition Internal Combustion Engines. 

10.10 Summary of BACT Emission Levels 

The BACT levels determined through this evaluation for the TEP are summarized in Tables 10-17

and 10-18. 

Table 10-17 

Summary of Proposed BACT Emission Limits for the PC Boilers 

Pollutant Emissions Limit (lb/MMBtu) Control Technology 

PC-Fired Boilers 

NOX 0.06, 24-hour average, based on continuous emission 

monitoring 

Low-NOX burners and SCR 

SO2 483.8 lb/hr and 1351 tpy, based on continuous 

emission monitoring 

Low sulfur western coal, hydrated lime injection before 

the fabric filter, and wet quicklime desulfurization 

CO 0.10, 24-hour average, based on continuous emission 

monitoring 

Good combustion practices 

VOC 0.003, based on EPA Methods 25A and 19 Good combustion practices 

PM 0.01, based on EPA Method 51 Baghouse 

PM10 0.03 (total)2, based on USEPA Methods 201 or 201A 

and 2023

Baghouse 

Pb No limit Baghouse 

H2SO4 0.005, 3 hour average, based on USEPA Method 8 Low sulfur western coal, hydrated lime injection before 

the fabric filter, and wet quicklime desulfurization 

HF 0.00024, 3 hour average, based on USEPA Method 

13B 

Hydrated lime injection before the fabric filter, and wet 

quicklime desulfurization 
10784-004-400 July, 2007 10-45

Table 10-18 

Summary of Proposed BACT Emission Limits for Other Sources 

Pollutant Emissions Limit Control Technology 

Auxiliary Boilers 

NOX 0.10 lb/MMBtu Low-NOX burners 

SO2 0.002 lb/MMBtu Ultra low sulfur distillate oil (0.0015% S) 

H2SO4 0.0004 lb/MMBtu Ultra low sulfur distillate oil (0.0015% S) 

CO 0.036 lb/MMBtu Good combustion 

VOC 0.003 lb/MMBtu Good combustion 

PM 0.0181 lb/MMBtu Ultra low sulfur distillate oil and good combustion 

PM10 0.0242 lb/MMBtu Ultra low sulfur distillate oil and good combustion 

Emergency Generator 

NOX/VOC 6.4 g/kWh July 2006 NSPS for NOX and NMHC emissions 

SO2 0.15 g/kWh Ultra low sulfur distillate oil (0.0015% S) 

H2SO4 Ultra low sulfur oil Ultra low sulfur distillate oil (0.0015% S) 

CO 3.5 g/kWh July 2006 NSPS 

PM/PM10 0.2 g/kWh July 2006 NSPS 

Emergency Firewater Pump 

NOX/VOC 4.0 g/kWh July 2006 NSPS for NOX and NMHC emissions 

SO2 0.01 g/kWh Ultra low sulfur distillate oil (0.0015% S) 

H2SO4 Ultra low sulfur oil Ultra low sulfur distillate oil (0.0015% S) 

CO 3.5 g/kWh July 2006 NSPS 

PM/PM10 0.2 g/kWh July 2006 NSPS 

Materials handling systems 

PM/PM10 0.005 gr/dscf (filterable) for coal handling baghouses and 

0.01 gr/dscf (filterable) for other materials 

Enclosures, dust suppression, and fabric filters 

1

 PM is defined as filterable particulate matter as measured by USEPA Method 5 or 17. 2

 PM10 is defined as solid particulate matter smaller than 10 micrometers diameter as measured by USEPA Method 201 or 201A plus condensable 

particulate matter as measured by USEPA Method 202. Because PM10 includes condensable particulate matter and PM does not include condensable 

particulate matter, PM10 emissions are higher than PM emissions. 

10.11 Mercury Control 

The TEP will be subject to the new boiler NSPS requirement for Hg under the CAMR as well as 

the requirement to offset all emissions of Hg produced with mercury allowances. This analysis 

addresses: 1) non-mercury metallic hazardous air pollutant (HAP) emissions; and 2) Hg 

emissions, acid gases (hydrogen chloride and HF), and organic HAPs. 

The proposed emission control train has been designed specifically to control Hg and other HAPs 

to extremely low levels, particularly for a facility designed to burn Western coal. 

Non-mercury metallic HAPs are emitted as part of the particulate emissions from coal combustion. 

The proposed TEP will use fabric filter technology to limit PM emissions to 0.01 lb/MMBtu 

(front-half), which is the lowest permitted emission rate for a coal-fired boiler and is, therefore, 

equivalent to LAER. USEPA has used PM emission limits as surrogates for control of HAP metal 

emissions since a strong correlation exists between metallic HAP emissions and PM emissions. 
10784-004-400 July, 2007 10-46

Therefore, the proposed fabric filter and PM emission rate represent a case-by-case Maximum 

Achievable Control Technology (or equivalent standard) for non-mercury metallic HAPs. 

The TEP is being designed to meet the 66.0x10-6 lb/MWh emission rate in the new NSPS for 

mercury for wet scrubbers burning subbituminous coal based on the Hg and chlorine 

characteristics of the PRB coal. Contributing Hg reductions will be achieved in the SCR, through 

injection of adsorbent(s) upstream of the fabric filter, in the filter cake of the fabric filter itself, and 

finally through humidification, cooling, and impingement in the wet FGD system. Toquop Energy is 

proposing state-of-the-art Hg control, which represents state-of-the-art control of Hg from burning 

Western coal. Based on an average expected Hg content of 0.08 ppm, it is expected that Hg 

emissions will be below the NSPS standard of 66x10-6 lb/MWh as an annual average. 

10.12 References 

Cho, S. M. 1994. Property Apply Selective Catalytic Reduction for NOX Removal. Chemical 

Engineering Progress. Page 39. 

U.S. Environmental Protection Agency (USEPA). 2000. Controlling SO2 Emissions: A Review of 

Technologies, EPA/600/R-00/093. USEPA, National Risk Management Research 

Laboratory, Research Triangle Park, North Carolina, 27711. November 2000. 

. 1996. OAQPS Control Cost Manual. 5th Edition, 6th Edition. USEPA document 453/B-96-

001, EPA/452/B-02-001. February 1996, revised January 2002. 

. 1994. Alternative Control Techniques Document – NOX Emissions From 

Industrial/Commercial/Institutional (ICI) Boilers. Office of Air Quality Planning and 

Standards. 

. 1990. DRAFT, “New Source Review Workshop Manual”, Office of Air Quality Planning 

and Standards. October 1990. 
ATTACHMENT 10-A 

CUECOST INPUT DATA AND RESULTS 
10A-1 

Inputs to CUECost Worksheet 

 

APC Technology Choices 

 

Description Units Input 1 

 

FGD Process Integer 1 

 (1 = LSFO, 2 = LSD) 

Particulate Control Integer 1 

 (1 = Fabric Filter, 2 = ESP) 

NOx Control Integer 1 

 (1 = SCR, 2 = SNCR, 3 = LNBs, 4 = NGR) 

 

 

INPUTS 

 

Description Units Input 1 

 

General Plant Technical Inputs 

 

Location - State Abbrev. NV 

MW Equivalent of Flue Gas to Control System MW 683 

Net Plant Heat Rate Btu/kWhr 8,557 

Plant Capacity Factor % 89% 

Total Air Downstream of Economizer % 120% 

Air Heater Leakage % 12% 

Air Heater Outlet Gas Temperature °F 300 

Inlet Air Temperature °F 80 

Ambient Absolute Pressure In. of Hg 29.4 

Pressure After Air Heater In. of H2O -12 

Moisture in Air lb/lb dry air 0.013 

Ash Split: 

 Fly Ash % 80% 

 Bottom Ash % 20% 

Seismic Zone Integer 1 

Retrofit Factor Integer 1 

 (1.0 = new, 1.3 = medium, 1.6 = difficult) 

Select Coal Integer 1 

Is Selected Coal a Powder River Basin Coal? Yes / No Yes 

 
10A-2 

Economic Inputs 

 

Cost Basis -Year Dollars Year 2010 

Sevice Life (levelization period) Years 30 

Inflation Rate % 3% 

After Tax Discount Rate (current $'s) % 9% 

AFDC Rate (current $'s) % 11% 

First-year Carrying Charge (current $'s) % 22% 

Levelized Carrying Charge (current $'s) % 17% 

First-year Carrying Charge (constant $'s) % 16% 

Levelized Carrying Charge (constant $'s) % 12% 

Sales Tax % 7% 

Escalation Rates: 

 Consumables (O&M) % 3% 

 Capital Costs: 

 Is Chem. Eng. Cost Index available? Yes / No Yes 

 If "Yes" input cost basis CE Plant Index. Integer 388 

 If "No" input escalation rate. % 3% 

Construction Labor Rate $/hr $45 

Prime Contractor's Markup % 3% 

Operating Labor Rate $/hr $40 

Power Cost Mills/kWh 25 

Steam Cost $/1000 lbs 3.5 

 

Limestone Forced Oxidation (LSFO) Inputs

 

SO2 Removal Required % 77%

L/G Ratio gal / 1000 acf 125

Design Scrubber with Dibasic Acid Addition? Integer 2

 (1 = yes, 2 = no) 

Adiabatic Saturation Temperature °F 127

Reagent Feed Ratio Factor 1.05

 (Mole CaCO3 / Mole SO2 removed) 

Scrubber Slurry Solids Concentration Wt. % 15%

Stacking, Landfill, Wallboard Integer 1

 (1 = stacking, 2 = lanfill, 3 = wallboard) 

Number of Absorbers Integer 1

 (Max. Capacity = 700 MW per absorber) 

Absorber Material Integer 1

 (1 = alloy, 2 = RLCS) 

Absorber Pressure Drop in. H2O 6

Reheat Required ? Integer 1

 (1 = yes, 2 = no) 

Amount of Reheat °F 25

Reagent Bulk Storage Days 60

Reagent Cost (delivered) $/ton $15 

Landfill Disposal Cost $/ton $30 

Stacking Disposal Cost $/ton $6 
10A-3 

Credit for Gypsum Byproduct $/ton $2 

Maintenance Factors by Area (% of Installed Cost) 

 Reagent Feed % 5%

 SO2 Removal % 5%

 Flue Gas Handling % 5%

 Waste / Byproduct % 5%

 Support Equipment % 5%

Contingency by Area (% of Installed Cost) 

 Reagent Feed % 20%

 SO2 Removal % 20%

 Flue Gas Handling % 20%

 Waste / Byproduct % 20%

 Support Equipment % 20%

General Facilities by Area (% of Installed Cost) 

 Reagent Feed % 10%

 SO2 Removal % 10%

 Flue Gas Handling % 10%

 Waste / Byproduct % 10%

 Support Equipment % 10%

Engineering Fees by Area (% of Installed Cost) 

 Reagent Feed % 10%

 SO2 Removal % 10%

 Flue Gas Handling % 10%

 Waste / Byproduct % 10%

 Support Equipment % 10%

 

Lime Spray Dryer (LSD) Inputs 

 

SO2 Removal Required % 30% 

Adiabatic Saturation Temperature °F 127 

Flue Gas Approach to Saturation °F 20 

Spray Dryer Outlet Temperature °F 147 

Reagent Feed Ratio Factor 0.31 

 (Mole CaO / Mole Inlet SO2) 

Recycle Rate Factor 30 

 (lb recycle / lb lime feed) 

Recycle Slurry Solids Concentration Wt. % 35% 

Number of Absorbers Integer 2 

 (Max. Capacity = 300 MW per spray dryer) 

Absorber Material Integer 1 

 (1 = alloy, 2 = RLCS) 

Spray Dryer Pressure Drop in. H2O 5 

Reagent Bulk Storage Days 60 

Reagent Cost (delivered) $/ton $65 

Dry Waste Disposal Cost $/ton $30 

Maintenance Factors by Area (% of Installed Cost) 

 Reagent Feed % 5% 

 SO2 Removal % 5% 

 Flue Gas Handling % 5% 

 Waste / Byproduct % 5% 
10A-4 

 Support Equipment % 5% 

Contingency by Area (% of Installed Cost) 

 Reagent Feed % 20% 

 SO2 Removal % 20% 

 Flue Gas Handling % 20% 

 Waste / Byproduct % 20% 

 Support Equipment % 20% 

General Facilities by Area (% of Installed Cost) 

 Reagent Feed % 10% 

 SO2 Removal % 10% 

 Flue Gas Handling % 10% 

 Waste / Byproduct % 10% 

 Support Equipment % 10% 

Engineering Fees by Area (% of Installed Cost) 

 Reagent Feed % 10% 

 SO2 Removal % 10% 

 Flue Gas Handling % 10% 

 Waste / Byproduct % 10% 

 Support Equipment % 10% 

 

Particulate Control Inputs 

 

Outlet Particulate Emission Limit lbs/MMBtu 0.01 

Fabric Filter: 

 Pressure Drop in. H2O 6 

 Type (1 = Reverse Gas, 2 = Pulse Jet) Integer 2 

 Gas-to-Cloth Ratio ACFM/ft2

 3.5 

 Bag Material (RGFF fiberglass only) Integer 2 

 (1 = Fiberglass, 2 = Nomex, 3 = Ryton) 

 Bag Diameter inches 6 

 Bag Length feet 20 

 Bag Reach 3 

 Compartments out of Service % 10% 

 Bag Life Years 5 

 Maintenance (% of installed cost) % 5% 

 Contingency (% of installed cost) % 20% 

 General Facilities (% of installed cost) % 10% 

 Engineering Fees (% of installed cost) % 10% 

ESP: 

 Strength of the electric field in the ESP = E kV/cm 10.0 

 Plate Spacing in. 12 

 Plate Height ft. 36 

 Pressure Drop in. H2O 3 

 Maintenance (% of installed cost) % 5% 

 Contingency (% of installed cost) % 20% 

 General Facilities (% of installed cost) % 10% 

 Engineering Fees (% of installed cost) % 10% 

 
10A-5 

NOX Control Inputs 

 

Selective Catalytic Reduction (SCR) Inputs 

 

NH3/NOx Stoichiometric Ratio NH3/NOx 0.9 

NOX Reduction Efficiency Fraction 0.60 

Inlet NOx lbs/MMBtu 0.15 

Space Velocity (Calculated if zero) 1/hr 0 

Overall Catalyst Life years 3 

Ammonia Cost $/ton 350 

Catalyst Cost $/ft3 356.34 

Solid Waste Disposal Cost $/ton 11.48 

Maintenance (% of installed cost) % 1.5% 

Contingency (% of installed cost) % 20% 

General Facilities (% of installed cost) % 5% 

Engineering Fees (% of installed cost) % 10% 

Number of Reactors integer 2 

Number of Air Preheaters integer 1 

 

Selective NonCatalytic Reduction (SNCR) Inputs

 

Reagent 1:Urea 2:Ammonia 1 

Number of Injector Levels integer 3 

Number of Injectors integer 18 

Number of Lance Levels integer 0 

Number of Lances integer 0 

Steam or Air Injection for Ammonia integer 1 

NOX Reduction Efficiency Fraction 0.60 

Inlet NOx lbs/MMBtu 0.15 

NH3/NOx Stoichiometric Ratio NH3/NOx 1.2 

Urea/NOx Stoichiometric Ratio Urea/NOx 1.2 

Urea Cost $/ton 225 

Ammonia Cost $/ton 205.66 

Water Cost $/1,000 gal 0.407 

Maintenance (% of installed cost) % 1.5% 

Contingency (% of installed cost) % 20% 

General Facilities (% of installed cost) % 5% 

Engineering Fees (% of installed cost) % 10% 

 

Low NOx Burner Technology Inputs 

 

NOx Reduction Efficiency fraction 0.98 

Boiler Type T:T-fired, W:Wall T 

Retrofit Difficulty L:Low, A:Average, H:High L 

Maintenance Labor (% of installed cost) % 0.8% 

Maintenance Materials (% of installed cost) % 1.2% 

 
10A-6 

Natural Gas Reburning Inputs 

 

NOx Reduction Efficiency fraction 0.61 

Gas Reburn Fraction fraction 0.15 

Waste Disposal Cost $/ton 11.48 

Natural Gas Cost $/MMBtu 2.31 

Maintenance (% of installed cost) % 1.5% 

Contingency (% of installed cost) % 20% 

General Facilities (% of installed cost) % 2% 

Engineering Fees (% of installed cost) % 10% 

 

SUMMARY OF COSTS 

 

Description Units Input 1 

 

APC Technologies 

NOx Control SCR 

Particulate Control PJFF 

SO2 Control LSFO 

 

NOx Control Costs SCR 

Total Capital Requirement (TCR) $ $31,165,225 

$/kW $45.6 

First Year Costs 

 Fixed O&M $ $486,263 

$/kW-Yr 0.71 

Mills/kWH 0.09 

$/ton NOx removed $130 

 Variable O&M $ $4,016,739 

$/kW-Yr 5.88 

Mills/kWH 0.75 

$/ton NOx removed $1,077 

 Fixed Charges $ $6,949,845 

$/kW-Yr 10.18 

Mills/kWH 1.30 

$/ton NOx removed $1,864 

 TOTAL $ $11,452,847 

$/kW-Yr 16.77 

Mills/kWH 2.14 

$/ton NOx removed $3,072 
10A-7 

Levelized Current Dollars 

 Fixed O&M $/kW-Yr 0.97 

Mills/kWH 0.12 

$/ton NOx removed $177 

 Variable O&M $/kW-Yr 8.00 

Mills/kWH 1.02 

$/ton NOx removed $1,466 

 Fixed Charges $/kW-Yr 7.71 

Mills/kWH 0.98 

$/ton NOx removed $1,413 

 TOTAL $/kW-Yr 16.68 

Mills/kWH 2.13 

$/ton NOx removed $3,056 

Levelized Constant Dollars 

 Fixed O&M $/kW-Yr 0.71 

Mills/kWH 0.09 

$/ton NOx removed $130 

 Variable O&M $/kW-Yr 5.88 

Mills/kWH 0.75 

$/ton NOx removed $1,077 

 Fixed Charges $/kW-Yr 5.34 

Mills/kWH 0.97 

$/ton NOx removed $1,389 

 TOTAL $/kW-Yr 11.93 

Mills/kWH 1.81 

$/ton NOx removed $2,597 

 

Particulate Control Costs PJFF 

Total Capital Requirement (TCR) $ $34,197,691 

$/kW $50 

First Year Costs 

 Fixed O&M $ $1,568,155 

$/kW-Yr 2.30 

Mills/kWH 0.29 

$/ton PM removed $12.7 

 Variable O&M $ $1,800,454 

$/kW-Yr 2.64 

Mills/kWH 0.34 

$/ton PM removed $14.6 

 Fixed Charges $ $7,626,085 

$/kW-Yr 11.17 

Mills/kWH 1.43 

$/ton PM removed $61.7 

 TOTAL $ $10,994,694 

$/kW-Yr 16.10 

Mills/kWH 2.06 

$/ton PM removed $89.0 
10A-8 

Levelized Current Dollars 

 Fixed O&M $/kW-Yr 3.12 

Mills/kWH 0.40 

$/ton PM removed $17.3 

 Variable O&M $/kW-Yr 3.59 

Mills/kWH 0.46 

$/ton PM removed $19.8 

 Fixed Charges $/kW-Yr 8.46 

Mills/kWH 1.08 

$/ton PM removed $46.8 

 TOTAL $/kW-Yr 15.17 

Mills/kWH 1.94 

$/ton PM removed $83.9 

Levelized Constant Dollars 

 Fixed O&M $/kW-Yr 2.30 

Mills/kWH 0.29 

$/ton PM removed $12.7 

 Variable O&M $/kW-Yr 2.64 

Mills/kWH 0.34 

$/ton PM removed $14.6 

 Fixed Charges $/kW-Yr 5.86 

Mills/kWH 1.06 

$/ton PM removed $46.0 

 TOTAL $/kW-Yr 10.79 

Mills/kWH 1.69 

$/ton PM removed $73.3 

 

SO2 Control Costs LSFO 

Total Capital Requirement (TCR) $ $77,519,298 

$/kW $113 

First Year Costs 

 Fixed O&M $ $7,641,525 

$/kW-Yr 11.19

Mills/kWH 1.43

$/ton SO2 removed $482.6 

 Variable O&M $ $5,108,268 

$/kW-Yr 7.48

Mills/kWH 0.96

$/ton SO2 removed $322.6 

 Fixed Charges $ $17,286,804 

$/kW-Yr 25.31

Mills/kWH 3.23

$/ton SO2 removed $1,091.7 

 TOTAL $ $30,036,596 

$/kW-Yr 43.98

Mills/kWH 5.62

$/ton SO2 removed $1,897 
10A-9 

Levelized Current Dollars 

 Fixed O&M $/kW-Yr 15.23

Mills/kWH 1.94

$/ton SO2 removed $656.7 

 Variable O&M $/kW-Yr 10.18

Mills/kWH 1.30

$/ton SO2 removed $439.0 

 Fixed Charges $/kW-Yr 19.18

Mills/kWH 2.45

$/ton SO2 removed $827.4 

 TOTAL $/kW-Yr 44.58

Mills/kWH 5.69

$/ton SO2 removed $1,923.1 

Levelized Constant Dollars 

 Fixed O&M $/kW-Yr 11.19

Mills/kWH 1.43

$/ton SO2 removed $482.6 

 Variable O&M $/kW-Yr 7.48

Mills/kWH 0.96

$/ton SO2 removed $322.6 

 Fixed Charges $/kW-Yr 13.28

Mills/kWH 2.41

$/ton SO2 removed $813.6 

 TOTAL $/kW-Yr 31.95

Mills/kWH 4.79

 $/ton SO2 removed $1,618.8 
10A-10 

CUECost Results 

Wet Scrubber 

LSFO Material Balance - Preliminary Case1 

Flue Gas, Downstream of ID Fans 

 Temperature °F 295

 Pressure in. H2O 10

 Flow Rate SCFM 1,455,241

 Flow Rate ACFM 2,097,860

 CO2 lb/hr 1,247,836

 N2 lb/hr 4,546,491

 SO2 lb/hr 5,252

 O2 lb/hr 365,006

 HCl lb/hr 73

 Other Gases lb/hr 1,587

 H2O lb/hr 501,931

 Fly Ash lb/hr 58

 Total (gas only) lb/hr 6,668,175

 

Flue Gas, to Absorber 

 Temperature °F 295

 Pressure in. H2O 10

 Flow Rate SCFM 1,455,241

 Flow Rate ACFM 2,097,860

 CO2 lb/hr 1,247,836

 N2 lb/hr 4,546,491

 SO2 lb/hr 5,252

 O2 lb/hr 365,006

 HCl lb/hr 73

 Other Gases lb/hr 1,587

 H2O lb/hr 501,931

 Fly Ash lb/hr 58

 Total (gas only) lb/hr 6,668,175

 

Flue Gas, from Absorbers (total) 

 Temperature °F 127

 Pressure in. H2O 4

 Flow Rate SCFM 1,488,937

 Flow Rate ACFM 1,693,584

 CO2 lb/hr 1,250,658

 N2 lb/hr 4,559,886

 SO2 lb/hr 1,208

 O2 lb/hr 368,035

 HCl lb/hr 0

 Other Gases lb/hr 1,587

 H2O lb/hr 587,241

 Fly Ash lb/hr 58

 Total (gas only) lb/hr 6,768,615
10A-11 

 Heat Capacities 

 O2 Btu/lbmol°F 7.213 

 CO2 Btu/lbmol°F 9.354 

 N2 Btu/lbmol°F 6.999 

 H2O Btu/lbmol°F 8.069 

 NO Btu/lbmol°F 7.164 

 SO2 Btu/lbmol°F 9.830 

 HCl Btu/lbmol°F 6.951 

 O2 Btu/lb°F 0.225

 CO2 Btu/lb°F 0.213

 N2 Btu/lb°F 0.250

 H2O Btu/lb°F 0.448

 NO Btu/lb°F 0.239

 SO2 Btu/lb°F 0.153

 HCl Btu/lb°F 0.191

 Reheated Gas Temperature: °C 66.7

 K 339.7

 FGD Outlet Temperature: °C 52.8

 K 325.8

 Total Btu/hr Btu/hr 43,784,294

 

Hot Reheat Air 

 Temperature °F 440

 Pressure in. H2O 1

 Flow Rate SCFM 134,425

 Flow Rate ACFM 236,183

 N2 lb/hr 461,211

 O2 lb/hr 139,090

 H2O lb/hr 7,907

 Total lb/hr 608,207

 Heat Capacities of Hot Reheat Air 

 O2 Btu/lbmol°F 7.332 

 N2 Btu/lbmol°F 7.113 

 H2O Btu/lbmol°F 8.338 

 O2 Btu/lb°F 0.229

 N2 Btu/lb°F 0.254

 H2O Btu/lb°F 0.463

 Heated Temperature: °C 226.7

 K 499.7

 FGD Outlet Temperature: °C 66.7

 K 339.7
10A-12 

 Heat Capacities of Inlet Reheat Air 

 O2 Btu/lbmol°F 7.304 

 N2 Btu/lbmol°F 7.087 

 H2O Btu/lbmol°F 8.276 

 O2 Btu/lb°F 0.228

 N2 Btu/lb°F 0.253

 H2O Btu/lb°F 0.459

 Heated Temperature: °C 226.7

 K 499.7

 Inlet Air Temperature: °C 26.7

 K 299.7

 Required Heat Btu/hr 54,730,368

 

Oxidation Air (total) 

 Temperature °F 60

 Pressure in. H2O 0

 Flow Rate SCFM 3,903

 Flow Rate ACFM 3,972

 N2 lb/hr 13,395

 O2 lb/hr 4,040

 H2O lb/hr 227

 Total (gas only) lb/hr 17,661

 

Quicklime to Ball Mill 

 Temperature °F 80

 Wt.% Solids wt. % 100%

 Inerts lb/hr 327

 CaCO3 lb/hr 6,634

 Total lb/hr 6,961

 

Quicklime Slurry to Quicklime Slurry Tank 

 Temperature °F 90

 Flow Rate GPM 24.8

 Wt.% Solids wt. % 40%

 Inerts lb/hr 327

 CaCO3 lb/hr 6,634

 H2O lb/hr 10,441

 Total lb/hr 17,402

 

Quicklime Slurry to Reaction Mix Tank (total) 

 Temperature °F 68

 Flow Rate GPM 58.0

 Wt.% Solids wt. % 20%

 Inerts lb/hr 327

 CaCO3 lb/hr 6,634

 H2O lb/hr 27,843

 Total lb/hr 34,804
10A-13 

Slurry to Absorber 

 Temperature °F 126

 Flow Rate GPM 209,112

 Wt.% Solids wt. % 15%

 CaSO3* 1⁄2 H2O lb/hr 0

 CaSO4*2H2O lb/hr 17,025,795

 Inerts lb/hr 512,538

 CaCl2 lb/hr 174,209

 CaCO3 lb/hr 337,783

 H2O lb/hr 102,285,176

 Total lb/hr 120,335,501

 

Slurry from Rxn Tank to Thickener 

 Temperature °F 126

 Flow Rate GPM 133.5

 Wt.% Solids wt. % 15%

 CaSO3* 1⁄2 H2O lb/hr 0

 CaSO4*2H2O lb/hr 10,868

 Inerts lb/hr 327

 CaCl2 lb/hr 111

 CaCO3 lb/hr 216

 H2O lb/hr 65,290

 Total lb/hr 76,811
10A-14 

LSFO Equipment Capital Costs Case1 

Cost Basis (Year) 2010

 Sizing Criteria

Reagent Feed System $ kpph Reag. $7,569,694 

 Ball Mill & Hydroclone System $ TPH Reag. $1,933,303 

 DBA Acid Tank (pump, heater, agitator) $ gpm DBA $0 

SO2 Removal System $ kpph SO2 $2,083,040 

 Absorber Tower $ kACFM $17,165,887 

 Spray Pumps $ slurry gpm $2,570,417 

Flue Gas Handling System $ * $7,114,785 

 ID Fans $ ACFM $2,494,517 

Waste / Byproduct Handling System $ kpph SO2 $89,978 

 Thickener System $ TPH solids $166,517 

Support Equipment $ MW $2,137,419 

 Chimney $ ACFM $4,831,824 

TOTAL $ $48,157,381 

* Based on flue gas flow and reheat 

temperature. 

 

Capital Costs with Retrofit Factors 

Reagent Feed System $ $7,569,694 

 Ball Mill & Hydroclone System $ $1,933,303 

 DBA Acid Tank (pump, heater, agitator) $ $0 

SO2 Removal System $ $2,083,040 

 Absorber Tower $ $17,165,887 

 Spray Pumps $ $2,570,417 

Flue Gas Handling System $ $7,114,785 

 ID Fans $ $2,494,517 

Waste / Byproduct Handling System $ $89,978 

 Thickener System $ $166,517 

Support Equipment $ $2,137,419 

 Chimney $ $4,831,824 

TOTAL $ $48,157,381 

 
10A-15 

General Facilities 

Reagent Feed System $ $756,969 

 Ball Mill & Hydroclone System $ $193,330 

 DBA Acid Tank (pump, heater, agitator) $ $0 

SO2 Removal System $ $208,304 

 Absorber Tower $ $1,716,589 

 Spray Pumps $ $257,042 

Flue Gas Handling System $ $711,478 

 ID Fans $ $249,452 

Waste / Byproduct Handling System $ $8,998 

 Thickener System $ $16,652 

Support Equipment $ $213,742 

 Chimney $ $483,182 

TOTAL $ $4,815,738 

 

Engineering Fees 

Reagent Feed System $ $756,969 

 Ball Mill & Hydroclone System $ $193,330 

 DBA Acid Tank (pump, heater, agitator) $ $0 

SO2 Removal System $ $208,304 

 Absorber Tower $ $1,716,589 

 Spray Pumps $ $257,042 

Flue Gas Handling System $ $711,478 

 ID Fans $ $249,452 

Waste / Byproduct Handling System $ $8,998 

 Thickener System $ $16,652 

Support Equipment $ $213,742 

 Chimney $ $483,182 

TOTAL $ $4,815,738 

 
10A-16 

Contingency 

Reagent Feed System $ $1,513,939 

 Ball Mill & Hydroclone System $ $386,661 

 DBA Acid Tank (pump, heater, agitator) $ $0 

SO2 Removal System $ $416,608 

 Absorber Tower $ $3,433,177 

 Spray Pumps $ $514,083 

Flue Gas Handling System $ $1,422,957 

 ID Fans $ $498,903 

Waste / Byproduct Handling System $ $17,996 

 Thickener System $ $33,303 

Support Equipment $ $427,484 

 Chimney $ $966,365 

TOTAL $ $9,631,476 

 

Total Plant Cost (TPC) $ $67,420,334 

Total Plant Cost (TPC) w/ Prime 

Contractor's Markup $ $69,442,944 

Total Cash Expended (TCE) $ $67,439,971 

 

Allow. for Funds During Constr. (AFDC) $ $7,394,505 

 

Total Plant Investment (TPI) $ $74,834,476 

 

 Preproduction Costs $ $2,609,645 

 Inventory Capital $ $75,177 

 

Total Capital Requirement (TCR) $ $77,519,298 

$/kW $113 

 
10A-17 

Maintenance Cost by Area Case1 

 

TPC w/o Retrofit Factor 

Reagent Feed System $ $10,900,359 

 Ball Mill & Hydroclone System $ $2,783,957 

 DBA Acid Tank (pump, heater, agitator) $ $0 

SO2 Removal System $ $2,999,578 

 Absorber Tower $ $24,718,877 

 Spray Pumps $ $3,701,400 

Flue Gas Handling System $ $10,245,290 

 ID Fans $ $3,592,105 

Waste / Byproduct Handling System $ $129,568 

 Thickener System $ $239,785 

Support Equipment $ $3,077,884 

 Chimney $ $6,957,826 

TOTAL $ $69,346,629 

 

First Year Maintenance Costs 

Reagent Feed System $ $545,018 

 Ball Mill & Hydroclone System $ $139,198 

 DBA Acid Tank (pump, heater, agitator) $ $0 

SO2 Removal System $ $149,979 

 Absorber Tower $ $1,235,944 

 Spray Pumps $ $185,070 

Flue Gas Handling System $ $512,265 

 ID Fans $ $179,605 

Waste / Byproduct Handling System $ $6,478 

 Thickener System $ $11,989 

Support Equipment $ $153,894 

 Chimney $ $347,891 

TOTAL $ $3,467,331 

 

 
10A-18 

LSFO O&M Data and Costs Case1 

Cost Basis (Year) 2010

Parameters 

 Reagent Required lbs/hr 6,961

 lbs/MMBtu 1.191

 DBA Required lbs/hr 0.0

 Percent SO2 Removal % 77%

 FGD Sludge to Disposal lbs/hr, dry 11,522

 Steam to FGD System lbs/hr 64,002

 Total FGD Power Consumption kW 13,660

 FGD Byproduct lbs/hr 0

 

Fixed O&M Costs 

 Number of Operators 35

 (40 hrs/week) 

 Operating Labor Cost ** $/yr $2,890,857 

 Maint. Labor & Matls. Cost $/yr $3,467,331 

 Admin. & Support Labor $/yr $1,283,337 

 TOTAL $/yr $7,641,525 

 

Variable Operating Costs ** 

 Reagent Costs $/yr $408,849 

 DBA Costs $/yr $0 

 Disposal Costs $/yr $270,694 

 Credit for Byproduct $/yr $0 

 Steam Costs $/yr $1,754,288 

 Power Costs $/yr $2,674,437 

 TOTAL $/yr $5,108,268 

 

** These costs assume inputs are in current dollars (no escalation included). 
10A-19 

Intermediate Material Balance Calcs. Case1 

 

Sulfite Reaction 

 SO2 lbmole/hr 63.12

 CaCO3 lbmole/hr 63.12

 H2O lbmole/hr 31.56

 CaSO3* 1⁄2 H2O lbmole/hr 63.12

 CO2 lbmole/hr 63.12

 SO2 lb/hr 4,044

 CaCO3 lb/hr 6,318

 H2O lb/hr 569

 CaSO3* 1⁄2 H2O lb/hr 8,152

 CO2 lb/hr 2,778

 

Sulfate Reaction 

 CaSO3* 1⁄2 H2O lbmole/hr 63.12

 O2 lbmole/hr 31.56

 H2O lbmole/hr 94.68

 CaSO4*2H2O lbmole/hr 63.12

 CaSO3*1/2H2O lb/hr 8,152

 O2 lb/hr 1,010

 H2O lb/hr 1,706

 CaSO4*2H2O lb/hr 10,868

 

Water in Absorber 

 Mole Fraction H2O in Absorber % 0.1389

 Moles H2O in Absorber lbmole 32,595.70

 

DBA Feed Calculations 

 SO2 Removed lbs/hr 4,044

 DBA Added lbs/hr 0.00

 DBA Added GPM 0.00
10A-20 

Fabric Filter 

Fabric Filter – Preliminary Case1 

 

Flue Gas, Upstream of Fabric Filter 

 Temperature °F 300 

 Pressure in. H2O -12 

 Flow Rate SCFM 1,455,241 

 Flow Rate ACFM 2,231,405 

 CO2 lb/hr 1,247,836 

 N2 lb/hr 4,546,491 

 SO2 lb/hr 5,252 

 O2 lb/hr 365,006 

 HCl lb/hr 73 

 Other Gases lb/hr 1,587 

 H2O lb/hr 501,931 

 Fly Ash lb/hr 31,603 

 Total (gas only) lb/hr 6,668,175 

 

Total Fabric Required Ft2

 637,544 

 

Surface Area per Bag Ft2

 31.4 

Required No. of Bags (no spare compartments) 20,294 

Final No. of Bags 22,323 

No. of Casings 2 

Fabric Filter Dimensions (per Casing) Ft2

 10,958 

 Length Ft 148 

 Width Ft 74 

 
10A-21 

Capital Cost Case1 

Cost Basis (Year) 2010

 

 Fabric Filter $ $9,124,437 

 Bags $ $1,175,962 

 Ash Handling System $ $593,466 

 ID Fan(s) $ $899,100 

 Equipment Cost Subtotal $ $11,792,965 

 Instruments & Controls $ $235,859 

 Taxes $ $796,025 

 Freight $ $589,648 

 Purchased Equipment Cost Subtotal $ $13,414,497 

 Installation $ $8,987,713 

 Total Direct Cost $ $22,402,210 

 

 Total Direct Cost with Retrofit Factor $ $22,402,210 

 General Facilities $ $2,240,221 

 Engineering Fees $ $2,240,221 

 Contingency $ $4,480,442 

Total Plant Cost (TPC) $ $31,363,095 

Total Plant Cost (TPC) w/ Prime 

Contractor's Markup $ $32,303,987 

Total Cash Expended (TCE) $ $31,833,541 

 

Allow. for Funds During Constr. (AFDC) $ $1,693,607 

Total Plant Investment (TPI) $ $33,527,148 

 Preproduction Costs $ $670,543 

 Inventory Capital $ $0 

 

Total Capital Requirement (TCR) $ $34,197,691 

$/kW $50.1 

 
10A-22 

O&M Data and Costs Case1 

Cost Basis (Year) 2010

 

 Power Required Excluding ID Fan(s) kW 936 

 ID Fan Power for FF Delta P kW 2,253

 Total Power kW 3,190 

 

 Power Cost ** $/yr $624,491 

 Maintenance Costs $/yr $1,568,155 

 Periodic Replacement Items $/yr $1,175,962 

 First Year Cost. Bags Replaced Every 5 Years 

** These costs assume inputs are in current dollars (no escalation included). 
10A-23 

SCR 

SCR (high-dust) - Preliminary Case1 

 

Ammonia Injection Rate lb/hr 292 

Space Velocity 1/hr 2,947 

Gross Catalyst Volume ft3

 26,455 

 

SCR Capital Costs Case1 

Cost Basis (Year) 2010

 

Reactor Housing and Installation $ 4,196,715 

Ammonia Handling and Injection $ 851,215 

Flue Gas Handling:Ductwork and Fans $ 5,507,915 

Air Preheater Modifications $ 1,385,387 

Misc. Other Direct Capital Costs $ 479,576

 Equipment Capital Cost Subtotal $ $12,420,808 

 Instruments & Controls $ $248,416 

 Taxes $ $838,405 

 Freight $ $621,040 

 Total Direct Cost $14,128,669 

 

Total Direct Cost with Retrofit Factor $ $14,128,669 

 General Facilities $ $706,433 

 Engineering Fees $ $1,412,867 

 Contingency $ $2,825,734 

Total Plant Cost (TPC) $ $19,073,703 

Total Plant Cost (TPC) w/ Prime Contractor's Markup $ $19,645,914 

Total Cash Expended (TCE) $ $19,079,258 

 

Allow. for Funds During Constr. (AFDC) $ $2,091,959 
10A-24 

Total Plant Investment (TPI) $ $21,171,218 

 Preproduction Costs $ $501,260 

Inventory Capital 

 Initial Ammonia(60 days) $ $65,804 

 Initial Catalyst $ $9,426,944 

Total Capital Requirement (TCR) $ $31,165,225 

$/kW $46 

 

 

SCR O&M Costs Case1 

Cost Basis (Year) 2010

 

Ammonia $/yr 400,306 

Catalyst Replacement $/yr 3,142,315 

Catalyst Disposal $/yr 2,430 

Electricity $/yr 441,316 

High-dust SCR Steam $/yr 30,373 

Operating Labor $/yr 200,157 

Maintenance $/yr 286,106 

Total O&M Costs $/yr 4,503,002 
ATTACHMENT 10-B 

RACT / BACT / LAER CLEARINGHOUSE DATA FOR COAL-FIRED BOILERS
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for NOXCoal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

WY-0063 Black Hills Corporation 1 Coal-Fired PC Boiler Low NOx burners, OFA & not given Primary = Secondary= 

WYGEN 3 1300 MMBtu/hr; 100 MW SCR 0.05 lb/MMBtu 65.0 lb/hr Campbell County, WY sub-bituminuous coal 12-mo rolling 30-day rolling

MO-0071 Great Plains Energy 2 Coal-Fired Boiler - Unit 1 Not Identified n/a Primary = Secondary= 

Iatan Station 7800 MMBtu/hr 0.10 lb/MMBtu none listed Platte County, MO sub-bituminuous coal 30-day rolling

VA-0296 Virginia Polytechnical Institute & 1 Stoker Fired Boiler - Boiler 11 Low excess air and not given Primary = Secondary= 

State University 146.7 MMBtu/hr staged combustion 0.246 lb/MMBtu 136.9 tpy Montgomery County, VA 30 day rolling

LA-0176 Louisiana Generating, LLC 1 Coal-Fired PC Boiler, Unit 4 Low NOx burners & 70% Primary = Secondary= 

Big Cajun II Power Plant 675 MW; supercritical boiler SCR 0.07 lb/MMBtu 459.6 lb/hr Pointe Coupee County, LA sub-bituminuous coal annual avg

PA-0249 River Hill Power Company, LLC 1 Waste Coal-Fired CFB Boiler SNCR not given Primary = Secondary= 

Clearfield County, PA 0.07 lb/MMBtu 0.10 lb/MMBtu 

30-day avg. 24-hr avg.

PA-0248 Wellington Dev/Greene Energy 2 Waste Coal-Fired CFB Boilers SNCR not given Primary = Secondary= 

Resource Recovery Project 580 MW (gross) 525 MW (net) 0.08 lb/MMBtu 0.10 lb/MMBtu Greene County, PA 30-day rolling 24-hr avg.

CO-0057 Xcel Energy (PSC of Colorado) 1 Coal-Fired PC Boilers, Units #1 & #2 Low-NOx burners not given Primary = Secondary= 

Comanche Power Station 660 MW (both units) 0.20 lb/MMBtu 0.15 lb/MMBtu Pueblo, CO 30-day avg annual avg.

ND-0021 Montana Dakota Utilities/Westmoreland 1 Lignite Fired CFB Boiler SNCR 40% Primary = Secondary= 

Gascoyne Generating Station 220 MW (gross) 175 MW (net) 0.865 lb/MWh 0.09 lb/MMBtu Bowman County, ND 30 day rolling 30 day rolling

NV-0036 Newmont Nevada Energy Investment LLC 1 Coal-Fired PC Boiler Low NOx burners & not given Primary = Secondary= 

TS Power Plant 200 MW; 2030 MMBtu/hr SCR 0.067 lb/MMBtu none listed Eureka County, NV 24-hr rolling

PA-0247 Robinson Power Company LLC 1 Waste Coal-Fired CFB Boiler SNCR 75% Primary = Secondary= 

Beech Hollow Power Project 272 MW (net); 2800 MMBtu/hr 0.08 lb/MMBtu 972 tpy Washington County, PA no avg. no avg

NE-0031 Omaha Public Power District 1 Coal-Fired PC Boiler SCR 90% Primary = Secondary= 

Nebraska City Station Unit 2 boiler 660 MW (net) 0.07 lb/MMBtu none listed Otoe County, NE sub-bituminuous coal 30-day rolling

MO-0060 Springfield Utilities 1 Coal-Fired PC Boiler SCR 82.6% Primary = Secondary= 

Southwest Power Station 275 MW; 2724 MMBtu/hr 0.08 lb/MMBtu none listed Greene County, MO 30-day rolling

WI-0228 Wisconsin Public Service Co. 1 Coal-Fired PC Boiler; supercritical Low NOx burners & not given Primary = Secondary= 

WPS - Weston Plant 500 MW; 5173 MMBtu/hr SCR 0.07 lb/MMBtu 0.06 lb/MMBtu Marathon County, WI PRB Coal; 8100 BTU/lb 30-day avg. 12-mo avg.

UT-0065 Intermountain Power Service Corp. 1 Coal-Fired PC Boiler Low NOx burners, OFA & 80% Primary = Secondary= 

Generating Station Unit #3 950 MW (gross) SCR 0.07 lb/MMBtu 633.5 lb/hr Millard County, UT Bituminous Coal or Blend 30-day rolling 24-hr block

UT-0064 Nevco-Sevier Power Company 1 Coal-Fired CFB Boiler Low NOx burners & 90% Primary = Secondary= 

Sevier Power Plant 270 MW SNCR 0.10 lb/MMBtu none listed Sevier County, UT 24-hr rolling

RBLC ID Emission Limit

Att 10-B_Coal Boilers_RBLC.xlsNOX 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for NOXCoal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

RBLC ID Emission Limit

NE-0018 Hastings Utilities 1 Unit 2 Coal-Fired Boiler SCR not given Primary = Secondary= 

Whelan Energy Center 220 MW; 2210 MMBtu/hr 0.08 lb/MMBtu none listed Adams County, NE 30-day rolling

WV-0023 Longview Power, LLC 1 Coal-Fired PC Boiler Low NOx burners & not given Primary = Secondary= 

Maidsville 600 MW; 6114 MMBtu/hr SCR 0.08 lb/MMBtu 0.065 lb/MMBtu Monongahela County, WV 24-hr rolling annual avg

SC-0104 Santee Cooper 2 Coal-Fired PC Boilers, #3 & #4 Low NOx burners & not given Primary = Secondary= 

Cross Generating Station Bituminous Coal & Pet Coke SCR 0.08 lb/MMBtu 2278 tpy Berkeley County, SC 5700 MMBtu/hr (each) 365-day rolling 365-day rolling

TX-0298 Reliant Energy Inc. 3 Coal Fired Boilers, Units 5 ,6, 7 None Indicated not given Primary = Secondary= 

WA Parish Electric Generating St. Units 5 & 6 @ 7400 mmbtu/hr 0.38, 0.324 8370, 8860 Houston, TX Unit 7 @ 6700 mmbtu/hr lb/mmbtu tpy 

PA-0182 Reliant Energy Inc. 2 Refused Coal-Fired CFB Boilers SNCR not given Primary = Secondary= 

Seward Power 2532 MMBtu/hr (each) 0.15 lb/MMBtu none listed Indiana County, PA no avg.

AR-0074 Plum Point Associates, LLC 1 Coal-Fired PC Boiler, Unit 1 Low NOx Burners not given Primary = Secondary= 

Plum Point Energy 800 MW 0.090 lb/MMBtu none listed Mississippi County, AR no avg.

OH-0231 First Energy/Toledo Edison Company 1 Coal & Coke-Fired CFB Boiler Limestone Fluidized Bed 65% Primary = Secondary= 

Bayshore Plant 1764 MMBtu/hr 0.20 lb/MMBtu 1.6 lb/MW-hr Lucas County, OH no avg.

MT-0022 Bull Mountain Development Co. 2 Coal-Fired PC Boilers, No. 1, 2 Low NOx Burner, OFA, SCR 90% Primary = Secondary= 

Roundup Power Project 390 MW (each); 4013 MMBtu/hr 0.07 lb/MMBtu 280.9 lb/hr Musselshell County, MT mine-mouth plant 24-hr rolling 24-hr rolling

IA-0067 Mid-American Energy Co. 1 Coal-Fired PC Boiler Low NOx Burner, OFA, SCR 60% Primary = Secondary= 

PRB coal 0.07 lb/MMBtu 2353 tpy 

Council Bluffs, Iowa 7675 MMBtu/hr 30-day rolling no avg

TX-0358 Reliant Energy Inc. 3 Coal Fired Boilers None Indicated not given Primary = Secondary= 

WA Parish Electric Generating St. 2 @ 6750 mmbtu/hr 0.382, 0.325 8370, 8860 Houston, TX 1 @ 6700 mmbtu/hr lb/mmbtu tpy

KY-0084 Thoroughbred Generating Company, LLC 2 Coal-Fired PC Boilers Low-NOx burners & SCR not given Primary = Secondary= 

Thoroughbred Generating Station 1500 MW (total); 7446 MMBtu/hr (ea) 0.08 lb/MMBtu none listed Muhlenburg County, KY 30-day rolling

KS-0026 Sand Sage Power, LLC 1 Subbituminous Coal-Fired PC Boiler Low-NOx burners, OFA & 70% Primary = Secondary= 

Holcomb Unit #2 660 MW SCR 0.08 lb/MMBtu 0.12 lb/MMBtu Finney County, KS no avg. initial 18 months

WY-0057 Black Hills Corporation 1 Subbituminous Coal-Fired PC Boiler Low-NOx burners & SCR not given Primary = Secondary= 

WYGEN 2 500 MW; 5146 MMBtu/hr 0.07 lb/MMBtu none listed Campbell County, WY 30-day rolling

KY-0086 East Kentucky Power Coop, Inc. 1 Coal-Fired CFB Boiler SNCR not given Primary = Secondary= 

Spurlock Power Station 270 MW; 2500 MMBtu/hr 0.07 lb/MMBtu none listed Mason County, KY 30-day rolling

MT-0027 Rocky Mountain Power, Inc. 1 Coal-Fired PC Boiler SCR not given Primary = Secondary= 

Hardin Generating Project 113 MW (nominal); 1304 MMBtu/hr 0.09 lb/MMBtu none listed Big Horn County, MT 30-day rolling

Att 10-B_Coal Boilers_RBLC.xlsNOX 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for NOXCoal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

RBLC ID Emission Limit

PA-0183 AES Beaver Valley, LLC 1 Coal-Fired CFB Boiler SNCR not given Primary = Secondary= 

2155 MMBtu/hr 0.101 lb/MMBtu none listed 

Beaver County, PA no avg.

PR-0007 AES Puerto Rico Cogeneration Plant 2 Coal-Fired CFB Boilers SNCR not given Primary = Secondary= 

454 MW (net); 4923 MMBtu/hr 0.10 lb/MMBtu 57 ppmvd @7% 

Guyama, Puerto Rico Bituminous Coal; max 1% sulfur no avg. no avg

LA-0122 International Paper- Mansfield Mill 2 Coal Fired Boilers Low NOx Staged not given 0.70 lb/mmbtu 

Burners 

Mansfield, Louisiana 645 mmbtu/hr each

TX-0342 Reliant Energy Inc. 2 Lignite Coal Fired Boilers None Indicated not given Primary = Secondary= 

Limestone Electric Generating St. 3932 0.50 Houston, TX 7863 mmbtu/hr each lb/hr lb/mmbtu

KY-0079 Kentucky Mountain Power, LLC 2 Coal & Coal Refuse-Fired CFB Boilers SNCR not given Primary = Secondary= 

Units 1 & 2 0.07 lb/MMBtu none listed 

Knott County, KY 2550 MMBtu/hr no avg.

FL-0003 Tampa Electric Co. 1 Coal Fired Boiler Equipment Design & not given Primary = Secondary= 

Teco- Big Bend Station Dry Bottom, Tangentially Fired Operation 0.6 2598 Apollo Beach, Florida 4330 mmbtu/hr lb/mmbtu lb/hr

TX-0275 Reliant Energy 1 Coal Fired Boiler, Unit 8 Low-NOx burners, OFA & not given Primary = Secondary= 

 W.A. Parish Electric Generating St. 6700 mmbtu/hr SCR 0.43 lb/MMBtu 2865 lb/hr Ft. Bend County, Texas Boiler also burns NG & Fuel Oil no avg. 30-day rolling

MO-0050 Kansas City Power & Light Co. 1 Coal Fired PC Boiler SCR & Good Combustion not given Primary = Secondary= 

Hawthorn Station Tangentially Fired Practice 0.08 lb/MMBtu 0.12 lb/MMBtu Kansas City, Missouri 384 T/H 30-day avg. 24-hr avg.

FL-0178 JEA Northside Generating St. 2 Coal Fired CFB Boilers SNCR not given Primary = Secondary= 

297.5 MW; 2764 MMBtu/hr (each) 0.09 lb/MMBtu none listed 

Jacksonville, Florida 30-day rolling

PA-0163 AES Beaver Valley Partners, Inc. 1 Coal Fired PC Boiler Low-NOx Burner & SOFA not given Primary = Secondary= 

550 MMBtu/hr 0.70 lb/MMBtu none listed 

Beaver County, PA no avg.

PA-0162 Edison Mission Energy 3 Coal-Fired PC Boilers, Units 1,2,3 SCR 70% Primary = Secondary= 

5700 MMBtu/hr (each) 0.15 lb/MMBtu none listed 

Homer City, Pennsylvania no avg.

IL-0060 Archer Daniels Midland Co. 2 Coal Fired CFB Boilers, Units 9,10 SNCR 85% Primary = Secondary= 

1500 mmbtu/hr each 0.09 lb/MMBtu 0.12 lb/MMBtu 

Decatur, Illinois no avg. no avg

MS-0036 Choctaw Generation L.P 2 Lignite-Fired CFB Boilers Circulating Fluidized Bed not given Primary = Secondary= 

Design 0.20 lb/MMBtu none listed 

Ackerman, Mississippi 2475.6 mmbtu/hr each no avg.

IA-0046 Archer Daniels Midland Company 2 Coal-Fired CFB Boiler, Unit #5, #6 SNCR not given Primary = Secondary= 

1500 mmbtu/hr (each) 0.07 lb/MMBtu none listed 

Linn County, IA 30-day rolling

IA-0051 Archer Daniels Midland Co. 1 Coal Fired CFB Boiler SNCR not given Primary = Secondary= 

0.07 lb/MMBtu none listed 

Cedar Rapids, Iowa 1500 mmbtu/hr 30-day rolling

Att 10-B_Coal Boilers_RBLC.xlsNOX 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for NOXCoal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

RBLC ID Emission Limit

PA-0204 Kimberly- Clark Tissue Co. 3 Coal Fired CFB & 2 Vertical Boilers None Indicated not given Primary = Secondary= 

Kimberly- Clark/Chester Plant 799 mmbtu/hr, 249 mmbtu/hr & 0.20 lb/MMBtu 1090 tpy total Chester, Pennsylvania 198 mmbtu/hr (respectively) no avg.

UT-0053 Deseret Generation & Transmission Co. 1 Coal-Fired PC Boiler Boiler Design not given Primary = Secondary= 

500 MW 0.55 lb/MMBtu 0.50 lb/MMBtu 

Unitah County, UT 30-day avg. annual avg

WY-0039 Two Elk Generation Partners, Ltd. 1 Coal-Fired PC Boiler Low NOx Burners, OFA & 75% Primary = Secondary= 

Partnership SCR 0.15 lb/MMBtu none listed Campbell County, WY 250 MW 30-day rolling

WY-0047 Encoal Corporation 1 Coal-Fired PC Boiler Low NOx Burners, OFA & 60% Primary = Secondary= 

North Rochelle Facility 240 MW SCR 0.15 lb/MMBtu none listed Campbell County, WY no avg.

WY-0047 Encoal Corporation 1 Coal-Fired PC Boiler Low NOx Burners & FGR not given Primary = Secondary= 

North Rochelle Facility 3960 MMBtu/hr 0.16 lb/MMBtu none listed Campbell County, WY Subbituminous Coal no avg.

WY-0048 WYGEN, Inc. 1 Coal-Fired PC Boiler Low NOx Burners & OFA 56% Primary = Secondary= 

WYGEN Unit #1 80 MW; 1014 MMBtu/hr 0.22 lb/MMBtu none listed Campbell County, WY 30-day rolling

PA-0133 Mon Valley Energy Ltd. 1 Pulverized Coal Fired Boiler SCR with LNB 50% Primary = Secondary= 

Partnership 0.15 635 Poland Mines, Pennsylvania 966 mmbtu/hr lb/mmbtu tpy

PA-0132 York County Energy Partners 1 Coal Fired CFB Boiler SNCR 40% Primary = Secondary= 

Spring Grove, Pennsylvania 0.125 328 

2500 mmbtu/hrR lb/mmbtu lb/hr

UT-0060 Deseret Generation & 1 Coal Fired Boiler Low NOx Burners not given 0.55 lb/mmbtu 

Transmission Co. Vernaz, Utah 4381 mmbtu/hr

PA-0123 West Penn Power Co. 1 Pulverized Coal Fired Boiler Low NOx Burners 36.6% Primary = Secondary= 

Dry Bottom 0.45 4849 

Monogahela, Pennsylvania 2460 mmbtu/hr lb/mmbtu tpy

PA-0112 Pennsylvania Power and Light Co. 1 Coke/Coal Fired Boiler O/M not given Primary = Secondary= 

Dry Bottom 1.4 5660 

Holtwood, Pennsylvania 923 mmbtu/hr lb/mmbtu tpy

PA-0134 Northampton Generating Co. 1 Ahlstrom Coal Fired CFB Boiler Thermo De-NOx 63% Primary = Secondary= 

0.1 467 

Northampton, Pennsylvania 1146 mmbtu/hr lb/mmbtu tpy

PA-0129 Metropolitan Edison Co. 3 Pulverized Coal Fired Boilers Low NOx Burners 27% Primary = Secondary= 

Dry Bottom 0.45 1580 

Reading, Pennsylvania 801.4 mmbtu/hr lb/mmbtu tpy

PA-0105 Pennsylvania Power Co. 3 Pulverized Coal Fired Boilers Low NOx Burners 2 @ 55% Primary = Secondary= 

Dry Bottom 29% 0.5 16466 

Shippingport, Pennsylvania 7914 mmbtu/hr lb/mmbtu tpy

Att 10-B_Coal Boilers_RBLC.xlsNOX 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for NOXCoal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

RBLC ID Emission Limit

PA-0109 Zinc Corporation of America 2 Pulverized Coal Fired Boilers Automated Air Controllers 10% Primary = Secondary= 

0.45 1754 

Monaca, Pennsylvania 600 mmbtu/hr lb/mmbtu tpy

PA-0115 Pennsylvania Electric Co. 2 Pulverized Coal Fired Boilers Low NOx Burners 35% Primary = Secondary= 

Dry Bottom 38% 0.45 15790 

Shelocta, Pennsylvania 8010 mmbtu/hr lb/mmbtu tpy

PA-0116 West Penn Power Co. 3 Pulverized Coal Fired Boilers Low NOx Burners 52% Primary = Secondary= 

Dry Bottom 0.58 12800 

Masontown, Pennsylvania 5036 mmbtu/hr lb/mmbtu tpy

PA-0117 Duquesne Light Co. 4 Pulverized Coal Fired Boilers Low NOx Burners 26%, 37% 0.5 lb/mmbtu 

 Dry Bottom 23%, 39% 

Elrama, Pennsylvania 2 @ 1100, 1200, & 1790 mmbtu/hr respectively

PA-0119 Pennsylvania Electric Co. 3 Pulverized Coal Fired Boilers Low NOx Burners 55%, 55% & Primary = Secondary= 

Dry Bottom 29% 0.5 13076 

Homer City, Pennsylvania 2 @ 6792 & 6600 mmbtu/hr respectively lb/mmbtu tpy

PA-0125 West Penn Power Co. 2 Pulverized Coal Fired Boilers Low NOx Burners 52%, 57% Primary = Secondary= 

Dry Bottom respectively 0.45 3272, 4025 

Kittenning, Pennsylvania 2 @ 1600 mmbtu/hr lb/mmbtu tpy

PA-0126 Pennsylvania Electric Co. 2 Pulverized Coal Fired Boilers Low NOx Burners 37%, 33% Primary = Secondary= 

Dry Bottom respectively 0.45 15524 

New Florence, Pennsylvania 2 @ 7876 mmbtu/hr lb/mmbtu tpy

PA-0142 P.H. Glatfelter 2 Coal Fired Dry Bottom Boilers Low NOx Burners not given 0.74 lb/mmbtu 

33% 0.51 lb/mmbtu 

Spring Grove, Pennsylvania 257 & 357 mmbtu/hr

PA-0108 Peco Energy Co. 2 Pulverized Coal Fired Boilers Low NOx Burners 12%, 20% 0.45 lb/mmbtu 

Dry Bottom respectively 

Eddystone, Pennsylvania 2704 & 2808 mmbtu/hr

PA-0101 International Paper Co. 2 Coal Fired Boilers Annual Tune-Up not given Primary = Secondary= 

Hammervill Papers Div. 0.7 780 Lock Haven, Pennsylvania 350 mmbtu/hr each lb/mmbtu tpy

PA-0111 Pennsylvania Electric Co. 4 Pulverized Coal Fired Boilers Low NOx Burners 56%, 42% Primary = Secondary= 

Dry Bottom respectively 0.5, 0.45 2946, 3528 

Shawville, Pennsylvania 2 @ 1345, 2 @ 1790 mmbtu/hr lb/mmbtu tpy

PA-0113 Pennsylvania Power and Light Co. 2 Coke/Coal Fired Dry Bottom Boiler Low NOx Burners 47%, 55% Primary = Secondary= 

respectively 0.5 2794, 3166 

Shamokin Dam, Pennsylvania 1277 &1415 mmbtu/hr lb/mmbtu tpy

PA-0124 Westwood Energy Properties, Inc. 1 Coal CFB Boiler No Controls Feasible not given Primary = Secondary= 

0.3 557 

Tremont, Pennsylvania 423 mmbtu/hr lb/mmbtu tpy

PA-0128 Pennsylvania Power and Light Co. 3 Pulverized Coal Fired Boilers Low NOx Burners 47%, 40% Primary = Secondary= 

& 30% 0.45, 0.45, 0.45 13748, 7135 & 

York Haven, Pennsylvania 7329, 3790 & 3345 mmbtu/hr respectively lb/mmbtu 6273 tpy

Att 10-B_Coal Boilers_RBLC.xlsNOX 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for NOXCoal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

RBLC ID Emission Limit

PA-0127 Pennsylvania Power Co. 3 Pulverized Coal Fired Boilers Limit Hours of Operation not given Primary = Secondary= 

0.79, 0.72 , 1.01 1302, 1567 & 

New Castle, Pennsylvania 2 @ 1029 & 1325 mmbtu/hr lb/mmbtu 3650 tpy

PA-0143 General Electric Transportation 1 Cyclone Coal Fired Boiler Won't Operate During not given Primary = Secondary= 

System Ozone Season 1.01 840 Erie, Pennsylvania 420 mmbtu/hr lb/mmbtu tpy

PA-0110 Gilberton Power Co. 2 Coal Fired CFB Boilers No Controls Feasible not given 0.3 lb/mmbtu 

Frackville, Pennsylvania 2 @ 520 mmbtu/hr

PA-0114 Pennsylvania Power and Light Co. 2 Pulverized Coal Fired Boilers Low NOx Burners 44%, 50% Primary = Secondary= 

respectively 0.5 3854, 3859 

Martins Creek, Pennsylvania 2 @ 1727 mmbtu/hr lb/mmbtu tpy

PA-0121 Metropolitan Edison Co. 2 Pulverized Coal Fired Boilers Low NOx Burners 34.9% , 37.3% Primary = Secondary= 

respectively 0.43, 0.37 2330 , 1424 

Portland, Pennsylvania 2342, 1464 mmbtu/hr lb/mmbtu tpy

PA-0100 Pennsylvania Power and Light Co. 2 Pulverized Coal Fired Boilers Low NOx Burners 55% 0.5 lb/mmbtu 

Washingtonville, Pennsylvania 2 @ 7100 mmbtu/hr

IL-0058 Archer Daniels Midland Co. 2 Coal Fired CFB Boilers SNCR 85% 0.12 lb/mmbtu 

1500 mmbtu/hr 

Decatur, Illinois 750 mmbtu/hr

MA-0028 Energy New Bedford 2 Coal Fired CFB Boilers SNCR, Controlled not given Primary = Secondary= 

Combustion 0.15 263.2 

New Bedford, Massachusetts 1671 mmbtu/hr each lb/mmbtu lb/hr

MD-0022 AES Warrior Run, Inc. 1 Coal Fired Atmospheric CFB Boiler Thermo De-NOx 40% 0.1 lb/mmbtu 

Cumberland, Maryland 2070 mmbtu/hr

FL-0255 Cedar Bay Generating Co., LP 3 Pulverized Coal Fired CFB Boilers SNCR not given Primary = Secondary= 

Ceder Bay Cogeneration 0.17 180.72 Jacksonville, Florida 132 mmbtu/hr each lb/mmbtu lb/hr

Notes:NSR RACT/BACT/LAER Clearinghouse Database (http://cfpub.epa.gov/rblc) was queried for the following:- RBLC Determinations added during or after January 1996- Process Type Code: 11.110 - Coal Combustion for Utility Boilers

Att 10-B_Coal Boilers_RBLC.xlsNOX 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for COCoal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

WY-0063 Black Hills Corporation 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

WYGEN 3 1300 MMBtu/hr; 100 MW 0.15 lb/MMBtu none listed Campbell County, WY sub-bituminuous coal 3-hr test

MO-0071 Great Plains Energy 2 Coal-Fired Boiler - Unit 1 Good Combustion Practices not given Primary = Secondary= 

Iatan Station 7800 MMBtu/hr 0.16 lb/MMBtu none listed 

Platte County, MO sub-bituminuous coal 30-day rolling

CO-0055 Lamar Utilities Board DBA 1 Coal-Fired CFB Boiler Good Combustion Practices not given Primary = Secondary= 

Lamar Light & Power Plant 501.7 MMBtu/hr 75.3 lb/hr none listed Powers County, CO sub-bit or bituminous coal 3-hr rolling

VA-0296 Virginia Polytechnical Institute & 1 Stoker Fired Boiler - Boiler 11 Combustion Control not given Primary = Secondary= 

State University 146.7 MMBtu/hr 0.226 lb/MMBtu 33.2 lb/hr 

Montgomery County, VA no avg.

LA-0176 Louisiana Generating, LLC 1 Coal-Fired PC Boiler, Unit 4 Good Combustion Practices not given Primary = Secondary= 

Big Cajun II Power Plant 675 MW; supercritical boiler 0.135 lb/MMBtu 886.4 lb/hr Pointe Coupee County, LA sub-bituminuous coal annual avg

PA-0249 River Hill Power Company, LLC 1 Waste Coal-Fired CFB Boiler Optimizing combustion temperature not given Primary = Secondary= 

Clearfield County, PA 0.20 lb/MMBtu 0.25 lb/MMBtu 

>70% load <70% load

PA-0248 Wellington Dev/Greene Energy 2 Waste Coal-Fired CFB Boilers Good Combustion Practices not given Primary = Secondary= 

Resource Recovery Project 580 MW (gross) 525 MW (net) 0.20 lb/MMBtu 4829 tpy Greene County, PA no avg. 12-month rolling

CO-0057 Xcel Energy (PSC of Colorado) 1 Coal-Fired PC Boiler, Unit #3 Good Combustion Practices not given Primary = Secondary= 

Comanche Power Station 750 MW (unit #3); 7421 MMBtu/hr 0.13 lb/MMBtu 0.30 lb/MMBtu Pueblo, CO sub-bituminuous coal 8-hr avg. avg startup

ND-0021 Montana Dakota Utilities/Westmoreland 1 Lignite Fired CFB Boiler Good Combustion Practices not given Primary = Secondary= 

Gascoyne Generating Station 220 MW (gross) 175 MW (net) 0.154 lb/MMBtu none listed Bowman County, ND 3-hr avg

NV-0036 Newmont Nevada Energy Investment LLC 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

TS Power Plant 200 MW; 2030 MMBtu/hr 0.15 lb/MMBtu none listed Eureka County, NV 24-hr rolling

PA-0247 Robinson Power Company LLC 1 Waste Coal-Fired CFB Boiler Good Combustion Practices not given Primary = Secondary= 

Beech Hollow Power Project 272 MW (net); 2800 MMBtu/hr 0.15 lb/MMBtu 1823 tpy Washington County, PA no avg. no avg

NE-0031 Omaha Public Power District 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

Nebraska City Station Unit 2 boiler 660 MW (net) 0.16 lb/MMBtu none listed Otoe County, NE sub-bituminuous coal 3-hr rolling

MO-0060 Springfield Utilities 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

Southwest Power Station 275 MW; 2724 MMBtu/hr 0.16 lb/MMBtu none listed Greene County, MO no avg.

WI-0228 Wisconsin Public Service Co. 1 Coal-Fired PC Boiler; supercritical Good Combustion Practices not given Primary = Secondary= 

WPS - Weston Plant 500 MW; 5173 MMBtu/hr 0.15 lb/MMBtu 3399 ton/yr 

Marathon County, WI PRB Coal; 8100 BTU/lb 24-hr avg. 12-mo avg.

UT-0065 Intermountain Power Service Corp. 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

Generating Station Unit #3 950 MW (gross) 0.15 lb/MMBtu 3000 lb/hr 

Millard County, UT Bituminous Coal or Blend 30-day rolling 8-hr block

GA-0114 Temple-Inland Inc. 1 Coal-Fired Boiler Good Combustion Practices not given Primary = Secondary= 

Rome Linerboard Mill 565 MMBtu/hr 300 ppm@3% O2 none listed Floyd County, GA

UT-0064 Nevco-Sevier Power Company 1 Coal-Fired CFB Boiler Good Combustion Practices not given Primary = Secondary= 

Sevier Power Plant 270 MW 292 lb/hr none listed Sevier County, UT 1-hr avg

RBLC ID Emission

Limit

Att 10-B_Coal Boilers_RBLC.xlsCO 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for COCoal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

RBLC ID Emission

Limit

IL- 0094 Corn Products International 1 Coal-Fired CFB Boiler Best Operating Practices not given Primary = Secondary= 

Cook County, IL 1670 MMBtu/hr 0.10 lb/MMBtu 400 ppm@7% O2 

24-hr block per Boiler MACT

NE-0018 Hastings Utilities 1 Unit 2 Coal-Fired Boiler Good Combustion Practices not given Primary = Secondary= 

Whelan Energy Center 220 MW; 2210 MMBtu/hr 0.15 lb/MMBtu none listed 

Adams County, NE no avg.

WV-0023 Longview Power, LLC 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

Maidsville 600 MW; 6114 MMBtu/hr 0.11 lb/MMBtu 673 lb/hr 

Monongahela County, WV 3-hr rolling no avg

SC-0104 Santee Cooper 2 Coal-Fired PC Boilers, #3 & #4 Good Combustion Practices not given Primary = Secondary= 

Cross Generating Station Bituminous Coal & Pet Coke 0.16 lb/MMBtu none listed Berkeley County, SC 5700 MMBtu/hr (each) no avg.

TX-0298 Reliant Energy Inc. 3 Coal Fired Boilers, Units 5 ,6, 7 Combustion Control not given Primary = Secondary= 

WA Parish Electric Generating St. Units 5 & 6 @ 7400 mmbtu/hr 0.292, 0.282 9496, 8281 Houston, TX Unit 7 @ 6700 mmbtu/hr lb/mmbtu tpy 

PA-0182 Reliant Energy Inc. 2 Refused Coal-Fired CFB Boilers Good Combustion Practices not given Primary = Secondary= 

Seward Power 2532 MMBtu/hr (each) 0.15 lb/MMBtu none listed Indiana County, PA no avg.

AR-0074 Plum Point Associates, LLC 1 Coal-Fired PC Boiler, Unit 1 Low NOx Burners not given Primary = Secondary= 

Plum Point Energy 800 MW 0.16 lb/MMBtu none listed Mississippi County, AR no avg.

OH-0231 First Energy/Toledo Edison Company 1 Coal & Coke-Fired CFB Boiler Good Combustion Practices not given Primary = Secondary= 

Bayshore Plant 1764 MMBtu/hr 0.13 lb/MMBtu 1220 tpy Lucas County, OH no avg. no avg

MT-0022 Bull Mountain Development Co. 2 Coal-Fired PC Boilers, No. 1, 2 Good Combustion Practices not given Primary = Secondary= 

Roundup Power Project 390 MW (each); 4013 MMBtu/hr 0.15 lb/MMBtu none listed Musselshell County, MT mine-mouth plant no avg.

IA-0067 Mid-American Energy Co. 1 Coal-Fired PC Boiler Combustion Control not given Primary = Secondary= 

PRB coal 0.154 lb/MMBtu 5177 tpy 

Council Bluffs, Iowa 7675 MMBtu/hr 24-hr avg no avg

TX-0358 Reliant Energy Inc. 3 Coal Fired Boilers Combustion Control not given Primary = Secondary= 

WA Parish Electric Generating St. 2 @ 6750 mmbtu/hr 0.321, 0.33 9496, 8281 Houston, TX 1 @ 6700 mmbtu/hr lb/mmbtu tpy

KY-0084 Thoroughbred Generating Company, LLC 2 Coal-Fired PC Boilers Good Combustion Practices not given Primary = Secondary= 

Thoroughbred Generating Station 1500 MW (total); 7446 MMBtu/hr (ea) 0.10 lb/MMBtu none listed Muhlenburg County, KY 30-day rolling

KS-0026 Sand Sage Power, LLC 1 Subbituminous Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

Holcomb Unit #2 660 MW 0.15 lb/MMBtu none listed Finney County, KS no avg.

WY-0057 Black Hills Corporation 1 Subbituminous Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

WYGEN 2 500 MW; 5146 MMBtu/hr 0.15 lb/MMBtu none listed Campbell County, WY no avg.

KY-0086 East Kentucky Power Coop, Inc. 1 Coal-Fired CFB Boiler Proper Boiler Design & Operation not given Primary = Secondary= 

Spurlock Power Station 270 MW; 2500 MMBtu/hr 0.15 lb/MMBtu none listed Mason County, KY 30-day rolling

MT-0027 Rocky Mountain Power, Inc. 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

Hardin Generating Project 113 MW (nominal); 1304 MMBtu/hr 0.15 lb/MMBtu none listed Big Horn County, MT no avg.

Att 10-B_Coal Boilers_RBLC.xlsCO 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for COCoal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

RBLC ID Emission

Limit

PA-0183 AES Beaver Valley, LLC 1 Coal-Fired CFB Boiler Good Combustion Practices not given Primary = Secondary= 

2155 MMBtu/hr 0.20 lb/MMBtu none listed 

Beaver County, PA no avg.

PR-0007 AES Puerto Rico Cogeneration Plant 2 Coal-Fired CFB Boilers Good Combustion Practices not given Primary = Secondary= 

454 MW (net); 4923 MMBtu/hr 0.10 lb/MMBtu 94 ppmvd @7% 

Guyama, Puerto Rico Bituminous Coal; max 1% sulfur 8-hr avg. no avg

LA-0122 International Paper- Mansfield Mill 2 Coal Fired Boilers Less than 0.041 lb/mmbtu not given 0.20 lb/mmbtu 

 from coal 

Mansfield, Louisiana 645 mmbtu/hr each

TX-0342 Reliant Energy Inc. 2 Lignite Coal Fired Boilers No Controls Feasible not given Primary = Secondary= 

Limestone Electric Generating St. 873 0.28 Houston, TX 7863 mmbtu/hr each lb/hr lb/mmbtu

KY-0079 Kentucky Mountain Power, LLC 2 Coal & Coal Refuse-Fired CFB Boilers Good Combustion Practices not given Primary = Secondary= 

Units 1 & 2 0.27 lb/MMBtu none listed 

Knott County, KY 2550 MMBtu/hr no avg.

FL-0003 Tampa Electric Co. 1 Coal Fired Boiler Equipment Design and Operation not given Primary = Secondary= 

Teco- Big Bend Station Dry Bottom, Tangentially Fired 0.029 124 

Apollo Beach, Florida 4330 mmbtu/hr lb/mmbtu lb/hr

TX-0275 Reliant Energy 1 Coal Fired Boiler, Unit 8 Good Combustion Practices not given Primary = Secondary= 

 W.A. Parish Electric Generating St. 6700 mmbtu/hr 0.05 lb/MMBtu 338 lb/hr 

Ft. Bend County, Texas Boiler also burns NG & Fuel Oil no avg. no avg

MO-0050 Kansas City Power & Light Co. 1 Coal Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

Hawthorn Station Tangentially Fired 0.16 lb/MMBtu none listed Kansas City, Missouri 384 T/H no avg.

FL-0178 JEA Northside Generating St. 2 Coal Fired CFB Boilers Good Combustion Practices not given Primary = Secondary= 

297.5 MW; 2764 MMBtu/hr (each) 0.13 lb/MMBtu 350 lb/hr 

Jacksonville, Florida no avg. 24-hr block

IL-0060 Archer Daniels Midland Co. 2 Coal Fired CFB Boilers, Units 9,10 Good Combustion Practices not given Primary = Secondary= 

1500 mmbtu/hr each 0.10 lb/MMBtu none listed 

Decatur, Illinois no avg.

MS-0036 Choctaw Generation L.P 2 Lignite-Fired CFB Boilers Circulating Fluidized Bed not given Primary = Secondary= 

Design 0.20 lb/MMBtu none listed 

Ackerman, Mississippi 2475.6 mmbtu/hr each no avg.

IA-0046 Archer Daniels Midland Company 2 Coal-Fired CFB Boiler, Unit #5, #6 Good Combustion Practices 10% Primary = Secondary= 

1500 mmbtu/hr (each) 0.15 lb/MMBtu none listed 

Linn County, IA 3-hr avg

IA-0051 Archer Daniels Midland Co. 1 Coal Fired CFB Boiler SNCR 10% Primary = Secondary= 

0.15 lb/MMBtu none listed 

Cedar Rapids, Iowa 1500 mmbtu/hr 3-hr avg

UT-0053 Deseret Generation & Transmission Co. 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

500 MW 602.45 tpy none listed 

Unitah County, UT no avg.

AR-0069 Entergy-Arkansas, Inc. 2 Coal-Fired PC Boilers Good Combustion Practices not given Primary = Secondary= 

Independence Plant 8700 MMBtu/hr (each) 100 ppm 0.37 lb/MMBtu 

Independence County, AR Subbituminous Coal 24-hr avg no avg

WY-0039 Two Elk Generation Partners, Ltd. 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

Partnership 0.15 lb/MMBtu none listed 

Campbell County, WY 250 MW no avg.

Att 10-B_Coal Boilers_RBLC.xlsCO 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for COCoal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

RBLC ID Emission

Limit

WY-0047 Encoal Corporation 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

North Rochelle Facility 240 MW 0.15 lb/MMBtu none listed 

Campbell County, WY no avg.

WY-0047 Encoal Corporation 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

North Rochelle Facility 3960 MMBtu/hr 0.15 lb/MMBtu none listed 

Campbell County, WY Subbituminous Coal no avg.

WY-0048 WYGEN, Inc. 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

WYGEN Unit #1 80 MW; 1014 MMBtu/hr 0.15 lb/MMBtu none listed 

Campbell County, WY no avg.

PA-0133 Mon Valley Energy Ltd. 1 Pulverized Coal Fired Boiler No Controls Feasible not given Primary = Secondary= 

Partnership 0.20 847 Poland Mines, Pennsylvania 966 mmbtu/hr lb/mmbtu tpy

PA-0134 Northampton Generating Co. 1 Ahlstrom Coal Fired CFB Boiler No Controls Feasible not given Primary = Secondary= 

0.15 700 

Northampton, Pennsylvania 1146 mmbtu/hr lb/mmbtu tpy

IL-0058 Archer Daniels Midland Co. 2 Coal Fired CFB Boilers Good Combustion Practice not given 0.1 lb/mmbtu 

1500 mmbtu/hr 

Decatur, Illinois 750 mmbtu/hr

MA-0028 Energy New Bedford 2 Coal Fired CFB Boilers Combustion Control not given Primary = Secondary= 

228.1 0.14 

New Bedford, Massachusetts 1671 mmbtu/hr each lb/hr lb/mmbtu

MD-0022 AES Warrior Run, Inc. 1 Coal Fired Atmospheric CFB Boiler Combustion Control not given 0.15 lb/mmbtu 

Cumberland, Maryland 2070 mmbtu/hr

FL-0255 Cedar Bay Generating Co., LP 3 Pulverized Coal Fired CFB Boilers Good Combustion Practice not given Primary = Secondary= 

Ceder Bay Cogeneration 0.175 186 Jacksonville, Florida 132 mmbtu/hr each lb/mmbtu lb/hr

Notes:NSR RACT/BACT/LAER Clearinghouse Database (http://cfpub.epa.gov/rblc) was queried for the following:- RBLC Determinations added during or after January 1996- Process Type Code: 11.110 - Coal Combustion for Utility Boilers

Att 10-B_Coal Boilers_RBLC.xlsCO 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for SO2Coal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

WY-0063 Black Hills Corporation 1 Coal-Fired PC Boiler Dry FGD not given Primary = Sec

WYGEN 3 1300 MMBtu/hr; 100 MW 0.09 lb/MMBtu 117Campbell County, WY sub-bituminuous coal 12-mo rolling 30-d

MO-0071 Great Plains Energy 2 Coal-Fired Boiler - Unit 1 Not Identified n/a Primary = Sec

Iatan Station 7800 MMBtu/hr 0.10 lb/MMBtu none Platte County, MO sub-bituminuous coal 30-day rolling

CO-0055 Lamar Utilities Board DBA 1 Coal-Fired CFB Boiler Limestone Injection not given Primary = Sec

Lamar Light & Power Plant 501.7 MMBtu/hr 0.103 lb/MMBtu none Powers County, CO sub-bit or bituminous coal daily avg

VA-0296 Virginia Polytechnical Institute & 1 Stoker Fired Boiler - Boiler 11 Dry Scrubber FGD System not given Primary = Sec

State University 146.7 MMBtu/hr max sulfur 1.4% by weight 0.161 23.6 Montgomery County, VA lb/MMBtu lb/hr

LA-0176 Louisiana Generating, LLC 1 Coal-Fired PC Boiler, Unit 4 Semi-dry lime SDA or 90% Primary = Sec

Big Cajun II Power Plant 675 MW; supercritical boiler Wet FGD 0.10 lb/MMBtu 656Pointe Coupee County, LA sub-bituminuous coal annual avg

PA-0249 River Hill Power Company, LLC 1 Waste Coal-Fired CFB Boiler Dry FGD System not given Primary = Sec

Clearfield County, PA 0.274 lb/MMBtu 0.20 

24-hr rolling 30-d

PA-0248 Wellington Dev/Greene Energy 2 Waste Coal-Fired CFB Boilers Limestone Injection plus 98% Primary = Sec

Resource Recovery Project 580 MW (gross) 525 MW (net) Dry Polishing Scrubber 0.156 lb/MMBtu 0.23Greene County, PA 30-day rolling 3-hr Xcel Energy (PSC of Colorado) 2 Coal-Fired PC Boilers, Units #1 & #2 Lime Spray Dryer Absorber not given Primary = SecComanche Power Station 660 MW (both units) 0.12 lb/MMBtu 0.10 Pueblo, CO 30-day avg annuXcel Energy (PSC of Colorado) 1 Coal-Fired PC Boiler, Unit #3 Lime Spray Dryer Absorber not given Primary = SecComanche Power Station 750 MW (unit #3); 7421 MMBtu/hr 0.10 lb/MMBtu not lPueblo, CO sub-bituminuous coal 30-day avg

ND-0021 Montana Dakota Utilities/Westmoreland 1 Lignite Fired CFB Boiler Limestone Injection plus 98.9% Primary = Sec

Gascoyne Generating Station 220 MW (gross) 175 MW (net) Spray Dryer 0.038 lb/MMBtu 140 Bowman County, ND 30 day rolling 24-h

NV-0036 Newmont Nevada Energy Investment LLC 1 Coal-Fired PC Boiler Spray Dryer Scrubber see limits Primary = Sec

TS Power Plant 200 MW; 2030 MMBtu/hr 0.065 lb/MMBtu 0.09Eureka County, NV if S <0.45% if S 

91% CE; 30-day 95% 

PA-0247 Robinson Power Company LLC 1 Waste Coal-Fired CFB Boiler Limestone Injection plus 97% Primary = Sec

Beech Hollow Power Project 272 MW (net); 2800 MMBtu/hr Fly Ash Hydration/Reinjection 0.245 lb/MMBtu 2957 Washington County, PA no avg. no a

NH-0013 Public Service of New Hampshire 1 Unit #5 Boiler Lime Injection; Fuel Sulfur Limits 70% Primary = Sec

Schiller Station Primary Wood-Fired; Coal Backup 0.12 lb/MMBtu 1.0 lRockingham County, NH 50 MW 24-hr avg max 

RBLC ID Emission

Limit

Att 10-B_Coal Boilers_RBLC.xlsSO2 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for SO2Coal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

RBLC ID Emission

Limit

NE-0031 Omaha Public Power District 1 Coal-Fired PC Boiler Dry FGD & Fabric Filter 90% Primary = Sec

Nebraska City Station Unit 2 boiler 660 MW (net) 0.095 lb/MMBtu 0.16Otoe County, NE sub-bituminuous coal 30-day rolling 24-h

MO-0060 Springfield Utilities 1 Coal-Fired PC Boiler Dry FGD 91.8% Primary = Sec

Southwest Power Station 275 MW; 2724 MMBtu/hr 0.095 lb/MMBtu none Greene County, MO 30-day rolling

WI-0228 Wisconsin Public Service Co. 1 Coal-Fired PC Boiler; supercritical Dry FGD 92% Primary = Sec

WPS - Weston Plant 500 MW; 5173 MMBtu/hr 0.10 lb/MMBtu 0.09 Marathon County, WI PRB Coal; 8100 BTU/lb 30-day avg. 12-m

UT-0065 Intermountain Power Service Corp. 1 Coal-Fired PC Boiler Wet FGD 90% Primary = Sec

Generating Station Unit #3 950 MW (gross) 0.10 lb/MMBtu 0.09 Millard County, UT Bituminous Coal or Blend 24-hr block 30-d

UT-0064 Nevco-Sevier Power Company 1 Coal-Fired CFR Boiler Dry Lime Scrubber 90% Primary = Sec

Sevier Power Plant 270 MW 0.05 lb/MMBtu 0.02Sevier County, UT 24-hr rolling 30-d

NE-0018 Hastings Utilities 1 Unit 2 Coal-Fired Boiler Spray Dryer Absorber not given Primary = Sec

Whelan Energy Center 220 MW; 2210 MMBtu/hr 0.12 lb/MMBtu 1.1 lAdams County, NE 30-day rolling 3-hr 

WV-0023 Longview Power, LLC 1 Coal-Fired PC Boiler Wet Limestone Forced Oxidation 97% Primary = Sec

Maidsville 600 MW; 6114 MMBtu/hr 0.12 lb/MMBtu 0.09Monongahela County, WV 24-hr rolling annu

SC-0104 Santee Cooper 2 Coal-Fired PC Boilers, #3 & #4 Wet FGD 95% Primary = Sec

Cross Generating Station Bituminous Coal & Pet Coke 0.13 lb/MMBtu 3250 Berkeley County, SC 5700 MMBtu/hr (each) 365-day rolling 365-

TX-0298 Reliant Energy Inc. 3 Coal Fired Boilers, Units 5 ,6, 7 Low Sulfur Coal not given Primary = Sec

WA Parish Electric Generating St. Units 5 & 6 @ 7400 mmbtu/hr 1.06, 1.2 3453Houston, TX Unit 7 @ 6700 mmbtu/hr lb/mmbtu tpy 

PA-0182 Reliant Energy Inc. 2 Refused Coal-Fired CFB Boilers Fly Ash Reinjection not given Primary = Sec

Seward Power 2532 MMBtu/hr (each) 0.60 lb/MMBtu none Indiana County, PA no avg.

AR-0074 Plum Point Associates, LLC 1 Coal-Fired PC Boiler, Unit 1 Dry FGD System not given Primary = Sec

Plum Point Energy 800 MW 0.16 lb/MMBtu none Mississippi County, AR no avg.

OH-0231 First Energy/Toledo Edison Company 1 Coal & Coke-Fired CFB Boiler Limestone Fluidized Bed not given Primary = Sec

Bayshore Plant 1764 MMBtu/hr 0.73 lb/MMBtu 554Lucas County, OH no avg. no a

Att 10-B_Coal Boilers_RBLC.xlsSO2 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for SO2Coal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

RBLC ID Emission

Limit

MT-0022 Bull Mountain Development Co. 2 Coal-Fired PC Boilers, No. 1, 2 Dry FGD System 94.5% Primary = Sec

Roundup Power Project 390 MW (each); 4013 MMBtu/hr 0.12 lb/MMBtu 481Musselshell County, MT mine-mouth plant 24-hr rolling 24-h

IA-0067 Mid-American Energy Co. 1 Coal-Fired PC Boiler Lime Spray Dryer 92% Primary = Sec

PRB coal Dry FGD 0.10 lb/MMBtu 3362 

Council Bluffs, Iowa 7675 MMBtu/hr 30-day rolling no a

TX-0358 Reliant Energy Inc. 3 Coal Fired Boilers Low Sulfur Coal not given Primary = Sec

WA Parish Electric Generating St. 2 @ 6750 mmbtu/hr 1.2, 1.2 3453

Houston, TX 1 @ 6700 mmbtu/hr lb/mmbtu tpy

KY-0084 Thoroughbred Generating Company, LLC 2 Coal-Fired PC Boilers Wet FGD & Wet ESP not given Primary = Sec

Thoroughbred Generating Station 1500 MW (total); 7446 MMBtu/hr (ea) 0.167 lb/MMBtu 0.41 Muhlenburg County, KY 30-day rolling 24-h

KS-0026 Sand Sage Power, LLC 1 Subbituminous Coal-Fired PC Boiler Dry FGD 94% Primary = Sec

Holcomb Unit #2 660 MW 0.12 lb/MMBtu none Finney County, KS no avg.

WY-0057 Black Hills Corporation 1 Subbituminous Coal-Fired PC Boiler Semi-Dry Lime SDA not given Primary = Sec

WYGEN 2 500 MW; 5146 MMBtu/hr 0.10 lb/MMBtu 0.15 Campbell County, WY 30-day rolling 3-hr 

KY-0086 East Kentucky Power Coop, Inc. 1 Coal-Fired CFB Boiler Limestone Injection plus not given Primary = Sec

Spurlock Power Station 270 MW; 2500 MMBtu/hr Dry Lime Scrubber 0.20 lb/MMBtu none Mason County, KY 24-hr block

MT-0027 Rocky Mountain Power, Inc. 1 Coal-Fired PC Boiler Wet Scrubber not given Primary = Sec

Hardin Generating Project 113 MW (nominal); 1304 MMBtu/hr 0.14 lb/MMBtu none Big Horn County, MT 30-day rolling

PA-0183 AES Beaver Valley, LLC 1 Coal-Fired CFB Boiler Hydrated Ash 95% Primary = Sec

2155 MMBtu/hr Limestone Reinjection 12-mo avg 0.14 lb/MMBtu none 

Beaver County, PA no avg.

PR-0007 AES Puerto Rico Cogeneration Plant 2 Coal-Fired CFB Boilers Limestone Injection plus not given Primary = Sec

454 MW (net); 4923 MMBtu/hr Circulating Dry Scrubber 0.022 lb/MMBtu 9.0 p

Guyama, Puerto Rico Bituminous Coal; max 1% sulfur no avg no a

LA-0122 International Paper- Mansfield Mill 2 Coal Fired Boilers Low Sulfur Coal not given Primary = Sec

774.00 1.2 

Mansfield, Louisiana 645 mmbtu/hr each lb/hr lb/m

TX-0342 Reliant Energy Inc. 2 Lignite Coal Fired Boilers Wet Limestone FGD not given Primary = Sec

Limestone Electric Generating St. 9000 lb/hr 0.82 Houston, TX 7863 mmbtu/hr each 3-hr rolling avg lb/m

Att 10-B_Coal Boilers_RBLC.xlsSO2 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for SO2Coal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

RBLC ID Emission

Limit

KY-0079 Kentucky Mountain Power, LLC 2 Coal & Coal Refuse-Fired CFB Boilers Naturally Integrated not given Primary = Sec

Units 1 & 2 Desulfurization System 0.13 lb/MMBtu none 

Knott County, KY 2550 MMBtu/hr no avg.

FL-0003 Tampa Electric Co. 1 Coal Fired Boiler Limestone Scrubber & 90% Primary = Sec

Teco- Big Bend Station Dry Bottom, Tangentially Fired Coal Washing 0.82 355

Apollo Beach, Florida 4330 mmbtu/hr lb/mmbtu lb/hr

TX-0275 Reliant Energy 1 Coal Fired Boiler, Unit 8 FGD not given Primary = Sec

 W.A. Parish Electric Generating St. 6700 mmbtu/hr 0.30 lb/MMBtu 2063 

Ft. Bend County, Texas Boiler also burns NG & Fuel Oil no avg. 3-hr 

MO-0050 Kansas City Power & Light Co. 1 Coal Fired PC Boiler Dry FGD not given Primary = Sec

Hawthorn Station Tangentially Fired 0.12 lb/MMBtu none Kansas City, Missouri 384 T/H 30-day avg

FL-0178 JEA Northside Generating St. 2 Coal Fired CFB Boilers CFB Scrubber & Fabric Filter not given Primary = Sec

297.5 MW; 2764 MMBtu/hr (each) or CFB Scrubber & SDA 0.15 lb/MMBtu 0.20 

Jacksonville, Florida 30-day avg 24-h

IL-0060 Archer Daniels Midland Co. 2 Coal Fired CFB Boilers, Units 9,10 Limestone Injection plus 92% Primary = Sec

1500 mmbtu/hr each Fabric Filter 0.70 lb/MMBtu none 

Decatur, Illinois no avg.

MS-0036 Choctaw Generation L.P 2 Lignite-Fired CFB Boilers Circulating Fluidized Bed not given Primary = Sec

Design w/Lime Injection 0.25 lb/MMBtu none 

Ackerman, Mississippi 2475.6 mmbtu/hr each no avg.

IA-0046 Archer Daniels Midland Company 2 Coal-Fired CFB Boiler, Unit #5, #6 Limestone Injection plus 92% Primary = Sec

1500 mmbtu/hr (each) CFB 0.36 lb/MMBtu none 

Linn County, IA 30-day rolling

IA-0051 Archer Daniels Midland Co. 1 Coal Fired CFB Boiler Limestone Injection plus 92% Primary = Sec

CFB 0.36 lb/MMBtu none 

Cedar Rapids, Iowa 1500 mmbtu/hr 30-day rolling

UT-0053 Deseret Generation & Transmission Co. 1 Coal-Fired PC Boiler Wet Scrubber 90.0% Primary = Sec

500 MW 0.0976 lb/MMBtu 0.15 

Unitah County, UT 12-month avg 30-d

WY-0039 Two Elk Generation Partners, Ltd. 1 Coal-Fired PC Boiler Lime Spray Dry Scrubber 91.0% Primary = Sec

Partnership 0.17 lb/MMBtu 0.20 Campbell County, WY 250 MW 30-day rolling 2-hr 

WY-0047 Encoal Corporation 1 Coal-Fired PC Boiler Lime Spray Dryer 73% Primary = Sec

North Rochelle Facility 3960 MMBtu/hr 0.20 lb/MMBtu none Campbell County, WY Subbituminous Coal 2-hr fixed

Att 10-B_Coal Boilers_RBLC.xlsSO2 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for SO2Coal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

RBLC ID Emission

Limit

FL-0177 JEA - St. John's River Power Park 1 Utility Boiler FGD Scrubbers not given Primary = Sec

100,000 lb/hr 0.676 lb/MMBtu none 

Duval County, FL up to 20% pet coke no avg

WY-0048 WYGEN, Inc. 1 Coal-Fired PC Boiler Circulating Dry Scrubber 92% Primary = Sec

WYGEN Unit #1 80 MW; 1014 MMBtu/hr 0.20 lb/MMBtu none Campbell County, WY 2-hr rolling

PA-0133 Mon Valley Energy Ltd. 1 Pulverized Coal Fired Boiler Spray Dryer Absorber 92% Primary = Sec

Partnership 0.25 874 

Poland Mines, Pennsylvania 966 mmbtu/hr lb/mmbtu tpy

PA-0132 York County Energy Partners 1 Coal Fired CFB Boiler Limestone Injection System 92% Primary = Sec

Spring Grove, Pennsylvania 0.25 660 

2500 mmbtu/hrR lb/mmbtu lb/hr

UT-0060 Deseret Generation & 1 Coal Fired Boiler Scrubber 90% Primary = Sec

Transmission Co. 0.1 lb/mmbtu 0.15 Vernaz, Utah 4381 mmbtu/hr 12-mo. avg 1-m

PA-0134 Northampton Generating Co. 1 Coal Fired CFB Boiler Limestone Injection System 92% Primary = Sec

0.129 602 

Northampton, Pennsylvania 1146 mmbtu/hr lb/mmbtu tpy

IL-0058 Archer Daniels Midland Co. 2 Coal Fired CFB Boilers Limestone Injection System 90% 0.7 lb/m

1500 mmbtu/hr 

Decatur, Illinois 750 mmbtu/hr

MA-0028 Energy New Bedford 2 Coal Fired CFB Boilers Limestone Injection System 70% Primary = Sec

0.23 403

New Bedford, Massachusetts 1671 mmbtu/hr each lb/mmbtu lb/hr

MD-0022 AES Warrior Run, Inc. 1 Coal Fired Atmospheric Limestone Injection System 95% 0.16 lb/m

CFB Boiler 

Cumberland, Maryland 2070 mmbtu/hr

FL-0255 Cedar Bay Generating Co., LP 3 Pulverized Coal Fired CFB Boilers Limestone Injection System not given Primary = Sec

Ceder Bay Cogeneration 0.3 lb/mmbtu 318Jacksonville, Florida 132 mmbtu/hr each 3- hr rolling 3- h

Notes:NSR RACT/BACT/LAER Clearinghouse Database (http://cfpub.epa.gov/rblc) was queried for the following:- RBLC Determinations added during or after January 1996- Process Type Code: 11.110 - Coal Combustion for Utility Boilers

Att 10-B_Coal Boilers_RBLC.xlsSO2 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for VOCCoal Fired Boilers

Company Name No. of Unit & Control Control Pe

and Location Units Size Technology Efficiency 

MO-0071 Great Plains Energy 2 Coal-Fired Boiler - Unit 1 Good Combustion Practices n/a Primary = Secondary= 

Iatan Station 7800 MMBtu/hr 0.0036 lb/MMBtu none listed 0Platte County, MO sub-bituminuous coal no avg

VA-0296 Virginia Polytechnical Institute & 1 Stoker Fired Boiler - Boiler 11 Good Combustion Practice not given Primary = Secondary= 

State University 146.7 MMBtu/hr 0.002 0.3 Montgomery County, VA lb/MMBtu lb/hr

LA-0176 Louisiana Generating, LLC 1 Coal-Fired PC Boiler, Unit 4 Good Combustion Practices not given Primary = Secondary= 

Big Cajun II Power Plant 675 MW; supercritical boiler 0.015 lb/MMBtu 98.5 lb/hr PPointe Coupee County, LA sub-bituminuous coal annual avg

PA-0249 River Hill Power Company, LLC 1 Waste Coal-Fired CFB Boiler Combustion Control not given Primary = Secondary= 

Clearfield County, PA 0.005 lb/MMBtu 14.36 lb/hr 

no avg no avg

PA-0248 Wellington Dev/Greene Energy 2 Waste Coal-Fired CFB Boilers SNCR 40% Primary = Secondary= 

Resource Recovery Project 580 MW (gross) 525 MW (net) Good Combustion Practice 0.005 lb/MMBtu 121 tpy Greene County, PA no avg 12-month rolling

CO-0057 Xcel Energy (PSC of Colorado) 1 Coal-Fired PC Boiler, Unit #3 Good Combustion Practices not given Primary = Secondary= 

Comanche Power Station 750 MW (unit #3); 7421 MMBtu/hr 0.0035 lb/MMBtu none listed 04Pueblo, CO sub-bituminuous coal 3 test run avg.

ND-0021 Montana Dakota Utilities/Westmoreland 1 Lignite Fired CFB Boiler Good Combustion Practices not given Primary = Secondary= 

Gascoyne Generating Station 220 MW (gross) 175 MW (net) 0.005 lb/MWh none listed Bowman County, ND 3-hr avg

PA-0247 Robinson Power Company LLC 1 Waste Coal-Fired CFB Boiler Combustion Optimization not given Primary = Secondary= 

Beech Hollow Power Project 272 MW (net); 2800 MMBtu/hr 0.006 lb/MMBtu 72.9 tpy Washington County, PA no avg. no avg

NE-0031 Omaha Public Power District 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

Nebraska City Station Unit 2 boiler 660 MW (net) 0.0034 lb/MMBtu none listed 

Otoe County, NE sub-bituminuous coal test avg

MO-0060 Springfield Utilities 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

Southwest Power Station 275 MW; 2724 MMBtu/hr 0.0036 lb/MMBtu none listed 1Greene County, MO no avg.

WI-0228 Wisconsin Public Service Co. 1 Coal-Fired PC Boiler; supercritical Good Combustion Practices not given Primary = Secondary= 

WPS - Weston Plant 500 MW; 5173 MMBtu/hr 0.0036 lb/MMBtu 81.6 ton/yr Marathon County, WI PRB Coal; 8100 BTU/lb 24-hr avg. 12-mo rolling

UT-0065 Intermountain Power Service Corp. 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

Generating Station Unit #3 950 MW (gross) 0.0027 lb/MMBtu none listed DAQE

Millard County, UT Bituminous Coal or Blend 3 test run avg.

GA-0114 Temple-Inland Inc. 1 Coal-Fired Boiler Good Combustion Practices not given Primary = Secondary= 

Rome Linerboard Mill 565 MMBtu/hr 0.01 lb/MMBtu none listed 2631-Floyd County, GA no avg.

RBLC ID Emission

Limit

Att 10-B_Coal Boilers_RBLC.xlsVOC 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for VOCCoal Fired Boilers

Company Name No. of Unit & Control Control Pe

and Location Units Size Technology Efficiency 

RBLC ID Emission

Limit

OK-0103 Weyerhaeuser 1 Coal-Fired CFB Boiler Good Combustion Practices not given Primary = Secondary= 

Valliant Mill 0.005 lb/MMBtu none listed 97-05

McCurtain County, OK monthly avg

WV-0023 Longview Power, LLC 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

Maidsville 600 MW; 6114 MMBtu/hr 0.004 lb/MMBtu 24.5 lb/hr Monongahela County, WV 3-hr rolling no avg

SC-0104 Santee Cooper 2 Coal-Fired PC Boilers, #3 & #4 Good Combustion Practices not given Primary = Secondary= 

Cross Generating Station Bituminous Coal & Pet Coke 0.0024 lb/MMBtu none listed 0Berkeley County, SC 5700 MMBtu/hr (each) no avg.

PA-0182 Reliant Energy Inc. 2 Refused Coal-Fired CFB Boilers Good Combustion Practices not given Primary = Secondary= 

Seward Power 2532 MMBtu/hr (each) 0.005 lb/MMBtu none listed PIndiana County, PA no avg.

AR-0074 Plum Point Associates, LLC 1 Coal-Fired PC Boiler, Unit 1 Combustion Control not given Primary = Secondary= 

Plum Point Energy 800 MW 0.02 lb/MMBtu none listed 19

Mississippi County, AR no avg.

OH-0231 First Energy/Toledo Edison Company 1 Coal & Coke-Fired CFB Boiler Good Combustion Practices not given Primary = Secondary= 

Bayshore Plant 1764 MMBtu/hr 4.4 lb/hr 19.3 tpy Lucas County, OH no avg. no avg

MT-0022 Bull Mountain Development Co. 2 Coal-Fired PC Boilers, No. 1, 2 Good Combustion Practices not given Primary = Secondary= 

Roundup Power Project 390 MW (each); 4013 MMBtu/hr 0.003 lb/MMBtu 12 lb/hr Musselshell County, MT mine-mouth plant no avg.

IA-0067 Mid-American Energy Co. 1 Coal-Fired PC Boiler Combustion Control not given Primary = Secondary= 

PRB coal 0.0036 lb/MMBtu 121 tpy P

Council Bluffs, Iowa 7675 MMBtu/hr 1-hr avg no avg

KY-0084 Thoroughbred Generating Company, LLC 2 Coal-Fired PC Boilers Good Combustion Practices not given Primary = Secondary= 

Thoroughbred Generating Station 1500 MW (total); 7446 MMBtu/hr (ea) 0.0072 lb/MMBtu none listed Muhlenburg County, KY 30-day rolling

KS-0026 Sand Sage Power, LLC 1 Subbituminous Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

Holcomb Unit #2 660 MW 0.0035 lb/MMBtu none listed 055

Finney County, KS no avg.

WY-0057 Black Hills Corporation 1 Subbituminous Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

WYGEN 2 500 MW; 5146 MMBtu/hr 0.01 lb/MMBtu none listed Campbell County, WY no avg.

KY-0086 East Kentucky Power Coop, Inc. 1 Coal-Fired CFB Boiler Proper Boiler Design & Operation not given Primary = Secondary= 

Spurlock Power Station 270 MW; 2500 MMBtu/hr 0.0036 lb/MMBtu none listed VMason County, KY 30-day avg

MT-0027 Rocky Mountain Power, Inc. 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

Hardin Generating Project 113 MW (nominal); 1304 MMBtu/hr 0.0034 lb/MMBtu none listed Big Horn County, MT no avg.

PA-0183 AES Beaver Valley, LLC 1 Coal-Fired CFB Boiler Good Combustion Practices not given Primary = Secondary= 

2155 MMBtu/hr 0.0068 lb/MMBtu none listed P

Beaver County, PA no avg.

Att 10-B_Coal Boilers_RBLC.xlsVOC 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for VOCCoal Fired Boilers

Company Name No. of Unit & Control Control Pe

and Location Units Size Technology Efficiency 

RBLC ID Emission

Limit

PR-0007 AES Puerto Rico Cogeneration Plant 2 Coal-Fired CFB Boilers Good Combustion Practices not given Primary = Secondary= 

454 MW (net); 4923 MMBtu/hr 0.0047 lb/MMBtu 7.7 ppmvd@7% 

Guyama, Puerto Rico Bituminous Coal; max 1% sulfur no avg no avg

KY-0079 Kentucky Mountain Power, LLC 2 Coal & Coal Refuse-Fired CFB Boilers Good Combustion Practices not given Primary = Secondary= 

Units 1 & 2 0.0072 lb/MMBtu none listed 

Knott County, KY 2550 MMBtu/hr no avg.

TX-0275 Reliant Energy 1 Coal Fired Boiler, Unit 8 Good Combustion Practices not given Primary = Secondary= 

 W.A. Parish Electric Generating St. 6700 mmbtu/hr 20.1 lb/hr 52.8 tpy P

Ft. Bend County, Texas Boiler also burns NG & Fuel Oil no avg. no avg

MO-0050 Kansas City Power & Light Co. 1 Coal Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

Hawthorn Station Tangentially Fired 0.0036 lb/MMBtu none listed Kansas City, Missouri 384 T/H no avg.

FL-0178 JEA Northside Generating St. 2 Coal Fired CFB Boilers Good Combustion Practices not given Primary = Secondary= 

297.5 MW; 2764 MMBtu/hr (each) 0.005 lb/MMBtu 14.0 lb/hr P

Jacksonville, Florida no avg. 3-hr avg

IL-0060 Archer Daniels Midland Co. 2 Coal Fired CFB Boilers, Units 9,10 Good Combustion Practices not given Primary = Secondary= 

1500 mmbtu/hr each 0.032 lb/MMBtu none listed 

Decatur, Illinois no avg.

IA-0046 Archer Daniels Midland Company 2 Coal-Fired CFB Boiler, Unit #5, #6 Good Combustion Practices not given Primary = Secondary= 

1500 mmbtu/hr (each) 0.0072 lb/MMBtu none listed 

Linn County, IA 3-hr avg

IA-0051 Archer Daniels Midland Co. 1 Coal Fired CFB Boiler Good Combustion Practices not given Primary = Secondary= 

0.0072 lb/MMBtu none listed 

Cedar Rapids, Iowa 1500 mmbtu/hr 3-hr avg

PA-0204 Kimberly- Clark Tissue Co. 3 Coal Fired CFB & 2 Vertical Boilers None Indicated not given Primary = Secondary= 

Kimberly- Clark/Chester Plant 799 mmbtu/hr, 249 mmbtu/hr & 0.006 lb/MMBtu 30 tpy total Chester, Pennsylvania 198 mmbtu/hr (respectively) no avg. rolling avg

UT-0053 Deseret Generation & Transmission Co. 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

500 MW 70.89 tpy none listed D

Unitah County, UT no avg.

WY-0039 Two Elk Generation Partners, Ltd. 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

Partnership 0.015 lb/MMBtu none listed 

Campbell County, WY 250 MW no avg.

WY-0047 Encoal Corporation 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

North Rochelle Facility 240 MW 0.05 lb/MMBtu none listed 

Campbell County, WY no avg.

WY-0047 Encoal Corporation 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

North Rochelle Facility 3960 MMBtu/hr 0.05 lb/MMBtu none listed 

Campbell County, WY Subbituminous Coal no avg.

Att 10-B_Coal Boilers_RBLC.xlsVOC 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for VOCCoal Fired Boilers

Company Name No. of Unit & Control Control Pe

and Location Units Size Technology Efficiency 

RBLC ID Emission

Limit

WY-0048 WYGEN, Inc. 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 

WYGEN Unit #1 80 MW; 1014 MMBtu/hr 0.015 lb/MMBtu none listed Campbell County, WY no avg.

PA-0133 Mon Valley Energy Ltd. 1 Pulverized Coal Fired Boiler No Controls Feasible not given Primary = Secondary= 

Partnership 0.01 42.3 3

Poland Mines, Pennsylvania 966 mmbtu/hr lb/mmbtu tpy

PA-0132 York County Energy Partners 1 Coal Fired CFB Boiler Combustion Control not given Primary = Secondary= 

Spring Grove, Pennsylvania 0.004 50 6

2500 mmbtu/hrR lb/mmbtu tpy

PA-0134 Northampton Generating Co. 1 Ahlstrom Coal Fired CFB Boiler No Controls Feasible not given Primary = Secondary= 

0.005 23.4 

Northampton, Pennsylvania 1146 mmbtu/hr lb/mmbtu tpy

IL-0058 Archer Daniels Midland Co. 2 Coal Fired CFB Boilers Good Combustion Practice not given 0.032 lb/mmbtu 

1500 mmbtu/hr 

Decatur, Illinois 750 mmbtu/hr

MA-0028 Energy New Bedford 2 Coal Fired CFB Boilers Combustion Control not given Primary = Secondary= 

10.55 0.006 

New Bedford, Massachusetts 1671 mmbtu/hr each lb/hr lb/mmbtu

Notes:NSR RACT/BACT/LAER Clearinghouse Database (http://cfpub.epa.gov/rblc) was queried for the following:- RBLC Determinations added during or after January 1996- Process Type Code: 11.110 - Coal Combustion for Utility Boilers

Att 10-B_Coal Boilers_RBLC.xlsVOC 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for PMCoal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

WY-0063 Black Hills Corporation 1 Coal-Fired PC Boiler Baghouse not given Primary = 

WYGEN 3 1300 MMBtu/hr; 100 MW 0.012 lb/MMBtu Campbell County, WY sub-bituminuous coal test avg (F only)

VA-0296 Virginia Polytechnical Institute & 1 Stoker Fired Boiler - Boiler 11 Baghouse not given Primary = 

State University 146.7 MMBtu/hr 0.02 lb/MMBtu Montgomery County, VA

CO-0057 Xcel Energy (PSC of Colorado) 1 Coal-Fired PC Boiler, Unit #3 Baghouse not given Primary = 

Comanche Power Station 750 MW (unit #3); 7421 MMBtu/hr 0.013 lb/MMBtu Pueblo, CO sub-bituminuous coal F only 

ND-0021 Montana Dakota Utilities/Westmoreland 1 Lignite Fired CFB Boiler Baghouse not given Primary = 

Gascoyne Generating Station 220 MW (gross) 175 MW (net) 0.0167 lb/MMBtu Bowman County, ND 3-hr avg (F only)

NE-0031 Omaha Public Power District 1 Coal-Fired PC Boiler Baghouse 99.9% Primary = 

Nebraska City Station Unit 2 boiler 660 MW (net) 0.018 lb/MMBtu 

Otoe County, NE sub-bituminuous coal test avg

WI-0228 Wisconsin Public Service Co. 1 Coal-Fired PC Boiler; supercritical Fabric Filter not given Primary = 

WPS - Weston Plant 500 MW; 5173 MMBtu/hr includes back-half 0.020 lb/MMBtu Marathon County, WI PRB Coal; 8100 BTU/lb 3-hr avg 

UT-0065 Intermountain Power Service Corp. 1 Coal-Fired PC Boiler Fabric Filter not given Primary = 

Generating Station Unit #3 950 MW (gross) 0.013 lb/MMBtu Millard County, UT Bituminous Coal or Blend 3 test run avg.

WV-0023 Longview Power, LLC 1 Coal-Fired PC Boiler Fabric Filter 99.0% Primary = 

Maidsville 600 MW; 6114 MMBtu/hr 0.018 lb/MMBtu Monongahela County, WV 6-hr rolling 

SC-0104 Santee Cooper 2 Coal-Fired PC Boilers, #3 & #4 ESP not given Primary = 

Cross Generating Station Bituminous Coal & Pet Coke 0.015 lb/MMBtu Berkeley County, SC 5700 MMBtu/hr (each) no avg.

TX-0298 Reliant Energy Inc. 3 Coal Fired Boilers, Units 5 ,6, 7 Combustion Control not given Primary = 

WA Parish Electric Generating St. Units 5 & 6 @ 7400 mmbtu/hr 0.088, 0.085 Houston, TX Unit 7 @ 6700 mmbtu/hr lb/mmbtu 

OH-0231 First Energy/Toledo Edison Company 1 Coal & Coke-Fired CFB Boiler Baghouse 99.0% Primary = 

Bayshore Plant 1764 MMBtu/hr 0.03 lb/MMBtu Lucas County, OH no avg. 

RBLC ID Em

L

Att 10-B_Coal Boilers_RBLC.xlsPM 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for PMCoal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

RBLC ID Em

L

IA-0067 Mid-American Energy Co. 1 Coal-Fired PC Boiler Baghouse 99.7% Primary = 

PRB coal 0.018 lb/MMBtu 

Council Bluffs, Iowa 7675 MMBtu/hr no avg.

KY-0084 Thoroughbred Generating Company, LLC 2 Coal-Fired PC Boilers ESP & Wet ESP 99.0% Primary = 

Thoroughbred Generating Station 1500 MW (total); 7446 MMBtu/hr (ea) 0.018 lb/MMBtu Muhlenburg County, KY 3-hr avg

WY-0057 Black Hills Corporation 1 Subbituminous Coal-Fired PC Boiler Fabric Filter not given Primary = 

WYGEN 2 500 MW; 5146 MMBtu/hr 0.012 lb/MMBtu Campbell County, WY no avg.

TX-0342 Reliant Energy Inc. 2 Lignite Coal Fired Boilers Cold Side ESP not given Primary = 

Limestone Electric Generating St. 0.03 

Houston, TX 7863 mmbtu/hr each lb/mmbtu 

KY-0079 Kentucky Mountain Power, LLC 2 Coal & Coal Refuse-Fired CFB Boilers Baghouse 99% Primary = 

Units 1 & 2 0.015 lb/MMBtu 

Knott County, KY 2550 MMBtu/hr no avg.

FL-0003 Tampa Electric Co. 1 Coal Fired Boiler ESP 99% Primary = 

Teco- Big Bend Station Dry Bottom, Tangentially Fired 0.03 Apollo Beach, Florida 4330 mmbtu/hr lb/mmbtu 

IL-0060 Archer Daniels Midland Co. 2 Coal Fired CFB Boilers, Units 9,10 Fabric Filter 99% Primary = 

1500 mmbtu/hr each 0.025 lb/MMBtu 

Decatur, Illinois no avg.

IA-0046 Archer Daniels Midland Company 2 Coal-Fired CFB Boiler, Unit #5, #6 Baghouse 99% Primary = 

1500 mmbtu/hr (each) 0.015 lb/MMBtu 

Linn County, IA 3-hr avg

IA-0051 Archer Daniels Midland Co. 1 Coal Fired CFB Boiler Baghouse 99% Primary = 

0.015 lb/MMBtu 

Cedar Rapids, Iowa 1500 mmbtu/hr 3-hr avg

MT-0009 Colstrip Energy L.P. 1 Coal-Fired CFB Boiler Baghouse 99.9% Primary = 

503 MMBtu/hr 0.03 lb/MMBtu 

Rosebud County, MT no avg. 

Att 10-B_Coal Boilers_RBLC.xlsPM 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for PMCoal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

RBLC ID Em

L

WY-0039 Two Elk Generation Partners, Ltd. 1 Coal-Fired PC Boiler Baghouse 99.5% Primary = 

Partnership 0.02 lb/MMBtu 

Campbell County, WY 250 MW no avg.

WY-0047 Encoal Corporation 1 Coal-Fired PC Boiler Baghouse 99% Primary = 

North Rochelle Facility 3960 MMBtu/hr 0.020 lb/MMBtu Campbell County, WY Subbituminous Coal no avg.

WY-0048 WYGEN, Inc. 1 Coal-Fired PC Boiler ESP 99% Primary = 

WYGEN Unit #1 80 MW; 1014 MMBtu/hr 0.020 lb/MMBtu Campbell County, WY no avg.

IL-0058 Archer Daniels Midland Co. 2 Coal Fired CFB Boilers Fabric Filter 99% 0.025 

1500 mmbtu/hr 

Decatur, Illinois 750 mmbtu/hr

MD-0022 AES Warrior Run, Inc. 1 Coal Fired Atmospheric CFB Boiler Fabric Filter not given 0.015 

Cumberland, Maryland 2070 mmbtu/hr

FL-0255 Cedar Bay Generating Co., LP 3 Pulverized Coal Fired CFB Boilers Fabric Baghouse not given Primary = 

Ceder Bay Cogeneration 0.018 Jacksonville, Florida 132 mmbtu/hr each lb/mmbtu 

Notes:NSR RACT/BACT/LAER Clearinghouse Database (http://cfpub.epa.gov/rblc) was queried for the following:- RBLC Determinations added during or after January 1996- Process Type Code: 11.110 - Coal Combustion for Utility Boilers

Att 10-B_Coal Boilers_RBLC.xlsPM 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for PM10Coal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

MO-0071 Great Plains Energy 2 Coal-Fired Boiler - Unit 1 Baghouse 99.50% Primary = Secondary= 

Iatan Station 7800 MMBtu/hr 0.0244 lb/MMBtu 0.014 lb/MMBtu Platte County, MO sub-bituminuous coal 30-day rolling (F & C) 3-hr (F only)

CO-0055 Lamar Utilities Board DBA 1 Coal-Fired CFB Boiler Baghouse 99.78% Primary = Secondary= 

Lamar Light & Power Plant 501.7 MMBtu/hr 0.012 lb/MMBtu 10% opacity Powers County, CO sub-bit or bituminous coal duration of tests 6-min avg

VA-0296 Virginia Polytechnical Institute & 1 Stoker Fired Boiler - Boiler 11 Baghouse not given Primary = Secondary= 

State University 146.7 MMBtu/hr 0.018 2.6 Montgomery County, VA lb/MMBtu lb/hr

LA-0176 Louisiana Generating, LLC 1 Coal-Fired PC Boiler, Unit 4 ESP& Baghouse 99.9% Primary = Secondary= 

Big Cajun II Power Plant 675 MW; supercritical boiler in series 0.015 lb/MMBtu 98.5 lb/hr Pointe Coupee County, LA sub-bituminuous coal annual avg

PA-0249 River Hill Power Company, LLC 1 Waste Coal-Fired CFB Boiler Baghouse not given Primary = Secondary= 

Clearfield County, PA 0.012 lb/MMBtu 34.45 lb/hr 

no avg no avg

PA-0248 Wellington Dev/Greene Energy 2 Waste Coal-Fired CFB Boilers Baghouse 99.0% Primary = Secondary= 

Resource Recovery Project 580 MW (gross) 525 MW (net) 0.012 lb/MMBtu 289.7 tpy Greene County, PA no avg 12-month rolling

CO-0057 Xcel Energy (PSC of Colorado) 1 Coal-Fired PC Boiler, Unit #3 Baghouse not given Primary = Secondary= 

Comanche Power Station 750 MW (unit #3); 7421 MMBtu/hr 0.012 lb/MMBtu 0.020 lb/MMBtu Pueblo, CO sub-bituminuous coal F only F+C

ND-0021 Montana Dakota Utilities/Westmoreland 1 Lignite Fired CFB Boiler Baghouse 99.91% Primary = Secondary= 

Gascoyne Generating Station 220 MW (gross) 175 MW (net) 0.013 lb/MMBtu 0.0275 lb/MMBtu Bowman County, ND 3-hr avg (F only) (both F & C)

NV-0036 Newmont Nevada Energy Investment LLC 1 Coal-Fired PC Boiler Baghouse not given Primary = Secondary= 

TS Power Plant 200 MW; 2030 MMBtu/hr 0.12 lb/MMBtu none listed Eureka County, NV 24-hr rolling (F only)

PA-0247 Robinson Power Company LLC 1 Waste Coal-Fired CFB Boiler Baghouse 99.9% Primary = Secondary= 

Beech Hollow Power Project 272 MW (net); 2800 MMBtu/hr 0.012 lb/MMBtu 147.2 tpy Washington County, PA no avg. no avg

MO-0060 Springfield Utilities 1 Coal-Fired PC Boiler Baghouse 99.90% Primary = Secondary= 

Southwest Power Station 275 MW; 2724 MMBtu/hr 0.018 lb/MMBtu none listed Greene County, MO no avg.

WI-0228 Wisconsin Public Service Co. 1 Coal-Fired PC Boiler; supercritical Fabric Filter not given Primary = Secondary= 

WPS - Weston Plant 500 MW; 5173 MMBtu/hr includes back-half 0.018 lb/MMBtu none listed Marathon County, WI PRB Coal; 8100 BTU/lb 3-hr avg

UT-0065 Intermountain Power Service Corp. 1 Coal-Fired PC Boiler Fabric Filter 99.85% Primary = Secondary= 

Generating Station Unit #3 950 MW (gross) 0.012 lb/MMBtu 221 lb/hr Millard County, UT Bituminous Coal or Blend 3 test run avg. 24-hr block

RBLC ID Emission

Limit

Att 10-B_Coal Boilers_RBLC.xlsPM10 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for PM10Coal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

RBLC ID Emission

Limit

GA-0114 Temple-Inland Inc. 1 Coal-Fired Boiler ESP not given Primary = Secondary= 

Rome Linerboard Mill 565 MMBtu/hr 0.05 lb/MMBtu none listed 2Floyd County, GA no avg.

UT-0064 Nevco-Sevier Power Company 1 Coal-Fired CFR Boiler Fabric Filter 99.9% Primary = Secondary= 

Sevier Power Plant 270 MW 39 lb/hr 10% opacity Sevier County, UT 24-hr rolling

WV-0023 Longview Power, LLC 1 Coal-Fired PC Boiler Fabric Filter 99.0% Primary = Secondary= 

Maidsville 600 MW; 6114 MMBtu/hr 0.018 lb/MMBtu 110 lb/hr Monongahela County, WV 6-hr rolling (both F&C) no avg

SC-0104 Santee Cooper 2 Coal-Fired PC Boilers, #3 & #4 ESP not given Primary = Secondary= 

Cross Generating Station Bituminous Coal & Pet Coke 0.018 lb/MMBtu none listed Berkeley County, SC 5700 MMBtu/hr (each) no avg. (both F&C implied)

TX-0358 Reliant Energy Inc. 3 Coal Fired Boilers, Units 5 ,6, 7 Combustion Control not given Primary = Secondary= 

WA Parish Electric Generating St. Units 5 & 6 @ 7400 mmbtu/hr 0.097, .086 2878, 2509 Houston, TX Unit 7 @ 6700 mmbtu/hr lb/mmbtu tpy

PA-0182 Reliant Energy Inc. 2 Refused Coal-Fired CFB Boilers Fabric Filter not given Primary = Secondary= 

Seward Power 2532 MMBtu/hr (each) 0.010 lb/MMBtu none listed Indiana County, PA no avg.

AR-0074 Plum Point Associates, LLC 1 Coal-Fired PC Boiler, Unit 1 Fabric Filter not given Primary = Secondary= 

Plum Point Energy 800 MW 0.018 lb/MMBtu none listed Mississippi County, AR no avg.

OH-0231 First Energy/Toledo Edison Company 1 Coal & Coke-Fired CFB Boiler Baghouse 99.0% Primary = Secondary= 

Bayshore Plant 1764 MMBtu/hr 0.025 lb/MMBtu 193 tpy Lucas County, OH no avg. no avg

MT-0022 Bull Mountain Development Co. 2 Coal-Fired PC Boilers, No. 1, 2 fabric Filter 99.82% Primary = Secondary= 

Roundup Power Project 390 MW (each); 4013 MMBtu/hr 0.015 lb/MMBtu limit may change to Musselshell County, MT mine-mouth plant no avg. 0.012 lb/MMBtu

IA-0067 Mid-American Energy Co. 1 Coal-Fired PC Boiler Baghouse 98.2% Primary = Secondary= 

PRB coal 0.025 lb/MMBtu none listed 

Council Bluffs, Iowa 7675 MMBtu/hr no avg. (both F&C)

KS-0026 Sand Sage Power, LLC 1 Subbituminous Coal-Fired PC Boiler Fabric Filter 99.71% Primary = Secondary= 

Holcomb Unit #2 660 MW 0.018 lb/MMBtu none listed Finney County, KS no avg.

KY-0086 East Kentucky Power Coop, Inc. 1 Coal-Fired CFB Boiler Baghouse not given Primary = Secondary= 

Spurlock Power Station 270 MW; 2500 MMBtu/hr 0.015 lb/MMBtu none listed Mason County, KY 3-hr avg

Att 10-B_Coal Boilers_RBLC.xlsPM10 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for PM10Coal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

RBLC ID Emission

Limit

MT-0027 Rocky Mountain Power, Inc. 1 Coal-Fired PC Boiler Multiclone w/ not given Primary = Secondary= 

Hardin Generating Project 113 MW (nominal); 1304 MMBtu/hr Wet Scrubber 0.015 lb/MMBtu none listed Big Horn County, MT no avg (Method 5)

PA-0183 AES Beaver Valley, LLC 1 Coal-Fired CFB Boiler Baghouse not given Primary = Secondary= 

2155 MMBtu/hr 0.02 lb/MMBtu none listed 

Beaver County, PA no avg.

PR-0007 AES Puerto Rico Cogeneration Plant 2 Coal-Fired CFB Boilers ESP not given Primary = Secondary= 

454 MW (net); 4923 MMBtu/hr 0.03 b/MMBtu 73.8 lb/hr 

Guyama, Puerto Rico Bituminous Coal; max 1% sulfur no avg no avg

LA-0122 International Paper- Mansfield Mill 2 Coal Fired Boilers ESP 99.50% 0.10 lb/mmbtu 

Mansfield, Louisiana 645 mmbtu/hr each

TX-0275 Reliant Energy 1 Coal Fired Boiler Fabric Filter not given 0.03 lb/mmbtu 

 W.A. Parish Electric Generating St. Thompsons, Texas 6700 mmbtu/hr

TX-0275 Reliant Energy 1 Coal Fired Boiler, Unit 8 Fabric Filter not given Primary = Secondary= 

 W.A. Parish Electric Generating St. 6700 mmbtu/hr 0.03 lb/MMBtu 639 tpy Ft. Bend County, Texas Boiler also burns NG & Fuel Oil no avg. no avg

MO-0050 Kansas City Power & Light Co. 1 Coal Fired PC Boiler Fabric Filter not given Primary = Secondary= 

Hawthorn Station Tangentially Fired 0.018 lb/MMBtu none listed Kansas City, Missouri 384 T/H no avg

FL-0178 JEA Northside Generating St. 2 Coal Fired CFB Boilers Fabric Filter not given Primary = Secondary= 

297.5 MW; 2764 MMBtu/hr (each) or ESP 0.011 lb/MMBtu none listed 

Jacksonville, Florida 3-hr avg (F only)

MS-0036 Choctaw Generation L.P 2 Lignite-Fired CFB Boilers Baghouse not given Primary = Secondary= 

0.015 lb/MMBtu none listed 

Ackerman, Mississippi 2475.6 mmbtu/hr each no avg.

IA-0046 Archer Daniels Midland Company 2 Coal-Fired CFB Boiler, Unit #5, #6 Baghouse not given Primary = Secondary= 

1500 mmbtu/hr (each) 0.030 lb/MMBtu none listed 

Linn County, IA 3-hr avg (F&C implied)

IA-0051 Archer Daniels Midland Co. 1 Coal Fired CFB Boiler Baghouse not given Primary = Secondary= 

0.030 lb/MMBtu none listed 

Cedar Rapids, Iowa 1500 mmbtu/hr 3-hr avg (F&C implied)

Att 10-B_Coal Boilers_RBLC.xlsPM10 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for PM10Coal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

RBLC ID Emission

Limit

UT-0053 Deseret Generation & Transmission Co. 1 Coal-Fired PC Boiler Fabric Filter 99.8% Primary = Secondary= 

500 MW 0.286 lb/MMBtu 0.018 gr/dscf 

Unitah County, UT no avg. no avg

FL-0193 Central Power and Lime, Inc. 1 Coal Fired Boiler Good Combustion not given Primary = Secondary= 

Practice 0.0135 25 

Brooksville, Florida 1850 mmbtu/hr lb/mmbtu lb/hr

PA-0133 Mon Valley Energy Ltd. 1 Pulverized Coal Fired Boiler Fabric Filter 99.95% Primary = Secondary= 

Partnership 0.015 63.5 Poland Mines, Pennsylvania 966 mmbtu/hr lb/mmbtu tpy

PA-0132 York County Energy Partners 1 Coal Fired CFB Boiler Fabric Filter 99.90% Primary = Secondary= 

Spring Grove, Pennsylvania 0.011 29 

2500 mmbtu/hrR lb/mmbtu lb/hr

UT-0060 Deseret Generation & 1 Coal Fired Boiler Fabric Filter not given 0.03 lb/mmbtu 

Transmission Co. Vernaz, Utah 4381 mmbtu/hr

PA-0134 Northampton Generating Co. 1 Ahlstrom Coal Fired CFB Boiler Fabric Filter 99.98% Primary = Secondary= 

0.01 44.4 

Northampton, Pennsylvania 1146 mmbtu/hr lb/mmbtu tpy

MA-0028 Energy New Bedford 2 Coal Fired CFB Boilers Baghouse not given Primary = Secondary= 

0.018 31.6 

New Bedford, Massachusetts 1671 mmbtu/hr each lb/mmbtu lb/hr

Notes:NSR RACT/BACT/LAER Clearinghouse Database (http://cfpub.epa.gov/rblc) was queried for the following:- RBLC Determinations added during or after January 1996- Process Type Code: 11.110 - Coal Combustion for Utility Boilers

Att 10-B_Coal Boilers_RBLC.xlsPM10 
Attachment 10-B

Recently Issued PSD Permits not listed in Clearinghouse DatabaseBACT-PSD Sources for H2SO4Coal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

PA-0249 River Hill Power Company, LLC 1 Waste Coal-Fired CFB Boiler Dry FGD System not given Primary = Seco

Clearfield County, PA 0.010 lb/MMBtu 28.7

no avg no a

PA-0248 Wellington Dev/Greene Energy 2 Waste Coal-Fired CFB Boilers Limestone Injection not given Primary = Seco

Resource Recovery Project 580 MW (gross) 525 MW (net) in CFB 0.006 lb/MMBtu none Greene County, PA no avg

CO-0057 Xcel Energy (PSC of Colorado) 1 Coal-Fired PC Boiler, Unit #3 Lime Spray Dryer & 96% Primary = Seco

Comanche Power Station 750 MW (unit #3); 7421 MMBtu/hr Baghouse 0.0042 lb/MMBtu none Pueblo, CO sub-bituminuous coal 3 test run avg

ND-0021 Montana Dakota Utilities/Westmoreland 1 Lignite Fired CFB Boiler Limestone Injection plus not given Primary = Seco

Gascoyne Generating Station 220 MW (gross) 175 MW (net) Spray Dryer 0.0061 lb/MMBtu none Bowman County, ND 3-hr rolling

NV-0036 Newmont Nevada Energy Investment LLC 1 Coal-Fired PC Boiler Spray Dry Scrubber & not given Primary = Seco

TS Power Plant 200 MW; 2030 MMBtu/hr Baghouse 2.06 lbs/hr none Eureka County, NV no avg

NE-0031 Omaha Public Power District 1 Coal-Fired PC Boiler Dry FGD & Fabric Filter 90% Primary = Seco

Nebraska City Station Unit 2 boiler 660 MW (net) 0.0042 lb/MMBtu none Otoe County, NE sub-bituminuous coal test avg

MO-0060 Springfield Utilities 1 Coal-Fired PC Boiler Dry FGD not given Primary = Seco

Southwest Power Station 275 MW; 2724 MMBtu/hr none listed none Greene County, MO

WI-0228 Wisconsin Public Service Co. 1 Coal-Fired PC Boiler; supercritical Dry FGD not given Primary = Seco

WPS - Weston Plant 500 MW; 5173 MMBtu/hr 0.0050 lb/MMBtu none Marathon County, WI PRB Coal; 8100 BTU/lb 24-hr avg

UT-0065 Intermountain Power Service Corp. 1 Coal-Fired PC Boiler Wet FGD & Baghouse 90% Primary = Seco

Generating Station Unit #3 950 MW (gross) 0.0044 lb/MMBtu none Millard County, UT Bituminous Coal or Blend 24-hr block

OK-0103 Weyerhaeuser 1 Coal-Fired CFB Boiler CFB with 90% Primary = Seco

Valliant Mill also burns combination of fuels Limestone Injection 0.0012 lb/MMBtu 0.00McCurtain County, OK monthly avg daily 

UT-0064 Nevco-Sevier Power Company 1 Coal-Fired CFR Boiler Dry Lime Scrubber not given Primary = Seco

Sevier Power Plant 270 MW 0.0024 lb/MMBtu none 

Sevier County, UT 24-hr rolling

RBLC ID Emission

Limit

Att 10-B_Coal Boilers_RBLC.xlsH2SO4 
Attachment 10-B

Recently Issued PSD Permits not listed in Clearinghouse DatabaseBACT-PSD Sources for H2SO4Coal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

RBLC ID Emission

Limit

WV-0023 Longview Power, LLC 1 Coal-Fired PC Boiler Dry Solid Injection w/ not given Primary = Seco

Maidsville 600 MW; 6114 MMBtu/hr Fabric Filter 0.0075 lb/MMBtu 45.8 Monongahela County, WV 3-hr rolling no a

SC-0104 Santee Cooper 2 Coal-Fired PC Boilers, #3 & #4 Wet FGD 95% Primary = Seco

Cross Generating Station Bituminous Coal & Pet Coke 0.0014 lb/MMBtu none Berkeley County, SC 5700 MMBtu/hr (each) 365-day rolling

AR-0074 Plum Point Associates, LLC 1 Coal-Fired PC Boiler, Unit 1 Dry FGD/Fabric Filter not given Primary = Seco

Plum Point Energy 800 MW 0.0061 lb/MMBtu none 

Mississippi County, AR no avg.

MT-0022 Bull Mountain Development Co. 2 Coal-Fired PC Boilers, No. 1, 2 Dry FGD System 90.0% Primary = Seco

Roundup Power Project 390 MW (each); 4013 MMBtu/hr 0.0064lb/MMBtu none Musselshell County, MT mine-mouth plant no avg

IA-0067 Mid-American Energy Co. 1 Coal-Fired PC Boiler Lime Spray Dryer 92% Primary = Seco

PRB coal Dry FGD 0.0042 lb/MMBtu none 

Council Bluffs, Iowa 7675 MMBtu/hr no avg

KY-0084 Thoroughbred Generating Company, LLC 2 Coal-Fired PC Boilers ESP, Wet ESP, & not given Primary = Seco

Thoroughbred Generating Station 1500 MW (total); 7446 MMBtu/hr (ea) Wet FGD 4.97E-03 lb/MMBtu none Muhlenburg County, KY no avg

KY-0086 East Kentucky Power Coop, Inc. 1 Coal-Fired CFB Boiler Limestone Injection plus not given Primary = Seco

Spurlock Power Station 270 MW; 2500 MMBtu/hr Dry Lime Scrubber 0.005 lb/MMBtu none Mason County, KY 30-day avg

PR-0007 AES Puerto Rico Cogeneration Plant 2 Coal-Fired CFB Boilers Limestone Injection plus not given Primary = Seco

454 MW (net); 4923 MMBtu/hr Circulating Dry Scrubber 0.0024 lb/MMBtu 0.64 

Guyama, Puerto Rico Bituminous Coal; max 1% sulfur no avg no a

KY-0079 Kentucky Mountain Power, LLC 2 Coal & Coal Refuse-Fired CFB Boilers Naturally Integrated not given Primary = Seco

Units 1 & 2 Desulfurization System 0.01 lb/MMBtu none 

Knott County, KY 2550 MMBtu/hr no avg.

TX-0275 Reliant Energy 1 Coal Fired Boiler, Unit 8 Fabric Filter & FGD not given Primary = Seco

 W.A. Parish Electric Generating St. 6700 mmbtu/hr 0.0015 lb/MMBtu 40 tpFt. Bend County, Texas Boiler also burns NG & Fuel Oil no avg. no a

Notes:NSR RACT/BACT/LAER Clearinghouse Database (http://cfpub.epa.gov/rblc) was queried for the following:- RBLC Determinations added during or after January 1996- Process Type Code: 11.110 - Coal Combustion for Utility Boilers

Att 10-B_Coal Boilers_RBLC.xlsH2SO4 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for LeadCoal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

PA-0249 River Hill Power Company, LLC 1 Waste Coal-Fired CFB Boiler Baghouse not given Primary = Second

Clearfield County, PA 1.4 lb/TBtu 34.0 lbs

12-month rolling 12-mon

PA-0248 Wellington Dev/Greene Energy 2 Waste Coal-Fired CFB Boilers Baghouse 90.0% Primary = Second

Resource Recovery Project 580 MW (gross) 525 MW (net) 0.0007 lb/MMBtu 15.7 tpy Greene County, PA no avg 12-mon

PA-0247 Robinson Power Company LLC 1 Waste Coal-Fired CFB Boiler Baghouse not given Primary = Second

Beech Hollow Power Project 272 MW (net); 2800 MMBtu/hr 0.014 lb/hr 0.06 tpy Washington County, PA no avg. no avg

MO-0060 Springfield Utilities 1 Coal-Fired PC Boiler Baghouse not given Primary = Second

Southwest Power Station 275 MW; 2724 MMBtu/hr 0.31 ton/yr none lisGreene County, MO no avg.

WI-0228 Wisconsin Public Service Co. 1 Coal-Fired PC Boiler; supercritical Fabric Filter not given Primary = Second

WPS - Weston Plant 500 MW; 5173 MMBtu/hr 0.13 lb/hr none lisMarathon County, WI PRB Coal; 8100 BTU/lb

UT-0065 Intermountain Power Service Corp. 1 Coal-Fired PC Boiler Baghouse not given Primary = Second

Generating Station Unit #3 950 MW (gross) 0.0 lb/MMBtu none lisMillard County, UT Bituminous Coal or Blend 3 test run avg

WV-0023 Longview Power, LLC 1 Coal-Fired PC Boiler Fabric Filter 99.0% Primary = Second

Maidsville 600 MW; 6114 MMBtu/hr 0.109 lb/hr none lisMonongahela County, WV 3-hr rolling

SC-0104 Santee Cooper 2 Coal-Fired PC Boilers, #3 & #4 ESP 99.75% Primary = Second

Cross Generating Station Bituminous Coal & Pet Coke 1.69E-05 lb/MMBtu Berkeley County, SC 5700 MMBtu/hr (each) no avg. none lis

TX-0298 Reliant Energy Inc. 3 Coal Fired Boilers, Units 5 ,6, 7 None Indicated not given Primary = Second

WA Parish Electric Generating St. Units 5 & 6 @ 7400 mmbtu/hr 0.43, 0.37 0.17, 0.Houston, TX Unit 7 @ 6700 mmbtu/hr lb/hr tpy 

AR-0074 Plum Point Associates, LLC 1 Coal-Fired PC Boiler, Unit 1 Fabric Filter not given Primary = Second

Plum Point Energy 800 MW 2.56E-05 lb/MMBtu none lisMississippi County, AR no avg.

RBLC ID Emission

Limit

Att 10-B_Coal Boilers_RBLC.xlsLead 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for LeadCoal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

RBLC ID Emission

Limit

IA-0067 Mid-American Energy Co. 1 Coal-Fired PC Boiler Baghouse 99.0% Primary = Second

PRB coal 2.6E-05 lb/MMBtu none lis

Council Bluffs, Iowa 7675 MMBtu/hr no avg

TX-0342 Reliant Energy Inc. 2 Coal Fired Boilers None Indicated not given Primary = Second

Limestone Electric Generating St. 0.26 0.46 Houston, TX 7863 mmbtu/hr each lb/hr tpy

KY-0086 East Kentucky Power Coop, Inc. 1 Coal-Fired CFB Boiler Baghouse not given Primary = Second

Spurlock Power Station 270 MW; 2500 MMBtu/hr 6.30E-06 lb/MMBtu none lisMason County, KY no avg

KY-0079 Kentucky Mountain Power, LLC 2 Coal & Coal Refuse-Fired CFB Boilers Baghouse not given Primary = Second

Units 1 & 2 1.94E-04 lb/MMBtu none lis

Knott County, KY 2550 MMBtu/hr no avg.

TX-0275 Reliant Energy 1 Coal Fired Boiler, Unit 8 Fabric Filter not given Primary = Second

 W.A. Parish Electric Generating St. 6700 mmbtu/hr 0.33 lb/hr 0.13 tpy Ft. Bend County, Texas Boiler also burns NG & Fuel Oil no avg. no avg

IA-0046 Archer Daniels Midland Company 2 Coal-Fired CFB Boiler, Unit #5, #6 Baghouse not given Primary = Second

1500 mmbtu/hr (each) 0.0002 lb/MMBtu none lis

Linn County, IA 3-month avg

IA-0051 Archer Daniels Midland Co. 1 Coal Fired CFB Boiler Baghouse not given Primary = Second

0.0002 lb/MMBtu none lis

Cedar Rapids, Iowa 1500 mmbtu/hr 3-month avg

Att 10-B_Coal Boilers_RBLC.xlsLead 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for LeadCoal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

RBLC ID Emission

Limit

MA-0028 Energy New Bedford 2 Coal Fired CFB Boilers None Indicated not given 4.70E-07 lb/mmb

New Bedford, Massachusetts 1671 mmbtu/hr each

FL-0255 Cedar Bay Generating Co., LP 3 Pulverized Coal Fired CFB Boilers None Indicated not given 6.03E-05 lb/mmb

Ceder Bay Cogeneration Jacksonville, Florida 132 mmbtu/hr each

VA-0213 SEI Birchwood, Inc. 1 Pulverized Coal Fired Boiler Baghouse 95% Primary = Second

0.2 0.9 

Sealston, Virginia 2200 mmbtu/hr lb/hr tpy

MA-0009 Energy New Bedford 2 Coal Fired CFB Boilers Baghouse not given 1.60E-03 lb/hr 

Cogeneration Facility 

New Bedford, Massachusetts 3342 mmbtu/hr

MA-0011 Taunton Energy Center 1 Coal Fired CFB Boiler Baghouse not given 3.50E-05 lb/mmb

Taunton, Massachusetts 1604.4 mmbtu/hr

PA-0058 North Branch Energy Partners, LP 1 Coal Fired CFB Boiler None Indicated not given 2.30E-03 lb/mmb

McDonald, Pennsylvania 563.5 mmbtu/hr

Notes:NSR RACT/BACT/LAER Clearinghouse Database (http://cfpub.epa.gov/rblc) was queried for the following:- RBLC Determinations added during or after January 1996- Process Type Code: 11.110 - Coal Combustion for Utility Boilers

Att 10-B_Coal Boilers_RBLC.xlsLead 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for FluoridesCoal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

MO-0071 Great Plains Energy 2 Coal-Fired Boiler - Unit 1 None Indicated n/a Primary = Secondary= 

Iatan Station 7800 MMBtu/hr 33.15 lb/hr none listed Platte County, MO sub-bituminuous coal no avg

PA-0249 River Hill Power Company, LLC 1 Waste Coal-Fired CFB Boiler Spray Dry Absorber not given Primary = Secondary= 

Clearfield County, PA with Limestone Inj. 0.0014 lb/MMBtu 18.09 tpy 

no avg. 12-month rollin

PA-0248 Wellington Dev/Greene Energy 2 Waste Coal-Fired CFB Boilers Boiler Control & 95.0% Primary = Secondary= 

Resource Recovery Project 580 MW (gross) 525 MW (net) SDA/FDA 0.0014 lb/MMBtu 33.0 tpy Greene County, PA no avg 12-month rollin

CO-0057 Xcel Energy (PSC of Colorado) 1 Coal-Fired PC Boiler, Unit #3 Lime Spray Dryer & 94% Primary = Secondary= 

Comanche Power Station 750 MW (unit #3); 7421 MMBtu/hr Baghouse 0.0005 lb/MMBtu none listed Pueblo, CO sub-bituminuous coal 3 test run avg

ND-0021 Montana Dakota Utilities/Westmoreland 1 Lignite Fired CFB Boiler Limestone Injection plus not given Primary = Secondary= 

Gascoyne Generating Station 220 MW (gross) 175 MW (net) Spray Dryer 0.0005 lb/MMBtu none listed Bowman County, ND 3-hr rolling

NV-0036 Newmont Nevada Energy Investment LLC 1 Coal-Fired PC Boiler Spray Dry Scrubber & not given Primary = Secondary= 

TS Power Plant 200 MW; 2030 MMBtu/hr Baghouse 1.17 lbs/hr none listed Eureka County, NV no avg

NE-0031 Omaha Public Power District 1 Coal-Fired PC Boiler Dry FGD & Fabric Filter 90% Primary = Secondary= 

Nebraska City Station Unit 2 boiler 660 MW (net) 0.004 lb/MMBtu none listed Otoe County, NE sub-bituminuous coal test avg

WI-0228 Wisconsin Public Service Co. 1 Coal-Fired PC Boiler; supercritical Dry FGD & Fabric Filter not given Primary = Secondary= 

WPS - Weston Plant 500 MW; 5173 MMBtu/hr 0.0002 lb/MMBtu 1.12 lb/hr Marathon County, WI PRB Coal; 8100 BTU/lb no avg no avg

UT-0065 Intermountain Power Service Corp. 1 Coal-Fired PC Boiler Wet FGD not given Primary = Secondary= 

Generating Station Unit #3 950 MW (gross) 0.0005 lb/MMBtu none listed Millard County, UT Bituminous Coal or Blend 3 test run avg

UT-0064 Nevco-Sevier Power Company 1 Coal-Fired CFR Boiler Dry Lime Scrubber & not given Primary = Secondary= 

Sevier Power Plant 270 MW Baghouse 0.0050 lb/MMBtu none listed Sevier County, UT no avg

NE-0018 Hastings Utilities 1 Unit 2 Coal-Fired Boiler Spray Dryer Absorber, not given Primary = Secondary= 

Whelan Energy Center 220 MW; 2210 MMBtu/hr PM controls 0.0004 lb/MMBtu none listed Adams County, NE 3-hr avg

WV-0023 Longview Power, LLC 1 Coal-Fired PC Boiler Dry Sorbent Injection w/ not given Primary = Secondary= 

Maidsville 600 MW; 6114 MMBtu/hr Fabric Filter 0.0001 lb/MMBtu none listed Monongahela County, WV 3-hr rolling

SC-0104 Santee Cooper 2 Coal-Fired PC Boilers, #3 & #4 Wet FGD 95% Primary = Secondary= 

Cross Generating Station Bituminous Coal & Pet Coke 0.0003 lb/MMBtu none listed Berkeley County, SC 5700 MMBtu/hr (each) 365-day rolling

TX-0298 Reliant Energy Inc. 3 Coal Fired Boilers, Units 5 ,6, 7 None Indicated not given Primary = Secondary= 

WA Parish Electric Generating St. Units 5 & 6 @ 7400 mmbtu/hr 128, 111 104, 91 Houston, TX Unit 7 @ 6700 mmbtu/hr lb/hr tpy 

AR-0074 Plum Point Associates, LLC 1 Coal-Fired PC Boiler, Unit 1 Dry FGD/Fabric Filter 90% Primary = Secondary= 

Plum Point Energy 800 MW 0.0004 lb/MMBtu none listed 

Mississippi County, AR no avg.

RBLC ID Emission

Limit

Att 10-B_Coal Boilers_RBLC.xlsFluorides 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for FluoridesCoal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

RBLC ID Emission

Limit

IA-0067 Mid-American Energy Co. 1 Coal-Fired PC Boiler Lime Spray Dryer 95% Primary = Secondary= 

PRB coal Dry FGD 0.0009 lb/MMBtu none listed 

Council Bluffs, Iowa 7675 MMBtu/hr no avg

TX-0342 Reliant Energy Inc. 2 Coal Fired Boilers None Indicated not given Primary = Secondary= 

Limestone Electric Generating St. 81.4 87.40 Houston, TX 7863 mmbtu/hr each lb/hr tpy

KY-0084 Thoroughbred Generating Company, LLC 2 Coal-Fired PC Boilers Wet ESP, & FGD not given Primary = Secondary= 

Thoroughbred Generating Station 1500 MW (total); 7446 MMBtu/hr (ea) 1.59E-04 lb/MMBtu none listed Muhlenburg County, KY no avg

KY-0086 East Kentucky Power Coop, Inc. 1 Coal-Fired CFB Boiler Baghouse not given Primary = Secondary= 

Spurlock Power Station 270 MW; 2500 MMBtu/hr 4.66E-05 lb/MMBtu none listed Mason County, KY 30-day rolling

PR-0007 AES Puerto Rico Cogeneration Plant 2 Coal-Fired CFB Boilers Limestone Injection plus not given Primary = Secondary= 

454 MW (net); 4923 MMBtu/hr Circulating Dry Scrubber 0.0005 lb/MMBtu 1.18 lb/hr 

Guyama, Puerto Rico Bituminous Coal; max 1% sulfur no avg no avg

KY-0079 Kentucky Mountain Power, LLC 2 Coal & Coal Refuse-Fired CFB Boilers Baghouse not given Primary = Secondary= 

Units 1 & 2 0.0053 lb/MMBtu none listed 

Knott County, KY 2550 MMBtu/hr no avg.

TX-0275 Reliant Energy 1 Coal Fired Boiler, Unit 8 Fabric Filter & FGD not given Primary = Secondary= 

 W.A. Parish Electric Generating St. 6700 mmbtu/hr 0.005 lb/MMBtu 29.3 tpy Ft. Bend County, Texas Boiler also burns NG & Fuel Oil no avg. no avg

IA-0046 Archer Daniels Midland Company 2 Coal-Fired CFB Boiler, Unit #5, #6 Baghouse not given Primary = Secondary= 

1500 mmbtu/hr (each) 0.0012 lb/MMBtu none listed 

Linn County, IA 3-month avg

IA-0051 Archer Daniels Midland Co. 1 Coal Fired CFB Boiler Baghouse not given Primary = Secondary= 

0.0012 lb/MMBtu none listed 

Cedar Rapids, Iowa 1500 mmbtu/hr 3-month avg

MA-0028 Energy New Bedford 2 Coal Fired CFB Boilers None Indicated not given 2.80E-03 lb/mmbtu 

New Bedford, Massachusetts 1671 mmbtu/hr each

FL-0255 Cedar Bay Generating Co., LP 3 Pulverized Coal Fired CFB Boilers None Indicated not given 7.44E-04 lb/mmbtu 

Ceder Bay Cogeneration Jacksonville, Florida 132 mmbtu/hr each

VA-0213 SEI Birchwood, Inc. 1 Pulverized Coal Fired Boiler None Indicated not given Primary = Secondary= 

3.6 8.28 

Sealston, Virginia 2200 mmbtu/hr lb/hr tpy

PA-0058 North Branch Energy Partners, LP 1 Coal Fired CFB Boiler None Indicated not given 1.40E-03 lb/mmbtu 

McDonald, Pennsylvania 563.5 mmbtu/hr

Notes:NSR RACT/BACT/LAER Clearinghouse Database (http://cfpub.epa.gov/rblc) was queried for the following:- RBLC Determinations added during or after January 1996- Process Type Code: 11.110 - Coal Combustion for Utility Boilers

Att 10-B_Coal Boilers_RBLC.xlsFluorides 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for MercuryCoal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

PA-0249 River Hill Power Company, LLC 1 Waste Coal-Fired CFB Boiler not given not given Primary = Secondary

Clearfield County, PA 17.4 lbs/yr -- 

19% run-of-mine coal

PA-0248 Wellington Dev/Greene Energy 2 Waste Coal-Fired CFB Boilers not provided not given Primary = Secondary

Resource Recovery Project 580 MW (gross) 525 MW (net) 20.05 lbs/yr Greene County, PA no avg

MO-0060 Springfield Utilities 1 Coal-Fired PC Boiler not provided not given Primary = Secondary

Southwest Power Station 275 MW; 2724 MMBtu/hr 0.09 ton/yr none listed Greene County, MO no avg.

WI-0228 Wisconsin Public Service Co. 1 Coal-Fired PC Boiler; supercritical Fabric Filter & Sorbent Injection 83% Primary = Secondary

WPS - Weston Plant 500 MW; 5173 MMBtu/hr 1.7 lb/Trillion BTU none listed Marathon County, WI PRB Coal; 8100 BTU/lb 12-mo rolling

UT-0065 Intermountain Power Service Corp. 1 Coal-Fired PC Boiler Wet FGD, Baghouse & SCR not given Primary = Secondary

Generating Station Unit #3 950 MW (gross) 0.0 lb/MW-hr none listed Millard County, UT Bituminous Coal or Blend 3 test run avg

UT-0064 Nevco-Sevier Power Company 1 Coal-Fired CFR Boiler Dry Lime Scrubber & not given Primary = Secondary

Sevier Power Plant 270 MW Baghouse 0.00 lb/MMBtu none listed Sevier County, UT no avg

WV-0023 Longview Power, LLC 1 Coal-Fired PC Boiler SCR ,Dry Sorbent Injection w/ not given Primary = Secondary

Maidsville 600 MW; 6114 MMBtu/hr Fabric Filter & 0.0146 lb/hr 0.0638 tpy Monongahela County, WV Limestone Forced Oxidation 3-hr rolling 12-month r

SC-0104 Santee Cooper 2 Coal-Fired PC Boilers, #3 & #4 ESP, Wet FGD, SCR & not given Primary = Secondary

Cross Generating Station Bituminous Coal & Pet Coke Low-NOx burners 3.6E-06 lb/MMBtu none listed Berkeley County, SC 5700 MMBtu/hr (each) no avg

IA-0067 Mid-American Energy Co. 1 Coal-Fired PC Boiler Activated Carbon 83.0% Primary = Secondary

PRB coal 1.7E-06 lb/MMBtu none listed 

Council Bluffs, Iowa 7675 MMBtu/hr no avg.

KY-0084 Thoroughbred Generating Company, LLC 2 Coal-Fired PC Boilers ESP, Wet ESP, & not given Primary = Secondary

Thoroughbred Generating Station 1500 MW (total); 7446 MMBtu/hr (ea) Wet FGD 3.21E-06 lb/MMBtu none listed Muhlenburg County, KY no avg

KY-0086 East Kentucky Power Coop, Inc. 1 Coal-Fired CFB Boiler Baghouse not given Primary = Secondary

Spurlock Power Station 270 MW; 2500 MMBtu/hr 2.65E-06 lb/MMBtu none listed Mason County, KY no avg

KY-0079 Kentucky Mountain Power, LLC 2 Coal & Coal Refuse-Fired CFB Boilers Baghouse not given Primary = Secondary

Units 1 & 2 8.10E-05 lb/MMBtu none listed 

Knott County, KY 2550 MMBtu/hr no avg.

TX-0275 Reliant Energy 1 Coal Fired Boiler, Unit 8 Fabric Filter & FGD not given Primary = Secondary

 W.A. Parish Electric Generating St. 6700 mmbtu/hr 1.71 lb/hr 0.24 tpy 

Ft. Bend County, Texas Boiler also burns NG & Fuel Oil no avg. no avg

Notes:NSR RACT/BACT/LAER Clearinghouse Database (http://cfpub.epa.gov/rblc) was queried for the following:- RBLC Determinations added during or after January 1996- Process Type Code: 11.110 - Coal Combustion for Utility Boilers

RBLC ID Emission

Limit

Att 10-B_Coal Boilers_RBLC.xlsMercury 
Attachment 10-B

NSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for Hydrogen ChlorideCoal Fired Boilers

Company Name No. of Unit & Control Control 

and Location Units Size Technology Efficiency 

PA-0249 River Hill Power Company, LLC 1 Waste Coal-Fired CFB Boiler Spray Dry Absorber not given Primary = Seconda

Clearfield County, PA with Limestone Inj. 0.0034 lb/MMBtu 42.2 tpy 

no avg 12-month 

PA-0248 Wellington Dev/Greene Energy 2 Waste Coal-Fired CFB Boilers not provided not given Primary = Seconda

Resource Recovery Project 580 MW (gross) 525 MW (net) 0.0067 lb/MMBtu Greene County, PA no avg

WI-0228 Wisconsin Public Service Co. 1 Coal-Fired PC Boiler; supercritical Dry FGD not given Primary = Seconda

WPS - Weston Plant 500 MW; 5173 MMBtu/hr 10.94 lb/hr none listeMarathon County, WI PRB Coal; 8100 BTU/lb 24-hr avg

UT-0065 Intermountain Power Service Corp. 1 Coal-Fired PC Boiler Wet FGD not given Primary = Seconda

Generating Station Unit #3 950 MW (gross) 38.13 lb/hr none listeMillard County, UT Bituminous Coal or Blend 3 test run avg

UT-0064 Nevco-Sevier Power Company 1 Coal-Fired CFR Boiler Dry Lime Scrubber & not given Primary = Seconda

Sevier Power Plant 270 MW Baghouse 4.01 lb/hr none listeSevier County, UT no avg

WV-0023 Longview Power, LLC 1 Coal-Fired PC Boiler Dry Sorbent Injection w/ not given Primary = Seconda

Maidsville 600 MW; 6114 MMBtu/hr Fabric Filter 0.0001 lb/MMBtu none listeMonongahela County, WV 3-hr rolling

SC-0104 Santee Cooper 2 Coal-Fired PC Boilers, #3 & #4 Wet FGD 95% Primary = Seconda

Cross Generating Station Bituminous Coal & Pet Coke 0.0024 lb/MMBtu none listeBerkeley County, SC 5700 MMBtu/hr (each) no avg

IA-0067 Mid-American Energy Co. 1 Coal-Fired PC Boiler Lime Spray Dryer 92% Primary = Seconda

PRB coal Dry FGD 0.0029 lb/MMBtu none liste

Council Bluffs, Iowa 7675 MMBtu/hr no avg

Notes:NSR RACT/BACT/LAER Clearinghouse Database (http://cfpub.epa.gov/rblc) was queried for the following:- RBLC Determinations added during or after January 1996- Process Type Code: 11.110 - Coal Combustion for Utility Boilers

RBLC ID Emission

Limit

Att 10-B_Coal Boilers_RBLC.xlsHCl 
ATTACHMENT 10-C 

 EPA REGION IV COAL-FIRED POWER PLANT LISTING
Region/State Company City (County) General Project Description

Added 

Capacity 

(MWe)

Date of 

Application

Operational 

Startup Date BACT-LAER-112(g) Standards 

BACT-L

EPA Region 1Connecticut NoneMaine NoneNew Hampshire NoneRhode Island NoneVermont NoneEPA Region 2New Jersey NoneNew York NonePuerto Rico NoneVirgin Islands None

ATTACHMENT 10-C

EPA Region IV Summary of BACT Determinations for Coal Fired Power Plants (March 2005) 
ATTACHMENT 10-C

EPA Region IV Summary of BACT Determinations for Coal Fired Power Plants (March 2005) 

EPA Region 3Delaware NoneWashington, DC NoneMaryland AES Cumberland (Garrett) Circulating Fluidized Bed Boiler 180 Pre-application 

Only

Pennsylvania Reliant Energy, 

Seward Power Plant

(Indiana) CFB boiler to replace existing unit, online by 2004 520 30-Sep-00 NOx-0.15lb/mmBtu SNCR

Pennsylvania Greene Energy 

(Wellington Development)

Greene Wellington Development of Fairmont, 

WV is proposing to build a 525 MW coal mine waste fueled Resource Recovery power project in Green County, Pennsylvania. The resulting project will be one of the cleanest solid fuel burning facilities in the world, utilizing state-of-the-art circulating fluidized bed combustion technology (CFBC).

525 2414 TPY NOx @.10 lb /mmbtu 

1207 TPY pm10@.5 lb/mmbtu 5649 TPY SO2@.234lb/mmbtu .314 TPY Hg 145 TPY H2SO4

Filter BagBoiler anfor SO2 ,Boiler for 

Pennsylvania River Hill Power 

Facility

Clearfield CIRCULATING FLUIDIZED BED 

BOILER

290 preapp 1300 TPY NOx, (bact), 

65 TPY VOCS(-LAER), CO 1900 TPY,. PM-10 150 TPY, H2SO4 50 TPY, 4300 TPY SO2

SNCR - NPM10, LIINJECTIO

Pennsylvania Beach Hollow Project Washington CIRCULATING FLUIDIZED BED 

BOILER

250 3018 TPY, SO2; 232 TPY PM-10; 

696 TPY NOX

Pennsylvania AES Beaver Valley AES proposes to install a new 

2,155MMBTU/HR CFB boiler and at the same time retire four existing pulverized coal boilers. This new configuration will generate approximate 180 MW, compared to the current 125 MW.

180 09-May-01 NOx-0.15lb/mmBtu SNCR

Virginia NoneWest Virginia Longview Power, LLC Longview has proposed to construct a 

600 megawatt (MW) (net) power generation facility with interconnection to Allegheny Energy Supply Company lines. The pulverized coal supercritical boiler burning 2.5 percent sulfur (nominal) bituminous coal would operate with a oncethrough, balanced draft, single reheat steam turbine/generator. A natural gas-fired auxiliary boiler would be used to supply startup steam to the main boiler.

600 NOx-0.08 lb/MMBtu, SO2 - 

0.15lb/MMBtu, PM -

0.018 lb/MMBtu, CO- 0.11 lb/MMBtu, H2SO4-0.0075 lb/MMBtu, Hg-6.38x10e-2 TPY

NOx burncatalytic 

West Virginia Anker Circulating Fluidized Bed Boiler 1000 Pre-application 

Only
ATTACHMENT 10-C

EPA Region IV Summary of BACT Determinations for Coal Fired Power Plants (March 2005) 

EPA Region 4Alabama NoneFlorida Tampa Electric 

Company- Polk Power

Mulberry (Polk) 1994 PSD permit allowed construction 

of an Integrated Gasification Combined Cycle (IGCC) plant. The permit required a NOx BACT evaluation based on data gathered from the plant's operation to be submitted 12-18 months after operation began. On May 10, 2001, the permitting agency issued a proposed BACT determination to require SCR. Tampa Electric appealed the determination, and SCR was not required in final permit.

N/A 05-Dec-00 NOx - 15 ppm (syngas), 42 ppm 

(fuel oil)

NOx - DL

Florida JEA Northside 

Generating Station

Jacksonville (Duval)

Construct two new 297.5 MW CFB boilers as a repowering project to replace two existing boilers. Allowable fuels include coal and petroleum coke.

595 2003 NOx-0.09 lb/mmBtu (30-day), 

PM/PM10-0.011 lb/mmBtu (3-hr), CO-350 lb/hr (24-hr), VOC-14 lb/hr (3-hr), HF- 0.43 lb/hr (3-hr), Hg-0.03 lb/hr (6-hr). [Note: Project nets out of review for SO2. SO2 emission limits are 0.20 lb/mmBtu (24-hr) and 0.15 lb/mmBtu (30-day). Project not subject to PSD review for SAM and Pb. SAM emission limit is 1.1 lb/hr (3-hr). Pb emission limit is 0.07 lb/hr (3-hr).]

NOx-CFBFF, CO-GCFB+FF, scrubbersubject to and Pb. method fCFB+polEmission 

Georgia Longleaf Energy 

Associates, LLC (LS Power Development, LLC)

(Early) Construct 2 new pulverized coal 

boilers (600 MW each)

1,200 19-Nov-04 Proposed: NOx-0.07 lb/mmbtu (30-

day), SO2-0.12 lb/mmbtu (30-day), PM/PM10-0.033 (30-day), CO-0.15 lb/mmbtu (30-day), VOC-0.006 lb/mmbtu (30-day), fluorides (as HF)-

0.0024 lb/mmbtu (PRB) or 0.0031 lb/mmbtu (CAPP), SAM-0.005 lb/mmbtu (30-day), Hg-0.000006 lb/MWh (CAPP) or 0.000020 lb/MWh (PRB)

NOx-LNBScrubberCO-GCPDry ScruDry ScruDry Scru
ATTACHMENT 10-C

EPA Region IV Summary of BACT Determinations for Coal Fired Power Plants (March 2005) 

Kentucky Kentucky Mountain 

Power, LLC

Ary (Knott) Construct coal-refuse-fired CFB 

boilers

500 19-Apr-00 NOx-0.07 lb/mmbtu, CO-0.27 

lb/mmbtu, PM-0.015 lb/mmbtu, VOC0.0072 lb/mmbtu, SO2-0.13 lb/mmbtu, SAM-0.010 lb/mmbtu, Be0.0000217 lb/mmbtu, Hg-0.000081 lb/mmbtu, Pb-0.000194 lb/mmbtu, HF-0.0053 lb/mmbtu

NOx-SNCBaghousSO2-NIDBe-BaghPb-Bagh

Kentucky Kentucky Eastern 

Power, LLC

(Martin) Construct 2 new fluidized bed 

combustors. [Project on hold as of Feb 2003]; 500 MWe

Kentucky Thoroughbred 

Generating Company, LLC (Peabody Energy)

Graham (Muhlenberg)

Construct an electric generating facility with 2 pulverized coal boilers (750 MWe each)

1500 28-Feb-01; 

complete 

revised appl. 26-

Oct-01

NOx-0.08 lb/mmbtu (30-day), CO0.1 lb/mmbtu (30-day), PM-0.018 lb/mmbtu (3-hr), VOC-0.0072 lb/mmbtu (30-day), SO2-0.167 lb/mmbtu (30-day) & 0.41 lb/mmbtu (24-hr) (see comment), SAM0.00497 lb/mmbtu (30-day), Be0.000000944 lb/mmbtu (quarterly), Hg-0.00000321 lb/mmbtu (quarterly), HF-0.000159 lb/mmbtu (30-day), Pb-0.00000386 lb/mmbtu (quarterly); also case-by-case MACT limits in tpy for VOC, Hg, HCl, 

HF A B C M Pb Cd

NOx-LNBESP/wet wet limesFGD/wet Hg-bagho

Kentucky Kentucky Pioneer 

Energy

Trapp (Clark) Construct integrated gasification 

system producing synthetic gas (syngas) to combust for electricity generation.

540 31-Jan-00 Draft Permit: NOx-0.072 lb/mmbtu, 

CO-0.032 lb/mmbtu, PM-0.011 lb/mmbtu, VOC-0.0044 lb/mmbtu, SO2-0.032 lb/mmbtu, SAM-0.010 lb/mmbtu, Be-6.0 e-7 lb/mmbtu, Hg0.08 mg/dscf, Pb-0.02 mg/dscf

Draft Per(steam), VOC-GCRecovery GCP, Pb

Kentucky Calla Energy Irvine (Estill) Construct atmospheric fluidized-bed 

combustion circulating-bed boiler which will co-fire waste coal and syngas (from coal & biomass gasifier); 110 MWe

04/25/01; 

complete 

revised appl. 

10/01

Proposed: NOx-0.07 lb/mmbtu, CO0.15 lb/mmbtu, PM-0.015 lb/mmbtu, SO2-0.15 lb/mmbtu (avg)/0.46 lb/mmbtu (max), SAM-0.002 lb/mmbtu, Be-0.000002.1 lb/mmbtu, Fluorides (as HF)-0.0023 lb/mmbtu

Proposeddesign/SSO2-AFB/FF, Fluo

Kentucky Kentucky Western 

Power, LLC

Calvert City (Marshall)

Construct 2 new fluidized bed combustors. [Project on hold as of Feb 2003]; 500 MWe

13-Jun-01 [Project on hold as of Feb 2003]

Kentucky East Kentucky Power 

Cooperative, Spurlock Generating Station

Maysville (Mason)

Construct 1 new circulating fluidized bed boiler

270 24-Apr-01 NOx-0.07 lb/mmbtu (30-day), CO0.15 lb/mmbtu (30-day), PM-0.015 

lb/mmbtu (3-hr), SO2-0.20 lb/mmbtu (24-hr), SAM-0.0050 lb/mmbtu (also see comments)

ProposedGCP, PMdesign/drCFB des(also see 

Kentucky East Kentucky Power 

Cooperative, Spurlock Generating Station (Unit 4)

Maysville (Mason)

Construct 1 new circulating fluidized bed boiler

300 13-Sep-04 Proposed: NOx-0.1 lb/mmbtu (?-

day), CO-0.15 lb/mmbtu (?-hr), PM/PM10-0.015 lb/mmbtu (?-hr), SO2-0.20 lb/mmbtu (?-hr), VOCnothing proposed, SAM-0.0050 lb/mmbtu (?-hr), Hg-0.0000026 lb/mmBtu (also see comments)

ProposedGCP, PMSO2-CFB scrubberlime scruproposedsee comm

Kentucky Cash Creek (Henderson) Pulverized coal boilers, 1000 MWe [See comment]

Kentucky Cash Creek 

Generation, LLC

 (Henderson) Construct 2 new pulverized coal 

boilers (500 MW each)

1,000 25-Nov-03 

revised

(see comments) (see com

Kentucky Louisville Gas & 

Electric Company (LG&E), Trimble County Generating Station

(Trimble) Construct 1 new pulverized coal boiler 

(750 MW)

750 01-Dec-04 

revised

Proposed: CO-0.10 lb/mmbtu (3-hr), PM/PM10-0.0018 lb/mmbtu (3-hr), SAM-26.6 lb/hr (3-hr), VOC-0.0032 lb/mmbtu (3-hr), fluorides-no rate proposed, Hg-no rate proposed

Proposed

BaghousVOC-GCHg-SCR+(also see 
ATTACHMENT 10-C

EPA Region IV Summary of BACT Determinations for Coal Fired Power Plants (March 2005) 

Kentucky Estill County Energy 

Partners

Irvine (Estill) Construct 1 new circulating fluidized 

bed boiler. Fuel will be waste eastern bituminous coal.

110 31-Aug-04 Proposed: SO2-0.13 lb/mmbtu (30-

day) and 0.15 lb/mmbtu (24-hr), PM/PM10-0.015 lb/mmbtu filterable (3-hr), NOx-0.07 lb/mmbtu (30-day), CO-0.15 lb/mmbtu (30-day), VOC0.007 lb/mmbtu (30-day), H2SO4-0.005 lb/mmbtu (30-day); Hg0.000004 lb/mmbtu or 90% removal

Proposedandn polPM/PM10 inherent GCP, VOinherent and baghfrom BAC

Mississippi Tractebel Power Inc Choctaw Lignite Fired 462 (see comments) (see comNorth Carolina NoneSouth Carolina Santee Cooper, Cross 

Generating Station

Cross (Berkeley)

Existing electric generating facility to be expanded with addition of two pulverized coal boilers (660 MWe each).

1,320 [See comment 

(1)]

PM (filterable only)-0.015 lb/mmBtu (3-hr), PM10 (filterable and condensible)-0.018 lb/mmBtu (3-hr), CO-0.16 lb/mmBtu (3-hr), VOC0.0024 lb/mmBtu (3-hour), Pb0.0000169 lb/mmBtu, Hg-0.0000036 lb/mmBtu [See comments (2), (3), (4)]

PM/PM10VOC-GCSCR, dry comment 

Tennessee None
ATTACHMENT 10-C

EPA Region IV Summary of BACT Determinations for Coal Fired Power Plants (March 2005) 

EPA Region 5Illinois Enviropower Benton 

(Franklin)

Two (2) CFB boilers, 250 MWe each 500 15-Aug-00 SO2 92% redux, 0.25 lb/mmBtu; 

NOx 0.125, PM 0.015, CO 0.27, VOC 0.007 lb/mmBtu

CFB w/sobaghouse

Illinois Southern Illinois Power 

Cooperative, Marion Power Station

(Williamson) 1st Project - 1 CFB boiler to replace 3 

existing coal fired generating units. 2nd Project - 2 simple cycle combustion turbines. 3rd ProjectInstallation of SCR on existing coal fired boiler

120 12-Jul-00 CO-0 .015lb/mmBtu Combust

Illinois Cornbelt Energy Elkhart (Logan) Prairie Energy Power Plant. PSD for 

low-emitting power plant. 

91 3rd quarter, 

2001

NOx - 0.132, SO2 - 0.3 lb/mmBtu SCR, ES

Illinois Peabody - Prairie State (Washington) Peabody will build the Prairie State 

Energy Campus -- a 1,500-megawatt (MW), coal-fired electricity plant, comprised of two 750 MWe pulverized coal boilers and one 400 mmBtu/hr auxillary boiler -- in Washington County in southern Illinois. Construction at Prairie, if the plans pass state approval, is scheduled to start in late 2002 to early 2003 and is expected to last approximately four years.

1500 10/2001 SO2 - 0.30 lb/mmBtu, PM10 - 0.018, 

NOx - 0.10, CO - 0.15, VOC - 0.01, H2SO4 - 0.039

SCR, weor ESP

Illinois Dynegy-Illinois Power Baldwin (Rando$1.5 billion, two 650 MW coal-fired 

boilers. 4 - 5 million tons of coal a year by rail/barge. Adding to 2000 MW from 3 existing boilers.

1300 No app as of 

12/4/01

Illinois Indeck-Elwood Elwood (Will) Two (660 MW total capacity) 

circulating fluidized bed boilers firing pulverized coal

660 21-Mar-02 PM-.015 lb/MMBTU, SO2-.15 

lb/MMBTU, NOx- .10 lb/MMBTU, CO-.10 lb/MMBTU, VOC- .004 lb/MMBTU

Baghoustechnologbed, SNC

Illinois Illinois Energy GroupFranklin Energy Coal 

Project

Ewing (Franklin)

Two 680 MW supercritical steam pulverized coal boilers, mine mouth plant

1360 07-Jun-02 SO2- .08 lb/mmBTU, NOx- 

.08lb/mmBTU, PM-.01 lb/mmBTU

SCR, ES
ATTACHMENT 10-C

EPA Region IV Summary of BACT Determinations for Coal Fired Power Plants (March 2005) 

Illinois Midwest Generation Morris (Grundy)PSD to convert 2 of 5 Oil/NG boilers 

to coal.

1000 Application 

Received

Indiana Enviropower Petersburg 

(Pike) 

2 - 250 MWe CFB boilers, combusting waste coal

500 03-Aug-00

Michigan NoneMinnesota Minnesota Power & 

Blandin Paper Company

Addition of 225 MWe.

Ohio Dominion Energy Ashtabula 600 08-Mar-04Wisconsin Wisconsin Energy - 

Elm Road Generating Station (At existing Oak Creek Facility)

Oak Creek (Milwaukee)

Two 615 MW supercritical pulverized coal boilers; construction is proposed to begin in 2004, with in-service dates of 2007, and 2009 for these units. (One 600 MW integrated gasification combined cycle unit was proposed, but was not approved by the WI Public Service Comission.)

1230 June 18 2002 - 

October 1 2003

CO: 0.12 lb/mmbtu, NOx: 0.07 lb/mmbtu, PM/PM10: 0.018 lb/mmbtu, SO2: 0.15 lb/mmbtu, VOC: 0.0035 lb/mmbtu, Pb: 7.9 lb/tbtu, Hg: 1.12 lb/tbtu, Be: 0.35 lb/tbtu, HF: 0.00088 lb/mmbtu, H2SO4: 0.01lb/mmbtu, HCL: 2.56 lb/mmbtu

CO: LNBPM/PM10VOC: LNFF, H2SO

Wisconsin Wisconsin Power and 

Light

On-line by 2006 500

Wisconsin Wisconsin Public 

Service Corporation 

Wausau The Weston Unit 4 plant, planned for 

construction at the existing Weston generating station located three miles south of Wausau in central Wisconsin, is being built to satisfy growing electric demand. 

500 July 16, 2004 CO: 0.15 lb/mmbtu, NOx: 0.06 

lb/mmbtu, PM/PM10: 0.020 lb/mmbtu/0.018 lb/mmbtu, SO2: 0.09lb/mmbtu, VOC: 0.0036 lb/mmbtu, Pb: 0.13 lbs/hr, Hg: 1.7 lb/tbtu, Be: 1.3 lb/tbtu, HF: 0.000217 lb/mmbtu, H2SO4: 0.005 lb/mmbtu, HCL: 10.94 lbs/hr

CO: LNBPM/PM10FGD, VOFF, Hg: SH2SO4/H

Wisconsin Manitowoc Public 

Utilities

Manitowoc Construction of a 64 MW CFB fired 

boiler. Project will include elimination of solid fuel burning capabilities at existing boiler #5. Boiler #5 will retain its ability to fire natural gas as the boiler is needed at peak usage periods. New boiler will fire coal, coke, and paper pellets as well as natural gas at startup. The emission reduction from the elimination of solid fuel burning capabilties at boiler #5 will be used to net out of PSD for PM, SO2, VOC, NOx, Pb, H2SO4, Be, Hg, and F.

64 October 13, 

2003

CO: 0.15 lb/mmbtu, NOx: 0.155 lb/mmbtu, PM/PM10: 0.03 lb/mmbtu, VOC: 0.013 lb/mmbtu, Pb: .0002 lb/mmbtu, HF: 0.00173 lb/mmbtu, H2SO4: 0.0045lb/mmbtu, 

CO: GCPPM/PM10Injection VOC: GCH2SO4: C
ATTACHMENT 10-C

EPA Region IV Summary of BACT Determinations for Coal Fired Power Plants (March 2005) 

EPA Region 6Arkansas LS Power, Plum Pt. 

Energy, Plum Pt. Power Sta.

Osceola (MS) Construct 1 pulverized Powder River 

basin coal fired boiler to yield 550-800 MW, fuel oil used for start-up. New power plant.

800 May 17, 2001 NOx: 0.09 #/mmbtu; CO: 0.16 

#/mmbtu; SO2: 0.16 #/mmbtu; PM/PM10; 0.018 #/mmbtu; VOC: 0.02 #/mmbtu; H2SO4: 0.0061 #/mmbtu

NOx: LNdry FGD; cc; H2SO

Louisiana NoneNew Mexico Mustang (Peabody) 

Energy, Mustang Generating Station

35 mi. no. of Milan, McKinley Co.

Construct 1 pulverized coal fired boiler to yield 300 MW, fuel oil or nat. gas used for start-up. Proposed with low NOx burners w/ SCR on the boiler, dry scrubber for SO2, baghouse or ESP for PM, good combustion for CO and VOC.

300 March '02 29-Jun-05 NOx: 0.09 #/mmbtu; CO: 0.15 

#/mmbtu; SO2: 0.11 #/mmbtu; PM/PM10; 0.018 #/mmbtu; VOC: 0.01 #/mmbtu

Proposed w/ SCR oscrubber ESP for Pfor CO an

Oklahoma NoneTexas City Public Service of 

San Antonio, Calaveras Lake Station

San Antonio (Bexar)

Construct 1 pulverized Powder River basin coal fired boiler to yield 750 MW. Natural gas as start-up fuel. Existing power plant

750 November '03 April, 2009 NOx: 0.05 #/mmbtu; CO: 0.15 

#/mmbtu; SO2: 0.06 #/mmbtu; PM/PM10; 0.022 #/mmbtu; VOC: 0.0025 #/mmbtu; H2SO4: 0.0037 #/mmbtu; Hg: 0.0000098 3/mmbtu

NOx: LNwet FGDFGD; VOFGD, FFSCR

Texas LS Power, Sandy 

Creek Energy Station

Reisel (McClennan)

Construct 1 pulverized Powder River basin coal fired boiler to yield 800 MW. Fuel oil as start-up fuel. New power plant

800 January '04 Late 2008 NOx: 0.09 #/mmbtu; CO: 0.15 

#/mmbtu; SO2: 0.12 #/mmbtu; PM/PM10; 0.033 #/mmbtu; VOC: 0.0036 #/mmbtu; H2SO4: 0.007 #/mmbtu, Hg: 0.000017 #/mmbtu

NOx: LNdry FGD; cc; H2SOdry FGD, 
ATTACHMENT 10-C

EPA Region IV Summary of BACT Determinations for Coal Fired Power Plants (March 2005) 

EPA Region 7Iowa MidAmerican Council Bluffs Installation of one 790 MWe 

supercritical pulverized coal fired boiler designed for base load operation on Powder River Basin coal. "Unit 4" will be co-located with existing Units 1-3.

790 September '02 Final.... NOx: 0.07 #/mmBtu (30-

day), SO2: 0.10 #/mmBtu (30-day), Pb: 0.00026 #/mmBtu, F: 0.0009 #/mmBtu, TRS: 0.001 #/mmBtu, H2SO4: 0.00421 #/mmBtu, PM-10: 0.025 #/mmBtu (3-hr with condensibles), VOC: 0.0036 #/mmBtu (3-hr), CO: 0.154 #/mmBtu (24-hour), 112(g) limits... Hg: 1.7#/Tbtu, HAP Acid Gases: 0.0029#/mmBtu HCl; Organic HAP: CO as surrogate; Metallic HAP: 1.04e-4 #/mmBtu "total selected metals"

NOx-SCRSO2-DLSactivated Gases-D

Kansas Sand Sage (colocated 

at existing Sunflower Holcomb Power Station)

Holcomb (Finney)

Installation of a 660 MWe (6,500 mmBtu/hr) pulverized PRB coal and gas-fired boiler, along with ancillary coal and ash handling equipment and cooling towers. Proposed with ultralow NOx burners (no SCR), dry scrubber, and baghouse

660 June '01 Final.... SO2 (0.15,30d); NOx 

(0.15*/0.08, 30d); CO (0.15, 3h?); PM10 (0.018 6-hr); VOC (0.0035,3h?); Pb (0.0004,3h?), * for 3 yrs after performance test; accepted "de minimis" HAP limits to avoid 112(g) review

NOx-ULNSO2-DLS

Kansas Great Plains Power, 

Atchison Generating Station

Atchison (Atchison)

Installation of one opposed-wall-fired, dry-bottom, boiler (8100 mmBtu/hr), subbituminous coal with No. 2 oil backup and associated equipment, including cooling tower

820 Jan '03 Proposed in Application... NOx 

(0.08,30d), CO (0.16), PM10 (0.018), SO2 (0.12,30d), VOC (0.0036); all except startup/shudown/malfunction

NOx - LNPM10-FFdrier(94%(5%S), C

Missouri Kansas City Power & 

Light, Hawthorn Power Station

Kansas City (Jackson)

Installation of a 570 MWe pulverized PRB coal and gas-fired boiler (Unit 5, completely rebuilt following catastrophic explosion of existing unit), with SCR, dry scrubber, and baghouse

570 May '99 05/01 Final... NOx: 0.08 #/mmBtu (30-

day), 0.10 #/mmBtu (24-hr), SO2: 0.12 #/mmBtu (30-day), 0.13 #/mmBtu ( 3-hr)PM-10: 0.018 #/mmBtu, VOC: 0.0036 #/mmBtu, CO: 0.16 #/mmBtu, Pb: 0.6 ton/yr; 112(g) not applicable to plant since final permitting action preceded December 20, 2000 HAP finding.

NOx-SCRSO2-DLS

Missouri Great Plains Power, 

Weston Bend Generating Station (colocated at existing KCPL, Iatan Station)

Weston (Platte)

Installation of one opposed-wall, drybottom boiler combusting low sulfur Wyoming subbituminous coal and oil (rated 8,100 mmBtu/hr)

820 Nov '01 Proposed in Application.... SO2 

(0.12,30d); NOx (0.08, 30d); CO (0.16, 3h?); PM10 (0.018,3h?); VOC (0.0036,3h?); 

NOx-SCRSO2-DLSPb-FF, V

Missouri City Utilities of 

Springfield, Southwest Power Station

Springfield (Greene)

Construction of a new 275 MW pulverized coal (low sulfur western subbituminous) utility boiler and associated equipment

275 April '03 Final.... SO2 (0.095,30d); NOx 

(0.08, 30d); CO (0.16, 3h); PM10 (0.018,3h); VOC (0.0036,3h); H2SO4 (1.84e-4,3h); Pb (2.56e-5)

NOx-SCRSO2-DLSPb-FF, V

Nebraska Omaha Public Power 

District

Nebraska City Addition of one 660 MWn (6478 

mmBtu/hr) coal-fired unit at the existing Nebraska City power station. Also includes installation of 125 mmBtu/hr auxiliary boiler and 1837 hp diesel-fired emergency generator

660 February '04 05/09 Final... SO2 (0.095#/mmBtu,30d); 

SO2 (0.163#/mmBtu, 24-h), SO2 (0.48#/mmBtu,3-h), H2SO4 (0.0042#/mmBtu, NOx (0.07#NOx/mmBtu, 30d, following 18mo optimization, interim 0.12), CO (0.16#/mmBtu, RM-average), PM10 (0.018#/mmBtu, F+C, RM-average), VOC (0.0034#/mmBtu), Fl (0.0004#/mmBtu, RM-average), Hg18e-6 #/MWhr(1.98#/TBtu)

NOx-SCRFF, SO2-coal), PbMACT
ATTACHMENT 10-C

EPA Region IV Summary of BACT Determinations for Coal Fired Power Plants (March 2005) 

Nebraska Municipal Energy 

Agency of Nebraska (colocated at existing City of Hastings, Gerald Whelan Energy Center)

Hastings Addition of one 220 MW (2,210.5 

MMBTU/hr) pulverized coal dry bottom boiler, 74 MMBTU/hr auxiliary boiler, diesel-fired 800 kW emergency generator, 50 hp diesel-fire fire pump

220 Oct '02 SO2 (0.12 #/mmBtu,30d); NOx (0.08 

#/mmBtu, 30d); CO (0.15 #/mmBtu, 3h); PM10 (0.018 #/mmBtu,3h); Fluorides (0.0004 #/mmBtu)

NOx-SCRSO2-DLSPb-FF, V
ATTACHMENT 10-C

EPA Region IV Summary of BACT Determinations for Coal Fired Power Plants (March 2005) 

EPA Region 8Colorado Tri-State Generation 

and Transmission Association

Southeastern Colorado

1200 MWe.

Colorado Colorado Springs 

Utilities

Colorado Springs (El Paso)

Addition of one 150 MW Circulating Fluidized Bed coal combustion boiler with fully integrated, multi-layered emission controls to produce what is predicted to be the cleanest coal plant in the world. Will demonstrate fuel flexibility for western & eastern coals, as well as waste coals. 

150 Preapplication 

meeting only.

Colorado Xcel Energy, 

Comanche Station

Pueblo (Pueblo) 

Addition of Unit 3, an approximately 750 MW super critical pulverized coal boiler to the existing Comanche Station.

750 9/10/2004 

Revised 1/19/05

PM/PM10 NOx - SCCO/VOC HAPs - csorbent i

Montana Composite Energy, 

Bear Creak

2000

Montana Bull Mountain 

Development Company, No.1, LLC. 

Roundup (Musselshell)

The Power Plant will consist of two coal-fired generating units and auxiliary equipment. Each unit will have a pulverized coal-fired boiler and steam turbine-generator with a gross electrical output of 390 MW. Pollution controls: dry FGD, SCR, and pulse jet baghouse.

780 16-Jan-02 PM10 (filt) - 0.015 (source test - 

submit emissions for consideration of lowering to 0.012 after 18 mo); NOx - 0.07 (24-hr ave) & 0.1 (1-hr ave); SO2 - 0.15 (1-hr ave) & 0.12 (24-hr ave); CO - 0.15 (source test); VOC - 0.003 (no ave); SAM - 0.0064 (sour

PM/PM10 NOx - SCCO/VOC 

Montana Rocky Mountain 

Power, Inc. (Bison)

Hardin, Montana

Pulverized coal-fired boiler (1968 vintage) with a heat input of up to 1,304 MMBtu/hr to produce up to 900,000 pounds of steam pounds per hour. 

113 116 31-Jan-02 PM/PM10 (filt) - 0.012 (source test); 

PM/PM10 (cond) - 0.024; NOx - 0.09 (30-day ave); SO2 - 0.14 (1-hr 

ave, increment) & 0.11 (30-day ave, BACT); CO - 0.15 (source test); VOC - 0.0034 (no ave) SAM - 0.0063 (1-hr); HCl - 0.00118; HF - 0.00051; All limits in lb/MMBtu. Hg - 5.8 lb/Tbtu (1 hr ave)

PM/PM10 

venturi sc

NOx - SC

scrubber 

CO/VOC 

North Dakota Great River Energy Applied for some funding under ND's 

Lignite Vision 21 Project

500

North Dakota Montana-Dakota 

Utilities, Westmoreland Power Inc.

Gascoyne (BowNew power plant consisting of one 

circulating fluidized bed boiler burning lignite from an adjacent mine with the following pollution controls: fabric filter baghouse, selective non-catalytic reduction (SNCR), dry lime scrubber with limestone injection.

175 14-May-04

South Dakota NoneUtah Intermountain Power 

Service Corp

Delta (Millard) Add Unit 3 to existing power plant 

(pulverized coal fired) with fabric filter baghouse, low NOx burners and SCR, forced oxidation wet limestone FGD system, and combustion controls (CO & VOC).

950 09-Dec-02 PM (filt) - 0.013 (3 test runs); PM10 

(filt) - 0.012 (3-test runs) ; PM10 (total) - 221 lb/hr (0.024 lb/MMBtu equiv - 24 hr block); NOx - 0.07 (30-day); SO2 - 0.10 (24-hr) & 0.09 (30-day); CO - 0.15 (30-day); VOC - 0.0027 (3 test runs); SAM - 0.0044 (24-hr block); Hg (bituminous) - 6.0 E-06 lb/MWhr (12-mo roll); Hg (subbituminous) - 20 E-06 lb/MWhr); Fluorides/HF - 0.0005 (3 test runs); Lead - 0.00002 ( 3 test runs)

PM/PM10 baghousewet FGDcombusticobenefit 
ATTACHMENT 10-C

EPA Region IV Summary of BACT Determinations for Coal Fired Power Plants (March 2005) 

Utah NEVCO Energy Sevier (Sevier) New power plant consisting of one 

circulating fluidized bed boiler with the following pollution controls: fabric filter baghouse, selective non-catalytic reduction (SNCR), dry lime scrubber with limestone injection, combustion controls (CO).

270 10-Sep-03 PM/PM10 (filt) - 0.0154 (24-hr); NOx 

- 0.1 (24-hr); SO2 - 0.05 (24-hr) & 0.022 (30-day); CO - 0.115 (1-hr); VOC - no limit; SAM - 0.0024 (24-hr); Hg - 4.0 E-07 (M29l); Fluorides - 0.00019 (M13A); HF - 0.005 (M26A); Lead - 0.0000113 (M12 or M29); HCl - 4.01 lb/hr (M26A)

PM/PM10 leak deteSO2 - dry CO/VOC HAPs - c

Utah PacifiCorp - Hunter Castle Dale 

(Emery)

Add Unit 4 to existing power plant (pulverized coal fired) with fabric filter baghouse, low NOx burners and SCR, and forced oxidation wet lime scrubber system, and combustion controls (CO & VOC).

575 14-Nov-03

Utah (Tribal Land) Deseret Generation & 

Transmission - Bonanza 

Bonanza (Uintah)

Add one circulating fluidized bed boiler (waste coal) to existing power plant with fabric filter baghouse, selective non-catalytic reduction (SNCR), limestone injection, and combustion controls (CO and VOC).

110 14-Apr-04

Wyoming Independent Energy 

Group of Black Hills Corporation @ Wygen Unit 1

Gillette Pulverized coal fired Electric 

Generating Plant

80 04-Jun-96 PM(filt): 0.02, SO2:0.20(2-hr rolling), 

0.17 (30-day), NOx: 0.22(30-day rolling), 0.2(365-day rolling), CO: 0.15, 0.015

PM-ESPCDS, VOcontrol

Wyoming Black Hills Power and 

Light (WYGEN 2)

Gillette Pulverized Coal Fired Electric 

Generating Plant

500 26-Apr-02 PM/PM10 (filt): 0.012 (source test); 

SO2: 0.1 (30-day ave) 0.15 (3-hr block); NOx: 0.07 (30 day); CO: 0.15 (source test), VOC: 0.01 (source test). Limits in lb/MMBtu.

PM10 - mscrubberSpray dry

combusti

Wyoming North Amercian Power 

Group

Wright 274

Wyoming Ziegler Coal Holding Wright 240EPA Region 9Arizona Unisource Energy @ 

Tuscon Electric's Springerville Station

Tucson 2 - 360 MW units, final committment 

to procede, July 2001, online 2004 and 2005

720

New Mexico (NavaSTEAG Power - 

Desert Rock Energy Facility

25 miles SW of Farmington, NM 

2 x 750 MW greenfield, mine mouth plant

1500 25-Feb-04

New Mexico (NavaBHP Billiton - 

Cottonwood Energy Center

Four Corners area, NM

One 550 MW coal-fired sub-critical boiler, 495 net.

495 23-Mar-04 NOx (0.06 lb/mmbtu), CO (0.14 

lb/mmbtu), SO2 (0.06 lb/mmbtu), VOC (0.0072 lb/mmbtu), PM10 (0.02 lb/mmbtu)

NOx - LNlimestone baghouse

California NoneHawaii NoneNevada Duke Energy (White Pine) 2 - 650 MW coal-fired units Conceptual

Nevada LS Power White Pine 

area near UT border

1000 MW 1000 Conceptual

Nevada Sempra Energy - 

Granite Fox Power

Gerlach (Washoe)

1450 MW greenfield plant 1450

Nevada Newmont Mining, TS 

Power Plant

Eureka County 200 MW pulverized coal-fired boiler 

(four oil-fired combustion turbines to be used for back-up power).

200 01-Oct-04 NOx (0.067 lb/MMBTU, 30-day 

rolling average); CO (0.15 lb/MMBTU, 24-rolling average); SO2 (0.09 lbs/MMBTU 24-hr rolling average); PM/PM10 0.038 lbs/MMBTU (24-hr rolling average)

Low-NOx combusticoal and filters

American Samoa NoneGuam None
ATTACHMENT 10-C

EPA Region IV Summary of BACT Determinations for Coal Fired Power Plants (March 2005) 

EPA Region 10Alaska Arctic Slope Regional 

Corporation

Point Lay (North Slope Borough)

Greenfield coal-fired power plant at mine mouth.

Alaska Golden Valley Electric 

Association

Healy (Denali Borough)

Retrofit existing Department of Energy Clean Coal Technology pulverized coal boiler to a conventional system. The boiler has been idle since 1999.

50 None submitted

Idaho Sempra Energy 

Resources

King Hill (Elmore County)

Coal-fired power plant is being considered.

? None submitted

Idaho Undetermined ShoshoneBannock 

Reservation outside Pocatello (Bannock)

Coal-fired power plant using PRB coal 550 None submitted

Idaho Southeast Idaho 

Energy LLC 

Power County and Fort Hall Indian Reservation outside Pocatello

IGCC 520 None submitted 01-Jan-10

Oregon Portland General 

Electric

Boardman (Morrow)

Additional coal-fired power generation at existing coal-fired power plant.

Oregon PacifiCorp ? ? 500 None submittedWashington Composite Power Richland 

(Benton County)

Develop former Washington Public Power Supply System sites 1&4.

2500 None submitted

Washington US Electric Power Blaine 

(Whatcom County)

Earliest on-line projection is April 2004.
ATTACHMENT 10-D 

RACT / BACT / LAER CLEARINGHOUSE DATA FOR OIL-FIRED BOILERS
FACILITY STATE PERMIT 

NUMBER

 PERMIT 

DATE

DESCRIPTION EMISSION 

LIMIT 

Lb/MMBtu

CONTRO

River Hill Power Company PA 17-00055A 7/21/2005 Auxiliary Boiler -- -- 0.09 Low-NOx BMN Municipal Power Agency - Fairbault Energy Park MN 13100071-001 7/15/2004 Auxiliary Boiler 40 MMBTUH 0.058 Low-NOx BNebraska Public Power District - Beatrice Power Station NE 76739C01 6/22/2004 Auxiliary Boiler 73.3 MMBTUH 0.10 None IdentBiomass Energy, LLC - South Point Power OH 07-00534 1/5/2004 Auxiliary Boiler 227 MMBTUH 0.19 None IdentUS DOE - Hanford WA PSD-02-01 11/13/2003 Fire-tube boilers 50.2 MMBTUH 0.09 Low-NOx BAbbott Laboratories - Sturgis Plant MI 64-03 9/16/2003 Boiler 98.51 MMBTUH 0.14 Low-NOx BColumbia Energy Center SC 0460-0024-CE 7/3/2003 Fuel Oil Boiler 550 MMBTUH 0.12 Low-NOx BCity of Harrisonburg - Harrisonburg Resource Recovery Facility VA 81016 3/24/2003 Boiler No. 2 43.2 MMBTUH 6.17 lb/hr Low-NOx BThoroughbred Generating Company, LLC KY V-02-001 10/11/2002 Auxiliary Boiler 300 MMBTUH 0.12 Good Oper

Limited to < 

Longview Fibre Company WA PSD-01-03 12/10/2001 Power Boilers 12, 13 444 MMBTUH 0.73 None IdentLongview Fibre Company WA PSD-01-03 12/10/2001 Power Boiler #16 525 MMBTUH 0.73 None IdentLongview Fibre Company WA PSD-01-03 12/10/2001 Power Boiler #20 900 MMBTUH 0.30 None IdentLongview Fibre Company WA PSD-01-03 12/10/2001 Power Boiler #17 591 MMBTUH 0.73 None IdentCentral Soya Company, Inc. OH 03-13369 11/29/2001 Boiler 91.2 MMBTUH 0.106 Low-NOx bAES Red Oak, LLC NJ 10001 10/24/2001 Auxiliary Boiler 99.0 MMBTUH 0.10 Limited to 3International Paper - Mansfield Mill LA PSD-LA-93 (M-6) 8/14/2001 Power Boilers 645 MMBTUH 0.30 Low-NOx B

NOx Emiss

Columbia Energy Center SC 0460-0024 4/9/2001 Auxiliary Boiler 350 MMBTUH 0.12 Low-NOx BGrays Ferry Cogen Partnership PA 97019 3/21/2001 Auxiliary Boiler 1119 MMBTUH 0.15 Low-NOx BMobile Energy, LLC - Hog Bayou AL 503-8066-X003 6/7/2000 Oil Backup 378 MMBTUH 0.15 Low-NOx BDegussa Corporation AL 503-5011-X046 9/29/1997 Boiler 355 MMBTUH 0.12 Low-NOx BRayonier Specialty Pulp Products GA 2631-151-12433 6/16/1007 Boiler 338 MMBTUH 0.10 Low-NOx BPedrickton Cogeneration Plant NJ 096453,55,57 9/19/1995 Auxiliary Boilers, 2 - Kerosene 262 MMBTUH 0.15 Low-NOx B

THROUGHPUT

RACT/BACT/LAER Clearinghouse Results for Oil-Fired Boilers (NOx)

Attachment 10-D

Att 10-D_OilFired Boilers_RBLC.xlsNOx 
FACILITY STATE PERMIT 

NUMBER

 PERMIT 

DATE

BOILER TYPE EMISSION 

LIMIT 

lb/MMBtu

CONTROL D

River Hill Power Company PA 17-00055A 7/21/2005 Auxiliary Boiler -- -- 0.077 None Identified Mirant Mid-Atlantic, LLC - Dickerson MD CPCN CASE NO. 8888 11/5/2004 Auxiliary Boiler 60 MMBTUH 0.150 Good Combustio

Fuel 

MN Municipal Power Agency - Fairbault Energy Park MN 13100071-001 7/15/2004 Auxiliary Boiler 40 MMBTUH 0.036 Good CombustioBiomass Energy, LLC - South Point Power OH 07-00534 1/5/2004 Auxiliary Boiler 227 MMBTUH 0.12 None Identified Columbia Energy Center SC 0460-0024-CE 7/3/2003 Fuel Oil Boiler 550 MMBTUH 0.04 Good Combustio

Fuel 

City of Harrisonburg - Harrisonburg Resource Recovery Facility VA 81016 3/24/2003 Boiler No. 2 43.2 MMBTUH 3.56 lb/hr Good Combustio

Fuel 

Thoroughbred Generating Company, LLC KY V-02-001 10/11/2002 Auxiliary Boiler 300 MMBTUH 0.06 Good Operating 

to < 500 hrs/yr 

Longview Fibre Company WA PSD-01-03 12/10/2001 Power Boilers 12, 13 444 MMBTUH 2.0 None Identified Longview Fibre Company WA PSD-01-03 12/10/2001 Power Boiler #16 525 MMBTUH 1.0 None Identified Longview Fibre Company WA PSD-01-03 12/10/2001 Power Boiler #20 900 MMBTUH 1.0 None Identified Longview Fibre Company WA PSD-01-03 12/10/2001 Power Boiler #17 591 MMBTUH 1.0 None Identified Central Soya Company, Inc. OH 03-13369 11/29/2001 Boiler 91.2 MMBTUH 0.140 None Identified AES Red Oak, LLC NJ 10001 10/24/2001 Auxiliary Boiler 99.0 MMBTUH 0.10 Good CombustioInternational Paper - Mansfield Mill LA PSD-LA-93 (M-6) 8/14/2001 Power Boilers 645 MMBTUH 0.036 Good CombustioColumbia Energy Center SC 0460-0024 4/9/2001 Auxiliary Boiler 350 MMBTUH 0.04 Good CombustioGrays Ferry Cogen Partnership PA 97019 3/21/2001 Auxiliary Boiler 1119 MMBTUH 0.04 Good CombustioMobile Energy, LLC - Hog Bayou AL 503-8066-X003 6/7/2000 Oil Backup 378 MMBTUH 0.16 Good CombustioDegussa Corporation AL 503-5011-X046 9/29/1997 Boiler 355 MMBTUH 0.09 Good CombustioRayonier Specialty Pulp Products GA 2631-151-12433 6/16/1007 Boiler 338 MMBTUH 0.12 Good CombustioPedrickton Cogeneration Plant NJ 096453,55,57 9/19/1995 Auxiliary Boilers, 2 - Kerosene 262 MMBTUH 0.164 Good Combustio

THROUGHPUT

RACT/BACT/LAER Clearinghouse Results for Oil-Fired Boilers (CO)

Attachment 10-D

Att 10-D_OilFired Boilers_RBLC.xlsCO 
FACILITY STATE PERMIT 

NUMBER

 PERMIT 

DATE

BOILER TYPE EMISSION 

LIMIT 

lb/MMBtu

CONTROL 

River Hill Power Company PA 17-00055A 7/21/2005 Auxiliary Boiler -- -- 0.203 None Identified Mirant Mid-Atlantic, LLC - Dickerson MD CPCN CASE NO. 8888 11/5/2004 Auxiliary Boiler 60 MMBTUH 0.050 Good Combustio

Fuel 

MN Municipal Power Agency - Fairbault Energy Park MN 13100071-001 7/15/2004 Auxiliary Boiler 40 MMBTUH 0.051 Fuel Sulfur LimiteBiomass Energy, LLC - South Point Power OH 07-00534 1/5/2004 Auxiliary Boiler 227 MMBTUH 0.0125 Fuel Sulfur LimiteColumbia Energy Center SC 0460-0024-CE 7/3/2003 Fuel Oil Boiler 550 MMBTUH 0.06 Low Sulfur Fuels City of Harrisonburg - Harrisonburg Resource Recovery Facility VA 81016 3/24/2003 Boiler No. 2 43.2 MMBTUH 2.19 lb/hr Good Combustio

Fuel 

Thoroughbred Generating Company, LLC KY V-02-001 10/11/2002 Auxiliary Boiler 300 MMBTUH 0.05 Good Operating P

< 500 hrs/yr 

Longview Fibre Company WA PSD-01-03 12/10/2001 Power Boilers 12, 13 444 MMBTUH 0.24 None Identified Longview Fibre Company WA PSD-01-03 12/10/2001 Power Boiler #16 525 MMBTUH 0.59 Low Sulfur Fuels Longview Fibre Company WA PSD-01-03 12/10/2001 Power Boiler #20 900 MMBTUH 0.25 Low Sulfur Fuels Longview Fibre Company WA PSD-01-03 12/10/2001 Power Boiler #17 591 MMBTUH 0.59 Low Sulfur Fuels Central Soya Company, Inc. OH 03-13369 11/29/2001 Boiler 91.2 MMBTUH 0.21 Fuel Sulfur Conte

0.5% by wt. 

AES Red Oak, LLC NJ 10001 10/24/2001 Auxiliary Boiler 99.0 MMBTUH 0.0507 Low Sulfur Fuels International Paper - Mansfield Mill LA PSD-LA-93 (M-6) 8/14/2001 Power Boilers 645 MMBTUH 0.8 Fuel Sulfur Conte

0.7% by wt. 

Columbia Energy Center SC 0460-0024 4/9/2001 Auxiliary Boiler 350 MMBTUH 0.0616 Low Sulfur Fuels Grays Ferry Cogen Partnership PA 97019 3/21/2001 Auxiliary Boiler 1119 MMBTUH 0.215 Good Combustio

Rayonier Specialty Pulp Products GA 2631-151-12433 6/16/1007 Boiler 338 MMBTUH NA Fuel Sulfur LimitePedrickton Cogeneration Plant NJ 096453,55,57 9/19/1995 Auxiliary Boilers, 2 - Kerosene 262 MMBTUH 0.04 Fuel Sulfur Limite

THROUGHPUT

RACT/BACT/LAER Clearinghouse Results for Oil-Fired Boilers (SO2)

Attachment 10-D

Att 10-D_OilFired Boilers_RBLC.xlsSO2 
FACILITY STATE PERMIT 

NUMBER

 PERMIT 

DATE

BOILER TYPE EMISSION 

LIMIT 

Lb/MMBtu

CONTROL D

River Hill Power Company PA 17-00055A 7/21/2005 Auxiliary Boiler -- -- 0.005 None Identified MN Municipal Power Agency - Fairbault Energy Park MN 13100071-001 7/15/2004 Auxiliary Boiler 40 MMBTUH 0.003 Good Combustion Columbia Energy Center SC 0460-0024-CE 7/3/2003 Fuel Oil Boiler 550 MMBTUH 0.004 Good Combustion PCity of Harrisonburg - Harrisonburg Resource Recovery Facility VA 81016 3/24/2003 Boiler No. 2 43.2 MMBTUH 0.23 lb/hr Good Combustion PThoroughbred Generating Company, LLC KY V-02-001 10/11/2002 Auxiliary Boiler 300 MMBTUH 0.03 Good Operating Pra

500 hrs/yr 

Central Soya Company, Inc. OH 03-13369 11/29/2001 Boiler 91.2 MMBTUH 0.0140 None Identified AES Red Oak, LLC NJ 10001 10/24/2001 Auxiliary Boiler 99.0 MMBTUH 0.0050 Low Sulfur Fuels International Paper - Mansfield Mill LA PSD-LA-93 (M-6) 8/14/2001 Power Boilers 645 MMBTUH 100 LB/HR Good Combustion PColumbia Energy Center SC 0460-0024 4/9/2001 Auxiliary Boiler 350 MMBTUH 1.75 LB/HR Good Combustion PGrays Ferry Cogen Partnership PA 97019 3/21/2001 Auxiliary Boiler 1119 MMBTUH 0.01 Good Combustion PMobile Energy, LLC - Hog Bayou AL 503-8066-X003 6/7/2000 Oil Backup 378 MMBTUH 0.005 Good Combustion PPedrickton Cogeneration Plant NJ 096453,55,57 9/19/1995

Auxiliary 

Boilers, 2 - 

Kerosene

262 MMBTUH 0.023 Good Combustion P

THROUGHPUT

RACT/BACT/LAER Clearinghouse Results for Oil-Fired Boilers (VOC)

Attachment 10-D

Att 10-D_OilFired Boilers_RBLC.xlsVOC 
FACILITY STATE PERMIT 

NUMBER

 PERMIT 

DATE

BOILER TYPE EMISSION 

LIMIT 

lb/MMBtu

CONTROL 

River Hill Power Company PA 17-00055A 7/21/2005 Auxiliary Boiler -- -- 0.030 None Identified Omaha Public Power District - Nebraska City Station NE 58343C01 3/9/2005 Auxiliary Boiler #2 -- -- 0.001 Fuel Sulfur Lim

S; limited to 50

Mirant Mid-Atlantic, LLC - Dickerson MD CPCN CASE NO. 8888 11/5/2004 Auxiliary Boiler 60 MMBTUH 0.050 Good Combust

Clean Fuel 

MN Municipal Power Agency - Fairbault Energy Park MN 13100071-001 7/15/2004 Auxiliary Boiler 40 MMBTUH 0.024 Good Combust

Clean Fuel 

Biomass Energy, LLC - South Point Power OH 07-00534 1/5/2004 Auxiliary Boiler 227 MMBTUH 0.040 Fuel Sulfur Lim

S 

US DOE - Hanford WA PSD-02-01 11/13/2003 Fire-tube boilers 50.2 MMBTUH 0.020 Ultra Low Sulfu

Combustion Pr

Columbia Energy Center SC 0460-0024-CE 7/3/2003 Fuel Oil Boiler 550 MMBTUH 0.024 Good CombustCity of Harrisonburg - Harrisonburg Resource Recovery Facility VA 81016 3/24/2003 Boiler No. 2 43.2 MMBTUH 0.62 lb/hr Good CombustThoroughbred Generating Company, LLC KY V-02-001 10/11/2002 Auxiliary Boiler 300 MMBTUH 0.06 Good Operatin

Limited to < 50

Longview Fibre Company WA PSD-01-03 12/10/2001 Power Boilers 12, 13 444 MMBTUH 0.10 None Identified Longview Fibre Company WA PSD-01-03 12/10/2001 Power Boiler #16 525 MMBTUH 0.21 None Identified Longview Fibre Company WA PSD-01-03 12/10/2001 Power Boiler #20 900 MMBTUH 0.093 None Identified Longview Fibre Company WA PSD-01-03 12/10/2001 Power Boiler #17 591 MMBTUH 0.20 None Identified Central Soya Company, Inc. OH 03-13369 11/29/2001 Boiler 91.2 MMBTUH 0.0054 Fuel Sulfur Con

Exceed 0.5% b

AES Red Oak, LLC NJ 10001 10/24/2001 Auxiliary Boiler 99.0 MMBTUH 0.040 None Identified International Paper - Mansfield Mill LA PSD-LA-93 (M-6) 8/14/2001 Power Boilers 645 MMBTUH 0.1 Single-stage duColumbia Energy Center SC 0460-0024 4/9/2001 Auxiliary Boiler 350 MMBTUH 0.03 Good CombustGrays Ferry Cogen Partnership PA 97019 3/21/2001 Auxiliary Boiler 1119 MMBTUH 0.0032 Good CombustMobile Energy, LLC - Hog Bayou AL 503-8066-X003 6/7/2000 Oil Backup 378 MMBTUH 0.01 Good CombustRayonier Specialty Pulp Products GA 2631-151-12433 6/16/1007 Boiler 338 MMBTUH 0.05 Fuel Sulfur Lim

S 

Pedrickton Cogeneration Plant NJ 096453,55,57 9/19/1995 Auxiliary Boilers, 2 - Kerosene 262 MMBTUH 0.02 Good Combust

THROUGHPUT

RACT/BACT/LAER Clearinghouse Results for Oil-Fired Boilers (PM-PM10)

Attachment 10-D

Att 10-D_OilFired Boilers_RBLC.xlsPM-PM10 
FACILITY STATE PERMIT 

NUMBER

 PERMIT 

DATE

BOILER TYPE EMISSION LIMIT CONTROL DESCRIPTI

Columbia Energy Center SC 0460-0024 4/9/2001 Auxiliary Boiler 350 MMBTUH 10 LB/HR Low Sulfur Fuel & Combu

Controls 

Pedrickton Cogeneration Plant NJ 096453,55,57 9/19/1995

Auxiliary 

Boilers, 2 - 

Kerosene

262 MMBTUH 0.0033 Lb/MMBtu Low Sulfur Fuel & Combu

Controls 

THROUGHPUT

RACT/BACT/LAER Clearinghouse Results for Oil-Fired Boilers (H2SO4)

Attachment 10-D

Att 10-D_OilFired Boilers_RBLC.xls

H2SO4 
ATTACHMENT 10-E 

RACT / BACT / LAER CLEARINGHOUSE DATA FOR DIESEL-FIRED 

ENGINES > 500 HP
FACILITY STATE PERMIT NUMBER PERMIT DATE DESCRIPTION CONTROL DESCRI

KANSAS CITY PUBLIC UTILITIES - NEARMAN CREEK STATION KS C-570 10/18/2005 EMERGENCY BLACK START GENERATOR 2800 KW 84.8 LB/HR GOOD COMBUSTION CONTROL ARIZONA CLEAN FUELS YUMA LLC AZ 1001205 4/14/2005 FIRE WATER PUMP ENGINES 5.46 MMBTU/H 4 GR/KW-HR NONE INDICATED - LIMIT IS FOR ARIZONA CLEAN FUELS YUMA LLC AZ 1001205 4/14/2005 EMERGENCY GENERATOR 10.9 MMBTU/H 6.4 GR/KW-HR NONE INDICATED - LIMIT IS FOR JOHN DEERE PRODUCT ENGINEERING CENTER IA

PROJECT NUMBER 00-

648 3/23/2005 TEST CELL 24.5 gal/h 1.52 LB/MMBTU GOOD COMBUSTION PRACTICE

FIRST QUALITY TISSUE, LLC PA 18-315-001 10/20/2004 FIRE PUMP 575 hp 0.031 LB/HP-H 

PSI ENERGY-MADISON STATION OH 14-04682 8/24/2004 EMERGENCY DIESEL GENERATOR, 2 17.21 MMBTU/H 55.07 LB/H FAIRBAULT ENERGY PARK MN 13100071-001 7/15/2004 IC ENGINE, LARGE, FUEL OIL (1) 670 HP 3.28 LB/MMBTU GOOD COMBUSTION.LONGVIEW POWER LLC - MAIDSVILLE WV R14-0024 3/2/2004 EMERGENCY GENERATOR 1801 HP 20.9 LB/HR GOOD COMBUSTION PRACTICEU.S. ARMY - PINE BLUFF ARSENAL AR 1113-AOP-R0 2/17/2004 EMERGENCY GENERATORS (2) 2500 KW 33.9 LB/HR NONE INDICATED ACE ETHANOL - STANLEY WI 03-DCF-184 1/21/2004 IC ENGINE, DIESEL GENERATOR SET, B70 1850 BHP 13 G/HP-H

LIMIT ON HOURS OF OPERATION MO. AVG.) 

MANKATO ENERGY CENTER MN 01300098-001 12/4/2003 INTERNAL COMBUSTION ENGINE, LARGE 1850 HP 12.7 G/B-HP-H GOOD COMBUSTION DUTCH HARBOR SEAFOOD PROCESSING FACILITY AK 433CP01(MOD) 10/10/2003 IC ENGINE, GENERATOR, FUEL OIL, (3) 2220 KW 42.3 LB/H WATER INJECTION, LOW NOX DUSAF EARECKSON AIR STATION AK 307CP01 9/29/2003 IC ENGINE, DIESEL, (2) 3000 KW 9.7 LB/H SCR USAF EARECKSON AIR STATION AK 307CP01 9/29/2003 IC ENGINES GOOD COMBUSTION PRACTICEDUKE ENERGY WASHINGTON COUNTY LLC OH 06-06792 8/14/2003 EMERGENCY DIESEL-FIRED GENERATOR 600 KW 12.4 LB/H LOW SULFUR FUEL, COMBUSTIOINGENCO - CHARLES CITY PLANT VA 51998 6/20/2003 IC ENGINES, (48) 550 HP 2.4 LB/MMBTU

AIR TO FUEL RATIO CONTROL, TAND CHARGE AIR COOLING SYSFUEL RATIO SHALL BE CONTROSEPARATE ENGINE CONTROL MENGINE. 

COMPANY IA PROJECT 02-528 6/17/2003 EMERGENCY GENERATOR 97.73 GAL/HR 1.71 LB/MMBTU GOOD COMBUSTION PRACTICESTEPHENS ENERGY OK 2001-157-C M-1 PSD 3/21/2003 IC ENGINE, BACKUP GENERATOR, DIESEL 749 BHP 2.16 LB/MMBTU OPERATION (<100 H/YR) CARDINAL FG CO./ CARDINAL GLASS PLANT OK 2002-487-C PSD 3/18/2003

IC ENGINES, EMERGENCY GENERATORS (2) 2000 KW 2.035 LB/MMBTU

ENGINE DESIGN AND LIMIT ON HOPERATION (<500 H/YR) 

PACIFIC BELL CA 16290 2/1/2003 IC ENGINES 2935 HP 6.9 G/B-HP-H 

ROQUETTE AMERICA IA 56-01-009 1/31/2003 IC ENGINE, DIESEL 710 HP 3.1 LB/MMBTU GOOD COMBUSTION PRACTICEBRIDGESTONE/FIRESTONE NORTH AMERICAN TIRE NC 01660T42 1/24/2003

IC ENGINES, AIR COMPRESSORS, DIESEL, (5) 4.46 MMBTU/H 7.8 LB/H IGNITION TIMING RETARD 

STERNE ELECTRIC GENERATING FACILITY TX PSD-TX-1015 12/6/2002 EMERGENCY GENERATOR 1350 HP 41.9 LB/H ORCHARD PARK GENERATING STATION PA 28-05031 11/8/2002 ENGINE-GENERATOR 8086 B-HP 1.5 G/B-HP-H

LEAN BURN, SCR, LOW EMISSIOCONTROL 

CITY OF PELLA IA PROJ. NO. 01-238 9/25/2002 IC ENGINES, DIESEL, (14) 144 G/H 1.71 LB/MMBTU COMBUSTION AIR CHILLER UNIVERSITY OF CINCINNATI OH 14-05108 8/15/2002

DIESEL FIRED ENGINES (2), 2 MW, 2922 BHP 19.17 MMBTU/H 40.92 LB/H 

HAWKEYE GENERATING, LLC IA 01-687 7/23/2002 EMERGENCY GENERATOR 18500 GALLONS/YR 10.61 LB/H GCP, TIMING RETARD GENOVA OK I POWER PROJECT OK 2001-223-C PSD 6/13/2002 DIESEL ENGINE, BACKUP GENERATOR 750 KW 3.01 LB/MMBTU ENGINE DESIGN AND LIMITATIOSCE&G - JASPER COUNTY GENERATING FACILITY SC 1360-0026-CA-CC 5/23/2002 GENERATOR, EMERGENCY,DIESEL FUEL 2000 KW 59.5 LB/H PHELPS DODGE TYRONE, INC NM PSD-NM-2488A 5/20/2002 IC ENGINES, NON-DUAL FUEL MODE, (15) 3090 HP/H 31.4 LB/H GOOD OPERATING PRACTICE REDBUD POWER PLT OK 2000-090-C M-1 PSD 5/6/2002

DIESEL ENGINE, EMERGENCY GENERATOR 1818 HP 0.024 LB/B-HP-H 

THROUGHPUT

RACT/BACT/LAER Clearinghouse Results for Diesel-Fired Engines > 500 HP (NOX)

Attachment 10-E

EMISSION LIMIT

Att 10-E_Diesel-Fired IC Engines over 500HP_RBLC.xlsNOx 
FACILITY STATE PERMIT NUMBER PERMIT DATE DESCRIPTION THROUGHPUT CONTROL DESCRI

RACT/BACT/LAER Clearinghouse Results for Diesel-Fired Engines > 500 HP (NOX)

Attachment 10-E

EMISSION LIMIT

GREATER DES MOINES ENERGY CENTER IA 77-13-002 4/10/2002 EMERGENCY GENERATOR 700 KW 22.69 LB/H RETARDED INGITION TIMING (3-DUKE ENERGY-JACKSON FACILITY AR

1998-AOP-R0 (34-

0259) 4/1/2002 GENERATOR, DIESEL-FIRED 671 HP 14 G/B-HP-H GOOD OPERATING PRACTICE 

AES RED OAK LLC NJ 10001 10/24/2001 EMERGENCY GENERATOR 49 MMBTU/H 159.65 LB/H LIMITED USE FORT BRAGG NC 04379T21 8/20/2001 IC ENGINES, DIESEL, (17) 44.4 T/YR

EACH GENERATOR USED IN PEASHALL OPERATE NO MORE THA

MANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001

CATERPILLAR BACK-UP DIESEL AIR COMPRESSORS, 2 775 HP EACH 38.6 LB/H PREVENTATIVE MAINTENANCE 

MANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001

AUXILIARY DIESEL GENERATORS NO.1 & NO.2 1100 HP EACH 34 LB/H PREVENTATIVE MAINTENANCE 

MANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001

ADMINISTRATION BUILDING DIESEL GENERATOR 587 HP 18.1 LB/H PREVENTATIVE MAINTENANCE 

PSEG WATERFORD ENERGY LLC OH 06-06739 3/29/2001 EMERGENCY GENERATOR 1000 KW 0.82 T/YR DUKE ENERGY HOT SPRINGS AR 1936-AOP-R0 12/29/2000 GENERATORS, (2) DIESEL 600 KW 14 G/B-HP-H CLEAN FUEL, COMBUSTION CONCOTTONWOOD ENERGY PROJECT TX PSD-965 12/15/2000 FIRE WATER PUMP 10.39 LB/H COTTONWOOD ENERGY PROJECT TX PSD-965 12/15/2000 EMERGENCY DIESEL GENERATOR 12.4 LB/H BADGER GENERATING CO LLC WI 99-RV-143 9/20/2000 DIESEL ENGINE, GENERATOR (4) 3.5 MMBTU/H 15.44 LB/H

GOOD COMBUSTION PRACTICESET IN LB/H, NOT G/BHP-H. 

BADGER GENERATING CO LLC WI 99-RV-143 9/20/2000 DIESEL ENGINE, EMERGENCY FIRE PUMP 3.8 MMBTU/H 16.76 LB/H

GOOD COMBUSTION PRACTICEUSAGE LIMITS. PERMIT LIMITS IN SET IN G/BHP-H 

OKEMO MOUNTAIN INC. VT OP-99-013 9/5/2000 GENERATOR, FUEL OIL 1480 BHP 1.6 G/B-HP-H SCR BRAZOS VALLEY ELECTRIC GENERATING FACILITY TX PSD-TX-966 8/23/2000 EMERGENCY GENERATOR 1350 hp 41.9 LB/H BRAZOS VALLEY ELECTRIC GENERATING FACILITY TX PSD-TX-966 8/23/2000 FIRE WATER PUMP 300 hp 9.3 LB/H FORD ELECTRONICS AND REFRIGERATION, LLC PA PA-46-0036A 6/19/2000 DIESEL ENGINES 2 MW 20.8 LB/H

JOHNSON MATHEY QXH1020-14DEGREE IGNITION RETARD. HOUEACH ENGINE, ANNUAL FOR ALL 

MILL RIVER LUMBER, LTD. VT AOP-95-081B 6/8/2000 ELECTRIC GENERATION- CATERPILLAR 1023 HP 1.7 LB/H SCR W/OXIDATION CATALYST. N

DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 IC ENGINES, DIESEL 21000000 KW-H/YR 21.9 LB/H LEAN BURN/LOW NOX PACKAGE DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #3 350 KW

FOLLOW POWER GENERATION SPECIFIED IN PROCESS NOTES

DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #5 750 KW

FOLLOW POWER GENERATION SPECIFIED IN THE PROCESS NO

DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #6 1000 KW

FOLLOW POWER GENERATION SPECIFIED IN THE PROCESS NO

DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #8 835 KW

FOLLOW THE POWER GENERATSPECIFIED IN THE PROCESS NO

DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #9 835 KW

FOLLOW POWER GENERATION SPECIFIED IN THE PROCESS NO

DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR, #10 1135 KW

FOLLOW POWER GENERATION SPECIFIED IN THE PROCESS NO

Att 10-E_Diesel-Fired IC Engines over 500HP_RBLC.xlsNOx 
FACILITY STATE PERMIT NUMBER PERMIT DATE DESCRIPTION THROUGHPUT CONTROL DESCRI

RACT/BACT/LAER Clearinghouse Results for Diesel-Fired Engines > 500 HP (NOX)

Attachment 10-E

EMISSION LIMIT

DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #11 1050 KW 24.9 LB/H

FOLLOW POWER GENERATION SPECIFIED IN THE PROCESS NOLEAN BURN/ LOW NOX ENGINE DSEPARATE AFTERCOOLER LOOELECTRONIC CONTROLS SET FOSTRATEGY. 

DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #12 1050 KW 24.9 LB/H

FOLLOW POWER GENERATION SPECIFIED IN THE PROCESS NOLEAN BURN/ LOW NOX ENGINE DSEPARATE AFTERCOOLER LOOELECTRONIC CONTROLS SET FOSTRATEGY. 

DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #13 1050 KW 24.9 LB/H

FOLLOW POWER GENERATION SPECIFIED IN THE PROCESS NO

KENAI REFINERY AK 9923-AC010 3/21/2000 UPPER TANK FARM CAT 3412DT, P708C 660 HP 3.1 LB/MMBTU NONE INDICATED. KENAI REFINERY AK 9923-AC010 3/21/2000 EMERGENCY GENERATOR, CF-G-70003 2 MW 7 G/KW-H

AFTER-COOLING COMBINED WITPRESSURE FUEL INJECTION PUCYLINDER DESIGN TO ENSURE THE CYLINDER. 

KENAI REFINERY AK 9923-AC010 3/21/2000 EMERGENCY GENERATOR, CF-G-70004 2 MW 7 G/KW-H

AFTER-COOLING COMBINED WITPRESSURE FUEL INJECTION PUCYLINDER DESIGN TO ENSURE THE CYLINDER. 

SAN JUAN REPOWERING PROJECT PR 5 3/2/2000 AUXILIARY DIESEL GENERATOR 5000 KW 168 LB/H (AS NO2) GOOD COMBUSTION CONTROL 

ARCHER GENERATING 

STATION TX PSD-TX-937 1/3/2000 EMERGENCY ELECTRICAL GENERATOR 2000 KW 46.8 LB/H 

Att 10-E_Diesel-Fired IC Engines over 500HP_RBLC.xlsNOx 
FACILITY STATE PERMIT NUMBER PERMIT 

DATE

DESCRIPTION CONTROL DESCR

KANSAS CITY PUBLIC UTILITIES - NEARMAN CREEK STATION KS C-570 10/18/2005 EMERGENCY BLACK START GENERATOR 2800 KW 7.01 LB/HR GOOD ENGINE DESIGN 

ARIZONA CLEAN FUELS YUMA LLC AZ 1001205 4/14/2005 FIRE WATER PUMP ENGINES 5.46 MMBTU/H 3.5 GR/KW-HR NONE INDICATED. ARIZONA CLEAN FUELS YUMA LLC AZ 1001205 4/14/2005 EMERGENCY GENERATOR 10.9 MMBTU/H 3.5 GR/KW-HR NONE INDICATED FIRST QUALITY TISSUE, LLC PA 18-315-001 10/20/2004 FIRE PUMP 575 hp 0.0067 LB/HP-H PSI ENERGY-MADISON STATION OH 14-04682 8/24/2004 EMERGENCY DIESEL GENERATOR, 2 17.21 MMBTU/H 14.63 LB/H FAIRBAULT ENERGY PARK MN 13100071-001 7/15/2004 IC ENGINE, LARGE, FUEL OIL (1) 670 HP 0.76 LB/MMBTU GOOD COMBUSTION. LONGVIEW POWER LLC - MAIDSVILLE WV R14-0024 3/2/2004 EMERGENCY GENERATOR 1801 HP 8.85 LB/HR GOOD COMBUSTION PRAACE ETHANOL - STANLEY WI 03-DCF-184 1/21/2004

IC ENGINE, DIESEL GENERATOR SET, B70 1850 BHP 1 G/HP-H LIMITED OPERATION, DES

MANKATO ENERGY CENTER MN 01300098-001 12/4/2003

INTERNAL COMBUSTION ENGINE, LARGE 1850 HP 1 G/B-HP-H GOOD COMBUSTION 

USAF EARECKSON AIR STATION AK 307CP01 9/29/2003 IC ENGINE, DIESEL, (2) 3000 KW 4.4 LB/H SCR OXIDATION CATALYSDUKE ENERGY WASHINGTON COUNTY LLC OH 06-06792 8/14/2003

EMERGENCY DIESEL-FIRED GENERATOR 600 KW 15.2 LB/H

LOW SULFUR FUEL, COMCONTROL 

INGENCO - CHARLES CITY PLANT VA 51998 6/20/2003 IC ENGINES, (48) 550 HP 3.3 LB/MMBTU

LIMITING THE TREATED LHEAT INPUT RATION TO 5LANDFILL GAS TREATMEN

MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 EMERGENCY GENERATOR 97.73 GAL/HR 0.85 LB/MMBTU GOOD COMBUSTION PRASTEPHENS ENERGY OK 2001-157-C M-1 PSD 3/21/2003 DIESEL 749 BHP 2.66 LB/MMBTU COMBUSTION PRACTICES GLASS PLANT OK 2002-487-C PSD 3/18/2003 GENERATORS (2) 2000 KW 0.202 LB/MMBTU OF OPERATION (<500 H/YPACIFIC BELL CA 16290 2/1/2003 IC ENGINES 2935 HP 8.5 G/B-HP-H STERNE ELECTRIC GENERATING FACILITY TX PSD-TX-1015 12/6/2002 EMERGENCY GENERATOR 1350 HP 9.02 LB/H UNIVERSITY OF CINCINNATI OH 14-05108 8/15/2002

DIESEL FIRED ENGINES (2), 2 MW, 2922 BHP 19.17 MMBTU/H 1.73 LB/H 

HAWKEYE GENERATING, LLC IA 01-687 7/23/2002 EMERGENCY GENERATOR 18500 GALLONS/YR 0.22 LB/H GCP, TIMING RETARD GENOVA OK I POWER PROJECT OK 2001-223-C PSD 6/13/2002

DIESEL ENGINE, BACKUP GENERATOR 750 KW 0.31 LB/MMBTU ENGINE DESIGN 

SCE&G - JASPER COUNTY GENERATING FACILITY SC 1360-0026-CA-CC 5/23/2002

GENERATOR, EMERGENCY,DIESEL FUEL 2000 KW 15.8 LB/H 

PHELPS DODGE TYRONE, INC NM PSD-NM-2488A 5/20/2002

IC ENGINES, NON-DUAL FUEL MODE, (15) 3090 HP/H 9.4 LB/H GOOD OPERATING PRACT

REDBUD POWER PLT OK 2000-090-C M-1 PSD 5/6/2002

DIESEL ENGINE, EMERGENCY GENERATOR 1818 HP 0.055 LB/B-HP-H ENGINE DESIGN 

GREATER DES MOINES ENERGY CENTER IA 77-13-002 4/10/2002 EMERGENCY GENERATOR 700 KW 2.86 LB/H DUKE ENERGY-JACKSON FACILITY AR 1998-AOP-R0 (34-0259) 4/1/2002 GENERATOR, DIESEL-FIRED 671 HP 8.5 G/B-HP-H GOOD OPERATING PRACTAES RED OAK LLC NJ 10001 10/24/2001 EMERGENCY GENERATOR 49 MMBTU/H 1.11 LB/H GOOD COMBUSTION PRA

THROUGHPUT

Attachment 10-E

RACT/BACT/LAER Clearinghouse Results for Diesel-Fired Engines > 500 HP (CO)

EMISSION LIMIT

Att 10-E_Diesel-Fired IC Engines over 500HP_RBLC.xlsCO 
FACILITY STATE PERMIT NUMBER PERMIT 

DATE

DESCRIPTION THROUGHPUT CONTROL DESCR

Attachment 10-E

RACT/BACT/LAER Clearinghouse Results for Diesel-Fired Engines > 500 HP (CO)

EMISSION LIMIT

MANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001

CATERPILLAR BACK-UP DIESEL AIR COMPRESSORS, 2 775 HP EACH 5.4 LB/H PREVENTATIVE MAINTEN

MANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001

AUXILIARY DIESEL GENERATORS 

NO.1 & NO.2 1100 HP EACH 10.6 LB/H PREVENTATIVE MAINTEN

MANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001

ADMINISTRATION BUILDING DIESEL 

GENERATOR 587 HP 3.9 LB/H PREVENTATIVE MAINTEN

PSEG WATERFORD ENERGY LLC OH 06-06739 3/29/2001 EMERGENCY GENERATOR 1000 KW 0.22 T/YR DUKE ENERGY HOT SPRINGS AR 1936-AOP-R0 12/29/2000 GENERATORS, (2) DIESEL 600 KW 31 G/B-HP-H PROPER COMBUSTION. COTTONWOOD ENERGY PROJECT TX PSD-965 12/15/2000 FIRE WATER PUMP 2.24 LB/H COTTONWOOD ENERGY PROJECT TX PSD-965 12/15/2000 EMERGENCY DIESEL GENERATOR 2.67 LB/H BADGER GENERATING CO LLC WI 99-RV-143 9/20/2000 DIESEL ENGINE, GENERATOR (4) 3.5 MMBTU/H 3.33 LB/H

GOOD COMBUSTION PRAPERMIT LIMITS SET IN LB/H. 

BADGER GENERATING CO LLC WI 99-RV-143 9/20/2000

DIESEL ENGINE, EMERGENCY FIRE PUMP 3.8 MMBTU/H 3.61 LB/H

GOOD COMBUSTION PRAEQUIPMENT USAGE LIMITLIMITS SET IN LB/H, NO LI

H. 

OKEMO MOUNTAIN INC. VT OP-99-013 9/5/2000 GENERATOR, FUEL OIL 1480 BHP 0.6 G/B-HP-H

SCR OXIDATION CATALYSINJECTION, NO REGULAT

BRAZOS VALLEY ELECTRIC GENERATING FACILITY TX PSD-TX-966 8/23/2000 EMERGENCY GENERATOR 1350 hp 9.02 LB/H BRAZOS VALLEY ELECTRIC GENERATING FACILITY TX PSD-TX-966 8/23/2000 FIRE WATER PUMP 300 hp 2 LB/H FORD ELECTRONICS AND REFRIGERATION, LLC PA PA-46-0036A 6/19/2000 DIESEL ENGINES 2 MW 34 LB/H

HOURLY LIMIT FOR EACH ANNUAL FOR ALL FIVE EN

MILL RIVER LUMBER, LTD. VT AOP-95-081B 6/8/2000

ELECTRIC GENERATIONCATERPILLAR 3412C 1023 HP 0.6 LB/H

SCR OXIDATION CATALYSINJECTION. NO REGULATLIMIT BASED ON MANUFAGUARANTEE. 

DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #11 1050 KW 90 T/12 MO PERIOD

COMPLY WITH POWER GELIMIT AS SPECIFIED IN THNOTES. 

DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #12 1050 KW 90 T/12 MO PERIOD

COMPLY WITH POWER GELIMITS AS SPECIFIED IN PNOTES. 

DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #13 1050 KW 90 T/12 MO PERIOD

COMPLY WITH POWER GELIMITS AS SPECIFIED IN PNOTES. 

KENAI REFINERY AK 9923-AC010 3/21/2000

UPPER TANK FARM CAT 3412DT, P708C 660 HP 0.81 LB/MMBTU NONE INDICATED. 

KENAI REFINERY AK 9923-AC010 3/21/2000

EMERGENCY GENERATOR, CF-G70003 2 MW 1.95 G/KW-H GOOD OPERATIONAL PRA

MAINTENANCE 

KENAI REFINERY AK 9923-AC010 3/21/2000

EMERGENCY GENERATOR, CF-G70004 2 MW 1.95 G/KW-H GOOD OPERATIONAL PRA

MAINTENANCE 

SAN JUAN REPOWERING PROJECT PR 5 3/2/2000 AUXILIARY DIESEL GENERATOR 5000 KW 44.6 LB/H GOOD COMBUSTION PRA

ARCHER GENERATING STATION TX PSD-TX-937 1/3/2000

EMERGENCY ELECTRICAL GENERATOR 2000 KW 34.9 LB/H 

Att 10-E_Diesel-Fired IC Engines over 500HP_RBLC.xlsCO 
FACILITY STATE PERMIT NUMBER PERMIT 

DATE

DESCRIPTION CONTROL DESCRI

KANSAS CITY PUBLIC UTILITIES - NEARMAN CREEK STATION KS C-570 10/18/2005

EMERGENCY BLACK START GENERATOR 2800 KW 1.2 LB/HR GOOD COMBUSTION CONTR

PSI ENERGY-MADISON STATION OH 14-04682 8/24/2004

EMERGENCY DIESEL GENERATOR, 2 17.21 MMBTU/H 8.61 LB/H

SULFUR LIMITED TO 0.05 % BOPERATIONS LIMITED TO 49YEAR 

FAIRBAULT ENERGY PARK MN 13100071-001 7/15/2004 IC ENGINE, LARGE, FUEL OIL (1) 670 HP 0.051 LB/MMBTU LOW SULFUR FUEL. 

LONGVIEW POWER LLC - MAIDSVILLE WV R14-0024 3/2/2004 EMERGENCY GENERATOR 1801 HP 6.5 LB/HR FUEL SULFUR CONTENT LIM

U.S. ARMY - PINE BLUFF ARSENAL AR 1113-AOP-R0 2/17/2004 EMERGENCY GENERATORS (2) 2500 KW 0.6 LB/HR FUEL SULFUR CONTENT LIM

MANKATO ENERGY CENTER MN 01300098-001 12/4/2003

INTERNAL COMBUSTION ENGINE, LARGE 1850 HP 0.59 G/B-HP-H LOW SULFUR FUEL 

DUTCH HARBOR SEAFOOD PROCESSING FACILITY AK 433CP01(MOD) 10/10/2003

IC ENGINE, GENERATOR, FUEL OIL, (3) 2220 KW

LOW SULFUR FUEL: SULFUR OF 0.24% S BY WT FOR A JET NO. 2 FUEL BLEND. 

USAF EARECKSON AIR STATION AK 307CP01 9/29/2003 IC ENGINES LOW SULFUR FUEL: < 0.3% S 

DUKE ENERGY WASHINGTON COUNTY LLC OH 06-06792 8/14/2003

EMERGENCY DIESEL-FIRED GENERATOR 600 KW 0.4 LB/H LOW SULFUR FUEL, COMBUS

INGENCO - CHARLES CITY PLANT VA 51998 6/20/2003 IC ENGINES, (48) 550 HP 0.5 LB/MMBTU GOOD COMBUSTION PRACT

MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 EMERGENCY GENERATOR 97.73 GAL/HR 0.052 LB/MMBTU

GOOD COMBUSTION PRACTSULFUR FUEL 

DUKE ENERGY STEPHENS, LLC STEPHENS ENERGY OK 2001-157-C M-1 PSD 3/21/2003

IC ENGINE, BACKUP GENERATOR, DIESEL 749 BHP 0.3 LB/H

USE OF LOW SULFUR DIESE

S BY WT) 

GLASS PLANT OK 2002-487-C PSD 3/18/2003 GENERATORS (2) 2000 KW 0.05 LB/MMBTU LOW SULFUR FUEL, < 0.05% 

PACIFIC BELL CA 16290 2/1/2003 IC ENGINES 2935 HP 0.16 G/B-HP-H 

BRIDGESTONE/FIRESTONE NORTH AMERICAN TIRE NC 01660T42 1/24/2003

IC ENGINES, AIR COMPRESSORS, DIESEL, (5) 4.46 MMBTU/H 2.3 LB/MMBTU 

STERNE ELECTRIC GENERATING FACILITY TX PSD-TX-1015 12/6/2002 EMERGENCY GENERATOR 1350 HP 2.77 LB/H

DISTILLATE FUEL OIL CONTATHAN 0.2 WEIGHT PERCENT 

UNIVERSITY OF CINCINNATI OH 14-05108 8/15/2002

DIESEL FIRED ENGINES (2), 2 MW, 2922 BHP 19.17 MMBTU/H 0.043 LB/MMBTU

SULFUR CONTENT OF DIESETHAN 0.05 PERCENT. 

SCE&G - JASPER COUNTY GENERATING FACILITY SC 1360-0026-CA-CC 5/23/2002

GENERATOR, EMERGENCY,DIESEL FUEL 2000 KW 0.9 LB/H LOW SULFUR (0.05%) DIESEL 

PHELPS DODGE TYRONE, INC NM PSD-NM-2488A 5/20/2002

IC ENGINES, NON-DUAL FUEL MODE, (15) 3090 HP/H

FUEL SULFUR LIMIT: LOW SU

0.05% S BY WT) 

REDBUD POWER PLT OK 2000-090-C M-1 PSD 5/6/2002

DIESEL ENGINE, EMERGENCY GENERATOR 1818 HP 0.4 LB/MMBTU 

DUKE ENERGY-JACKSON FACILITY AR 1998-AOP-R0 (34-0259) 4/1/2002 GENERATOR, DIESEL-FIRED 671 HP FUELS LIMIT: 0.05% S BY WT 

AES RED OAK LLC NJ 10001 10/24/2001 EMERGENCY GENERATOR 49 MMBTU/H 2.45 LB/H LOW SULFUR FUEL 

FORT BRAGG NC 04379T21 8/20/2001 IC ENGINES, DIESEL, (17) 2.3 LB/MMBTU 

THROUGHPUT

Attachment 10-E

RACT/BACT/LAER Clearinghouse Results for Diesel-Fired Engines > 500 HP (SO2)

EMISSION LIMIT

Att 10-E_Diesel-Fired IC Engines over 500HP_RBLC.xlsSO2 
FACILITY STATE PERMIT NUMBER PERMIT 

DATE

DESCRIPTION THROUGHPUT CONTROL DESCRI

Attachment 10-E

RACT/BACT/LAER Clearinghouse Results for Diesel-Fired Engines > 500 HP (SO2)

EMISSION LIMIT

MANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001

CATERPILLAR BACK-UP DIESEL AIR COMPRESSORS, 2 775 HP EACH 1.6 LB/H PREVENTATIVE MAINTENANC

MANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001

AUXILIARY DIESEL GENERATORS 

NO.1 & NO.2 1100 HP EACH 2.2 LB/H PREVENTATIVE MAINTENANC

MANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001

ADMINISTRATION BUILDING DIESEL 

GENERATOR 587 HP 1.2 LB/H PREVENTATIVE MAINTENANC

PSEG WATERFORD ENERGY LLC OH 06-06739 3/29/2001 EMERGENCY GENERATOR 1000 KW 0.01 T/YR LOW SULFUR FUEL 

COTTONWOOD ENERGY PROJECT TX PSD-965 12/15/2000 FIRE WATER PUMP 0.69 LB/H 

COTTONWOOD ENERGY PROJECT TX PSD-965 12/15/2000 EMERGENCY DIESEL GENERATOR 0.82 LB/H 

BADGER GENERATING CO LLC WI 99-RV-143 9/20/2000 DIESEL ENGINE, GENERATOR (4) 3.5 MMBTU/H 1.02 LB/H

SULFUR CONTENT <= .05% BLIMITS ARE FUEL SULFUR COAND LB/H LIMIT, NOT G/BHP-

BADGER GENERATING CO LLC WI 99-RV-143 9/20/2000

DIESEL ENGINE, EMERGENCY FIRE PUMP 3.8 MMBTU/H 1.1 LB/H

THE USE OF DIESEL FUEL HACONTENT OF .05% BY WT., AUSAGE LIMITS. PERMIT LIMITSULFUR CONTENT LIMITS ANNO LIMIT IN G/BHP-H. 

BRAZOS VALLEY ELECTRIC

GENERATING FACILITY TX PSD-TX-966 8/23/2000 EMERGENCY GENERATOR 1350 hp 2.77 LB/H FUEL SULFUR LIMIT: < 0.3 WT 

BRAZOS VALLEY ELECTRIC

GENERATING FACILITY TX PSD-TX-966 8/23/2000 FIRE WATER PUMP 300 hp 0.62 LB/H FUEL SULFUR LIMITS: < 0.3 W

FORD ELECTRONICS AND

REFRIGERATION, LLC PA PA-46-0036A 6/19/2000 DIESEL ENGINES 2 MW 4 LB/H

HOURLY LIMIT FOR EACH EN

FOR ALL FIVE ENGINES. EMIS

NORTH COOK INLET UNIT AK 0023-AC007 6/6/2000

CATERPILLAR D-398 ENGINES NO. 1 AND 2 500 KW EACH 500 PPM

USE NATURAL GAS WITH A HSULFIDE CONTENT NOT TO EAND FUEL OIL WITH A SULFUNOT TO EXCEED 0.25% BY W

DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #3 350 KW 63.3 T/12 MO. PERIOD

THE SULFUR CONTENT OF TBURNED MUST NOT EXCEED BY WEIGHT AT ANY TIME. FOPOWER GENERATION LIMITS IN THE PROCESS NOTES. 

DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #4 500 KW 63.3 T/12 MO PERIOD

THE SULFUR CONTENT OF TBURNED MUST NOT EXCEED BY WEIGHT AT ANY TIME. 

DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #5 750 KW 63.3 T/12 MO PERIOD

THE SULFUR CONTENT OF TBURNED MUST NOT EXCEED BY WEIGHT AT ANY TIME. FOPOWER GENERATION LIMITS IN THE PROCESS NOTES. 

DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #6 1000 KW 63.3 T/12 MO. PERIOD

THE SULFUR CONTENT OF TBURNED MUST NOT EXCEED BY WEIGHT AT ANY TIME. FOPOWER GENERATION LIMITS IN THE PROCESS NOTES. 

Att 10-E_Diesel-Fired IC Engines over 500HP_RBLC.xlsSO2 
FACILITY STATE PERMIT NUMBER PERMIT 

DATE

DESCRIPTION THROUGHPUT CONTROL DESCRI

Attachment 10-E

RACT/BACT/LAER Clearinghouse Results for Diesel-Fired Engines > 500 HP (SO2)

EMISSION LIMIT

DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #8 835 KW 63.3 T/12 MO PERIOD

THE SULFUR CONTENT OF TBURNED MUST NOT EXCEED BY WEIGHT AT ANY TIME. FOPOWER GENERATION LIMITS IN THE PROCESS NOTES. 

DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #9 835 KW 63.3 T/12 MO. PERIOD

THE SULFUR CONTENT OF TBURNED MUST NOT EXCEED BY WEIGHT AT ANY TIME. FOPOWER GENERATION LIMITS IN THE PROCESS NOTES. 

DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR, #10 1135 KW 63.3 T/12 MO. PERIOD

THE SULFUR CONTENT OF TBURNED MUST NOT EXCEED BY WEIGHT AT ANY TIME. FOPOWER GENERATION LIMITS IN THE PROCESS NOTES. 

DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #11 1050 KW 63.3 T/12 MO PERIOD

THE SULFUR CONTENT OF TBURNED MUST NOT EXCEED BY WEIGHT AT ANY TIME. FOPOWER GENERATION LIMITS IN THE PROCESS NOTES. 

DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #12 1050 KW 63.3 T/12 MO. PERIOD

THE SULFUR CONTENT OF TBURNED MUST NOT EXCEED BY WEIGHT AT ANY TIME. FOPOWER GENERATION LIMITS IN THE PROCESS NOTES. 

DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #13 1050 KW 63.3 T/12 MO PERIOD

THE SULFUR CONTENT OF TBURNED MUST NOT EXCEED BY WEIGHT AT ANY TIME. FOPOWER GENERATION LIMITS IN THE PROCESS NOTES. 

LAKEFIELD JUNCTION LP GENERATING STATION MN 09100058-002 5/4/2000 GENERATOR, BLACK-START 2 MW 0.5 LB/MMBTU

LOW SULFUR FUEL; LIMITED 1,000 H/ROLLING 12-MO 

KENAI REFINERY AK 9923-AC010 3/21/2000

UPPER TANK FARM CAT 3412DT, P708C 660 HP 500 PPM

FUEL SULFUR CONTENT LIMFOLLOWS: DIESEL, 0.35% SUGAS, 0.01% SULFUR; LPG, 0.0REFINERY GAS, 168 PPMV H2

KENAI REFINERY AK 9923-AC010 3/21/2000

EMERGENCY GENERATOR, CF-G70003 2 MW

USE ONLY FUEL GAS WITH A SULFIDE CONTENT NOT TO EAND USE DISTILLATE FUEL OSULFUR CONTENT NOT TO E

KENAI REFINERY AK 9923-AC010 3/21/2000

EMERGENCY GENERATOR, CF-G70004 2 MW

USE ONLY FUEL GAS WITH A SULFIDE CONTENT NOT TO EAND USE DISTILLATE FUEL OSULFUR CONTENT NOT TO E

SAN JUAN REPOWERING PROJECT PR 5 3/2/2000 AUXILIARY DIESEL GENERATOR 5000 KW 2.65 LB/H GOOD COMBUSTION CONTR

ARCHER GENERATING STATION TX PSD-TX-937 1/3/2000

EMERGENCY ELECTRICAL GENERATOR 2000 KW 1.9 LB/H 

Att 10-E_Diesel-Fired IC Engines over 500HP_RBLC.xlsSO2 
FACILITY STATE PERMIT NUMBER PERMIT 

DATE

DESCRIPTION CONTROL DESCRIPT

PSI ENERGY-MADISON STATION OH 14-04682 8/24/2004 EMERGENCY DIESEL GENERATOR, 2 17.21 MMBTU/H 1.55 LB/H FAIRBAULT ENERGY PARK MN 13100071-001 7/15/2004 IC ENGINE, LARGE, FUEL OIL (1) 670 HP 0.1 LB/MMBTU GOOD COMBUSTION. 

LONGVIEW POWER LLC - MAIDSVILLE WV R14-0024 3/2/2004 EMERGENCY GENERATOR 1801 HP 1.21 LB/HR GOOD COMBUSTION PRACT

ACE ETHANOL - STANLEY WI 03-DCF-184 1/21/2004

IC ENGINE, DIESEL GENERATOR SET, B70 1850 BHP 0.12 G/HP-H LIMITED OPERATION, DESIG

MANKATO ENERGY CENTER MN 01300098-001 12/4/2003

INTERNAL COMBUSTION ENGINE, LARGE 1850 HP 0.12 G/B-HP-H GOOD COMBUSTION 

DUKE ENERGY WASHINGTON COUNTY LLC OH 06-06792 8/14/2003

EMERGENCY DIESEL-FIRED GENERATOR 600 KW 1.76 LB/H

LOW SULFUR FUEL, COMBUCONTROL 

INGENCO - CHARLES CITY PLANT VA 51998 6/20/2003 IC ENGINES, (48) 550 HP 0.4 LB/MMBTU GOOD COMBUSTION PRACT

MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 EMERGENCY GENERATOR 97.73 GAL/HR 0.09 LB/MMBTU GOOD COMBUSTION PRACT

DUKE ENERGY STEPHENS, LLC STEPHENS ENERGY OK 2001-157-C M-1 PSD 3/21/2003

IC ENGINE, BACKUP GENERATOR, DIESEL 749 BHP 1.7 LB/H BACT IS GOOD ENGINE DES

CARDINAL FG CO./ CARDINAL GLASS PLANT OK 2002-487-C PSD 3/18/2003

IC ENGINES, EMERGENCY GENERATORS (2) 2000 KW 2.17 LB/H

ENGINE DESIGN AND LIMIT HOURS OF OPERATION (<50

PACIFIC BELL CA 16290 2/1/2003 IC ENGINES 2935 HP 1 G/B-HP-H STERNE ELECTRIC GENERATING FACILITY TX PSD-TX-1015 12/6/2002 EMERGENCY GENERATOR 1350 HP 3.33 LB/H 

UNIVERSITY OF CINCINNATI OH 14-05108 8/15/2002

DIESEL FIRED ENGINES (2), 2 MW, 2922 BHP 19.17 MMBTU/H 1.04 LB/H 

HAWKEYE GENERATING, LLC IA 01-687 7/23/2002 EMERGENCY GENERATOR 18500 GALLONS/YR 0.07 LB/H GCP, TIMING RETARD 

SCE&G - JASPER COUNTY GENERATING FACILITY SC 1360-0026-CA-CC 5/23/2002

GENERATOR, EMERGENCY,DIESEL FUEL 2000 KW 1.7 LB/H 

REDBUD POWER PLT OK 2000-090-C M-1 PSD 5/6/2002

DIESEL ENGINE, EMERGENCY GENERATOR 1818 HP 0.0007 LB/B-HP-H ENGINE DESIGN 

DUKE ENERGY-JACKSON FACILITY AR 1998-AOP-R0 (34-0259) 4/1/2002 GENERATOR, DIESEL-FIRED 671 HP 1.1 G/B-HP-H GOOD OPERATING PRACTIC

AES RED OAK LLC NJ 10001 10/24/2001 EMERGENCY GENERATOR 49 MMBTU/H 12.04 LB/H GOOD COMBUSTION 

MANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001

CATERPILLAR BACK-UP DIESEL AIR COMPRESSORS, 2 775 HP EACH 1.9 LB/H PREVENTATIVE MAINTENAN

MANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001

AUXILIARY DIESEL GENERATORS NO.1 & NO.2 1100 HP EACH 2.7 LB/H PREVENTATIVE MAINTENAN

MANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001

ADMINISTRATION BUILDING DIESEL GENERATOR 587 HP 1.4 LB/H PREVENTATIVE MAINTENAN

PSEG WATERFORD ENERGY LLC OH 06-06739 3/29/2001 EMERGENCY GENERATOR 1000 KW 0.02 T/YR 

DUKE ENERGY HOT SPRINGS AR 1936-AOP-R0 12/29/2000 GENERATORS, (2) DIESEL 600 KW 1.1 G/B-HP-H PROPER COMBUSTION PRA

COTTONWOOD ENERGY PROJECT TX PSD-965 12/15/2000 FIRE WATER PUMP 0.84 LB/H 

COTTONWOOD ENERGY PROJECT TX PSD-965 12/15/2000 EMERGENCY DIESEL GENERATOR 1.01 LB/H BADGER GENERATING CO LLC WI 99-RV-143 9/20/2000 DIESEL ENGINE, GENERATOR (4) 3.5 MMBTU/H 1.26 LB/H

GOOD COMBUSTION PRACTPERMIT LIMITS SET IN LB/H, G/BHP-H. 

BADGER GENERATING CO LLC WI 99-RV-143 9/20/2000

DIESEL ENGINE, EMERGENCY FIRE PUMP 3.8 MMBTU/H 1.37 LB/H

GOOD COMBUSTION PRACTEQUIPMENT USAGE LIMITS. LIMITS SET IN LB/H, NO LIMIG/BHP-H. 

BRAZOS VALLEY ELECTRIC GENERATING FACILITY TX PSD-TX-966 8/23/2000 EMERGENCY GENERATOR 1350 hp 3.39 LB/H 

BRAZOS VALLEY ELECTRIC GENERATING FACILITY TX PSD-TX-966 8/23/2000 FIRE WATER PUMP 300 hp 0.75 LB/H 

FORD ELECTRONICS AND REFRIGERATION, LLC PA PA-46-0036A 6/19/2000 DIESEL ENGINES 2 MW 0.46 LB/H

HOURLY LIMIT FOR EACH EANNUAL FOR ALL FIVE ENGEMISSION LIMITS AVAILABLIN LB/H AND T/YR. 

SAN JUAN REPOWERING PROJECT PR 5 3/2/2000 AUXILIARY DIESEL GENERATOR 5000 KW 4.3 LB/H

GOOD COMBUSTION; LIMITEOPERATION 

ARCHER GENERATING STATION TX PSD-TX-937 1/3/2000

EMERGENCY ELECTRICAL GENERATOR 2000 KW 2.9 LB/H 

THROUGHPUT

RACT/BACT/LAER Clearinghouse Results for Diesel-Fired Engines > 500 HP (VOC)

Attachment 10-E

EMISSION LIMIT

Att 10-E_Diesel-Fired IC Engines over 500HP_RBLC.xlsVOC 
FACILITY STATE PERMIT NUMBER PERMIT 

DATE

DESCRIPTION CONTROL DES

ARIZONA CLEAN FUELS YUMA LLC AZ 1001205 4/14/2005 FIRE WATER PUMP ENGINES 5.46 MMBTU/H 0.2 GR/KW-HR NONE INDICATED. ARIZONA CLEAN FUELS YUMA LLC AZ 1001205 4/14/2005 EMERGENCY GENERATOR 10.9 MMBTU/H 0.2 GR/KW-HR NONE INDICATED FAIRBAULT ENERGY PARK MN 13100071-001 7/15/2004 IC ENGINE, LARGE, FUEL OIL (1) 670 HP 0.1 LB/MMBTU

CLEAN FUEL AND GOCOMBUSTION. 

ACE ETHANOL - STANLEY WI 03-DCF-184 1/21/2004

IC ENGINE, DIESEL GENERATOR SET, B70 1850 BHP 0.07 G/HP-H

USE OF VERY LOW SFUEL (0.05 WT % S). 

MANKATO ENERGY CENTER MN 01300098-001 12/4/2003

INTERNAL COMBUSTION ENGINE, LARGE 1850 HP 0.07 G/B-HP-H GOOD COMBUSTION 

DUKE ENERGY WASHINGTON COUNTY LLC OH 06-06792 8/14/2003

EMERGENCY DIESEL-FIRED GENERATOR 600 KW 0.72 LB/H

LOW SULFUR FUEL, CONTROL 

INGENCO - CHARLES CITY PLANT VA 51998 6/20/2003 IC ENGINES, (48) 550 HP 0.2 LB/MMBTU GOOD COMBUSTION MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 EMERGENCY GENERATOR 97.73 GAL/HR 0.14 LB/MMBTU GOOD COMBUSTION ROQUETTE AMERICA IA 56-01-009 1/31/2003 IC ENGINE, DIESEL 710 HP 0.069 LB/MMBTU

LOW ASH FUELS, GOCOMBUSTION PRAC

HAWKEYE GENERATING, LLC IA 01-687 7/23/2002 EMERGENCY GENERATOR 18500 GALLONS/YR 0.34 LB/H GCP, TIMING RETARSCE&G - JASPER COUNTY GENERATING FACILITY SC 1360-0026-CA-CC 5/23/2002

GENERATOR, EMERGENCY,DIESEL FUEL 2000 KW 1.9 LB/H

CLEAN FUEL(LOW SGOOD COMBUSTION 

AES RED OAK LLC NJ 10001 10/24/2001 EMERGENCY GENERATOR 49 MMBTU/H 2.67 LB/H LIMITED USE DUKE ENERGY HOT SPRINGS AR 1936-AOP-R0 12/29/2000 GENERATORS, (2) DIESEL 600 KW 1.8 LB/H CONTROLS KLAMATH FALLS COGENERATION OR 18-0003 12/29/2000 EMERGENCY GENERATOR 6 MMBTU/H 0.1 GR/SCF BADGER GENERATING CO LLC WI 99-RV-143 9/20/2000 DIESEL ENGINE, GENERATOR (4) 3.5 MMBTU/H 0.35 LB/H

GOOD COMBUSTION FUEL < 0.05 % BY WTPERMIT LIMITS SET G/BHP-H. 

BADGER GENERATING CO LLC WI 99-RV-143 9/20/2000

DIESEL ENGINE, EMERGENCY FIRE PUMP 3.8 MMBTU/H 0.38 LB/H

GOOD COMBUSTION USE OF FUEL < 0.05% EQUIPMENT USAGE 

FORD ELECTRONICS AND REFRIGERATION, LLC PA PA-46-0036A 6/19/2000 DIESEL ENGINES 2 MW 1.2 LB/H

HOURLY LIMIT FOR ANNUAL FOR ALL FIV

NORTH COOK INLET UNIT AK 0023-AC007 6/6/2000

CATERPILLAR D-398 ENGINES NO. 1 AND 2 500 KW EACH 0.05 GR/DSCF NONE INDICATED 

THROUGHPUT

RACT/BACT/LAER Clearinghouse Results for Diesel-Fired Engines > 500 HP (PM)

Attachment 10-E

EMISSION LIMIT

Att 10-E_Diesel-Fired IC Engines over 500HP_RBLC.xlsPM 
FACILITY STATE PERMIT NUMBER PERMIT 

DATE

DESCRIPTION CONTROL DES

THROUGHPUT

RACT/BACT/LAER Clearinghouse Results for Diesel-Fired Engines > 500 HP (PM)

Attachment 10-E

EMISSION LIMIT

DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #3 350 KW 0.05 GR/DSCF NONE INDICATED DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #4 500 KW 0.05 GR/DSCF NONE INDICATED DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #5 750 KW 0.05 GR/DSCF NONE INDICATED DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #6 1000 KW 0.05 GR/DSCF NONE INDICATED DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #8 835 KW 0.05 GR/DSCF NONE INDICATED DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #9 835 KW 0.05 GR/DSCF NONE INDICATED DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR, #10 1135 KW 0.05 GR/DSCF NONE INDICATED DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #11 1050 KW 0.05 GR/DSCF NONE INDICATED DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #12 1050 KW 0.05 GR/DSCF NONE INDICATED DILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #13 1050 KW 0.05 GR/DSCF NONE INDICATED KENAI REFINERY AK 9923-AC010 3/21/2000

UPPER TANK FARM CAT 3412DT, P708C 660 HP 0.3627 LB/MMBTU NONE INDICATED. 

KENAI REFINERY AK 9923-AC010 3/21/2000

EMERGENCY GENERATOR, CF-G70003 2 MW 0.0573 LB/MMBTU GOOD OPERATIONA

AND MAINTENANCE

KENAI REFINERY AK 9923-AC010 3/21/2000

EMERGENCY GENERATOR, CF-G70004 2 MW 0.0573 LB/MMBTU GOOD OPERATIONA

AND MAINTENANCE 

Att 10-E_Diesel-Fired IC Engines over 500HP_RBLC.xlsPM 
FACILITY STATE PERMIT NUMBER PERMIT 

DATE

DESCRIPTION CONTROL DESCR

Omaha Public Power District - Nebraska City Station NE 58343C01 3/9/2005 Auxiliary Boiler #2

-- --

0.001 GR/DSCF

FUEL SULFUR LIMITED TS; LIMITED TO 500 HRS/Y

PSI ENERGY-MADISON STATION OH 14-04682 8/24/2004 EMERGENCY DIESEL GENERATOR, 2 17.21 MMBTU/H 0.27 T/YR LONGVIEW POWER LLC - MAIDSVILLE WV R14-0024 3/2/2004 EMERGENCY GENERATOR 1801 HP 1.13 LB/HR GOOD COMBUSTION PU.S. ARMY - PINE BLUFF ARSENAL AR 1113-AOP-R0 2/17/2004 EMERGENCY GENERATORS (2) 2500 KW 1.1 LB/HR NONE INDICATED MANKATO ENERGY CENTER MN 01300098-001 12/4/2003

INTERNAL COMBUSTION ENGINE, LARGE 1850 HP 0.07 G/B-HP-H GOOD COMBUSTION 

DUTCH HARBOR SEAFOOD PROCESSING FACILITY AK 433CP01(MOD) 10/10/2003 IC ENGINE, GENERATOR, FUEL OIL, (3) 2220 KW

GOOD COMBUSTION POPACITY LIMITS 

INGENCO - CHARLES CITY PLANT VA 51998 6/20/2003 IC ENGINES, (48) 550 HP 0.2 LB/MMBTU GOOD COMBUSTION PMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 EMERGENCY GENERATOR 97.73 GAL/HR 0.14 LB/MMBTU GOOD COMBUSTION PDUKE ENERGY STEPHENS, LLC STEPHENS ENERGY OK 2001-157-C M-1 PSD 3/21/2003

IC ENGINE, BACKUP GENERATOR, DIESEL 749 BHP 0.124 LB/MMBTU

COMBUSTION CONTRGOOD ENGINE DESIG

CARDINAL FG CO./ CARDINAL GLASS PLANT OK 2002-487-C PSD 3/18/2003

IC ENGINES, EMERGENCY GENERATORS (2) 2000 KW 0.0444 LB/MMBTU ENGINE DESIGN 

PACIFIC BELL CA 16290 2/1/2003 IC ENGINES 2935 HP 0.1 G/B-HP-H STERNE ELECTRIC GENERATING FACILITY TX PSD-TX-1015 12/6/2002 EMERGENCY GENERATOR 1350 HP 2.97 LB/H UNIVERSITY OF CINCINNATI OH 14-05108 8/15/2002

( )

2922 BHP 19.17 MMBTU/H 0.23 LB/H 

HAWKEYE GENERATING, LLC IA 01-687 7/23/2002 EMERGENCY GENERATOR 18500 GALLONS/YR 0.34 LB/H GCP, TIMING RETARD GENOVA OK I POWER PROJECT OK 2001-223-C PSD 6/13/2002 DIESEL ENGINE, BACKUP GENERATOR 750 KW 0.033 LB/MMBTU

COMBUSTION CONTRGOOD ENGINE DESIG

GREATER DES MOINES ENERGY CENTER IA 77-13-002 4/10/2002 EMERGENCY GENERATOR 700 KW 0.95 LB/H DUKE ENERGY-JACKSON FACILITY AR 1998-AOP-R0 (34-0259) 4/1/2002 GENERATOR, DIESEL-FIRED 671 HP 1.5 LB/H GOOD OPERATING PRMANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001

CATERPILLAR BACK-UP DIESEL AIR

COMPRESSORS, 2 775 HP EACH 1.7 LB/H PREVENTATIVE MAINT

MANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001

AUXILIARY DIESEL GENERATORS NO.1

& NO.2 1100 HP EACH 2.4 LB/H PREVENTATIVE MAINT

MANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001

ADMINISTRATION BUILDING DIESEL

GENERATOR 587 HP 1.3 LB/H PREVENTATIVE MAINT

PSEG WATERFORD ENERGY LLC OH 06-06739 3/29/2001 EMERGENCY GENERATOR 1000 KW 0.01 T/YR COTTONWOOD ENERGY PROJECT TX PSD-965 12/15/2000 FIRE WATER PUMP 0.74 LB/H COTTONWOOD ENERGY PROJECT TX PSD-965 12/15/2000 EMERGENCY DIESEL GENERATOR 0.88 LB/H BRAZOS VALLEY ELECTRIC GENERATING FACILITY TX PSD-TX-966 8/23/2000 EMERGENCY GENERATOR 1350 hp 2.97 LB/H BRAZOS VALLEY ELECTRIC GENERATING FACILITY TX PSD-TX-966 8/23/2000 FIRE WATER PUMP 300 hp 0.66 LB/H SAN JUAN REPOWERING PROJECT PR 5 3/2/2000 AUXILIARY DIESEL GENERATOR 5000 KW 7.18 LB/H

LIMITED OPERATION, COMBUSTION PRACTI

ARCHER GENERATING STATION TX PSD-TX-937 1/3/2000

EMERGENCY ELECTRICAL GENERATOR 2000 KW 2.07 LB/H 

AGRIMARK/ CABOT INC. (AMC) VT AOP-99-014 1/3/2000 IC ENGINE, DIESEL 250 KW 0.5 LB/MMBTU AGRIMARK/ CABOT INC. (AMC) VT AOP-99-014 1/3/2000 IC ENGINE, DIESEL 100 KW 0.5 LB/MMBTU 

THROUGHPUT

RACT/BACT/LAER Clearinghouse Results for Diesel-Fired Engines > 500 HP (PM10)

Attachment 10-E

EMISSION LIMIT

Att 10-E_Diesel-Fired IC Engines over 500HP_RBLC.xlsPM10 
FACILITY STATE PERMIT 

NUMBER

 PERMIT 

DATE

DESCRIPTION CONTRO

ARCHER GENERATING STATION TX PSD-TX-937 1/3/2000

EMERGENCY ELECTRICAL GENERATOR 2000 KW 0.29 LB/H None Liste

THROUGHPUT

RACT/BACT/LAER Clearinghouse Results for Diesel-Fired Engines > 500 HP (H2SO4)

Attachment 10-E

EMISSION LIMIT

Att 10-E_Diesel-Fired IC Engines over 500HP_RBLC.xlsH2SO4 
ATTACHMENT 10-F 

RACT / BACT / LAER CLEARINGHOUSE DATA FOR MATERIAL HANDLING 

OPERATIONS
RBLC CODE FACILITY STATE PERMIT NUMBER PERMIT DATE PROCESS TYPE CONTROL DESCRIPTION 

90.011

MONTANA DAKOTA UTILITIES/WESTMORELAND POWER - GASCOYNE GENERATING STATION ND PTC 05005 6/3/2005 COAL HANDLING 0.005 GR/DSCF BAGHOUSES; 3 HR AVG. 

Coal Handling,AUBURN NUGGET IN 033-19475-00092 5/31/2005 COAL CAR UNLOADING 0.0052 GR/DSCF BAGHOUSES 

Processing, ISLAND CREEK COAL - VP #8 GARDEN PLANT VA 10704 11/2/2004 COAL PROCESSING PLANT - THERMAL DRYER 153 btu/h 0.025 GR/DSCF WET VENTURI SCRUBBER 

Preparation, ISLAND CREEK COAL - VP #8 GARDEN PLANT VA 10704 11/2/2004 COAL HANDLING AND TRANSFER OPERATIONS 3.5 MMT/YR 16.95 T/YR WET SUPPRESSION 

Cleaning SANTEE COOPER CROSS GENERATING 

STATION SC 0420-0030-CI 2/5/2004 COAL HANDLING 26,280,000 T/YR 1.4 LB/H BAGHOUSE CARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 SOLID FUEL HANDLING - COAL AND COKE 0.89 LB/H

WORK PRACTICES THAT MINIMIZE OR ELEMISSIONS OF FUGITIVE DUST. 

MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 STACKER CONVEYOR CHEMICAL DUST SUPPRESSANT MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 TRANSFER TO ACTIVE PILE CHEMICAL DUST SUPPRESSANT MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 BUCKET RECLAIM CHEMICAL DUST SUPPRESSANT MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 RAIL UNLOADING CHEMICAL DUST SUPPRESSANT MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 ACTIVE COAL PILE 311155 SQ FT CHEMICAL DUST SUPPRESSANT MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 INACTIVE COAL STORAGE PILE 1196459 SQ FT CHEMICAL DUST SUPPRESSANT MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 RAIL UNLOADING COAL STOCKOUT PILE 28224 SQ FT CHEMICAL DUST SUPPRESSANT MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 ROTARY CAR DUMPER 3500 TONS/HR 0.005 GR/DSCF BAGHOUSE MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 TRANSFER CONVEYING BAY 1800 TONS/HR 0.005 GR/DSCF BAGHOUSE MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 TRANSFER HOUSE 2 3500 TONS/HR 0.005 GR/DSCF BAGHOUSE MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 TRANSFER HOUSE 4 3600 TONS/HR 0.005 GR/DSCF BAGHOUSE MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 SILOS 900 TONS/HR 0.005 GR/DSCF BAGHOUSE THOROUGHBRED GENERATING STATION KY V-02-001 10/11/2002 COAL HANDLING AND STORAGE 99 % REDUCTION

ENCLOSURES/PARTIAL ENCLOSURES, BAFILTERS, LOW-PRESSURE DROP AND TECHUTES 

BLACK HILLS CORPORATION - WYGEN 2 WY CT-3030 9/25/2002 COAL HANDLING EQUIPMENT 0.009 GR/DSCF FABRIC FILTER CONSOLIDATION COAL -BUCHANAN PREP PLANT VA 10945 9/26/2001 COAL HANDLING 138 MMBTU/H 0.025 GR/DSCF VENTURI SCRUBBER CONSOLIDATION COAL -BUCHANAN PREP PLANT VA 10945 9/26/2001 COAL HANDLING-2 253 MMBTU/H 0.025 GR/DSCF VENTURI SCRUBBER ENERGY SERVICES OF MANITOWOC WI 00-RV-092 6/26/2001 FUEL HANDLING 0.004 GR/DSCF

PULSE-JET BAGHOUSES, ENCLOSED CONSUPPRESSION 

RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING OVERLAND CONVEYOR 4.3 LB/H PARTIAL ENCLOSURE RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 (2) FUEL HANDLING ACTIVE STORAGE PILES A&B 3.24 T/YR

WATER SPRAY & UNDERGROND RECLAIM BAGHOUSE 

RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING INACTIVE STORAGE PILE 18.4 T/YR WATERING RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING EMERGENCY STORAGE PILE 0.42 T/YR TELESCOPING CHUTE & WATER SPRAY RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING STACKING HOPPER 0.63 LB/H WATER SPRAY RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001

FUEL HANDLING STACKING HOPPER CONVEYOR 1A 0.37 LB/H PARTIAL ENCLOSURE 

RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING RAIL CAR UNLOADER 0.63 LB/H PARTIAL ENCLOSURE & WATER SPRAY RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001

FUEL HANDLING RAIL CAR UNLOADER CONVEYOR 1B 0.19 LB/H PARTIAL ENCLOSURE 

RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING ACTIVE STORAGE PILE 2 T/YR NONE INDICATED RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING CONVEYOR NO 2 0.16 LB/H PARTIAL ENCLOSURE RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING CONVEYOR NO 3 0.12 LB/H NONE INDICATED HAVERHILL NORTH COKE COMPANY OH 07-00466 2/27/2001

LOAD IN AND LOAD OUT OF COKE/COAL STORAGE PILES 4 T/YR

LOAD-IN COAL, COKE, AND COKE BREEZTUBE; LOAD-IN COAL W/WATER SPRAYS/SUPPRESSANT; LOAD-OUT COAL UNDER FEED AND WATER SPRAY; LOAD-OUT COPILE GRAVITY FEED. 

HAVERHILL NORTH COKE COMPANY OH 07-00466 2/27/2001 COAL HANDLING, CONVEYING, AND TRANSFER 6602850 T/YR 7.95 T/YR

RAIL CAR BOTTOM DUMPING AND ENCLOCONVEYORS ENCLOSED; WET AND/OR CSUPPRESSION 

SUWANNEE AMERICAN CEMENT COMPANY, INC. FL 1210465-001-AC 6/1/2000 COAL MILL 0.01 GR/DSCF BAGHOUSE CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL TX PSD-TX-138 (M5) 4/24/2000

RAILCAR LOADING FROM PELLETIZER SILO/BAGHOUSE DUST 0.0006 LB/H NONE INDICATED 

HOLNAM, FLORENCE CO 98-FR-0895 7/29/1999 UNLOADING & CONVEYING, COAL TO STOCKPILE 1.94 T/YR

NEG PRESSURE AND BAGHOUSE. STANDUNITS NOT AVAILABLE. 

HOLNAM, FLORENCE CO 98-FR-0895 7/29/1999 COAL STOCKPILE 0.45 T/YR SURFACE MOISTURE 

THROUGHPUT

RACT/BACT/LAER Clearinghouse for Material Handling Operations

Attachment 10-F

EMISSION LIMIT

Att 10-F_Material Handling_RBLC.xlsPM 
RBLC CODE FACILITY STATE PERMIT NUMBER PERMIT DATE PROCESS TYPE THROUGHPUT CONTROL DESCRIPTION 

RACT/BACT/LAER Clearinghouse for Material Handling Operations

Attachment 10-F

EMISSION LIMIT

HOLNAM, FLORENCE CO 98-FR-0895 7/29/1999

RECLAIMING, CONVEYING, & TRANS COAL TO COAL SCREEN 0.19 T/YR

BAGHOUSE. PERMIT MODIFICATION TRIGREVIEW OF CO ONLY. PM LIMITS IN STANUNITS NOT AVAILABLE. 

HOLNAM, FLORENCE CO 98-FR-0895 7/29/1999 SCREENING AND CRUSHING OVERSIZE COAL 0.19 T/YR

BAGHOUSE. PERMIT MODIFICATION TRIGREVIEW OF CO ONLY. PM LIMITS IN STANUNITS NOT AVAILABLE. 

HOLNAM, FLORENCE CO 98-FR-0895 7/29/1999

TRANS & CONVEYING - CRUSHED COAL TO TRANSFER TOWER 0.02 T/YR

BAGHOUSE. PERMIT MODIFICATION TRIGREVIEW OF CO ONLY. PM LIMITS IN STANUNITS NOT AVAILABLE. 

HOLNAM, FLORENCE CO 98-FR-0895 7/29/1999 TRANSFER, COAL, TRANSFER TOWER TO SILO 0.02 T/YR

BAGHOUSE. PERMIT MODIFICATION TRIGREVIEW OF CO ONLY. PM LIMITS IN STANUNITS NOT AVAILABLE. 

NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 RAW COAL/COKE BIN 0.08 LB/H BAGHOUSE & SPRAY COAL/COKE PILES NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 MAT STORAGE, CRUSHED COAL/COKE BIN 0.01 LB/H BAGHOUSE AND SPRAY PILE 

NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999

MAT HANDLING, COAL/COKE DROP PT TO HOPPER (MT08) 0.19 LB/H PARTIAL ENCLOSURE AND WATER SPRA

NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999

MATERIAL HANDLING, COAL/COKE DROP POINT TO STACKER 0.47 LB/H PARTIAL ENCLOSURE AND WATER SPRA

NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999

MATERIAL HANDLING, COAL/COKE DROP POINT TO PILE 0.47 LB/H PARTIAL ENCLOSURE AND WATER SPRA

NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999

MATERIAL HANDLING, COAL/COKE DROP TO HOPPER (MT05) 0.47 LB/H PARTIAL ENCLOSURE AND WATER SPRA

NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999

MATERIAL HANDLING COAL/COKE DROP FEEDER TO BELT 0.19 LB/H PARTIAL ENCLOSURE AND WATER SPRA

NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999

MATERIAL HANDLING COAL/COKE DROP BELT TO BELT 0.19 LB/H COVERED CONVEYOR BELTS 

NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999

MAT HANDLING, COAL/COKE RECEIVING DROP TO HOPPER 0.07 LB/H PARTIAL ENCLOSURE AND WATER SPRA

NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999

MAT HANDLING, COAL/COKE UNLOADING CONVEYOR BELT 0.01 LB/H COVERED CONVEYOR BELT 

NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999

MAT HANDLING COAL/COKE CONVEYOR TO STACKER 0.01 LB/H COVERED CONVEYOR BELT 

NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999

MATERIAL HANDLING, COAL/COKE STACKER TO PILE 0.01 LB/H PARTIAL ENCLOSURES, WATER SPRAYS 

NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999

MAT HANDLING COAL/COKE CONVEYOR TO COAL GRINDING 0.01 LB/H COVERED CONVEYOR BELT 

NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999

MAT HANDLING COAL/COKE CONVEYOR TO MILL FEED BIN 0.01 LB/H COVERED CONVEYOR BELT 

NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 MATERIAL STORAGE, COAL/COKE PILES 0.55 LB/H SPRAY THE C/C PILES COLSTRIP ENERGY LIMITED PARTNERSHIP MT 2035-03 3/20/1998 ELECTRIC GENERATION, MATERIAL TRANSFER 0 6 LB/H BAGHOUSE TWO ELK GENERATION PARTNERS, LIMITED PARTNERSHIP WY CT-1352 2/27/1998 DUMP POCKET, COAL 3000 SCFM 0.01 GR/DSCF BAGHOUSE TWO ELK GENERATION PARTNERS, LIMITED PARTNERSHIP WY CT-1352 2/27/1998 SILO, COAL 6000 SCFM 0.01 GR/DSCF BAGHOUSE TWO ELK GENERATION PARTNERS, LIMITED PARTNERSHIP WY CT-1352 2/27/1998 CRUSHER, CONE, SECONDARY COAL 6000 SCFM 0.01 GR/DSCF 6000 SCFM BAGHOUSE TWO ELK GENERATION PARTNERS, LIMITED PARTNERSHIP WY CT-1352 2/27/1998 SILO, BOILER, PLANT COAL 8500 SCFM 0.01 GR/DCSF 8500 SCFM BAGHOUSE CONSOLIDATED PENNSYLVANIA COAL CO., BAILY MINES PA 30-0072B 12/19/1997 THERMAL COAL DRYER NO. 1 27 MMTPY 0.031 GR/DSCF VENTURI SCRUBBER CONSOLIDATED PENNSYLVANIA COAL CO., BAILY MINES PA 30-0072B 12/19/1997 THERMAL COAL DRYER NO. 2 27 MMTPY 0.02 GR/DSCF VENTURI SCRUBBER ENCOAL CORPORATION-ENCOAL NORTH ROCHELLE FACILITY WY CT-1324 10/10/1997 STORAGE, PROCESS DERIVED FUEL 0 0.01 GR/DSCF SCRUBBER 40000 DSCFM 

Att 10-F_Material Handling_RBLC.xlsPM 
RBLC CODE FACILITY STATE PERMIT NUMBER PERMIT DATE PROCESS TYPE THROUGHPUT CONTROL DESCRIPTION 

RACT/BACT/LAER Clearinghouse for Material Handling Operations

Attachment 10-F

EMISSION LIMIT

WYGEN, INC. - WYGEN UNIT ONE WY CT-1236 9/6/1996 BOILER BUILDING 0 0.01 GR/DSCF BAGHOUSE 

90.019 ARKANSAS LIME COMPANY AR 0045-AOP-R3 8/30/2005 LIME DISCHARGE, SN-32Q #3 0.01 GR/DSCF BAGHOUSE 

Lime, 

MONTANA DAKOTA UTILITIES/WESTMORELAND POWER - GASCOYNE GENERATING STATION ND PTC 05005 6/3/2005

MATERIAL HANDLING, LIME & LIMESTONE HANDLING 0.005 GR/DSCF BAGHOUSES; 3-HR AVG.; ADDITIONAL 5% 

Limestone

SANTEE COOPER CROSS GENERATING STATION SC 0420-0030-CI 2/5/2004 LIMESTONE HANDLING 230000 T/YR 0.022 GR/DSCF BAGHOUSE 

Handling,

SANTEE COOPER CROSS GENERATING STATION SC 0420-0030-CI 2/5/2004 LIMESTONE STORAGE PILE 0.29 LB/H 

Kilns,

SANTEE COOPER CROSS GENERATING STATION SC 0420-0030-CI 2/5/2004 LIMESTONE TRUCK UNLOADING 0.02 LB/H 

Storage, STORA ENSO NORTH AMERICA - WHITING MILL WI 02-DCF-039 12/19/2003 LIME STORAGE / RECEIVING, P01, S01 4400 LBS/DAY 0.3 LB/H BIN VENT BAGHOUSE Manufacturing CARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 KILN DUST HANDLING 0.5 T/YR WATERING OF DUST AND BAGHOUSE. 

CARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 MATERIAL STORAGE PILES 0.61 T/YR

WATER APPLICATIONS AND DAILY INSPESTORAGE PILE. 

CARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 LIMESTONE MATERIAL HANDLING 4.34 T/YR WATER APPLICATION. CARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 LIME MATERIAL HANDLING #2 1.38 LB/H BAGHOUSE. CARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 LIME MATERIAL HANDLING #1 1.05 LB/H BAGHOUSE. CARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 COMMON PRODUCT HANDLING 1.77 LB/H

WORK PRACTICES THAT MINIMIZE OR ELEMISSIONS OF FUGITIVE DUST. 

CARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 PRODUCT STORAGE/LOADOUT #2 1.3 LB/H

WORK PRACTICES THAT MINIMIZE OR ELEMISSIONS OF FUGITIVE DUST. 

CARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 PRODUCT STORAGE/LOADOUT #1 0.62 LB/H

WORK PRACTICES THAT MINIMIZE OR ELEMISSIONS OF FUGITIVE DUST. 

FIRST ENERGY/TOLEDO EDISON CO. - BAYSHORE PLANT OH 04-1056 7/31/2003 LIMESTONE CRUSHING, SIZING, AND CONVEYING 0.05 G/DSCM BAGHOUSEFIRST ENERGY/TOLEDO EDISON CO. - BAYSHORE PLANT OH 04-1056 7/31/2003 LIMESTONE DRYER 87 gal/h #2 fuel oil 0.002 LB/H FABRIC FILTERMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 LIME STORAGE SILO 2000 TONS/HR 0.01 GR/DSCF VENT BAG FILTER MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 LIME FILTER SEPARATOR 100 TONS/HR 0.01 GR/DSCF BAGHOUSE MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 UREA SILO 60 TONS 0.01 GR/DSCF VENT BAG FILTER THOROUGHBRED GENERATING STATION KY V-02-001 10/11/2002 FGD REAGENT PREP HANDLING, LIME 400 T/H 0.05 G/DSCM ENCLOSURES AND FILTERS RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001

LIMESTONE HANDLING RAILCAR UNLOADING FACILITY 0.6 LB/H WATER SPRAY 

RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 LIMESTONE HANDLING STORAGE PILE 0.42 T/YR

PARTIAL ENCLOSURE, TELESCOPING CHUNDERGROUND RECLAIM 

KENTUCKY MOUNTAIN POWER, LLC KY V-00-045 5/4/2001 MATERIAL HANDLING, LIMESTONE PREP SYSTEM 220 T/H 0.05 GR/DSCM

ENCLOSURE AND BAGHOUSE FOR TRUCFEED & CONVEY POINTS, BAGHOUSE FOAND SILOS 

KENTUCKY MOUNTAIN POWER, LLC KY V-00-045 5/4/2001 MILL/DRYER, LIMESTONE 10 MMBTU/H 0.05 GR/DSCM BAGHOUSE RELIANT ENERGY - W.A. PARISH ELECTRIC GENERATING STATION TX PSD-TX-234 12/21/2000 RAILCAR UNLOADING, LH1 500 T/H 30 LB/H

PERMANENTLY MOUNTED SPRAY NOZZLROADS CLEANED BY SWEEPING OR WASSPRINKLING OF ROADS WITH WATER/ CH

RELIANT ENERGY - W.A. PARISH ELECTRIC GENERATING STATION TX PSD-TX-234 12/21/2000 TRACK HOPPERS, LH1A 500 T/H* 0.54 LB/H

PERMANENTLY MOUNTED SPRAY NOZZLROADS WITH CLEANING/SWEEPING, WATSPRAY ON ROADS. 

RELIANT ENERGY - W.A. PARISH ELECTRIC GENERATING STATION TX PSD-TX-234 12/21/2000 STOCKPILE, LH2 500 T/H* 0.13 T/YR NONE INDICATED TEXAS LIME COMPANY TX PSD-TX-54 8/2/1999 DUST BIN LOADOUT DUST COLLECTOR, 6-AS-3 0.36 LB/H DUST COLLECTOR TEXAS LIME COMPANY TX PSD-TX-54 8/2/1999 DUST BIN COLLECTOR, 6-AS-2 0.13 LB/H DUST COLLECTOR NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 SHIFTABLE QUARRY BELT DROP POINT 0.29 LB/H PARTIAL ENCLOSURE AND SPRAYING. NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 QUARRY BELT DROP POINT (FUTURE) 0.29 LB/H COVERED AND SPRAYED NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999

QUARRY CONVEYOR BELT TO LIMESTONE STORAGE DROP PT. 0.29 LB/H COVERED AND SPRAYED 

NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 MOBILE CRUSHER 0.65 LB/H NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 LIMESTONE STORAGE BUILDING VENT 0.1 LB/H FULLY ENCLOSED BUILDING FOR LIME STNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999

QUARRY CONVEYOR BELT TO LIMESTONE STORAGE 0.01 LB/H COVERED CONVEYOR 

NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 QUARRY BELT (SHIFTABLE) 0.13 LB/H COVERED CONVEYOR BELT NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 QUARRY BELT (FUTURE) 0.19 LB/H COVERED CONVEYOR BELT 

Att 10-F_Material Handling_RBLC.xlsPM 
RBLC CODE FACILITY STATE PERMIT NUMBER PERMIT DATE PROCESS TYPE THROUGHPUT CONTROL DESCRIPTION 

RACT/BACT/LAER Clearinghouse for Material Handling Operations

Attachment 10-F

EMISSION LIMIT

NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 LIMESTONE CONVEYOR BELT TO FEED BINS 0.01 LB/H COVERED CONVEYOR BELT TWO ELK GENERATION PARTNERS, LIMITED PARTNERSHIP WY CT-1352 2/27/1998 SILO, LIME 3000 SCFM 0.01 GR/DSCF 3000 SCFM BAGHOUSE ENCOAL CORPORATION-ENCOAL NORTH ROCHELLE FACILITY WY CT-1324 10/10/1997 SILO, LIME STORAGE 0 0.01 GR/DSCF BAGHOUSE 3500 DSCFM 

99.120 TOLEDO EDISON CO. - BAYSHORE PLANT OH 04-1056 7/31/2003

COKE AND FLY ASH TRANSFERRING AND CONVEYING 730000 t/yr 12 T/YR FABRIC FILTER AND ADEQUATE ENCLOS

Ash Handling, MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003

FLYASH/FGD WASTE VACUUM SYSTEM EXHAUSTER 40.44 TONS/HR 0.005 GR/DSCF BAGHOUSE 

Storage, MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 FLYASH/FGD WASTE STORAGE SILO 2000 TONS 0.005 GR/DSCF VENT BAG FILTER Disposal ALAMO CEMENT COMPANY II, LTD TX PSD-TX-145 (M1) 6/29/2001 FLYASH BINE, N-20 0.17 LB/H BAGHOUSE 

RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001

WASTE HANDLING FLY ASH TRUCK LOADING OPERATION 3.38 LB/H TELESCOPING CHUTE, VACUUM RECOVE

RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001

WASTE HANDLING FLY ASH BAG LOADING OPERATION 0.11 LB/H VACUUM RECOVERY 

RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 BOTTOM ASH TRUCK LOADING 0.94 LB/H WET MATERIAL RELIANT ENERGY - W.A. PARISH ELECTRIC GENERATING STATION TX PSD-TX-234 12/21/2000 FLY ASH TANK, WH2 75 T/H 0.43 LB/H BAGHOUSE TWO ELK GENERATION PARTNERS, LIMITED PARTNERSHIP WY CT-1352 2/27/1998 SILO, FLY ASH 4000 SCFM 0.01 GR/DSCF 4000 SCFM BAGHOUSE TWO ELK GENERATION PARTNERS, LIMITED PARTNERSHIP WY CT-1352 2/27/1998 HANDLING BUILDING, FLY ASH 5000 SCFM 0.01 GR/DSCF 5000 SCFM BAGHOUSE ENCOAL CORPORATION-ENCOAL NORTH ROCHELLE FACILITY WY CT-1324 10/10/1997 BIN, ASH STORAGE 0 0.01 GR/DSCF BAGHOUSE, 3500 DSCFM WYGEN, INC. - WYGEN UNIT ONE WY CT-1236 9/6/1996 FLY ASH HANDLING BUILDING 0 0.01 GR/DSCF BAGHOUSE WYGEN, INC. - WYGEN UNIT ONE WY CT-1236 9/6/1996 SILO, FLY ASH STORAGE 0 0.01 GR/DSCF BAGHOUSE 

99.140

R.J. REYNOLDS TOBACCO COMPANY - TOBACCOVILLE FACILITY NC 00745-TV12 7/1/2003 PAVED ROADS -- SEE CONTROLS/P2

RACT IS PAVING ALL MAIN ROADS AND MMAINTENANCE ROADS, INSTALLATION OGUTTER,ENCLOSED TRAILERS/TRUCKS 

Paved Roads MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 HAUL ROADS 46 TRUCKS/DAY

WATER FLUSHING FOLLOWED BY SWEEPEFFICIENCY ASSUMED 

WOLD TRONA COMPANY, INC. WY MD-455 4/27/2000 FUGITIVE EMISSIONS - ROAD DUST 41.3 T/YR PAVED ROADS CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL TX PSD-TX-138 (M5) 4/24/2000 IN-PLANT VEHICLE TRAFFIC 34.8 T/YR CHEMICAL AND WATER SPRAY 

HOLNAM, FLORENCE CO 98-FR-0895 7/29/1999 PAVED ROADS, CEMENT PRODUCT HAULOUT 1.6 T/YR CONTROL PLAN INTERNATIONAL PAPER LUMBER MILL TX PSD-TX-892 9/28/1998 HR-FUG HAUL ROAD FUGITIVES 2.76 LB/H

PLANT ROADS SHALL BE PAVED WITH A CSURFACE WHICH CAN BE CLEANED BY SWASHING. ALL ROADS SHALL BE SPRINKWATER AND/OR ENVIRONMENTALLY SENCHEMICALS AS NEEDED TO CONTROL PM

CAPITOL CEMENT DIVISION TX PSD-TX-120M3 9/16/1998 PAVED ROADS (F-TR-1) 10.37 T/YR

PLANT ROADS SHALL BE PAVED AND CLEROADS SHALL BE SPRINKLED WITH WATCHEMICALS TO MAINTAIN COMPLIANCE WRULES AND REGULATIONS. 

SPRINGFIELD PLANT OR 202125 6/4/1998 ROAD AND PARKING LOTS 27 LB/D DESERET GENERATION AND TRANSMISSION CO. UT DAQE-523-95 6/14/1995 ROADS (PAVED)

CONTROLLED BY DUST CONTROL PLAN. RATE LIMIT. 

99.150

Unpaved Road

RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 PLANT ROADS 17.42 T/YR WATER SPRAY SUN COKE COMPANY - HAVERHILL NORTH COKE COMPANY OH 07-00466 2/27/2001 ROADWAYS AND PARKING 8.01 T/YR

WATERING AS SUFFICIENT FREQUENCY COMPLIANCE 

TEMPLE INLAND PINELAND MANUFACTURING COMPLEX TX PSD-TX-924 8/6/2000 HAUL ROADS, EPN119 7.53 LB/H WATER AS NEEDED CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL TX PSD-TX-138 (M5) 4/24/2000 SLAG ROAD EMISSIONS, S38 21.26 T/YR NONE INDICATED CAPITOL CEMENT DIVISION TX PSD-TX-120M3 9/16/1998 UNPAVED ROADS (PT. F-L-1) 25.34 T/YR

QUARRY ROADS SHALL BE SPRINKLED WAND/OR CHEMICALS, AS NECESSARY TO COMPLIANCE WITH ALL TNRCC RULES ANREGULATIONS. 

DESERET GENERATION AND TRANSMISSION CO. UT DAQE-523-95 6/14/1995 ROADS (UNPAVED)

WATER SPRAYED AND/OR CHEMICALLY TEMISSION RATE LIMITS 

99.190 ACE ETHANOL, LLC - STANLEY WI 03-DCF-184 1/21/2004 FUGITIVE EMISSIONS - TRUCK TRAFFIC -- SEE CONTROLS/P2

NO EMISSION RATE LIMITS. THE PERMITTTHE ROADS, SCALES, PADS AND OTHER NEEDED TO PREVENT FUGITIVE DUST EM

Other Fugitive

Dust Sources

Att 10-F_Material Handling_RBLC.xlsPM 
RBLC CODE FACILITY STATE PERMIT NUMBER PERMIT DATE PROCESS TYPE CONTROL DESCR

90.011 ARKANSAS LIME COMPANY AR 0045-AOP-R3 8/30/2005 COAL/COKE BIN VENT, SN-33Q #3 0.015 GR/DSCF DUST COLLECTOR 

Coal Handling,

NEWMONT NEVADA ENERGY INVESTMENT LLC TS POWER PLANT NV AP4911-1349 5/5/2005 COAL HANDLING OPERATIONS 0.10 GR/DSCF FABRIC FILTER DUST COLLECTOR 

Processing, IRON DYNAMICS, INC. (IDI) IN 033-19160-00076 4/13/2005 COAL DRYER 25 mmbtu/h 0.01 GR/DSCF BAGHOUSE Preparation, ISLAND CREEK COAL - VP #8 GARDEN PLANT VA 10704 11/2/2004 COAL PROCESSING PLANT - THERMAL DRYER 153 btu/h 0.019 GR/DSCF WET VENTURI SCRUBBER Cleaning

ISLAND CREEK COAL - VP #8 GARDEN PLANT VA 10704 11/2/2004 COAL HANDLING AND TRANSFER OPERATIONS 3.5 MMT/YR 3.35 T/YR WET SUPPRESSION 

RED TRAIL ENERGY, LLC - RICHARDTON PLANT ND 4004 8/4/2004 COAL HANDLING 27 T/H 0.004 GR/DSCF BAGHOUSE CARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 SOLID FUEL HANDLING - COAL AND COKE 0.31 T/YR

WORK PRACTICES THAT MINIMIZE OR ELOF FUGITIVE DUST. 

PLUM POINT ENERGY AR 1995-AOP-R0 8/20/2003 MATERIAL HANDLING, COAL, PARTIALLY INCLOSED 0.1 LB/H PARTIAL ENCLOSURES PLUM POINT ENERGY AR 1995-AOP-R0 8/20/2003 MATERIAL HANDLING, COAL, SUPPRESSION 0.1 LB/H WATER SPRAYS, DUST SUPPRESSANTS, PLUM POINT ENERGY AR 1995-AOP-R0 8/20/2003 MATERIAL HANDLING, COAL, BAGHOUSES 0.1 LB/H BAGHOUSES BULL MOUNTAIN, NO. 1, LLC - ROUNDUP POWER PROJECT MT 3182-00 7/21/2003 MATERIAL TRANSFER, COAL HANDLING TRANSFER POINTS 0.01 GR/DSCF DUST SUPPRESSION SYSTEMS AND ENCBULL MOUNTAIN, NO. 1, LLC - ROUNDUP POWER PROJECT MT 3182-00 7/21/2003 ACTIVE COAL STORAGE PILE 98 % REDUCTION WIND FENCE AND DUST SUPPRESSION; WBULL MOUNTAIN, NO. 1, LLC - ROUNDUP POWER PROJECT MT 3182-00 7/21/2003 INACTIVE COAL STORAGE PILE 98 % REDUCTION WIND FENCE, DUST SUPPRESSION, PILE MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 STACKER CONVEYOR CHEMICAL DUST SUPPRESSANT MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 TRANSFER TO ACTIVE PILE CHEMICAL DUST SUPPRESSANT MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 BUCKET RECLAIM CHEMICAL DUST SUPPRESSANT MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 RAIL UNLOADING CHEMICAL DUST SUPPRESSANT MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 ACTIVE COAL PILE 311155 SQ FT CHEMICAL DUST SUPPRESSANT MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 INACTIVE COAL STORAGE PILE 1196459 SQ FT CHEMICAL DUST SUPPRESSANT MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 RAIL UNLOADING COAL STOCKOUT PILE 28224 SQ FT CHEMICAL DUST SUPPRESSANT MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 ROTARY CAR DUMPER 3500 TONS/HR 0.005 GR/DSCF BAGHOUSE MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 TRANSFER CONVEYING BAY 1800 TONS/HR 0.005 GR/DSCF BAGHOUSE MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 TRANSFER HOUSE 2 3500 TONS/HR 0.005 GR/DSCF BAGHOUSE MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 TRANSFER HOUSE 4 3600 TONS/HR 0.005 GR/DSCF BAGHOUSE MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 SILOS 900 TONS/HR 0.005 GR/DSCF BAGHOUSE GCC DACOTAH SD 28.1101-PSD 4/10/2003 COAL SURGE BIN TOP (2) 400 T/H 0.01 GR/DSCF FABRIC FILTER GCC DACOTAH SD 28.1101-PSD 4/10/2003 COAL TUNNEL TO COAL STACKER 400 T/H 0.01 GR/DSCF FABRIC FILTER GCC DACOTAH SD 28.1101-PSD 4/10/2003 COAL TRANSFER 400 T/H 0.01 GR/DSCF FABRIC FILTER GCC DACOTAH SD 28.1101-PSD 4/10/2003 COAL DRYER - FK PUMP 20 T/H 0.01 GR/DSCF FABRIC FILTER GCC DACOTAH SD 28.1101-PSD 4/10/2003 COAL HOPPER TO CONVEYOR 400 T/H 0.01 GR/DSCF FABRIC FILTER ROCKY MOUNTAIN POWER, LLC - HARDIN GENERATOR PROJECT MT 3185-00 6/11/2002 MATERIAL TRANSFER, COAL HANDLING TRANSFER POINTS 0.01 GR/DSCF

DUST SUPPRESSION SYSTEMS AND ENCBAGHOUSE 

CONSOLIDATION COAL -BUCHANAN PREP PLANT VA 10945 9/26/2001 COAL HANDLING 138 MMBTU/H 0.019 GR/DSCF VENTUI SCRUBBER CONSOLIDATION COAL -BUCHANAN PREP PLANT VA 10945 9/26/2001 COAL HANDLING-2 253 MMBTU/H 0.019 GR/DSCF VENTURI SCRUBBER INTERNATIONAL PAPER - MANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001 COAL STORAGE AND HANDLING 452016 T/YR 0.59 LB/H UNLOADED TO COVER CONVEYOR, PULVRELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING LIGNITE MINE TRANSFER SILO 2.23 LB/H BAGHOUSE RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING OVERLAND CONVEYOR 2.04 LB/H PARTIAL ENCLOSURE RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING TRANSFER TOWER NO. 4 1.37 LB/H BAGHOUSE RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING TRANSFER TOWER NO 1Y 3.43 LB/H BAGHOUSE RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 (2) FUEL HANDLING ACTIVE STORAGE PILES A&B RECLAIM 1.03 LB/H BAGHOUSE RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING CRUSHER HOUSE 2.66 LB/H BAGHOUSE RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING TRANSFER TOWER NO 2 1.46 LB/H BAGHOUSE RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING TRANSFER TOWER NO 3 2.74 LB/H BAGHOUSE RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING OUTBOARD TOWER NO 1 0.26 LB/H BAGHOUSE RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING SILOS GALLERY A-D (4) UNIT 1&2 2.49 LB/H BAGHOUSE RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 (2) FUEL HANDLING ACTIVE STORAGE PILES A&B 1.56 T/YR WATER SPRAY & UNDERGROUND RECLA

RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING INACTIVE STORAGE PILE 9.02 T/YR WATERING 

RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING EMERGENCY STORAGE PILE 0.21 T/YR TELESCOPING CHUTE & WATER SPRAY RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING STACKING HOPPER 0.3 LB/H WATER SPRAY RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING STACKING HOPPER VAULT 0.13 LB/H BAGHOUSE 

THROUGHPUT

RACT/BACT/LAER Clearinghouse for Material Handling Operations

Attachment 10-F

EMISSION LIMIT

Att 10-F_Material Handling_RBLC.xlsPM10 
RBLC CODE FACILITY STATE PERMIT NUMBER PERMIT DATE PROCESS TYPE THROUGHPUT CONTROL DESCR

RACT/BACT/LAER Clearinghouse for Material Handling Operations

Attachment 10-F

EMISSION LIMIT

RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING STACKING HOPPER CONVEYOR 1A 0.17 LB/H PARTIAL ENCLOSURE RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING RAIL CAR UNLOADER 0.3 LB/H PARTIAL ENCLOSURE & WATER SPRAY RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING RAIL CAR UNLOADER VAULT 0.17 LB/H BAGHOUSE RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING RAIL CAR UNLOADER CONVEYOR 1B 0.09 LB/H PARTIAL ENCLOSURE RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING ACTIVE STORAGE PILE RECLAIM 0.17 LB/H BAGHOUSE & WATERSPRAY RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING ACTIVE STORAGE PILE 0.98 T/YR NONE INDICATED RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING CONVEYOR NO 2 0.07 LB/H PARTIAL ENCLOSURE RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING TRANSFER STATION NO 1 0.13 LB/H BAGHOUSE RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING CONVEYOR NO 3 0.06 LB/H NONE INDICATED RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING TRIPPER TOWER NO 2 0.17 LB/H BAGHOUSE RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING TRANSFER STATION NO 3 0.09 LB/H BAGHOUSE RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 (2) FUEL HANDLING LIME ADDITION SILOS A & B 0.63 LB/H BAGHOUSE SUN COKE COMPANY - HAVERHILL NORTH COKE COMPANY OH 07-00466 2/27/2001 LOAD IN AND LOAD OUT OF COKE/COAL STORAGE PILES 1.98 T/YR

LOAD-IN COAL, COKE, AND COKE BREEZIN COAL W/WATER SPRAYS/DUST SUPPRUNDER PILE GRAVITY FEED AND WATER UNDER PILE GRAVITY FEED. 

SUN COKE COMPANY - HAVERHILL NORTH COKE COMPANY OH 07-00466 2/27/2001 COAL HANDLING, CONVEYING, AND TRANSFER 6602850 T/YR 3.77 T/YR

RAIL CAR BOTTOM DUMPING AND ENCLOENCLOSED; WET AND/OR CHEMICAL SUP

SUWANNEE AMERICAN CEMENT COMPANY, INC. FL 1210465-001-AC 6/1/2000 COAL MILL 0.01 GR/DSCF BAGHOUSE CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL TX PSD-TX-138 (M5) 4/24/2000 RAILCAR LOADING FROM PELLETIZER SILO/BAGHOUSE DUST 0.0003 LB/H NONE INDICATED HOLNAM, FLORENCE CO 98-FR-0895 7/29/1999 UNLOADING & CONVEYING, COAL TO STOCKPILE 1.85 T/YR

NEG PRESSURE AND BAGHOUSE. STANDAVAILABLE. 

HOLNAM, FLORENCE CO 98-FR-0895 7/29/1999 COAL STOCKPILE 0.33 T/YR SURFACE MOISTURE HOLNAM, FLORENCE CO 98-FR-0895 7/29/1999 RECLAIMING, CONVEYING, & TRANS COAL TO COAL SCREEN 0.19 T/YR

BAGHOUSE. PERMIT MODIFICATION TRIGONLY. PM LIMITS IN STANDARD EMISSIO

HOLNAM, FLORENCE CO 98-FR-0895 7/29/1999 SCREENING AND CRUSHING OVERSIZE COAL 0.19 T/YR

BAGHOUSE. PERMIT MODIFICATION TRIGONLY. PM LIMITS IN STANDARD EMISSIO

HOLNAM, FLORENCE CO 98-FR-0895 7/29/1999

TRANS & CONVEYING - CRUSHED COAL TO TRANSFER TOWER 0.02 T/YR

BAGHOUSE. PERMIT MODIFICATION TRIGONLY. PM LIMITS IN STANDARD EMISSIO

HOLNAM, FLORENCE CO 98-FR-0895 7/29/1999 TRANSFER, COAL, TRANSFER TOWER TO SILO 0.02 T/YR

BAGHOUSE. PERMIT MODIFICATION TRIGONLY. PM LIMITS IN STANDARD EMISSIO

LONE STAR INDUSTRIES, INC. IN 133-10159 4/16/1999 CEMENT MANUFACTURING, COAL MILL 40 T/YR 0.01 GR/DSCF FABRIC FILTER NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 RAW COAL/COKE BIN 0.08 LB/H BAGHOUSE & SPRAY COAL/COKE PILES NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 MAT STORAGE, CRUSHED COAL/COKE BIN 0.01 LB/H BAGHOUSE AND SPRAY THE PILE NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 MAT HANDLING, COAL/COKE DROP PT TO HOPPER (MT08) 0.09 LB/H PARTIAL ENCLOSURE AND WATER SPRANORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 MATERIAL HANDLING, COAL/COKE DROP POINT TO STACKER 0.22 LB/H PARTIAL ENCLOSURE AND WATER SPRANORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 MATERIAL HANDLING, COAL/COKE DROP POINT TO PILE 0.22 LB/H PARTIAL ENCLOSURE AND WATER SPRANORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 MATERIAL HANDLING, COAL/COKE DROP TO HOPPER (MT05) 0.22 LB/H PARTIAL ENCLOSURE AND WATER SPRANORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 MATERIAL HANDLING COAL/COKE DROP FEEDER TO BELT 0.09 LB/H NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 MATERIAL HANDLING COAL/COKE DROP BELT TO BELT 0.09 LB/H COVERED CONVEYOR BELTS NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 MAT HANDLING, COAL/COKE RECEIVING DROP TO HOPPER 0.04 LB/H PARTIAL ENCLOSURE AND WATER SPRANORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 MAT HANDLING, COAL/COKE UNLOADING CONVEYOR BELT 0.01 LB/H COVERED CONVEYOR BELT, WATER SPRNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 MAT HANDLING COAL/COKE CONVEYOR TO STACKER 0.01 LB/H COVERED CONVEYOR BELT NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 MATERIAL HANDLING, COAL/COKE STACKER TO PILE 0.01 LB/H ENCLOSURE, WATER SPRAY NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 MAT HANDLING COAL/COKE CONVEYOR TO COAL GRINDING 0.01 LB/H COVERED CONVEYOR BELT NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 MAT HANDLING COAL/COKE CONVEYOR TO MILL FEED BIN 0.01 LB/H COVERED CONVEYOR BELT 

Att 10-F_Material Handling_RBLC.xlsPM10 
RBLC CODE FACILITY STATE PERMIT NUMBER PERMIT DATE PROCESS TYPE THROUGHPUT CONTROL DESCR

RACT/BACT/LAER Clearinghouse for Material Handling Operations

Attachment 10-F

EMISSION LIMIT

NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 MATERIAL STORAGE, COAL/COKE PILES 0.28 LB/H SPRAY THE C/C PILES DESERET GENERATION AND TRANSMISSION COMPANY UT DAQE-186-98 3/16/1998 CONVEYOR COAL 475 T/H 925.76 T/Y CARGILL, INC IA 83-A-090-S2, ET AL 2/24/1997 COAL BUNKER II-CUSTOM FABRICATED 0.129 LB/H

FABRIC FILTERS. STANDARD EMISSION LPERMIT PROCESS DATA. 

CARGILL, INC IA 83-A-090-S2, ET AL 2/24/1997 COAL BUNKER III-CUSTOM FABRICATED 0.129 LB/H

FABRIC FILTER. STANDARD EMISSION LIMPROCESS DATA. 

CARGILL, INC IA 83-A-090-S2, ET AL 2/24/1997 COAL CONVEYING ASPIRATION 0.6 LB/H

FABRIC FILTER. STANDARD EMISSION LIMPROCESS DATA. 

CARGILL, INC IA 83-A-090-S2, ET AL 2/24/1997 COAL BUNKER I 0.129 LB/H

FABRIC FILTER. STANDARD EMISSION UNPERMIT PROCESS DATA. BASIS OF LIMIT

CARGILL, INC IA 83-A-090-S2, ET AL 2/24/1997 COAL DUMPING SHED 1.541 LB/H

FABRIC FILTER. STANDARD EMISSION LIMPERMIT PROCESS DATA. BASIS OF LIMIT 

ASH GROVE CEMENT COMPANY UT DAQE-958-96 10/24/1996 COAL DELIVERY SYSTEM 1.08 LB/H BAGHOUSE 

90.019 ARKANSAS LIME COMPANY AR 0045-AOP-R3 8/30/2005 LIME STORAGE SILO DUST COLLECTORS, SN-36Q & SN-37Q 0.015 GR/DSCF DUST COLLECTOR 

Lime, ARKANSAS LIME COMPANY AR 0045-AOP-R3 8/31/2005 LIME STORAGE SILO DUST COLLECTORS, SN-38Q & SN-39Q 0.015 GR/DSCF DUST COLLECTOR Limestone ARKANSAS LIME COMPANY AR 0045-AOP-R3 9/1/2005 KILN FEED BELT INTO NO. 3 KILN SURGE BIN, SN-35Q 10 % OPACITY FUGITIVE SOURCE - READINGS VIA EPA MHandling, CARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 KILN DUST HANDLING 0.21 T/YR WATERING OF DUST AND BAGHOUSEKilns, CARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 MATERIAL STORAGE PILES 0.4 T/YR

WATER APPLICATIONS AND DAILY INSPEPILE.

Storage, CARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 LIMESTONE MATERIAL HANDLING 2.1 T/YR WATER APPLICATION.Manufacturing CARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 COMMON PRODUCT HANDLING 0.3 T/YR

WORK PRACTICES THAT MINIMIZE OR ELOF FUGITIVE DUST.

CARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 PRODUCT STORAGE/LOADOUT #2 1.13 T/YR

WORK PRACTICES THAT MINIMIZE OR ELOF FUGITIVE DUST.

CARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 PRODUCT STORAGE/LOADOUT #1 0.3 T/YR

WORK PRACTICES THAT MINIMIZE OR ELOF FUGITIVE DUST.

PLUM POINT ENERGY AR 1995-AOP-R0 8/20/2003 MATERIAL HANDLING, LIME, BAGHOUSES 0.1 LB/H BAGHOUSEFIRST ENERGY/TOLEDO EDISON CO. - BAYSHORE PLANT OH 04-1056 7/31/2003 LIMESTONE CRUSHING, SIZING, AND CONVEYING 12.8 T/YR BAGHOUSEFIRST ENERGY/TOLEDO EDISON CO. - BAYSHORE PLANT OH 04-1056 7/31/2003 LIMESTONE DRYER 87 gal/h #2 fuel oil 0.001 LB/H FABRIC FILTERBULL MOUNTAIN, NO. 1, LLC - ROUNDUP POWER PROJECT MT 3182-00 7/21/2003 MATERIAL TRANSFER, LIME HANDLING TRANSFER POINTS 0.01 GR/DSCF PNEUMATIC TRANSFERS AND BAGHOUSMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 LIME STORAGE SILO 2000 TONS/HR 0.01 GR/DSCF VENT BAG FILTER MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 LIME FILTER SEPARATOR 100 TONS/HR 0.01 GR/DSCF BAGHOUSE MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 UREA SILO 60 TONS 0.01 GR/DSCF VENT BAG FILTER ROCKY MOUNTAIN POWER - HARDIN GENERATOR PROJECT MT 3185-00 6/11/2002 MATERIAL TRANSFER, LIME HANDLING TRANSFER POINTS 0.01 GR/DSCF DUST SUPPRESSION SYSTEMS AND ENCRELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 LIMESTONE HANDLING RAILCAR UNLOADING FACILITY 0.3 LB/H WATER SPRAYRELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 LIMESTONE HANDLING UNLOADER & HOPPER VAULT 1.29 LB/H BAGHOUSERELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 LIMESTONE HANDLING SHUTTLE CONVEYOR 0.77 LB/H BAGHOUSERELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 LIMESTONE HANDLING RECLAIM 0.51 LB/H BAGHOUSERELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 LIMESTONE HANDLING TRANSFER TOWER 1.71 LB/H BAGHOUSERELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 LIMESTONE HANDLING 0.61 LB/H BAGHOUSERELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 LIMESTONE HANDLING STORAGE PILE 0.21 T/YR

PARTIAL ENCLOSURE, TELESCOPING CHRECLAIM

RELIANT ENERGY - W.A. PARISH ELECTRIC GENERATING STATION TX PSD-TX-234 12/21/2000 RAILCAR UNLOADING, LH1 500 T/H 15 LB/H

PERMANENTLY MOUNTED SPRAY NOZZLBY SWEEPING/WASHING, WATER/CHEMIC

RELIANT ENERGY - W.A. PARISH ELECTRIC GENERATING STATION TX PSD-TX-234 12/21/2000 TRACK HOPPERS, LH1A 500 T/H* 0.27 LB/H

PERMANENTLY MOUNTED SPRAY NOZZLCLEANING/SWEEPING, CHEMICAL/WATER 

RELIANT ENERGY - W.A. PARISH ELECTRIC GENERATING STATION TX PSD-TX-234 12/21/2000 STOCKPILE, LH2 500 T/H* 0.06 T/YR NONE INDICATED RELIANT ENERGY - W.A. PARISH ELECTRIC GENERATING STATION TX PSD-TX-234 12/21/2000 STORAGE PILE RECLAIM, CONVEYOR, CRUSHER; LH5 500 T/H* 2.1 LB/H

ENCLOSED CONVEYORS. LOADING STOCCHUTE. UNDERGROUND RECLAIM SYSTE

RELIANT ENERGY - W.A. PARISH ELECTRIC GENERATING STATION TX PSD-TX-234 12/21/2000 STORAGE SILO, LH6 500 T/H* 0.39 LB/H BAGHOUSE MEADWESTVACO KENTUCKY LP - WICKLIFFE CARBON PLANT KY V-99-009 (R1) 11/16/1999 LIME STORAGE AND FEED SYSTEM 0.3 LB/H CARTRIDGE FILTER NUCOR STEEL CORPORATION AR 1139-AOP-R5 9/9/1999 LIME SILO 0.005 GR/DSCF FABRIC FILTER TEXAS LIME COMPANY TX PSD-TX-54 8/2/1999 DUST BIN LOADOUT DUST COLLECTOR, 6-AS-3 0.36 LB/H DUST COLLECTOR TEXAS LIME COMPANY TX PSD-TX-54 8/2/1999 DUST BIN COLLECTOR, 6-AS-2 0.13 LB/H DUST COLLECTOR LONE STAR INDUSTRIES, INC. IN 133-10159 4/16/1999 CEMENT MANUFACTURING, SECONDARY CRUSHER 400 T/H 0.015 GR/DSCF BAGHOUSE. PM10 = TOTAL FILTERABLE GCC DACOTAH SD 28.1101-PSD 4/10/2003 GYPSUM RAW SHED (2) 350 T/H 0.01 GR/DSCF FABRIC FILTER 

Att 10-F_Material Handling_RBLC.xlsPM10 
RBLC CODE FACILITY STATE PERMIT NUMBER PERMIT DATE PROCESS TYPE THROUGHPUT CONTROL DESCR

RACT/BACT/LAER Clearinghouse for Material Handling Operations

Attachment 10-F

EMISSION LIMIT

NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 SHIFTABLE QUARRY BELT DROP POINT 0.29 LB/H PATIAL ENCLOSURE AND SPRAYING.NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 QUARRY BELT DROP POINT (FUTURE) 0.29 LB/H COVERED AND SPRAYEDNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999

QUARRY CONVEYOR BELT TO LIMESTONE STORAGE DROP PT. 0.29 LB/H SPRAYED AND COVERED

NORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 MOBILE CRUSHER 0.65 LB/HNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 LIMESTONE STORAGE BUILDING VENT 0.05 LB/H FULLY ENCLOSED BUILDING FOR LIME SNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 QUARRY CONVEYOR BELT TO LIMESTONE STORAGE 0.01 LB/H COVERED CONVEYOR BELTNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 QUARRY BELT (SHIFTABLE) 0.07 LB/H COVERED CONVEYOR BELTNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 QUARRY BELT (FUTURE) 0.09 LB/H COVERED CONVEYOR BELTNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 LIMESTONE CONVEYOR BELT TO FEED BINS 0.01 LB/H COVERED CONVEYOR BELTDESERET GENERATION AND TRANSMISSION COMPANY UT DAQE-186-98 3/16/1998 MATL HANDLING, LIMESTONE 55.6 METRIC T/Y 925.76 T/YCARGILL, INC IA 83-A-090-S2, ET AL 2/24/1997 LIME / PRECOAT WEIGH HOPPER DUST COLLECTER 9000 T/MO 0.039 LB/H

FABRIC FILTER. STANDARD EMISSION UNFROM PERMIT PROCESS DATA.

CARGILL, INC IA 83-A-090-S2, ET AL 2/24/1997 LIME PRECOAT STORAGE 9000 T/MO 0.032 LB/H

FABRIC FILTER. STANDARD EMISSIONS EDATA BASIS OF LIMIT: OTHER- NAAQS

99.120

NEWMONT NEVADA ENERGY INVESTMENT LLC TS POWER PLANT NV AP4911-1349 5/5/2005 ASH, LIME AND CARBON SILOS 0.02 GR/DSCF BIN VENT FILTERS 

Ash Handling, PLUM POINT ENERGY AR 1995-AOP-R0 8/20/2003 MATERIAL HANDLING, FLYASH, BAGHOUSES 0.1 LB/H BAGHOUSE Storage, PLUM POINT ENERGY AR 1995-AOP-R0 8/20/2003 MATERIAL HANDLING, FLY ASH, SUPPRESSION 0.1 LB/H DUST SUPPRESSION - WATER SPRAYS Disposal TOLEDO EDISON CO. - BAYSHORE PLANT OH 04-1056 7/31/2003 COKE AND FLY ASH TRANSFERRING AND CONVEYING 730000 t/yr 6.79 T/YR FABRIC FILTER AND ADEQUATE ENCLOS

BULL MOUNTAIN, NO. 1, LLC - ROUNDUP POWER PROJECT MT 3182-00 7/21/2003 MATERIAL HANDLING, FLY ASH HANDLING TRANSFER POINT 0.01 GR/DSCF VACUUM PRESSURE SYSTEM AND BAGHMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 FLYASH/FGD WASTE VACUUM SYSTEM EXHAUSTER 40.44 TONS/HR 0.005 GR/DSCF BAGHOUSE MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 FLYASH/FGD WASTE STORAGE SILO 2000 TONS 0.005 GR/DSCF VENT BAG FILTER ROCKY MOUNTAIN POWER, INC. - HARDIN GENERATOR PROJECT MT 3185-00 6/11/2002 MATERIAL TRANSFER, FLY ASH HANDLING TRANSFER POINT 0.01 GR/DSCF DUST SUPPRESSION SYSTEMS AND ENCINTERNATIONAL PAPER - MANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001 ASH HANDLING OPERATIONS 28 T/H 0.96 LB/H WET SUPPRESSION DURING LOADING RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 (2) WASTE HANDLING FLY ASH SILOS NO 1 & 2 1.59 LB/H BAGHOUSE RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 WASTE HANDLING FLY ASH TRUCK LOADING OPERATION 1.65 LB/H TELESCOPING CHUTE, VACUUM RECOVERELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 WASTE HANDLING FLY ASH BAG LOADING OPERATION 0.05 LB/H VACUUM RECOVERY RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 (3) WASTE HANDLING FLY ASH SILOS A,B,&C 1.15 LB/H BAGHOUSE RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 BOTTOM ASH TRUCK LOADING 0.47 LB/H WET MATERIAL TEMPLE INLAND PINELAND MANUFACTURING COMPLEX TX PSD-TX-924 8/6/2000 ASH PICKUP, EPN93 0.47 LB/H BAGFILTER LONE STAR INDUSTRIES, INC. IN 133-10159 4/16/1999 CEMENT MANUFACTURING, FLY ASH SILOS 135300 T/YR 0.015 GR/DSCF BAGHOUSE. PM10 = TOTAL FILTERABLE 

99.140 STEELCOOR, INC. - BLUEWATER PROJECT AR 2062-AOP-R0 7/22/2004 ROADWAY EMISSIONS 26.9 T/YR APPLICATION OF WETTING AGENT 

Paved Roads PLUM POINT ENERGY AR 1995-AOP-R0 8/20/2003 ROAD DUST 0.2 LB/H DUST SUPPRESSION - WATERING, DUST 

MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 HAUL ROADS 46 TRUCKS/DAY

WATER FLUSHING FOLLOWED BY SWEEPASSUMED 

ARKANSAS STEEL ASSOCIATES AR 35-AOP-R3 1/5/2001 PAVED ROADS 6.9 T/YR WATER APPLICATON TO CONTROL FUGITCHAPPARRAL STEEL MIDLOTHIAN STEEL MILL TX PSD-TX-138 (M5) 4/24/2000 IN-PLANT VEHICLE TRAFFIC 12.5 T/YR CHEMICAL AND WATER SPRAY HOLNAM, FLORENCE CO 98-FR-0895 7/29/1999 PAVED ROADS, CEMENT PRODUCT HAULOUT 1.2 T/YR CONTROL PLAN INTERNATIONAL PAPER LUMBER MILL TX PSD-TX-892 9/28/1998 HR-FUG HAUL ROAD FUGITIVES 1.24 LB/H

PLANT ROADS SHALL BE PAVED WITH A WHICH CAN BE CLEANED BY SWEEPING SHALL BE SPRINKLED WITH WATER AND/SENSITIVE CHEMICALS AS NEEDED TO C

CAPITOL CEMENT DIVISION TX PSD-TX-120M3 9/16/1998 PAVED ROADS (F-TR-1) 0.86 T/YR

PLANT ROADS SHALL BE PAVED AND CLESHALL BE SPRINKLED WITH WATER AND/NECESSARY, TO MAINTAIN COMPLIANCE REGULATIONS. 

CON AGRA SOYBEAN PROCESSING CO. IN 129-8541-00039 8/14/1998 FUGITIVE DUST

ROADS ARE PAVED, REGULAR PROGRAM AND/OR ROAD WETTING AS NEEDED. 

SPRINGFIELD PLANT OR 202125 6/4/1998 ROAD AND PARKING LOTS 11 LB/D 

LAFARGE CORPORATION MO 0897-019 8/20/1997 PAVED HAUL ROADS(EP 95) 60969.6 VMT 0 SEE CONTROLS/P2 WATER FLUSHING FOLLOWED BY VACUUBUNGE CORPORATION IA 97-A-419, ET-AL. 5/20/1997 ROADWAY AREA SOURCE, PAVED 0.055 LB/H HARD SURFACE PAVEMENT 

99.150 RECMIX OF PA, INC. KY V-03-051 8/6/2004 UNPAVED ROAD 0.78 T/YR WATERING - 70% REDUCTION TAKEN INT

Unpaved RoadsPLUM POINT ENERGY AR 1995-AOP-R0 8/20/2003 ROAD DUST 0.3 LB/H DUST SUPPRESSION - WATERING, DUST 

INTERNATIONAL PAPER - MANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001 HAUL ROADS 18.5 LB/H

WET SUPPRESSION ON UNPAVED ROADPERIOD DURING DAYLIGHT HOURS (EXC

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RBLC CODE FACILITY STATE PERMIT NUMBER PERMIT DATE PROCESS TYPE THROUGHPUT CONTROL DESCR

RACT/BACT/LAER Clearinghouse for Material Handling Operations

Attachment 10-F

EMISSION LIMIT

RELIANT ENERGY - LIMESTONE ELECTRIC GENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 PLANT ROADS 8.71 T/YR WATER SPRAY SUN COKE COMPANY - HAVERHILL NORTH COKE COMPANY OH 07-00466 2/27/2001 ROADWAYS AND PARKING 1.56 T/YR WATERING AS SUFFICIENT FREQUENCY NUCOR STEEL IN 107-12143-00038 1/19/2001 TRANSPORTATION ON ROADS 16.8 LB/MILE

SPEED LIMITS, VACUUMING/SWEEPING ESUPPRESSANT ON UNPAVED ROADS AT ONCE PER MONTH. EMISSION UNIT IS LB 

ARKANSAS STEEL ASSOCIATES AR 35-AOP-R3 1/5/2001 UNPAVED ROADS 6.9 T/YR WATER APPLICATON TO CONTROL FUGITTEMPLE INLAND PINELAND MANUFACTURING COMPLEX TX PSD-TX-924 8/6/2000 HAUL ROADS, EPN119 3.45 LB/H WATER AS NEEDED CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL TX PSD-TX-138 (M5) 4/24/2000 SLAG ROAD EMISSIONS, S38 10.63 T/YR NONE INDICATED CAPITOL CEMENT DIVISION TX PSD-TX-120M3 9/16/1998 UNPAVED ROADS (PT. F-L-1) 11.4 T/YR

QUARRY ROADS SHALL BE SPRINKLED WCHEMICALS, AS NECESSARY, TO COMPLAND REGULATIONS. 

LAFARGE CORPORATION MO 0897-019 8/20/1997 UNPAVED HAUL ROADS(EP 96) 33025.2 VMT 0 SEE CONTROLS/P2

USE OF EMULSION AT MANUFACTURER'S RATE (SURFACTANT, DUST SUPPRESSAN

99.190

LOUISIANA-PACIFIC CORPORATION - URANIA PLANT LA PSD-LA-578 12/7/2000 PLANT ROADWAY FUGITIVES 0.02 LB/H NONE INDICATED 

Other Fugitive RIO GRANDE PORTLAND CEMENT CORP. CO 98PB0893 9/25/2000 RAW MATERIAL TRANSFER, ROAD DUST -- SEE CONTROLS/P2

CE = 85-90%. TREATMENT OF UNPAVED HCHEMICAL STABILIZERS AND REGULAR WINSPECTION AND CLEANING OF PAVED HSURFACTANTS IN SPRAY WATERS. NO LEMISSION 

Dust Sources

Att 10-F_Material Handling_RBLC.xlsPM10