# 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 (NO X 

# ), sulfur dioxide (SO 2 

# ), carbon

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

10 microns or less (PM 10 

# ), volatile organic compounds (VOCs), lead (Pb), hydrogen fluoride (HF),

and sulfuric acid mist (H 2 

# SO 4 

# ). The TEP also will be subjec t 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)

# 10784-004-400 July, 2007 

# 10-3 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 Spreadshee t 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 (C UECost) 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 t heir 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 (D I) 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 (D I) 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 wa ste 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 CUECo st 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 NO X



# 10.2.1 Formation

NO X 

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

either thermal NO X 

# or fuel NO X 

# . Thermal NO X 

# is formed when elemental nitrogen reacts with

oxygen (O 2 

# ) in the combustion air within the high temperature environment of the furnace. The

rate of formation of thermal NO X 

# is a function of residence time and free O 2 

# , and is exponential

with peak flame temperature. Fuel NO X 

# is generated when nitrogen contained in the fuel itself is

oxidized. The rate of formation of fuel NO X 

# is primarily a function of fuel bound nitrogen content of

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

NO X 

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

techniques such as Low-NO X 

# burners (LNB), flue gas recirculat ion (FGR), over fire air (OFA),

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

SCR. SCONO X 

# 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 NO X 

# 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 boile rs (see Attachment 10-B) and recent permits and

applications indicates general levels of NO X 

# 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 NO X 

# Control Technologies for PC Boilers

PC

Control Technologies Typical Control

Efficiency Range

(% Removal) Typical Emission

Level 1



# (lb/MMBtu) Technically Feasible for

PC Boilers

SCR and LNB 80-90 0.06-0.15 lb/MMBtu 2 

# Yes

SNCR 40-60 0.2-0.3 lb/MMBtu Yes

Staged Combustion Techniques

Including Low-NO X 

# Burners 30-50 0.15-0.5 lb/MMBtu 3 

# Yes

SCONO X 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 sta ged 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 NO X 

# 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/MMBt u. 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 NO X 

# 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 NO X 

# through retrofit of controls to pre-existing sources. The Weston Plant

currently has the lowest NO X 

# 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 NO X 

# /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 NO X 

# Control Technology Discussion

Selective Catalytic Reduction

SCR is a process that involves post-combustion removal of NO X 

# from flue gas with a catalytic

reactor. In the SCR process, ammonia injected into the exhaust gas reacts with NO X 

# and O 2 

# to

# 10784-004-400 July, 2007 

# 10-11 form nitrogen and water. SCR converts NO X 

# to nitrogen and water by the following reactions

(Cho 1994):

4NO + 4NH 3 

# +O 2 

# → 4N 2 

# + 6H 2 

# O

6NO + 4NH 3 

# → 5N 2 

# + 6H 2 

# O

2NO 2 

# + 4NH 3 

# + O 2 

# → 3N 2 

# + 6H 2 

# O

6NO 2 

# + 8NH 3 

# → 7N 2 

# + 12H 2 

# O

NO + NO 2 

# + 2NH 3 

# → 2N 2 

# + 3H 2 

# O

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

lower the activation energy of the NO X 

# 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 ammoni a 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 syst em 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/NO X 

# ratio, and optimum O 2



# 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 NO X 

# (thereby actually increasing NO X 

# 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

NO X 

# (increasing NO X 

# emissions) or ammonium nitrate.

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

promote partial oxidation of SO 2 

# to sulfur trioxide (SO 3 

# ), which combines with water to form

sulfuric acid. At typical SCR operating temperatures, SO 3 

# 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 PM 10 

# entering the particulate

collector. Fouling may eventually lead to decreased NO X 

# 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 esti mate 10 parts per million (p pm) volume dry of unreacted

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

achieve high NO X 

# 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 NO X 

# and ammonia may occur in high NO X 

# 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 PM 10 

# (and PM

with an aerodynamic diameter of 2.5 microns or less [PM 2.5 

# ]).

• 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 NO X 

# in the flue gas and either injected NH 3 

# or urea to produce

gaseous nitrogen and water vapor. SNCR systems do not employ a catalyst; the NO X 

# reduction

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

NO X 

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

Critical to the successful reduction of NO X 

# 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 NO X 

# , 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 NO X 

# 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 PM 2.5 

# . Thus,

for a given boiler configuration, there is a limit on the degree of NO X 

# 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 NO X 

# 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 NO X



# 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 NO X 

# from PCs compared with CFBs.

Staged Combustion

A number of techniques have been employed to reduce the formation of NO X 

# by reducing peak

flame temperature and/or starving the hottest parts of the flame for O 2 

# . By staging the combustion

process, a longer, cooler flame results that forms less NO X 

# . 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 NO X 

# to 0.15 lb/MMBtu simply by starving

the coal burners for excess O 2 

# 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 NO X 

# 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 NO X



# Based on a review of available control technologies for emissions of NO X 

# 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 NO X 

# 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 NO X 

# 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 NO X 

# 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 NO X 

# 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 NO X 

# 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 C UECost 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 NO X 

# 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 cont ent of 0.0015 weight percent. These boi lers 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 NO X 

# . 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 NO X 

# control, we

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

made the presumption that SCR might represent tran sferable 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

NO X 

# /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 NO X 

# emissions of around

0.10 lb NO X 

# /MMBtu. This proposed emission limit provides a maximum allowable NO X 

# 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 NO X 

# /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 NO X 

# control is

experienced at all until the catalyst bed achieves full operating temperature, negating any NO X



# 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 NO X 

# 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 NO X



# 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 boile rs. 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 NO X 

# to effectively contact, which pr ecludes the ability to utilize SNCR

for NO X 

# control. The USEPA document, “Alternative Control Techniques Document – NO X



# 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 NO X 

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

sufficient volume and residence time exists to st arve the high temperature combustion zone of O 2 

# , then adding the O 2 

# 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 NO X 

# , 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 NO X 

# control are determined to be

technically feasible for application to the proposed auxiliary package boiler.

10.2.3.4 Low NO X 

# 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 m anufacturers 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 NO X 

# /MMBtu.

10.2.3.5 Selection of BACT for NO X 

# 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 NO X 

# , 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 li mited to 6 percent capacity. The

550 hour per year operating limit results in the cost per ton of NO X 

# 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 NO X 

# emissions to 0.10 lb/MMBtu, the

demonstrated capability of thes e 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. NO X 

# 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 NO X 

# 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 NO X 

# and NMHC of no more than 4.0 g/kWh.

10.3 BACT for Sulfur Dioxide

10.3.1 Formation

Emissions of SO 2 

# 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 SO 2 

# 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 SO 2 

# 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 SO 2 

# 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 SO 2 

# 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 SO 2 

# control technologies ( Table 10-10 ) must take into

consideration multiple variables including coal sulfur content and vari ability, percent removal

capability (which varies depending on the amount of uncontrolled SO 2 

# 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 SO 2 

# Technologies for PC Boilers

Control Technology Typical Level

of Control 1 

# Typical Emission Level 1



# (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 st eady 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

SO 2 

# 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 SO 2 

# 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 de monstrated 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 (CO 2 

# ), and would be

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

have been permitted at SO 2 

# 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 SO 2 

# 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 SO 2 

# from a supercritical PC-fired boiler.

10.3.2.3 SO 2 

# 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 SO 2 

# 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 SO 2 

# 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

H 2 

# SO 4 

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

Use of Low Sulfur Coal

Any discussion of the relative effectiveness of add on SO 2 

# control also must take into account the

level of uncontrolled SO 2 

# 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 SO 2 

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

resulting emission rate in units of lb of SO 2 

# per MMBtu of fuel burned (or lb of SO 2 

# 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 SO 2 

# to

BACT levels in combination with add-on control.

10.3.2.4 Summary of PC-fired Boiler BACT for SO 2



# Toquop Energy is proposing to limit SO 2 

# 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 SO 2 

# 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 SO 2 

# 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 SO 2 

# 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 SO 2 

# . Therefore, the cost effectiveness of the

wet FGD system is about $3,300 per ton of SO

2 

# removed.

The cost effectiveness is significantly higher than the typical cost effectiveness to control SO 2



# (SO 2 

# 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 SO 2 

# compared with similar PC boiler permits. While the cost effectiveness

is high enough to eliminate the proposed level of SO 2 

# control as BACT, Toquop Energy has

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

emissions of H 2 

# SO 4 

# and SO 2 

# 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.

SO 2 

# 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 SO 2 

# controls have ever been applied to similar

sources. The use of very low sulfur fuel is the only available SO 2 

# control option. On-road

transportation distillate oil is curr ently 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 SO 2 

# 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 SO 2 

# and SO 3



# .

# 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 EQUI PMENT (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 Fiel d 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 SO 2 

# 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 SO 2 

# , 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 SO 2 

# control

option and represents the top level of control. Toquop Energy proposes an SO 2 

# 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 O 2 

# , and high temperature in the

combustion zone to ensure complete combustion. These control factors, however, also tend to

result in increased emissions of NO X 

# . Conversely, a low NO X 

# 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 NO X 

# 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 O 2 

# availability (excess air), flame

temperature, residence time at flame temperatur e, 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 listi ngs 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

SO 2 

# to produce SO 3 

# , which would exacerbate H 2 

# SO 4 

# emissions. The SO 2 

# 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 NO X 

# limit is 0.43 lb/MMBtu.

Since the TEP is proposing a very stringent NO X 

# 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 0.10 1 

# to 0.16 Yes

Oxidation catalyst Not determined No

SCONO X 

# Not determined No

1 

# Lowest level achievable for PC boilers with aggressive NO X 

# 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 NO X 

# 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 O 2 

# to CO 2 

# 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 SO 2 

# to SO 3 

# as well as CO to CO 2 

# . The amount of SO 2



# conversion is a function of temperature and catalyst design. Under optimum conditions, formation

of SO 3 

# can be minimized to 5 percent of inlet SO 2 

# . This level of conversion would result in a large

collateral increase in H 2 

# SO 4 

# 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 SO 2 

# 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.

SCONO X



# SCONO X 

# 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, SCONO X 

# actually utilizes the same CO reduction technology as

oxidation catalyst discussed previously. The SCONO X 

# 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. SCONO X 

# 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 meas ure 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 NO X 

# , 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 au xiliary 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 NO X 

# 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 NO X 

# 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 temperatur e, 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 utiliz e 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 0.0024 1 

# 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 SCONO X 

# 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 meas ures 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 NO X 

# , 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 NO X 

# as described in Section 10.2.4.

Toquop Energy proposes that the combined NMHC and NO X 

# emission limits are BACT for VOC

for the emergency engines. The proposed emission limit is 6.4 g/kWh of NMHC and NO X 

# 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 PM 10 

# (PM 2.5 

# is a subset of PM 10 

# ) require the application of BACT

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

or 17. PM 10 

# includes filterable PM 10 

# 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

PM 10 

# 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 PM 10 

# and do not include condensable PM 10 

# . The permit

for AES-Puerto Rico addressed this issue in detail. AES’s permit limits filterable PM 10 

# to

0.015 lb/MMBtu and allowed for stack testing to determine an achievable total PM 10 

# emission limit.

Stack tests showed that filterable PM 10 

# 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 PM 10 

# emission limit at 0.03 lb/MMBtu to account for the condensable fraction of PM 10



# . 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 PM 10 

# must account for

additional emissions attributable to the condensable fraction of PM 10



# .

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 stead y-state values at base load, for front-half (filterable) only. Inclusion of the con densable 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 PM 10 

# varying from 0.012 to 0.018 lb/MMBtu; however, the USEPA RBLC

specified whether these limits included condensable PM 10 

# in only a few cases. Fabric filter

represents the technology of choice to achieve the lowest PM 10 

# 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 PM 10 

# 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 PM 10 

# 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 PM 10 

# 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 PM 10 

# levels less than 0.03 lb/MMbtu. For this

reason, Toquop Energy proposes to limit total PM 10 

# (including condensable PM 10 

# ) emissions to no

more than 0.03 lb/MMBtu.

10.6.3 Auxiliary Boilers

10.6.3.1 Identification and Ranking of PM/PM 10 

# 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 th e 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 facilit y will not have natural gas serv ice. 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 PM 10



# .

# 10784-004-400 July, 2007 

# 10-37 10.6.3.2 Selection of BACT for PM 10 

# 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 PM 10 

# 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 PM 10 

# 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 PM 10 

# , BACT

includes an emission limit of 0.024 lb/MMBtu based on adding the condensable PM 10 

# 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 PM 10 

# 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/PM 10 

# Emissions

PM and filterable PM 10 

# 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 fac ility will be able to dump coal from

two railcars simultaneously. Hoppers and two f eeder 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. Th e active coal pile will be a 30-da y 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 tr ucks 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 tr ansferred 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. Alte rnatively, 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 transfer red to trucks or railcars. Alternatively, if the

bottom ash is being shipped to purchasers, it wi ll 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, wett ed 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/PM 10 

# Control Technologies

Potential PM/PM 10 

# 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 PM 10 

# controls for materials handling

and storage operations. The results are provided separately for PM and PM 10 

# ; 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/PM 10 

# Control Technologies for Material Handling

Dust Sources

All of the above options are technically f easible 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/PM 10 

# 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 insi de 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/PM 10 

# 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/PM 10 

# 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 propos es 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

H 2 

# SO 4 

# is formed in coal fired boilers due to oxidation of SO 2 

# to SO 3 

# , and subsequent reaction with

water vapor to form H 2 

# SO 4 

# . The formation of H 2 

# SO 4 

# is therefore highly dependent on coal sulfur

content and the presence of oxidizing catalysts. H 2 

# SO 4 

# 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 H 2 

# SO 4 

# 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 H 2 

# SO 4 

# proportionately to SO 2 

# . 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 H 2 

# SO 4 

# . This project exhibits high uncontrolled

# 10784-004-400 July, 2007 

# 10-43 H 2 

# SO 4 

# emission levels because it will utilize a relatively high sulfur eastern coal. The proposed

TEP, by comparison, will have uncontrolled H 2 

# SO 4 

# levels that are only a fraction of

Thoroughbred’s levels.

Toquop Energy recognizes, however, that H 2 

# SO 4 

# is a precursor to the formation of regional haze

and also has included active control of H 2 

# SO 4 

# in the design of the TEP. Dry sorbent injection has

been proposed upstream of the fabric filter to selectively scrub H 2 

# SO 4 

# 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 H 2 

# SO 4 

# 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 H 2 

# SO 4 

# 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 H 2 

# SO 4 

# 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 H 2 

# SO 4 

# 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 H 2 

# SO 4 

# 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 H 2 

# SO 4 

# also will control HF emissions throu gh 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-fir ed 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 fluor ine bearing fuel (very lo w 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 PM 10 

# 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 PM 10



# .

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

NO X 

# 0.06, 24-hour average, based on continuous emission

monitoring Low-NO X 

# burners and SCR

SO 2 

# 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 5 1 

# Baghouse

PM 10 

# 0.03 (total) 2 

# , based on USEPA Methods 201 or 201A

and 202 3 

# Baghouse

Pb No limit Baghouse

H 2 

# SO 4 

# 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

NO X 

# 0.10 lb/MMBtu Low-NO X 

# burners

SO 2 

# 0.002 lb/MMBtu Ultra low sulfur distillate oil (0.0015% S)

H 2 

# SO 4 

# 0.0004 lb/MMBtu Ultra low sulf ur distillate oil (0.0015% S)

CO 0.036 lb/MMBtu Good combustion

VOC 0.003 lb/MMBtu Good combustion

PM 0.018 1 

# lb/MMBtu Ultra low sulfur distillate oil and good combustion

PM 10 

# 0.024 2 

# lb/MMBtu Ultra low sulfur distillate oil and good combustion

Emergency Generator

NO X 

# /VOC 6.4 g/kWh July 2006 NSPS for NO X 

# and NMHC emissions

SO 2 

# 0.15 g/kWh Ultra low sulfur distillate oil (0.0015% S)

H 2 

# SO 4 

# Ultra low sulfur oil Ultra low sulfur distillate oil (0.0015% S)

CO 3.5 g/kWh July 2006 NSPS

PM/PM 10 

# 0.2 g/kWh July 2006 NSPS

Emergency Firewater Pump

NO X 

# /VOC 4.0 g/kWh July 2006 NSPS for NO X 

# and NMHC emissions

SO 2 

# 0.01 g/kWh Ultra low sulfur distillate oil (0.0015% S)

H 2 

# SO 4 

# Ultra low sulfur oil Ultra low sulfur distillate oil (0.0015% S)

CO 3.5 g/kWh July 2006 NSPS

PM/PM 10 

# 0.2 g/kWh July 2006 NSPS

Materials handling systems

PM/PM 10 

# 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 ma tter as measured by USEPA Method 5 or 17.

2 

# PM 10 

# is defined as solid particulate matter smaller than 10 micrometer s diameter as measured by USE PA Method 201 or 201A plus conde nsable

particulate matter as measured by USEPA Method 202. Because PM 10 

# includes condensable part iculate matter and PM does not include condensable

particulate matter, PM 10 

# emissions are higher than PM emissions.



# 10.11 Mercury Control

The TEP will be subject to the new boiler NSPS r equirement 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 emi ssion 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 represent s 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 NO X 

# Removal. Chemical

Engineering Progress. Page 39.

U.S. Environmental Protection Agency (USEPA). 2000. Controlling SO 2 

# 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. 5 th 

# Edition, 6 th 

# Edition. USEPA document 453/B-96-

001, EPA/452/B-02-001. February 1996, revised January 2002.

. 1994. Alternative Control Techniques Document – NO X 

# 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

SO 2 

# 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 CaCO 3 

# / Mole SO 2 

# 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%



# SO 2 

# Removal % 5%



# Flue Gas Handling % 5%



# Waste / Byproduct % 5%



# Support Equipment % 5%



# Contingency by Area (% of Installed Cost)

Reagent Feed % 20%



# SO 2 

# Removal % 20%



# Flue Gas Handling % 20%



# Waste / Byproduct % 20%



# Support Equipment % 20%



# General Facilities by Area (% of Installed Cost)

Reagent Feed % 10%



# SO 2 

# Removal % 10%



# Flue Gas Handling % 10%



# Waste / Byproduct % 10%



# Support Equipment % 10%



# Engineering Fees by Area (% of Installed Cost)

Reagent Feed % 10%



# SO 2 

# Removal % 10%



# Flue Gas Handling % 10%



# Waste / Byproduct % 10%



# Support Equipment % 10%



# Lime Spray Dryer (LSD) Inputs

SO 2 

# 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 SO 2 

# )

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%

SO 2 

# Removal % 5%

Flue Gas Handling % 5%

Waste / Byproduct % 5%

# 10A-4 

# Support Equipment % 5%

Contingency by Area (% of Installed Cost)

Reagent Feed % 20%

SO 2 

# Removal % 20%

Flue Gas Handling % 20%

Waste / Byproduct % 20%

Support Equipment % 20%

General Facilities by Area (% of Installed Cost)

Reagent Feed % 10%

SO 2 

# Removal % 10%

Flue Gas Handling % 10%

Waste / Byproduct % 10%

Support Equipment % 10%

Engineering Fees by Area (% of Installed Cost)

Reagent Feed % 10%

SO 2 

# 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/ft 2 

# 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 

# NO X



# Control Inputs

Selective Catalytic Reduction (SCR) Inputs

NH 3 

# /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

NH 3 

# /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

SO 2 

# 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. H 2 

# O 10



# Flow Rate SCFM 1,455,241



# Flow Rate ACFM 2,097,860



# CO 2 

# lb/hr 1,247,836



# N 2 

# lb/hr 4,546,491



# SO 2 

# lb/hr 5,252



# O 2 

# lb/hr 365,006



# HCl lb/hr 73



# Other Gases lb/hr 1,587



# H 2 

# O 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. H 2 

# O 10



# Flow Rate SCFM 1,455,241



# Flow Rate ACFM 2,097,860



# CO 2 

# lb/hr 1,247,836



# N 2 

# lb/hr 4,546,491



# SO 2 

# lb/hr 5,252



# O 2 

# lb/hr 365,006



# HCl lb/hr 73



# Other Gases lb/hr 1,587



# H 2 

# O 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. H 2 

# O 4



# Flow Rate SCFM 1,488,937



# Flow Rate ACFM 1,693,584



# CO 2 

# lb/hr 1,250,658



# N 2 

# lb/hr 4,559,886



# SO 2 

# lb/hr 1,208



# O 2 

# lb/hr 368,035



# HCl lb/hr 0



# Other Gases lb/hr 1,587



# H 2 

# O lb/hr 587,241



# Fly Ash lb/hr 58



# Total (gas only) lb/hr 6,768,615

# 10A-11 

# Heat Capacities

O 2 

# Btu/lbmol°F 7.213



# CO 2 

# Btu/lbmol°F 9.354



# N 2 

# Btu/lbmol°F 6.999



# H 2 

# O Btu/lbmol°F 8.069



# NO Btu/lbmol°F 7.164



# SO 2 

# Btu/lbmol°F 9.830



# HCl Btu/lbmol°F 6.951



# O 2 

# Btu/lb°F 0.225



# CO 2 

# Btu/lb°F 0.213



# N 2 

# Btu/lb°F 0.250



# H 2 

# O Btu/lb°F 0.448



# NO Btu/lb°F 0.239



# SO 2 

# 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. H 2 

# O 1



# Flow Rate SCFM 134,425



# Flow Rate ACFM 236,183



# N 2 

# lb/hr 461,211



# O 2 

# lb/hr 139,090



# H 2 

# O lb/hr 7,907



# Total lb/hr 608,207



# Heat Capacities of Hot Reheat Air

O 2 

# Btu/lbmol°F 7.332



# N 2 

# Btu/lbmol°F 7.113



# H 2 

# O Btu/lbmol°F 8.338



# O 2 

# Btu/lb°F 0.229



# N 2 

# Btu/lb°F 0.254



# H 2 

# O 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

O 2 

# Btu/lbmol°F 7.304



# N 2 

# Btu/lbmol°F 7.087



# H 2 

# O Btu/lbmol°F 8.276



# O 2 

# Btu/lb°F 0.228



# N 2 

# Btu/lb°F 0.253



# H 2 

# O 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. H 2 

# O 0



# Flow Rate SCFM 3,903



# Flow Rate ACFM 3,972



# N 2 

# lb/hr 13,395



# O 2 

# lb/hr 4,040



# H 2 

# O 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



# CaCO 3 

# 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



# CaCO 3 

# lb/hr 6,634



# H 2 

# O 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



# CaCO 3 

# lb/hr 6,634



# H 2 

# O 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%



# CaSO 3 

# * 1⁄2 H 2 

# O lb/hr 0



# CaSO 4 

# *2H 2 

# O lb/hr 17,025,795



# Inerts lb/hr 512,538



# CaCl 2 

# lb/hr 174,209



# CaCO 3 

# lb/hr 337,783



# H 2 

# O 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%



# CaSO 3 

# * 1⁄2 H 2 

# O lb/hr 0



# CaSO 4 

# *2H 2 

# O lb/hr 10,868



# Inerts lb/hr 327



# CaCl 2 

# lb/hr 111



# CaCO 3 

# lb/hr 216



# H 2 

# O 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



# SO 2 

# 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



# SO 2 

# 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



# SO 2 

# 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



# SO 2 

# 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



# SO 2 

# 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



# SO 2 

# 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



# SO 2 

# 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 SO 2 

# 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

SO 2 

# lbmole/hr 63.12



# CaCO 3 

# lbmole/hr 63.12



# H 2 

# O lbmole/hr 31.56



# CaSO 3 

# * 1⁄2 H 2 

# O lbmole/hr 63.12



# CO 2 

# lbmole/hr 63.12



# SO 2 

# lb/hr 4,044



# CaCO 3 

# lb/hr 6,318



# H 2 

# O lb/hr 569



# CaSO 3 

# * 1⁄2 H 2 

# O lb/hr 8,152



# CO 2 

# lb/hr 2,778



# Sulfate Reaction

CaSO 3 

# * 1⁄2 H 2 

# O lbmole/hr 63.12



# O 2 

# lbmole/hr 31.56



# H 2 

# O lbmole/hr 94.68



# CaSO 4 

# *2H 2 

# O lbmole/hr 63.12



# CaSO 3 

# *1/2H 2 

# O lb/hr 8,152



# O 2 

# lb/hr 1,010



# H 2 

# O lb/hr 1,706



# CaSO 4 

# *2H 2 

# O lb/hr 10,868



# Water in Absorber

Mole Fraction H 2 

# O in Absorber % 0.1389



# Moles H 2 

# O in Absorber lbmole 32,595.70



# DBA Feed Calculations

SO 2 

# 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. H 2 

# O -12

Flow Rate SCFM 1,455,241

Flow Rate ACFM 2,231,405

CO 2 

# lb/hr 1,247,836

N 2 

# lb/hr 4,546,491

SO 2 

# lb/hr 5,252

O 2 

# lb/hr 365,006

HCl lb/hr 73

Other Gases lb/hr 1,587

H 2 

# O lb/hr 501,931

Fly Ash lb/hr 31,603

Total (gas only) lb/hr 6,668,175

Total Fabric Required Ft 2 

# 637,544

Surface Area per Bag Ft 2 

# 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) Ft 2 

# 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 ft 3 

# 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 BOILERSAttachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for NOXCoal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.WY-0063Black Hills Corporation 1 Coal-Fired PC Boiler Low NOx burners, OFA & not given Primary = Secondary= 2/5/2007WYGEN 3 1300 MMBtu/hr; 100 MW SCR 0.05 lb/MMBtu 65.0 lb/hr CT-4517Campbell County, WY sub-bituminuous coal 12-mo rolling 30-day rollingMO-0071Great Plains Energy 2 Coal-Fired Boiler - Unit 1 Not Identified n/a Primary = Secondary= 1/27/2006Iatan Station 7800 MMBtu/hr0.10 lb/MMBtu none listed 012006-019Platte County, MO sub-bituminuous coal 30-day rollingVA-0296Virginia Polytechnical Institute & 1 Stoker Fired Boiler - Boiler 11 Low excess air and not given Primary = Secondary= 9/15/2005State University 146.7 MMBtu/hr staged combustion 0.246 lb/MMBtu 136.9 tpy 20124Montgomery County, VA30 day rollingLA-0176Louisiana Generating, LLC 1 Coal-Fired PC Boiler, Unit 4 Low NOx burners & 70% Primary = Secondary= 8/22/2005Big Cajun II Power Plant 675 MW; supercritical boiler SCR 0.07 lb/MMBtu 459.6 lb/hr PSD-LA-677Pointe Coupee County, LA sub-bituminuous coal annual avgPA-0249River Hill Power Company, LLC 1 Waste Coal-Fired CFB Boiler SNCR not given Primary = Secondary= 7/21/2005Clearfield County, PA0.07 lb/MMBtu 0.10 lb/MMBtu 17-00055A30-day avg. 24-hr avg.PA-0248Wellington Dev/Greene Energy 2 Waste Coal-Fired CFB Boilers SNCR not given Primary = Secondary= 7/8/2005Resource Recovery Project 580 MW (gross) 525 MW (net) 0.08 lb/MMBtu 0.10 lb/MMBtu 30-00150AGreene County, PA30-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= 7/5/2005Comanche Power Station 660 MW (both units) 0.20 lb/MMBtu 0.15 lb/MMBtu 04UNITPB1015Pueblo, CO30-day avg annual avg.ND-0021Montana Dakota Utilities/Westmoreland 1 Lignite Fired CFB Boiler SNCR 40% Primary = Secondary= 6/3/2005Gascoyne Generating Station 220 MW (gross) 175 MW (net) 0.865 lb/MWh 0.09 lb/MMBtu PTC 05005Bowman County, ND30 day rolling 30 day rollingNV-0036Newmont Nevada Energy Investment LLC 1 Coal-Fired PC Boiler Low NOx burners & not given Primary = Secondary= 5/5/2005TS Power Plant 200 MW; 2030 MMBtu/hr SCR 0.067 lb/MMBtu none listed AP4911-1349Eureka County, NV24-hr rollingPA-0247Robinson Power Company LLC 1 Waste Coal-Fired CFB Boiler SNCR 75% Primary = Secondary= 4/1/2005Beech Hollow Power Project 272 MW (net); 2800 MMBtu/hr 0.08 lb/MMBtu 972 tpy 63-00922AWashington County, PAno avg. no avgNE-0031Omaha Public Power District 1 Coal-Fired PC Boiler SCR 90% Primary = Secondary= 3/9/2005Nebraska City Station Unit 2 boiler 660 MW (net)0.07 lb/MMBtu none listed 58343C01Otoe County, NE sub-bituminuous coal 30-day rollingMO-0060Springfield Utilities 1 Coal-Fired PC Boiler SCR 82.6% Primary = Secondary= 12/15/2004Southwest Power Station 275 MW; 2724 MMBtu/hr 0.08 lb/MMBtu none listed 122004-007Greene County, MO30-day rollingWI-0228Wisconsin Public Service Co. 1 Coal-Fired PC Boiler; supercritical Low NOx burners & not given Primary = Secondary= 10/19/2004WPS - Weston Plant 500 MW; 5173 MMBtu/hr SCR 0.07 lb/MMBtu 0.06 lb/MMBtu 04-RV-248Marathon County, WI PRB Coal; 8100 BTU/lb 30-day avg. 12-mo avg.UT-0065Intermountain Power Service Corp. 1 Coal-Fired PC Boiler Low NOx burners, OFA & 80% Primary = Secondary= 10/15/2004Generating Station Unit #3 950 MW (gross) SCR 0.07 lb/MMBtu 633.5 lb/hr DAQE-AN0327010-04Millard County, UT Bituminous Coal or Blend 30-day rolling 24-hr blockUT-0064Nevco-Sevier Power Company 1 Coal-Fired CFB Boiler Low NOx burners & 90% Primary = Secondary= 10/12/2004Sevier Power Plant 270 MW SNCR 0.10 lb/MMBtu none listed DAQE-AN2529001-04Sevier County, UT24-hr rollingRBLC IDEmissionLimitAtt 10-B_Coal Boilers_RBLC.xlsNOX7/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for NOXCoal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.RBLC IDEmissionLimitNE-0018Hastings Utilities 1 Unit 2 Coal-Fired Boiler SCR not given Primary = Secondary= 3/30/2004Whelan Energy Center 220 MW; 2210 MMBtu/hr 0.08 lb/MMBtu none listed 58048Adams County, NE30-day rollingWV-0023Longview Power, LLC 1 Coal-Fired PC Boiler Low NOx burners & not given Primary = Secondary= 3/2/2004Maidsville 600 MW; 6114 MMBtu/hr SCR 0.08 lb/MMBtu 0.065 lb/MMBtu R14-0024Monongahela County, WV24-hr rolling annual avgSC-0104Santee Cooper 2 Coal-Fired PC Boilers, #3 & #4 Low NOx burners & not given Primary = Secondary= 2/5/2004Cross Generating Station Bituminous Coal & Pet Coke SCR 0.08 lb/MMBtu 2278 tpy 0420-0030-ClBerkeley County, SC 5700 MMBtu/hr (each) 365-day rolling 365-day rollingTX-0298 Reliant Energy Inc. 3 Coal Fired Boilers, Units 5 ,6, 7 None Indicated not given Primary = Secondary= 10/15/2003WA Parish Electric Generating St. Units 5 & 6 @ 7400 mmbtu/hr 0.38, 0.324 8370, 8860 PSD-TX-901,Houston, TX Unit 7 @ 6700 mmbtu/hr lb/mmbtu tpy -902 & -33M1PA-0182 Reliant Energy Inc. 2 Refused Coal-Fired CFB Boilers SNCR not given Primary = Secondary= 8/26/2003Seward Power 2532 MMBtu/hr (each) 0.15 lb/MMBtu none listed PA-32-040BIndiana County, PAno avg.AR-0074 Plum Point Associates, LLC 1 Coal-Fired PC Boiler, Unit 1 Low NOxBurners not given Primary = Secondary= 8/20/2003Plum Point Energy 800 MW0.090 lb/MMBtu none listed 1995-AOP-R0Mississippi County, ARno avg.OH-0231 First Energy/Toledo Edison Company 1 Coal & Coke-Fired CFB Boiler Limestone Fluidized Bed 65% Primary = Secondary= 7/31/2003Bayshore Plant 1764 MMBtu/hr0.20 lb/MMBtu 1.6 lb/MW-hr 04-1056Lucas County, OHno avg.MT-0022 Bull Mountain Development Co. 2 Coal-Fired PC Boilers, No. 1, 2 Low NOx Burner, OFA, SCR 90% Primary = Secondary= 7/21/2003Roundup Power Project 390 MW (each); 4013 MMBtu/hr 0.07 lb/MMBtu 280.9 lb/hr 3182-00Musselshell County, MT mine-mouth plant24-hr rolling 24-hr rollingIA-0067 Mid-American Energy Co. 1 Coal-Fired PC Boiler Low NOx Burner, OFA, SCR 60% Primary = Secondary= 6/17/2003PRB coal0.07 lb/MMBtu 2353 tpy Project 02-528Council Bluffs, Iowa 7675 MMBtu/hr30-day rolling no avgTX-0358 Reliant Energy Inc. 3 Coal Fired Boilers None Indicated not given Primary = Secondary= 10/15/2002WA Parish Electric Generating St. 2 @ 6750 mmbtu/hr 0.382, 0.325 8370, 8860 PSD-TX-33 M1Houston, TX 1 @ 6700 mmbtu/hr lb/mmbtu tpyKY-0084 Thoroughbred Generating Company, LLC 2 Coal-Fired PC Boilers Low-NOx burners & SCR not given Primary = Secondary= 10/11/2002Thoroughbred Generating Station 1500 MW (total); 7446 MMBtu/hr (ea) 0.08 lb/MMBtu none listed V-02-001Muhlenburg County, KY30-day rollingKS-0026 Sand Sage Power, LLC 1 Subbituminous Coal-Fired PC Boiler Low-NOx burners, OFA & 70% Primary = Secondary= 10/8/2002Holcomb Unit #2 660 MW SCR 0.08 lb/MMBtu 0.12 lb/MMBtu 0550087/C-3855Finney County, KSno avg. initial 18 monthsWY-0057 Black Hills Corporation 1 Subbituminous Coal-Fired PC Boiler Low-NOx burners & SCR not given Primary = Secondary= 9/25/2002WYGEN 2 500 MW; 5146 MMBtu/hr 0.07 lb/MMBtu none listed CT-3030Campbell County, WY30-day rollingKY-0086 East Kentucky Power Coop, Inc. 1 Coal-Fired CFB Boiler SNCR not given Primary = Secondary= 8/4/2002Spurlock Power Station 270 MW; 2500 MMBtu/hr 0.07 lb/MMBtu none listed V-97-050 (R1)Mason County, KY30-day rollingMT-0027 Rocky Mountain Power, Inc. 1 Coal-Fired PC Boiler SCR not given Primary = Secondary= 6/11/2002Hardin Generating Project 113 MW (nominal); 1304 MMBtu/hr 0.09 lb/MMBtu none listed 3185-00Big Horn County, MT30-day rollingAtt 10-B_Coal Boilers_RBLC.xlsNOX7/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for NOXCoal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.RBLC IDEmissionLimitPA-0183 AES Beaver Valley, LLC 1 Coal-Fired CFB Boiler SNCR not given Primary = Secondary= 11/21/20012155 MMBtu/hr0.101 lb/MMBtu none listed PA-04-446CBeaver County, PAno avg.PR-0007 AES Puerto Rico Cogeneration Plant 2 Coal-Fired CFB Boilers SNCR not given Primary = Secondary= 10/29/2001454 MW (net); 4923 MMBtu/hr 0.10 lb/MMBtu 57 ppmvd @7% 14Guyama, Puerto Rico Bituminous Coal; max 1% sulfur no avg. no avgLA-0122 International Paper- Mansfield Mill 2 Coal Fired Boilers Low NOxStaged not given 0.70 lb/mmbtu 8/14/2001BurnersPSD-LA-93 (M-6)Mansfield, Louisiana 645 mmbtu/hr eachTX-0342 Reliant Energy Inc. 2 Lignite Coal Fired Boilers None Indicated not given Primary = Secondary= 5/23/2001Limestone Electric Generating St.3932 0.50 P371 (M3)Houston, TX 7863 mmbtu/hr each lb/hr lb/mmbtuKY-0079 Kentucky Mountain Power, LLC 2 Coal & Coal Refuse-Fired CFB Boilers SNCR not given Primary = Secondary= 5/4/2001Units 1 & 20.07 lb/MMBtu none listed V-00-045Knott County, KY 2550 MMBtu/hrno avg.FL-0003 Tampa Electric Co. 1 Coal Fired Boiler Equipment Design & not given Primary = Secondary= 1/1/2001Teco- Big Bend Station Dry Bottom, Tangentially Fired Operation 0.6 2598PSD-FL-040Apollo Beach, Florida 4330 mmbtu/hrlb/mmbtu lb/hrTX-0275 Reliant Energy 1 Coal Fired Boiler, Unit 8 Low-NOx burners, OFA & not given Primary = Secondary= 12/21/2000W.A. Parish Electric Generating St. 6700 mmbtu/hr SCR 0.43 lb/MMBtu 2865 lb/hr PSD-TX-234Ft. Bend County, Texas Boiler also burns NG & Fuel Oil no avg. 30-day rollingMO-0050 Kansas City Power & Light Co. 1 Coal Fired PC Boiler SCR & Good Combustion not given Primary = Secondary= 8/17/1999Hawthorn Station Tangentially Fired Practice 0.08 lb/MMBtu 0.12 lb/MMBtu 888Kansas City, Missouri 384 T/H30-day avg. 24-hr avg.FL-0178 JEA Northside Generating St. 2 Coal Fired CFB Boilers SNCR not given Primary = Secondary= 7/14/1999297.5 MW; 2764 MMBtu/hr (each) 0.09 lb/MMBtu none listedPSD-FL-265Jacksonville, Florida30-day rollingPA-0163 AES Beaver Valley Partners, Inc. 1 Coal Fired PC Boiler Low-NOx Burner & SOFA not given Primary = Secondary= 6/1/1999550 MMBtu/hr0.70 lb/MMBtu none listed 040446BBeaver County, PAno avg.PA-0162 Edison Mission Energy 3 Coal-Fired PC Boilers, Units 1,2,3 SCR 70% Primary = Secondary= 5/25/19995700 MMBtu/hr (each) 0.15 lb/MMBtu none listed 32-0055CHomer City, Pennsylvaniano avg.IL-0060 Archer Daniels Midland Co. 2 Coal Fired CFB Boilers, Units 9,10 SNCR 85% Primary = Secondary= 12/24/19981500 mmbtu/hr each 0.09 lb/MMBtu 0.12 lb/MMBtu97070097Decatur, Illinoisno avg. no avgMS-0036 Choctaw Generation L.P 2 Lignite-Fired CFB Boilers Circulating Fluidized Bed not given Primary = Secondary= 8/25/1998Design 0.20 lb/MMBtu none listed 0400-00011Ackerman, 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= 6/30/19981500 mmbtu/hr (each) 0.07 lb/MMBtu none listed 98-A-507PLinn County, IA30-day rollingIA-0051 Archer Daniels Midland Co. 1 Coal Fired CFB Boiler SNCR not given Primary = Secondary= 6/30/19980.07 lb/MMBtu none listed 98-A-508PCedar Rapids, Iowa 1500 mmbtu/hr30-day rollingAtt 10-B_Coal Boilers_RBLC.xlsNOX7/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for NOXCoal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.RBLC IDEmissionLimitPA-0204 Kimberly- Clark Tissue Co. 3 Coal Fired CFB & 2 Vertical Boilers None Indicated not given Primary = Secondary= 6/24/1998Kimberly- Clark/Chester Plant 799 mmbtu/hr, 249 mmbtu/hr & 0.20 lb/MMBtu 1090 tpy total 23-0014AChester, Pennsylvania 198 mmbtu/hr (respectively) no avg.UT-0053 Deseret Generation & Transmission Co. 1 Coal-Fired PC Boiler Boiler Design not given Primary = Secondary= 3/16/1998500 MW0.55 lb/MMBtu 0.50 lb/MMBtu DAQE-186-98Unitah County, UT30-day avg. annual avgWY-0039 Two Elk Generation Partners, Ltd. 1 Coal-Fired PC Boiler Low NOxBurners, OFA & 75% Primary = Secondary= 2/27/1998PartnershipSCR 0.15 lb/MMBtu none listed CT-1352Campbell County, WY 250 MW30-day rollingWY-0047 Encoal Corporation 1 Coal-Fired PC Boiler Low NOxBurners, OFA & 60% Primary = Secondary= 10/10/1997North Rochelle Facility 240 MW SCR 0.15 lb/MMBtu none listed CT-1324Campbell County, WYno avg.WY-0047 Encoal Corporation 1 Coal-Fired PC Boiler Low NOxBurners & FGR not given Primary = Secondary= 10/10/1997North Rochelle Facility 3960 MMBtu/hr0.16 lb/MMBtu none listed CT-1324Campbell County, WY Subbituminous Coal no avg.WY-0048 WYGEN, Inc. 1 Coal-Fired PC Boiler Low NOxBurners & OFA 56% Primary = Secondary= 9/6/1996WYGEN Unit #1 80 MW; 1014 MMBtu/hr 0.22 lb/MMBtu none listed CT-1236Campbell County, WY30-day rollingPA-0133 Mon Valley Energy Ltd. 1 Pulverized Coal Fired Boiler SCR with LNB 50% Primary = Secondary= 8/8/1995Partnership0.15 635 30-306-001Poland Mines, Pennsylvania966 mmbtu/hrlb/mmbtu tpyPA-0132 York County Energy Partners 1 Coal Fired CFB Boiler SNCR 40% Primary = Secondary= 7/25/1995Spring Grove, Pennsylvania0.125 328 67-306-0072500 mmbtu/hrRlb/mmbtu lb/hrUT-0060 Deseret Generation & 1 Coal Fired Boiler Low NOxBurners not given 0.55 lb/mmbtu 6/14/1995Transmission Co.DAQE-523-95Vernaz, Utah 4381 mmbtu/hrPA-0123 West Penn Power Co. 1 Pulverized Coal Fired Boiler Low NOxBurners 36.6% Primary = Secondary= 6/12/1995Dry Bottom0.45 4849 63-0016Monogahela, Pennsylvania 2460 mmbtu/hrlb/mmbtu tpyPA-0112 Pennsylvania Power and Light Co. 1 Coke/Coal Fired Boiler O/M not given Primary = Secondary= 5/25/1995Dry Bottom1.4 5660 36-2016Holtwood, Pennsylvania 923 mmbtu/hrlb/mmbtu tpyPA-0134 Northampton Generating Co. 1 Ahlstrom Coal Fired CFB Boiler Thermo De-NOx63% Primary = Secondary= 4/14/19950.1 467 48-00021Northampton, Pennsylvania 1146 mmbtu/hrlb/mmbtu tpyPA-0129 Metropolitan Edison Co. 3 Pulverized Coal Fired Boilers Low NOxBurners 27% Primary = Secondary= 3/9/1995Dry Bottom0.45 1580 06-1024Reading, Pennsylvania 801.4 mmbtu/hrlb/mmbtu tpyPA-0105 Pennsylvania Power Co. 3 Pulverized Coal Fired Boilers Low NOxBurners 2 @ 55% Primary = Secondary= 12/29/1994Dry Bottom 29% 0.5 16466 04-0235Shippingport, Pennsylvania 7914 mmbtu/hrlb/mmbtu tpyAtt 10-B_Coal Boilers_RBLC.xlsNOX7/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for NOXCoal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.RBLC IDEmissionLimitPA-0109 Zinc Corporation of America 2 Pulverized Coal Fired Boilers Automated Air Controllers 10% Primary = Secondary= 12/29/19940.45 1754 04-0044Monaca, Pennsylvania 600 mmbtu/hrlb/mmbtu tpyPA-0115 Pennsylvania Electric Co. 2 Pulverized Coal Fired Boilers Low NOxBurners 35% Primary = Secondary= 12/29/1994Dry Bottom 38% 0.45 15790 03-0027Shelocta, Pennsylvania 8010 mmbtu/hrlb/mmbtu tpyPA-0116 West Penn Power Co. 3 Pulverized Coal Fired Boilers Low NOxBurners 52% Primary = Secondary= 12/29/1994Dry Bottom0.58 12800 30-0099Masontown, Pennsylvania 5036 mmbtu/hrlb/mmbtu tpyPA-0117 Duquesne Light Co. 4 Pulverized Coal Fired Boilers Low NOxBurners 26%, 37% 0.5 lb/mmbtu 12/29/1994Dry Bottom 23%, 39% 63-0014Elrama, Pennsylvania 2 @ 1100, 1200, & 1790 mmbtu/hr respectivelyPA-0119 Pennsylvania Electric Co. 3 Pulverized Coal Fired Boilers Low NOxBurners 55%, 55% & Primary = Secondary= 12/29/1994Dry Bottom 29% 0.5 13076 32-0055Homer City, Pennsylvania 2 @ 6792 & 6600 mmbtu/hr respectively lb/mmbtu tpyPA-0125 West Penn Power Co. 2 Pulverized Coal Fired Boilers Low NOxBurners 52%, 57% Primary = Secondary= 12/29/1994Dry Bottom respectively 0.45 3272, 4025 03-0023Kittenning, Pennsylvania 2 @ 1600 mmbtu/hr lb/mmbtu tpyPA-0126 Pennsylvania Electric Co. 2 Pulverized Coal Fired Boilers Low NOxBurners 37%, 33% Primary = Secondary= 12/29/1994Dry Bottom respectively 0.45 15524 32-0059New Florence, Pennsylvania 2 @ 7876 mmbtu/hr lb/mmbtu tpyPA-0142 P.H. Glatfelter 2 Coal Fired Dry Bottom Boilers Low NOxBurners not given 0.74 lb/mmbtu 12/29/199433% 0.51 lb/mmbtu 67-2004Spring Grove, Pennsylvania 257 & 357 mmbtu/hrPA-0108 Peco Energy Co. 2 Pulverized Coal Fired Boilers Low NOxBurners 12%, 20% 0.45 lb/mmbtu 12/28/1994Dry Bottom respectively 23-0017Eddystone, Pennsylvania 2704 & 2808 mmbtu/hrPA-0101 International Paper Co. 2 Coal Fired Boilers Annual Tune-Up not given Primary = Secondary= 12/27/1994Hammervill Papers Div.0.7 780 18-0005Lock Haven, Pennsylvania 350 mmbtu/hr each lb/mmbtu tpyPA-0111 Pennsylvania Electric Co. 4 Pulverized Coal Fired Boilers Low NOxBurners 56%, 42% Primary = Secondary= 12/27/1994Dry Bottom respectively 0.5, 0.45 2946, 3528 17-0001Shawville, Pennsylvania 2 @ 1345, 2 @ 1790 mmbtu/hr lb/mmbtu tpyPA-0113 Pennsylvania Power and Light Co. 2 Coke/Coal Fired Dry Bottom Boiler Low NOxBurners 47%, 55% Primary = Secondary= 12/27/1994respectively 0.5 2794, 3166 55-0001AShamokin Dam, Pennsylvania 1277 &1415 mmbtu/hr lb/mmbtu tpyPA-0124 Westwood Energy Properties, Inc. 1 Coal CFB Boiler No Controls Feasible not given Primary = Secondary= 12/27/19940.3 557 54-0006Tremont, Pennsylvania 423 mmbtu/hrlb/mmbtu tpyPA-0128 Pennsylvania Power and Light Co. 3 Pulverized Coal Fired Boilers Low NOxBurners 47%, 40% Primary = Secondary= 12/22/1994& 30% 0.45, 0.45, 0.45 13748, 7135 & 67-2005York Haven, Pennsylvania 7329, 3790 & 3345 mmbtu/hr respectively lb/mmbtu 6273 tpyAtt 10-B_Coal Boilers_RBLC.xlsNOX7/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for NOXCoal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.RBLC IDEmissionLimitPA-0127 Pennsylvania Power Co. 3 Pulverized Coal Fired Boilers Limit Hours of Operation not given Primary = Secondary= 12/21/19940.79, 0.72 , 1.01 1302, 1567 & 37-0023New Castle, Pennsylvania 2 @ 1029 & 1325 mmbtu/hr lb/mmbtu 3650 tpyPA-0143 General Electric Transportation 1 Cyclone Coal Fired Boiler Won't Operate During not given Primary = Secondary= 12/21/1994SystemOzone Season 1.01 840 OP-25-0025Erie, Pennsylvania 420 mmbtu/hrlb/mmbtu tpyPA-0110 Gilberton Power Co. 2 Coal Fired CFB Boilers No Controls Feasible not given 0.3 lb/mmbtu 12/20/199454-0004Frackville, Pennsylvania 2 @ 520 mmbtu/hrPA-0114 Pennsylvania Power and Light Co. 2 Pulverized Coal Fired Boilers Low NOxBurners 44%, 50% Primary = Secondary= 12/14/1994respectively 0.5 3854, 3859 48-0011AMartins Creek, Pennsylvania 2 @ 1727 mmbtu/hr lb/mmbtu tpyPA-0121 Metropolitan Edison Co. 2 Pulverized Coal Fired Boilers Low NOxBurners 34.9% , 37.3% Primary = Secondary= 12/14/1994respectively 0.43, 0.37 2330 , 1424 48-0006APortland, Pennsylvania 2342, 1464 mmbtu/hr lb/mmbtu tpyPA-0100 Pennsylvania Power and Light Co. 2 Pulverized Coal Fired Boilers Low NOxBurners 55% 0.5 lb/mmbtu 11/27/199447-0001AWashingtonville, Pennsylvania 2 @ 7100 mmbtu/hrIL-0058 Archer Daniels Midland Co. 2 Coal Fired CFB Boilers SNCR 85% 0.12 lb/mmbtu 8/11/19941500 mmbtu/hr94020006Decatur, Illinois 750 mmbtu/hrMA-0028 Energy New Bedford 2 Coal Fired CFB Boilers SNCR, Controlled not given Primary = Secondary= 7/11/1994Combustion 0.15 263.24B90041New Bedford, Massachusetts 1671 mmbtu/hr each lb/mmbtu lb/hrMD-0022 AES Warrior Run, Inc. 1 Coal Fired Atmospheric CFB Boiler Thermo De-NOx40% 0.1 lb/mmbtu 6/30/199494-01Cumberland, Maryland 2070 mmbtu/hrFL-0255 Cedar Bay Generating Co., LP 3 Pulverized Coal Fired CFB Boilers SNCR not given Primary = Secondary= 11/16/1993Ceder Bay Cogeneration0.17 180.72 PSD-FL-137AJacksonville, Florida 132 mmbtu/hr eachlb/mmbtu lb/hrNotes: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 BoilersAtt 10-B_Coal Boilers_RBLC.xlsNOX7/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for COCoal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.WY-0063Black Hills Corporation 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 2/5/2007WYGEN 3 1300 MMBtu/hr; 100 MW0.15 lb/MMBtu none listed CT-4517Campbell County, WY sub-bituminuous coal3-hr testMO-0071Great Plains Energy 2 Coal-Fired Boiler - Unit 1 Good Combustion Practices not given Primary = Secondary= 1/27/2006Iatan Station 7800 MMBtu/hr0.16 lb/MMBtu none listed 012006-019Platte County, MO sub-bituminuous coal30-day rollingCO-0055Lamar Utilities Board DBA 1 Coal-Fired CFB Boiler Good Combustion Practices not given Primary = Secondary= 9/28/2005Lamar Light & Power Plant 501.7 MMBtu/hr75.3 lb/hr none listed 05-A-655-PPowers County, CO sub-bit or bituminous coal3-hr rollingVA-0296Virginia Polytechnical Institute & 1 Stoker Fired Boiler - Boiler 11 Combustion Control not given Primary = Secondary= 9/15/2005State University 146.7 MMBtu/hr0.226 lb/MMBtu 33.2 lb/hr 20124Montgomery County, VAno avg.LA-0176Louisiana Generating, LLC 1 Coal-Fired PC Boiler, Unit 4 Good Combustion Practices not given Primary = Secondary= 8/22/2005Big Cajun II Power Plant 675 MW; supercritical boiler 0.135 lb/MMBtu 886.4 lb/hr PSD-LA-677Pointe Coupee County, LA sub-bituminuous coalannual avgPA-0249River Hill Power Company, LLC 1 Waste Coal-Fired CFB Boiler Optimizing combustion temperature not given Primary = Secondary= 7/21/2005Clearfield County, PA0.20 lb/MMBtu 0.25 lb/MMBtu 17-00055A>70% load <70% loadPA-0248Wellington Dev/Greene Energy 2 Waste Coal-Fired CFB Boilers Good Combustion Practices not given Primary = Secondary= 7/8/2005Resource Recovery Project 580 MW (gross) 525 MW (net) 0.20 lb/MMBtu 4829 tpy 30-00150AGreene County, PAno avg. 12-month rollingCO-0057 Xcel Energy (PSC of Colorado) 1 Coal-Fired PC Boiler, Unit #3 Good Combustion Practices not given Primary = Secondary= 7/5/2005Comanche Power Station 750 MW (unit #3); 7421 MMBtu/hr 0.13 lb/MMBtu 0.30 lb/MMBtu 04UNITPB1015Pueblo, CO sub-bituminuous coal8-hr avg. avg startupND-0021Montana Dakota Utilities/Westmoreland 1 Lignite Fired CFB Boiler Good Combustion Practices not given Primary = Secondary= 6/3/2005Gascoyne Generating Station 220 MW (gross) 175 MW (net) 0.154 lb/MMBtu none listed PTC 05005Bowman County, ND3-hr avgNV-0036Newmont Nevada Energy Investment LLC 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 5/5/2005TS Power Plant 200 MW; 2030 MMBtu/hr0.15 lb/MMBtu none listed AP4911-1349Eureka County, NV24-hr rollingPA-0247Robinson Power Company LLC 1 Waste Coal-Fired CFB Boiler Good Combustion Practices not given Primary = Secondary= 4/1/2005Beech Hollow Power Project 272 MW (net); 2800 MMBtu/hr 0.15 lb/MMBtu 1823 tpy 63-00922AWashington County, PAno avg. no avgNE-0031Omaha Public Power District 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 3/9/2005Nebraska City Station Unit 2 boiler 660 MW (net)0.16 lb/MMBtu none listed 58343C01Otoe County, NE sub-bituminuous coal3-hr rollingMO-0060Springfield Utilities 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 12/15/2004Southwest Power Station 275 MW; 2724 MMBtu/hr0.16 lb/MMBtu none listed 122004-007Greene County, MOno avg.WI-0228Wisconsin Public Service Co. 1 Coal-Fired PC Boiler; supercritical Good Combustion Practices not given Primary = Secondary= 10/19/2004WPS - Weston Plant 500 MW; 5173 MMBtu/hr0.15 lb/MMBtu 3399 ton/yr 04-RV-248Marathon County, WI PRB Coal; 8100 BTU/lb24-hr avg. 12-mo avg.UT-0065Intermountain Power Service Corp. 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 10/15/2004Generating Station Unit #3 950 MW (gross)0.15 lb/MMBtu 3000 lb/hr DAQE-AN0327010-04Millard County, UT Bituminous Coal or Blend30-day rolling 8-hr blockGA-0114Temple-Inland Inc. 1 Coal-Fired Boiler Good Combustion Practices not given Primary = Secondary= 10/13/2004Rome Linerboard Mill 565 MMBtu/hr300 ppm@3% O2 none listed 2631-115-0021-V-01-4Floyd County, GAUT-0064Nevco-Sevier Power Company 1 Coal-Fired CFB Boiler Good Combustion Practices not given Primary = Secondary= 10/12/2004Sevier Power Plant 270 MW292 lb/hr none listed DAQE-AN2529001-04Sevier County, UT1-hr avgRBLC IDEmissionLimitAtt 10-B_Coal Boilers_RBLC.xlsCO7/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for COCoal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.RBLC IDEmissionLimitIL- 0094Corn Products International 1 Coal-Fired CFB Boiler Best Operating Practices not given Primary = Secondary= 6/3/2004Cook County, IL 1670 MMBtu/hr0.10 lb/MMBtu 400 ppm@7% O2 309002024-hr block per Boiler MACTNE-0018Hastings Utilities 1 Unit 2 Coal-Fired Boiler Good Combustion Practices not given Primary = Secondary= 3/30/2004Whelan Energy Center 220 MW; 2210 MMBtu/hr0.15 lb/MMBtu none listed 58048Adams County, NEno avg.WV-0023Longview Power, LLC 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 3/2/2004Maidsville 600 MW; 6114 MMBtu/hr0.11 lb/MMBtu 673 lb/hr R14-0024Monongahela County, WV3-hr rolling no avgSC-0104Santee Cooper 2 Coal-Fired PC Boilers, #3 & #4 Good Combustion Practices not given Primary = Secondary= 2/5/2004Cross Generating Station Bituminous Coal & Pet Coke 0.16 lb/MMBtu none listed 0420-0030-ClBerkeley 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= 10/15/2003WA Parish Electric Generating St. Units 5 & 6 @ 7400 mmbtu/hr 0.292, 0.282 9496, 8281 PSD-TX-901,Houston, TX Unit 7 @ 6700 mmbtu/hrlb/mmbtu tpy -902 & -33M1PA-0182 Reliant Energy Inc. 2 Refused Coal-Fired CFB Boilers Good Combustion Practices not given Primary = Secondary= 8/26/2003Seward Power 2532 MMBtu/hr (each)0.15 lb/MMBtu none listed PA-32-040BIndiana County, PAno avg.AR-0074 Plum Point Associates, LLC 1 Coal-Fired PC Boiler, Unit 1 Low NOxBurners not given Primary = Secondary= 8/20/2003Plum Point Energy 800 MW0.16 lb/MMBtu none listed 1995-AOP-R0Mississippi County, ARno avg.OH-0231 First Energy/Toledo Edison Company 1 Coal & Coke-Fired CFB Boiler Good Combustion Practices not given Primary = Secondary= 7/31/2003Bayshore Plant 1764 MMBtu/hr0.13 lb/MMBtu 1220 tpy 04-1056Lucas County, OHno avg. no avgMT-0022 Bull Mountain Development Co. 2 Coal-Fired PC Boilers, No. 1, 2 Good Combustion Practices not given Primary = Secondary= 7/21/2003Roundup Power Project 390 MW (each); 4013 MMBtu/hr 0.15 lb/MMBtu none listed 3182-00Musselshell County, MT mine-mouth plantno avg.IA-0067 Mid-American Energy Co. 1 Coal-Fired PC Boiler Combustion Control not given Primary = Secondary= 6/17/2003PRB coal0.154 lb/MMBtu 5177 tpy Project 02-528Council Bluffs, Iowa 7675 MMBtu/hr24-hr avg no avgTX-0358 Reliant Energy Inc. 3 Coal Fired Boilers Combustion Control not given Primary = Secondary= 10/15/2002WA Parish Electric Generating St. 2 @ 6750 mmbtu/hr0.321, 0.33 9496, 8281 PSD-TX-33 M1Houston, TX 1 @ 6700 mmbtu/hrlb/mmbtu tpyKY-0084 Thoroughbred Generating Company, LLC 2 Coal-Fired PC Boilers Good Combustion Practices not given Primary = Secondary= 10/11/2002Thoroughbred Generating Station 1500 MW (total); 7446 MMBtu/hr (ea) 0.10 lb/MMBtu none listed V-02-001Muhlenburg County, KY30-day rollingKS-0026 Sand Sage Power, LLC 1 Subbituminous Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 10/8/2002Holcomb Unit #2 660 MW0.15 lb/MMBtu none listed 0550087/C-3855Finney County, KSno avg.WY-0057 Black Hills Corporation 1 Subbituminous Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 9/25/2002WYGEN 2 500 MW; 5146 MMBtu/hr0.15 lb/MMBtu none listed CT-3030Campbell County, WYno avg.KY-0086 East Kentucky Power Coop, Inc. 1 Coal-Fired CFB Boiler Proper Boiler Design & Operation not given Primary = Secondary= 8/4/2002Spurlock Power Station 270 MW; 2500 MMBtu/hr0.15 lb/MMBtu none listed V-97-050 (R1)Mason County, KY30-day rollingMT-0027 Rocky Mountain Power, Inc. 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 6/11/2002Hardin Generating Project 113 MW (nominal); 1304 MMBtu/hr 0.15 lb/MMBtu none listed 3185-00Big Horn County, MTno avg.Att 10-B_Coal Boilers_RBLC.xlsCO7/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for COCoal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.RBLC IDEmissionLimitPA-0183 AES Beaver Valley, LLC 1 Coal-Fired CFB Boiler Good Combustion Practices not given Primary = Secondary= 11/21/20012155 MMBtu/hr0.20 lb/MMBtu none listed PA-04-446CBeaver County, PAno avg.PR-0007 AES Puerto Rico Cogeneration Plant 2 Coal-Fired CFB Boilers Good Combustion Practices not given Primary = Secondary= 10/29/2001454 MW (net); 4923 MMBtu/hr 0.10 lb/MMBtu 94 ppmvd @7% 14Guyama, Puerto Rico Bituminous Coal; max 1% sulfur 8-hr avg. no avgLA-0122 International Paper- Mansfield Mill 2 Coal Fired Boilers Less than 0.041 lb/mmbtu not given 0.20 lb/mmbtu 8/14/2001from coalPSD-LA-93 (M-6)Mansfield, Louisiana 645 mmbtu/hr eachTX-0342 Reliant Energy Inc. 2 Lignite Coal Fired Boilers No Controls Feasible not given Primary = Secondary= 5/23/2001Limestone Electric Generating St.873 0.28 P371 (M3)Houston, TX 7863 mmbtu/hr eachlb/hr lb/mmbtuKY-0079 Kentucky Mountain Power, LLC 2 Coal & Coal Refuse-Fired CFB Boilers Good Combustion Practices not given Primary = Secondary= 5/4/2001Units 1 & 20.27 lb/MMBtu none listed V-00-045Knott County, KY 2550 MMBtu/hrno avg.FL-0003 Tampa Electric Co. 1 Coal Fired Boiler Equipment Design and Operation not given Primary = Secondary= 1/1/2001Teco- Big Bend Station Dry Bottom, Tangentially Fired 0.029 124PSD-FL-040Apollo Beach, Florida 4330 mmbtu/hrlb/mmbtu lb/hrTX-0275 Reliant Energy 1 Coal Fired Boiler, Unit 8 Good Combustion Practices not given Primary = Secondary= 12/21/2000W.A. Parish Electric Generating St. 6700 mmbtu/hr0.05 lb/MMBtu 338 lb/hr PSD-TX-234Ft. Bend County, Texas Boiler also burns NG & Fuel Oil no avg. no avgMO-0050 Kansas City Power & Light Co. 1 Coal Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 8/17/1999Hawthorn Station Tangentially Fired0.16 lb/MMBtu none listed 888Kansas City, Missouri 384 T/Hno avg.FL-0178 JEA Northside Generating St. 2 Coal Fired CFB Boilers Good Combustion Practices not given Primary = Secondary= 7/14/1999297.5 MW; 2764 MMBtu/hr (each) 0.13 lb/MMBtu 350 lb/hrPSD-FL-265Jacksonville, Floridano avg. 24-hr blockIL-0060 Archer Daniels Midland Co. 2 Coal Fired CFB Boilers, Units 9,10 Good Combustion Practices not given Primary = Secondary= 12/24/19981500 mmbtu/hr each0.10 lb/MMBtu none listed97070097Decatur, Illinoisno avg.MS-0036 Choctaw Generation L.P 2 Lignite-Fired CFB Boilers Circulating Fluidized Bed not given Primary = Secondary= 8/25/1998Design 0.20 lb/MMBtu none listed 0400-00011Ackerman, Mississippi 2475.6 mmbtu/hr eachno avg.IA-0046 Archer Daniels Midland Company 2 Coal-Fired CFB Boiler, Unit #5, #6 Good Combustion Practices 10% Primary = Secondary= 6/30/19981500 mmbtu/hr (each)0.15 lb/MMBtu none listed 98-A-507PLinn County, IA3-hr avgIA-0051 Archer Daniels Midland Co. 1 Coal Fired CFB Boiler SNCR 10% Primary = Secondary= 6/30/19980.15 lb/MMBtu none listed 98-A-508PCedar Rapids, Iowa 1500 mmbtu/hr3-hr avgUT-0053 Deseret Generation & Transmission Co. 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 3/16/1998500 MW602.45 tpy none listed DAQE-186-98Unitah County, UTno avg.AR-0069 Entergy-Arkansas, Inc. 2 Coal-Fired PC Boilers Good Combustion Practices not given Primary = Secondary= 3/10/1998Independence Plant 8700 MMBtu/hr (each)100 ppm 0.37 lb/MMBtu 449-AOP-R0Independence County, AR Subbituminous Coal24-hr avg no avgWY-0039 Two Elk Generation Partners, Ltd. 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 2/27/1998Partnership0.15 lb/MMBtu none listed CT-1352Campbell County, WY 250 MWno avg.Att 10-B_Coal Boilers_RBLC.xlsCO7/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for COCoal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.RBLC IDEmissionLimitWY-0047 Encoal Corporation 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 10/10/1997North Rochelle Facility 240 MW0.15 lb/MMBtu none listed CT-1324Campbell County, WYno avg.WY-0047 Encoal Corporation 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 10/10/1997North Rochelle Facility 3960 MMBtu/hr0.15 lb/MMBtu none listed CT-1324Campbell County, WY Subbituminous Coalno avg.WY-0048 WYGEN, Inc. 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 9/6/1996WYGEN Unit #1 80 MW; 1014 MMBtu/hr0.15 lb/MMBtu none listed CT-1236Campbell County, WYno avg.PA-0133 Mon Valley Energy Ltd. 1 Pulverized Coal Fired Boiler No Controls Feasible not given Primary = Secondary= 8/8/1995Partnership0.20 847 30-306-001Poland Mines, Pennsylvania966 mmbtu/hrlb/mmbtu tpyPA-0134 Northampton Generating Co. 1 Ahlstrom Coal Fired CFB Boiler No Controls Feasible not given Primary = Secondary= 4/14/19950.15 700 48-00021Northampton, Pennsylvania 1146 mmbtu/hrlb/mmbtu tpyIL-0058 Archer Daniels Midland Co. 2 Coal Fired CFB Boilers Good Combustion Practice not given 0.1 lb/mmbtu 8/11/19941500 mmbtu/hr94020006Decatur, Illinois 750 mmbtu/hrMA-0028 Energy New Bedford 2 Coal Fired CFB Boilers Combustion Control not given Primary = Secondary= 7/11/1994228.1 0.144B90041New Bedford, Massachusetts 1671 mmbtu/hr eachlb/hr lb/mmbtuMD-0022 AES Warrior Run, Inc. 1 Coal Fired Atmospheric CFB Boiler Combustion Control not given 0.15 lb/mmbtu 6/30/199494-01Cumberland, Maryland 2070 mmbtu/hrFL-0255 Cedar Bay Generating Co., LP 3 Pulverized Coal Fired CFB Boilers Good Combustion Practice not given Primary = Secondary= 11/16/1993Ceder Bay Cogeneration0.175 186 PSD-FL-137AJacksonville, Florida 132 mmbtu/hr eachlb/mmbtu lb/hrNotes: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 BoilersAtt 10-B_Coal Boilers_RBLC.xlsCO7/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for SO2Coal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.WY-0063Black Hills Corporation 1 Coal-Fired PC Boiler Dry FGD not given Primary = Secondary= 2/5/2007WYGEN 3 1300 MMBtu/hr; 100 MW 0.09 lb/MMBtu 117.0 lb/hr CT-4517Campbell County, WY sub-bituminuous coal12-mo rolling 30-day rollingMO-0071Great Plains Energy 2 Coal-Fired Boiler - Unit 1 Not Identified n/a Primary = Secondary= 1/27/2006Iatan Station 7800 MMBtu/hr0.10 lb/MMBtu none listed 012006-019Platte County, MO sub-bituminuous coal30-day rollingCO-0055Lamar Utilities Board DBA 1 Coal-Fired CFB Boiler Limestone Injection not given Primary = Secondary= 9/28/2005Lamar Light & Power Plant 501.7 MMBtu/hr0.103 lb/MMBtu none listed 05-A-655-PPowers County, CO sub-bit or bituminous coal daily avgVA-0296Virginia Polytechnical Institute & 1 Stoker Fired Boiler - Boiler 11 Dry Scrubber FGD System not given Primary = Secondary= 9/15/2005State University 146.7 MMBtu/hr max sulfur 1.4% by weight 0.161 23.6 20124Montgomery County, VAlb/MMBtu lb/hrLA-0176Louisiana Generating, LLC 1 Coal-Fired PC Boiler, Unit 4 Semi-dry lime SDA or 90% Primary = Secondary= 8/22/2005Big Cajun II Power Plant 675 MW; supercritical boiler Wet FGD 0.10 lb/MMBtu 656.6 lb/hr PSD-LA-677Pointe Coupee County, LA sub-bituminuous coalannual avgPA-0249River Hill Power Company, LLC 1 Waste Coal-Fired CFB Boiler Dry FGD System not given Primary = Secondary= 7/21/2005Clearfield County, PA0.274 lb/MMBtu 0.20 lb/MMBtu 17-00055A24-hr rolling 30-day rollingPA-0248Wellington Dev/Greene Energy 2 Waste Coal-Fired CFB Boilers Limestone Injection plus 98% Primary = Secondary= 7/8/2005Resource Recovery Project 580 MW (gross) 525 MW (net) Dry Polishing Scrubber 0.156 lb/MMBtu 0.234 lb/MMBtu 30-00150AGreene County, PA30-day rolling 3-hr avgXcel Energy (PSC of Colorado) 2 Coal-Fired PC Boilers, Units #1 & #2 Lime Spray Dryer Absorber not given Primary = Secondary=Comanche Power Station 660 MW (both units)0.12 lb/MMBtu 0.10 lb/MMBtuPueblo, CO30-day avg annual avg.Xcel Energy (PSC of Colorado) 1 Coal-Fired PC Boiler, Unit #3 Lime Spray Dryer Absorber not given Primary = Secondary=Comanche Power Station 750 MW (unit #3); 7421 MMBtu/hr 0.10 lb/MMBtu not listedPueblo, CO sub-bituminuous coal30-day avgND-0021Montana Dakota Utilities/Westmoreland 1 Lignite Fired CFB Boiler Limestone Injection plus 98.9% Primary = Secondary= 6/3/2005Gascoyne Generating Station 220 MW (gross) 175 MW (net) Spray Dryer 0.038 lb/MMBtu 140 lbs/hr PTC 05005Bowman County, ND30 day rolling 24-hr rollingNV-0036Newmont Nevada Energy Investment LLC 1 Coal-Fired PC Boiler Spray Dryer Scrubber see limits Primary = Secondary= 5/5/2005TS Power Plant 200 MW; 2030 MMBtu/hr 0.065 lb/MMBtu 0.090 lb/MMBtu AP4911-1349Eureka County, NVif S <0.45% if S > 0.4591% CE; 30-day 95% CE; 30-dayPA-0247Robinson Power Company LLC 1 Waste Coal-Fired CFB Boiler Limestone Injection plus 97% Primary = Secondary= 4/1/2005Beech Hollow Power Project 272 MW (net); 2800 MMBtu/hr Fly Ash Hydration/Reinjection 0.245 lb/MMBtu 2957 tpy 63-00922AWashington County, PAno avg. no avgNH-0013Public Service of New Hampshire 1 Unit #5 Boiler Lime Injection; Fuel Sulfur Limits 70% Primary = Secondary= 10/25/2004Schiller Station Primary Wood-Fired; Coal Backup 0.12 lb/MMBtu 1.0 lb/MMBtu TP-B-0501Rockingham County, NH 50 MW24-hr avg max coal sulfurRBLC IDEmissionLimitAtt 10-B_Coal Boilers_RBLC.xlsSO27/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for SO2Coal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.RBLC IDEmissionLimitNE-0031Omaha Public Power District 1 Coal-Fired PC Boiler Dry FGD & Fabric Filter 90% Primary = Secondary= 3/9/2005Nebraska City Station Unit 2 boiler 660 MW (net)0.095 lb/MMBtu 0.163 lb/MMBtu 58343C01Otoe County, NE sub-bituminuous coal30-day rolling 24-hr rollingMO-0060Springfield Utilities 1 Coal-Fired PC Boiler Dry FGD 91.8% Primary = Secondary= 12/15/2004Southwest Power Station 275 MW; 2724 MMBtu/hr 0.095 lb/MMBtu none listed 122004-007Greene County, MO30-day rollingWI-0228Wisconsin Public Service Co. 1 Coal-Fired PC Boiler; supercritical Dry FGD 92% Primary = Secondary= 10/19/2004WPS - Weston Plant 500 MW; 5173 MMBtu/hr 0.10 lb/MMBtu 0.09 lb/MMBtu 04-RV-248Marathon County, WI PRB Coal; 8100 BTU/lb 30-day avg. 12-mo rollingUT-0065Intermountain Power Service Corp. 1 Coal-Fired PC Boiler Wet FGD 90% Primary = Secondary= 10/15/2004Generating Station Unit #3 950 MW (gross)0.10 lb/MMBtu 0.09 lb/MMBtu DAQE-AN0327010-04Millard County, UT Bituminous Coal or Blend 24-hr block 30-day rollingUT-0064Nevco-Sevier Power Company 1 Coal-Fired CFR Boiler Dry Lime Scrubber 90% Primary = Secondary= 10/12/2004Sevier Power Plant 270 MW0.05 lb/MMBtu 0.022 lb/MMBtu DAQE-AN2529001-04Sevier County, UT24-hr rolling 30-day rollingNE-0018Hastings Utilities 1 Unit 2 Coal-Fired Boiler Spray Dryer Absorber not given Primary = Secondary= 3/30/2004Whelan Energy Center 220 MW; 2210 MMBtu/hr 0.12 lb/MMBtu 1.1 lb/MMBtu 58048Adams County, NE30-day rolling 3-hr rollingWV-0023Longview Power, LLC 1 Coal-Fired PC Boiler Wet Limestone Forced Oxidation 97% Primary = Secondary= 3/2/2004Maidsville 600 MW; 6114 MMBtu/hr 0.12 lb/MMBtu 0.095 lb/MMBtu R14-0024Monongahela County, WV24-hr rolling annual avg.SC-0104Santee Cooper 2 Coal-Fired PC Boilers, #3 & #4 Wet FGD 95% Primary = Secondary= 2/5/2004Cross Generating Station Bituminous Coal & Pet Coke 0.13 lb/MMBtu 3250 tpy 0420-0030-ClBerkeley County, SC 5700 MMBtu/hr (each) 365-day rolling 365-day rollingTX-0298 Reliant Energy Inc. 3 Coal Fired Boilers, Units 5 ,6, 7 Low Sulfur Coal not given Primary = Secondary= 10/15/2003WA Parish Electric Generating St. Units 5 & 6 @ 7400 mmbtu/hr 1.06, 1.2 34530, 30112 PSD-TX-901,Houston, TX Unit 7 @ 6700 mmbtu/hr lb/mmbtu tpy -902 & -33M1PA-0182 Reliant Energy Inc. 2 Refused Coal-Fired CFB Boilers Fly Ash Reinjection not given Primary = Secondary= 8/26/2003Seward Power 2532 MMBtu/hr (each) 0.60 lb/MMBtu none listed PA-32-040BIndiana County, PAno avg.AR-0074 Plum Point Associates, LLC 1 Coal-Fired PC Boiler, Unit 1 Dry FGD System not given Primary = Secondary= 8/20/2003Plum Point Energy 800 MW0.16 lb/MMBtu none listed 1995-AOP-R0Mississippi County, ARno avg.OH-0231 First Energy/Toledo Edison Company 1 Coal & Coke-Fired CFB Boiler Limestone Fluidized Bed not given Primary = Secondary= 7/31/2003Bayshore Plant 1764 MMBtu/hr0.73 lb/MMBtu 5541 tpy 04-1056Lucas County, OHno avg. no avgAtt 10-B_Coal Boilers_RBLC.xlsSO27/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for SO2Coal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.RBLC IDEmissionLimitMT-0022 Bull Mountain Development Co. 2 Coal-Fired PC Boilers, No. 1, 2 Dry FGD System 94.5% Primary = Secondary= 7/21/2003Roundup Power Project 390 MW (each); 4013 MMBtu/hr 0.12 lb/MMBtu 481.6 tpy 3182-00Musselshell County, MT mine-mouth plant24-hr rolling 24-hr rollingIA-0067 Mid-American Energy Co. 1 Coal-Fired PC Boiler Lime Spray Dryer 92% Primary = Secondary= 6/17/2003PRB coal Dry FGD 0.10 lb/MMBtu 3362 tpy Project 02-528Council Bluffs, Iowa 7675 MMBtu/hr30-day rolling no avgTX-0358 Reliant Energy Inc.3Coal Fired Boilers Low Sulfur Coal not given Primary = Secondary= 10/15/2002WA Parish Electric Generating St. 2 @ 6750 mmbtu/hr1.2, 1.2 34530, 30112 PSD-TX-33 M1Houston, TX 1 @ 6700 mmbtu/hrlb/mmbtu tpyKY-0084 Thoroughbred Generating Company, LLC 2 Coal-Fired PC Boilers Wet FGD & Wet ESP not given Primary = Secondary= 10/11/2002Thoroughbred Generating Station 1500 MW (total); 7446 MMBtu/hr (ea) 0.167 lb/MMBtu 0.41 lb/MMBtu V-02-001Muhlenburg County, KY30-day rolling 24-hr avgKS-0026 Sand Sage Power, LLC 1 Subbituminous Coal-Fired PC Boiler Dry FGD 94% Primary = Secondary= 10/8/2002Holcomb Unit #2 660 MW0.12 lb/MMBtu none listed 0550087/C-3855Finney County, KSno avg.WY-0057 Black Hills Corporation 1 Subbituminous Coal-Fired PC Boiler Semi-Dry Lime SDA not given Primary = Secondary= 9/25/2002WYGEN 2 500 MW; 5146 MMBtu/hr 0.10 lb/MMBtu 0.15 lb/MMBtu CT-3030Campbell County, WY30-day rolling 3-hr blockKY-0086 East Kentucky Power Coop, Inc. 1 Coal-Fired CFB Boiler Limestone Injection plus not given Primary = Secondary= 8/4/2002Spurlock Power Station 270 MW; 2500 MMBtu/hr Dry Lime Scrubber 0.20 lb/MMBtu none listed V-97-050 (R1)Mason County, KY24-hr blockMT-0027 Rocky Mountain Power, Inc. 1 Coal-Fired PC Boiler Wet Scrubber not given Primary = Secondary= 6/11/2002Hardin Generating Project 113 MW (nominal); 1304 MMBtu/hr 0.14 lb/MMBtu none listed 3185-00Big Horn County, MT30-day rollingPA-0183 AES Beaver Valley, LLC 1 Coal-Fired CFB Boiler Hydrated Ash 95% Primary = Secondary= 11/21/20012155 MMBtu/hr Limestone Reinjection 12-mo avg 0.14 lb/MMBtu none listed PA-04-446CBeaver County, PAno avg.PR-0007 AES Puerto Rico Cogeneration Plant 2 Coal-Fired CFB Boilers Limestone Injection plus not given Primary = Secondary= 10/29/2001454 MW (net); 4923 MMBtu/hr Circulating Dry Scrubber 0.022 lb/MMBtu 9.0 ppmvd@7% 14Guyama, Puerto Rico Bituminous Coal; max 1% sulfur no avg no avgLA-0122 International Paper- Mansfield Mill 2 Coal Fired Boilers Low Sulfur Coal not given Primary = Secondary= 8/14/2001774.00 1.2 PSD-LA-93 (M-6)Mansfield, Louisiana 645 mmbtu/hr eachlb/hr lb/mmbtuTX-0342 Reliant Energy Inc. 2 Lignite Coal Fired Boilers Wet Limestone FGD not given Primary = Secondary= 5/23/2001Limestone Electric Generating St.9000 lb/hr 0.82 P371 (M3)Houston, TX 7863 mmbtu/hr each3-hr rolling avg lb/mmbtuAtt 10-B_Coal Boilers_RBLC.xlsSO27/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for SO2Coal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.RBLC IDEmissionLimitKY-0079 Kentucky Mountain Power, LLC 2 Coal & Coal Refuse-Fired CFB Boilers Naturally Integrated not given Primary = Secondary= 5/4/2001Units 1 & 2 Desulfurization System 0.13 lb/MMBtu none listed V-00-045Knott County, KY 2550 MMBtu/hrno avg.FL-0003 Tampa Electric Co. 1 Coal Fired Boiler Limestone Scrubber & 90% Primary = Secondary= 1/1/2001Teco- Big Bend Station Dry Bottom, Tangentially Fired Coal Washing 0.82 3551PSD-FL-040Apollo Beach, Florida 4330 mmbtu/hrlb/mmbtu lb/hrTX-0275 Reliant Energy 1 Coal Fired Boiler, Unit 8 FGD not given Primary = Secondary= 12/21/2000W.A. Parish Electric Generating St. 6700 mmbtu/hr0.30 lb/MMBtu 2063 lb/hr PSD-TX-234Ft. Bend County, Texas Boiler also burns NG & Fuel Oil no avg. 3-hr avgMO-0050 Kansas City Power & Light Co. 1 Coal Fired PC Boiler Dry FGD not given Primary = Secondary= 8/17/1999Hawthorn Station Tangentially Fired0.12 lb/MMBtu none listed 888Kansas City, Missouri 384 T/H30-day avgFL-0178 JEA Northside Generating St. 2 Coal Fired CFB Boilers CFB Scrubber & Fabric Filter not given Primary = Secondary= 7/14/1999297.5 MW; 2764 MMBtu/hr (each) or CFB Scrubber & SDA 0.15 lb/MMBtu 0.20 lb/MMBtuPSD-FL-265Jacksonville, Florida30-day avg 24-hr avgIL-0060 Archer Daniels Midland Co. 2 Coal Fired CFB Boilers, Units 9,10 Limestone Injection plus 92% Primary = Secondary= 12/24/19981500 mmbtu/hr each Fabric Filter 0.70 lb/MMBtu none listed97070097Decatur, Illinoisno avg.MS-0036 Choctaw Generation L.P 2 Lignite-Fired CFB Boilers Circulating Fluidized Bed not given Primary = Secondary= 8/25/1998Design w/Lime Injection 0.25 lb/MMBtu none listed 0400-00011Ackerman, 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 = Secondary= 6/30/19981500 mmbtu/hr (each) CFB 0.36 lb/MMBtu none listed 98-A-507PLinn County, IA30-day rollingIA-0051 Archer Daniels Midland Co. 1 Coal Fired CFB Boiler Limestone Injection plus 92% Primary = Secondary= 6/30/1998CFB 0.36 lb/MMBtu none listed 98-A-508PCedar Rapids, Iowa 1500 mmbtu/hr30-day rollingUT-0053 Deseret Generation & Transmission Co. 1 Coal-Fired PC Boiler Wet Scrubber 90.0% Primary = Secondary= 3/16/1998500 MW0.0976 lb/MMBtu 0.15 lb/MMBtu DAQE-186-98Unitah County, UT12-month avg 30-day avgWY-0039 Two Elk Generation Partners, Ltd. 1 Coal-Fired PC Boiler Lime Spray Dry Scrubber 91.0% Primary = Secondary= 2/27/1998Partnership0.17 lb/MMBtu 0.20 lb/MMBtu CT-1352Campbell County, WY 250 MW30-day rolling 2-hr fixedWY-0047 Encoal Corporation 1 Coal-Fired PC Boiler Lime Spray Dryer 73% Primary = Secondary= 10/10/1997North Rochelle Facility 3960 MMBtu/hr0.20 lb/MMBtu none listed CT-1324Campbell County, WY Subbituminous Coal2-hr fixedAtt 10-B_Coal Boilers_RBLC.xlsSO27/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for SO2Coal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.RBLC IDEmissionLimitFL-0177 JEA - St. John's River Power Park 1 Utility Boiler FGD Scrubbers not given Primary = Secondary= 10/14/1996100,000 lb/hr0.676 lb/MMBtu none listed PSD-FL-010BDuval County, FL up to 20% pet cokeno avgWY-0048 WYGEN, Inc. 1 Coal-Fired PC Boiler Circulating Dry Scrubber 92% Primary = Secondary= 9/6/1996WYGEN Unit #1 80 MW; 1014 MMBtu/hr 0.20 lb/MMBtu none listed CT-1236Campbell County, WY2-hr rollingPA-0133 Mon Valley Energy Ltd. 1 Pulverized Coal Fired Boiler Spray Dryer Absorber 92% Primary = Secondary= 8/8/1995Partnership0.25 874 30-306-001Poland Mines, Pennsylvania966 mmbtu/hrlb/mmbtu tpyPA-0132 York County Energy Partners 1 Coal Fired CFB Boiler Limestone Injection System 92% Primary = Secondary= 7/25/1995Spring Grove, Pennsylvania0.25 660 67-306-0072500 mmbtu/hrRlb/mmbtu lb/hrUT-0060 Deseret Generation & 1 Coal Fired Boiler Scrubber 90% Primary = Secondary= 6/14/1995Transmission Co.0.1 lb/mmbtu 0.15 lb/mmbtu DAQE-523-95Vernaz, Utah 4381 mmbtu/hr12-mo. avg 1-mo. AvgPA-0134 Northampton Generating Co. 1 Coal Fired CFB Boiler Limestone Injection System 92% Primary = Secondary= 4/14/19950.129 602 48-00021Northampton, Pennsylvania 1146 mmbtu/hrlb/mmbtu tpyIL-0058 Archer Daniels Midland Co. 2 Coal Fired CFB Boilers Limestone Injection System 90% 0.7 lb/mmbtu 8/11/19941500 mmbtu/hr94020006Decatur, Illinois 750 mmbtu/hrMA-0028 Energy New Bedford 2 Coal Fired CFB Boilers Limestone Injection System 70% Primary = Secondary= 7/11/19940.23 403.554B90041New Bedford, Massachusetts 1671 mmbtu/hr eachlb/mmbtu lb/hrMD-0022 AES Warrior Run, Inc. 1 Coal Fired Atmospheric Limestone Injection System 95% 0.16 lb/mmbtu 6/30/1994CFB Boiler94-01Cumberland, Maryland 2070 mmbtu/hrFL-0255 Cedar Bay Generating Co., LP 3 Pulverized Coal Fired CFB Boilers Limestone Injection System not given Primary = Secondary= 11/16/1993Ceder Bay Cogeneration0.3 lb/mmbtu 318.9 lb/hr PSD-FL-137AJacksonville, Florida 132 mmbtu/hr each3- hr rolling 3- hr rollingNotes: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 BoilersAtt 10-B_Coal Boilers_RBLC.xlsSO27/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for VOCCoal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.MO-0071Great Plains Energy 2 Coal-Fired Boiler - Unit 1 Good Combustion Practices n/a Primary = Secondary= 1/27/2006Iatan Station 7800 MMBtu/hr0.0036 lb/MMBtu none listed 012006-019Platte County, MO sub-bituminuous coal no avgVA-0296Virginia Polytechnical Institute & 1 Stoker Fired Boiler - Boiler 11 Good Combustion Practice not given Primary = Secondary= 9/15/2005State University 146.7 MMBtu/hr0.002 0.3 20124Montgomery County, VAlb/MMBtu lb/hrLA-0176Louisiana Generating, LLC 1 Coal-Fired PC Boiler, Unit 4 Good Combustion Practices not given Primary = Secondary= 8/22/2005Big Cajun II Power Plant 675 MW; supercritical boiler 0.015 lb/MMBtu 98.5 lb/hr PSD-LA-677Pointe Coupee County, LA sub-bituminuous coal annual avgPA-0249River Hill Power Company, LLC 1 Waste Coal-Fired CFB Boiler Combustion Control not given Primary = Secondary= 7/21/2005Clearfield County, PA0.005 lb/MMBtu 14.36 lb/hr 17-00055Ano avg no avgPA-0248Wellington Dev/Greene Energy 2 Waste Coal-Fired CFB Boilers SNCR 40% Primary = Secondary= 7/8/2005Resource Recovery Project 580 MW (gross) 525 MW (net) Good Combustion Practice 0.005 lb/MMBtu 121 tpy 30-00150AGreene County, PAno avg 12-month rollingCO-0057 Xcel Energy (PSC of Colorado) 1 Coal-Fired PC Boiler, Unit #3 Good Combustion Practices not given Primary = Secondary= 7/5/2005Comanche Power Station 750 MW (unit #3); 7421 MMBtu/hr 0.0035 lb/MMBtu none listed 04UNITPB1015Pueblo, CO sub-bituminuous coal 3 test run avg.ND-0021Montana Dakota Utilities/Westmoreland 1 Lignite Fired CFB Boiler Good Combustion Practices not given Primary = Secondary= 6/3/2005Gascoyne Generating Station 220 MW (gross) 175 MW (net) 0.005 lb/MWh none listed PTC 05005Bowman County, ND3-hr avgPA-0247Robinson Power Company LLC 1 Waste Coal-Fired CFB Boiler Combustion Optimization not given Primary = Secondary= 4/1/2005Beech Hollow Power Project 272 MW (net); 2800 MMBtu/hr 0.006 lb/MMBtu 72.9 tpy 63-00922AWashington County, PAno avg. no avgNE-0031Omaha Public Power District 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 3/9/2005Nebraska City Station Unit 2 boiler 660 MW (net)0.0034 lb/MMBtu none listed 58343C01Otoe County, NE sub-bituminuous coal test avgMO-0060Springfield Utilities 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 12/15/2004Southwest Power Station 275 MW; 2724 MMBtu/hr 0.0036 lb/MMBtu none listed 122004-007Greene County, MOno avg.WI-0228Wisconsin Public Service Co. 1 Coal-Fired PC Boiler; supercritical Good Combustion Practices not given Primary = Secondary= 10/19/2004WPS - Weston Plant 500 MW; 5173 MMBtu/hr 0.0036 lb/MMBtu 81.6 ton/yr 04-RV-248Marathon County, WI PRB Coal; 8100 BTU/lb 24-hr avg. 12-mo rollingUT-0065Intermountain Power Service Corp. 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 10/15/2004Generating Station Unit #3 950 MW (gross)0.0027 lb/MMBtu none listed DAQE-AN0327010-04Millard County, UT Bituminous Coal or Blend 3 test run avg.GA-0114Temple-Inland Inc. 1 Coal-Fired Boiler Good Combustion Practices not given Primary = Secondary= 10/13/2004Rome Linerboard Mill 565 MMBtu/hr0.01 lb/MMBtu none listed 2631-115-0021-V-01-4Floyd County, GAno avg.RBLC IDEmissionLimitAtt 10-B_Coal Boilers_RBLC.xlsVOC7/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for VOCCoal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.RBLC IDEmissionLimitOK-0103 Weyerhaeuser 1 Coal-Fired CFB Boiler Good Combustion Practices not given Primary = Secondary= 10/13/2004Valliant Mill0.005 lb/MMBtu none listed 97-057-C (M-4) PSDMcCurtain County, OKmonthly avgWV-0023Longview Power, LLC 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 3/2/2004Maidsville 600 MW; 6114 MMBtu/hr 0.004 lb/MMBtu 24.5 lb/hr R14-0024Monongahela County, WV3-hr rolling no avgSC-0104Santee Cooper 2 Coal-Fired PC Boilers, #3 & #4 Good Combustion Practices not given Primary = Secondary= 2/5/2004Cross Generating Station Bituminous Coal & Pet Coke 0.0024 lb/MMBtu none listed 0420-0030-ClBerkeley 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= 8/26/2003Seward Power 2532 MMBtu/hr (each) 0.005 lb/MMBtu none listed PA-32-040BIndiana County, PAno avg.AR-0074 Plum Point Associates, LLC 1 Coal-Fired PC Boiler, Unit 1 Combustion Control not given Primary = Secondary= 8/20/2003Plum Point Energy 800 MW0.02 lb/MMBtu none listed 1995-AOP-R0Mississippi County, ARno avg.OH-0231 First Energy/Toledo Edison Company 1 Coal & Coke-Fired CFB Boiler Good Combustion Practices not given Primary = Secondary= 7/31/2003Bayshore Plant 1764 MMBtu/hr4.4 lb/hr 19.3 tpy 04-1056Lucas County, OHno avg. no avgMT-0022 Bull Mountain Development Co. 2 Coal-Fired PC Boilers, No. 1, 2 Good Combustion Practices not given Primary = Secondary= 7/21/2003Roundup Power Project 390 MW (each); 4013 MMBtu/hr 0.003 lb/MMBtu 12 lb/hr 3182-00Musselshell County, MT mine-mouth plantno avg.IA-0067 Mid-American Energy Co. 1 Coal-Fired PC Boiler Combustion Control not given Primary = Secondary= 6/17/2003PRB coal0.0036 lb/MMBtu 121 tpy Project 02-528Council Bluffs, Iowa 7675 MMBtu/hr1-hr avg no avgKY-0084 Thoroughbred Generating Company, LLC 2 Coal-Fired PC Boilers Good Combustion Practices not given Primary = Secondary= 10/11/2002Thoroughbred Generating Station 1500 MW (total); 7446 MMBtu/hr (ea) 0.0072 lb/MMBtu none listed V-02-001Muhlenburg County, KY30-day rollingKS-0026 Sand Sage Power, LLC 1 Subbituminous Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 10/8/2002Holcomb Unit #2 660 MW0.0035 lb/MMBtu none listed 0550087/C-3855Finney County, KSno avg.WY-0057 Black Hills Corporation 1 Subbituminous Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 9/25/2002WYGEN 2 500 MW; 5146 MMBtu/hr 0.01 lb/MMBtu none listed CT-3030Campbell County, WYno avg.KY-0086 East Kentucky Power Coop, Inc. 1 Coal-Fired CFB Boiler Proper Boiler Design & Operation not given Primary = Secondary= 8/4/2002Spurlock Power Station 270 MW; 2500 MMBtu/hr 0.0036 lb/MMBtu none listed V-97-050 (R1)Mason County, KY30-day avgMT-0027 Rocky Mountain Power, Inc. 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 6/11/2002Hardin Generating Project 113 MW (nominal); 1304 MMBtu/hr 0.0034 lb/MMBtu none listed 3185-00Big Horn County, MTno avg.PA-0183 AES Beaver Valley, LLC 1 Coal-Fired CFB Boiler Good Combustion Practices not given Primary = Secondary= 11/21/20012155 MMBtu/hr0.0068 lb/MMBtu none listed PA-04-446CBeaver County, PAno avg.Att 10-B_Coal Boilers_RBLC.xlsVOC7/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for VOCCoal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.RBLC IDEmissionLimitPR-0007 AES Puerto Rico Cogeneration Plant 2 Coal-Fired CFB Boilers Good Combustion Practices not given Primary = Secondary= 10/29/2001454 MW (net); 4923 MMBtu/hr 0.0047 lb/MMBtu 7.7 ppmvd@7% 14Guyama, Puerto Rico Bituminous Coal; max 1% sulfur no avg no avgKY-0079 Kentucky Mountain Power, LLC 2 Coal & Coal Refuse-Fired CFB Boilers Good Combustion Practices not given Primary = Secondary= 5/4/2001Units 1 & 20.0072 lb/MMBtu none listed V-00-045Knott County, KY 2550 MMBtu/hrno avg.TX-0275 Reliant Energy 1 Coal Fired Boiler, Unit 8 Good Combustion Practices not given Primary = Secondary= 12/21/2000W.A. Parish Electric Generating St. 6700 mmbtu/hr20.1 lb/hr 52.8 tpy PSD-TX-234Ft. Bend County, Texas Boiler also burns NG & Fuel Oil no avg. no avgMO-0050 Kansas City Power & Light Co. 1 Coal Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 8/17/1999Hawthorn Station Tangentially Fired0.0036 lb/MMBtu none listed 888Kansas City, Missouri 384 T/Hno avg.FL-0178 JEA Northside Generating St. 2 Coal Fired CFB Boilers Good Combustion Practices not given Primary = Secondary= 7/14/1999297.5 MW; 2764 MMBtu/hr (each) 0.005 lb/MMBtu 14.0 lb/hrPSD-FL-265Jacksonville, Floridano avg. 3-hr avgIL-0060 Archer Daniels Midland Co. 2 Coal Fired CFB Boilers, Units 9,10 Good Combustion Practices not given Primary = Secondary= 12/24/19981500 mmbtu/hr each0.032 lb/MMBtu none listed97070097Decatur, Illinoisno avg.IA-0046 Archer Daniels Midland Company 2 Coal-Fired CFB Boiler, Unit #5, #6 Good Combustion Practices not given Primary = Secondary= 6/30/19981500 mmbtu/hr (each) 0.0072 lb/MMBtu none listed 98-A-507PLinn County, IA3-hr avgIA-0051 Archer Daniels Midland Co. 1 Coal Fired CFB Boiler Good Combustion Practices not given Primary = Secondary= 6/30/19980.0072 lb/MMBtu none listed 98-A-508PCedar Rapids, Iowa 1500 mmbtu/hr3-hr avgPA-0204 Kimberly- Clark Tissue Co. 3 Coal Fired CFB & 2 Vertical Boilers None Indicated not given Primary = Secondary= 6/24/1998Kimberly- Clark/Chester Plant 799 mmbtu/hr, 249 mmbtu/hr & 0.006 lb/MMBtu 30 tpy total 23-0014AChester, Pennsylvania 198 mmbtu/hr (respectively) no avg. rolling avgUT-0053 Deseret Generation & Transmission Co. 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 3/16/1998500 MW70.89 tpy none listed DAQE-186-98Unitah County, UTno avg.WY-0039 Two Elk Generation Partners, Ltd. 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 2/27/1998Partnership0.015 lb/MMBtu none listed CT-1352Campbell County, WY 250 MWno avg.WY-0047 Encoal Corporation 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 10/10/1997North Rochelle Facility 240 MW0.05 lb/MMBtu none listed CT-1324Campbell County, WYno avg.WY-0047 Encoal Corporation 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 10/10/1997North Rochelle Facility 3960 MMBtu/hr0.05 lb/MMBtu none listed CT-1324Campbell County, WY Subbituminous Coalno avg.Att 10-B_Coal Boilers_RBLC.xlsVOC7/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for VOCCoal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.RBLC IDEmissionLimitWY-0048 WYGEN, Inc. 1 Coal-Fired PC Boiler Good Combustion Practices not given Primary = Secondary= 9/6/1996WYGEN Unit #1 80 MW; 1014 MMBtu/hr 0.015 lb/MMBtu none listed CT-1236Campbell County, WYno avg.PA-0133 Mon Valley Energy Ltd. 1 Pulverized Coal Fired Boiler No Controls Feasible not given Primary = Secondary= 8/8/1995Partnership0.01 42.3 30-306-001Poland Mines, Pennsylvania966 mmbtu/hrlb/mmbtu tpyPA-0132 York County Energy Partners 1 Coal Fired CFB Boiler Combustion Control not given Primary = Secondary= 7/25/1995Spring Grove, Pennsylvania0.004 50 67-306-0072500 mmbtu/hrRlb/mmbtu tpyPA-0134 Northampton Generating Co. 1 Ahlstrom Coal Fired CFB Boiler No Controls Feasible not given Primary = Secondary= 4/14/19950.005 23.4 48-00021Northampton, Pennsylvania 1146 mmbtu/hrlb/mmbtu tpyIL-0058 Archer Daniels Midland Co. 2 Coal Fired CFB Boilers Good Combustion Practice not given 0.032 lb/mmbtu 8/11/19941500 mmbtu/hr94020006Decatur, Illinois 750 mmbtu/hrMA-0028 Energy New Bedford 2 Coal Fired CFB Boilers Combustion Control not given Primary = Secondary= 7/11/199410.55 0.0064B90041New Bedford, Massachusetts 1671 mmbtu/hr eachlb/hr lb/mmbtuNotes: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 BoilersAtt 10-B_Coal Boilers_RBLC.xlsVOC7/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for PMCoal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.WY-0063Black Hills Corporation 1 Coal-Fired PC Boiler Baghouse not given Primary = Secondary= 2/5/2007WYGEN 3 1300 MMBtu/hr; 100 MW 0.012 lb/MMBtu none listed CT-4517Campbell County, WY sub-bituminuous coal test avg (F only)VA-0296Virginia Polytechnical Institute & 1 Stoker Fired Boiler - Boiler 11 Baghouse not given Primary = Secondary= 9/15/2005State University 146.7 MMBtu/hr 0.02 lb/MMBtu 2.9 lb/hr 20124Montgomery County, VACO-0057 Xcel Energy (PSC of Colorado) 1 Coal-Fired PC Boiler, Unit #3 Baghouse not given Primary = Secondary= 7/5/2005Comanche Power Station 750 MW (unit #3); 7421 MMBtu/hr 0.013 lb/MMBtu 0.022 lb/MMBtu 04UNITPB1015Pueblo, CO sub-bituminuous coal F only F+CND-0021Montana Dakota Utilities/Westmoreland 1 Lignite Fired CFB Boiler Baghouse not given Primary = Secondary= 6/3/2005Gascoyne Generating Station 220 MW (gross) 175 MW (net) 0.0167 lb/MMBtu none listed PTC 05005Bowman County, ND3-hr avg (F only)NE-0031Omaha Public Power District 1 Coal-Fired PC Boiler Baghouse 99.9% Primary = Secondary= 3/9/2005Nebraska City Station Unit 2 boiler 660 MW (net)0.018 lb/MMBtu none listed 58343C01Otoe County, NE sub-bituminuous coal test avgWI-0228Wisconsin Public Service Co. 1 Coal-Fired PC Boiler; supercritical Fabric Filter not given Primary = Secondary= 10/19/2004WPS - Weston Plant 500 MW; 5173 MMBtu/hr includes back-half 0.020 lb/MMBtu 103.52 lb/hr 04-RV-248Marathon County, WI PRB Coal; 8100 BTU/lb 3-hr avg 3-hr avgUT-0065Intermountain Power Service Corp. 1 Coal-Fired PC Boiler Fabric Filter not given Primary = Secondary= 10/15/2004Generating Station Unit #3 950 MW (gross) 0.013 lb/MMBtu none listed DAQE-AN0327010-04Millard County, UT Bituminous Coal or Blend 3 test run avg.WV-0023Longview Power, LLC 1 Coal-Fired PC Boiler Fabric Filter 99.0% Primary = Secondary= 3/2/2004Maidsville 600 MW; 6114 MMBtu/hr 0.018 lb/MMBtu 110 lb/hr R14-0024Monongahela County, WV6-hr rolling no avgSC-0104Santee Cooper 2 Coal-Fired PC Boilers, #3 & #4 ESP not given Primary = Secondary= 2/5/2004Cross Generating Station Bituminous Coal & Pet Coke 0.015 lb/MMBtu none listed 0420-0030-ClBerkeley 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= 10/15/2003WA Parish Electric Generating St. Units 5 & 6 @ 7400 mmbtu/hr 0.088, 0.085 2878, 2509 PSD-TX-901,Houston, TX Unit 7 @ 6700 mmbtu/hr lb/mmbtu tpy -902 & -33M1OH-0231 First Energy/Toledo Edison Company 1 Coal & Coke-Fired CFB Boiler Baghouse 99.0% Primary = Secondary= 7/31/2003Bayshore Plant 1764 MMBtu/hr 0.03 lb/MMBtu 232 tpy 04-1056Lucas County, OHno avg. no avgRBLC IDEmissionLimitAtt 10-B_Coal Boilers_RBLC.xlsPM7/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for PMCoal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.RBLC IDEmissionLimitIA-0067 Mid-American Energy Co. 1 Coal-Fired PC Boiler Baghouse 99.7% Primary = Secondary= 6/17/2003PRB coal0.018 lb/MMBtu none listed Project 02-528Council Bluffs, Iowa 7675 MMBtu/hr no avg.KY-0084 Thoroughbred Generating Company, LLC 2 Coal-Fired PC Boilers ESP & Wet ESP 99.0% Primary = Secondary= 10/11/2002Thoroughbred Generating Station 1500 MW (total); 7446 MMBtu/hr (ea) 0.018 lb/MMBtu none listed V-02-001Muhlenburg County, KY3-hr avgWY-0057 Black Hills Corporation 1 Subbituminous Coal-Fired PC Boiler Fabric Filter not given Primary = Secondary= 9/25/2002WYGEN 2 500 MW; 5146 MMBtu/hr 0.012 lb/MMBtu none listed CT-3030Campbell County, WYno avg.TX-0342 Reliant Energy Inc. 2 Lignite Coal Fired Boilers Cold Side ESP not given Primary = Secondary= 5/23/2001Limestone Electric Generating St.0.03 236.00 P371 (M3)Houston, TX 7863 mmbtu/hr each lb/mmbtu lb/hrKY-0079 Kentucky Mountain Power, LLC 2 Coal & Coal Refuse-Fired CFB Boilers Baghouse 99% Primary = Secondary= 5/4/2001Units 1 & 20.015 lb/MMBtu none listed V-00-045Knott County, KY 2550 MMBtu/hr no avg.FL-0003 Tampa Electric Co. 1 Coal Fired Boiler ESP 99% Primary = Secondary= 1/1/2001Teco- Big Bend Station Dry Bottom, Tangentially Fired 0.03 569PSD-FL-040Apollo Beach, Florida 4330 mmbtu/hr lb/mmbtu tpyIL-0060 Archer Daniels Midland Co. 2 Coal Fired CFB Boilers, Units 9,10 Fabric Filter 99% Primary = Secondary= 12/24/19981500 mmbtu/hr each 0.025 lb/MMBtu none listed97070097Decatur, Illinoisno avg.IA-0046 Archer Daniels Midland Company 2 Coal-Fired CFB Boiler, Unit #5, #6 Baghouse 99% Primary = Secondary= 6/30/19981500 mmbtu/hr (each) 0.015 lb/MMBtu none listed 98-A-507PLinn County, IA3-hr avgIA-0051 Archer Daniels Midland Co. 1 Coal Fired CFB Boiler Baghouse 99% Primary = Secondary= 6/30/19980.015 lb/MMBtu none listed 98-A-508PCedar Rapids, Iowa 1500 mmbtu/hr 3-hr avgMT-0009 Colstrip Energy L.P. 1 Coal-Fired CFB Boiler Baghouse 99.9% Primary = Secondary= 3/20/1998503 MMBtu/hr 0.03 lb/MMBtu 6.01 lb/hr 2035-03Rosebud County, MTno avg. no avgAtt 10-B_Coal Boilers_RBLC.xlsPM7/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for PMCoal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.RBLC IDEmissionLimitWY-0039 Two Elk Generation Partners, Ltd. 1 Coal-Fired PC Boiler Baghouse 99.5% Primary = Secondary= 2/27/1998Partnership0.02 lb/MMBtu none listed CT-1352Campbell County, WY 250 MWno avg.WY-0047 Encoal Corporation 1 Coal-Fired PC Boiler Baghouse 99% Primary = Secondary= 10/10/1997North Rochelle Facility 3960 MMBtu/hr 0.020 lb/MMBtu none listed CT-1324Campbell County, WY Subbituminous Coal no avg.WY-0048 WYGEN, Inc. 1 Coal-Fired PC Boiler ESP 99% Primary = Secondary= 9/6/1996WYGEN Unit #1 80 MW; 1014 MMBtu/hr 0.020 lb/MMBtu none listed CT-1236Campbell County, WYno avg.IL-0058 Archer Daniels Midland Co. 2 Coal Fired CFB Boilers Fabric Filter 99% 0.025 lb/mmbtu 8/11/19941500 mmbtu/hr94020006Decatur, Illinois 750 mmbtu/hrMD-0022 AES Warrior Run, Inc. 1 Coal Fired Atmospheric CFB Boiler Fabric Filter not given 0.015 lb/mmbtu 6/30/199494-01Cumberland, Maryland 2070 mmbtu/hrFL-0255 Cedar Bay Generating Co., LP 3 Pulverized Coal Fired CFB Boilers Fabric Baghouse not given Primary = Secondary= 11/16/1993Ceder Bay Cogeneration0.018 19.1 PSD-FL-137AJacksonville, Florida 132 mmbtu/hr each lb/mmbtu lb/hrNotes: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 BoilersAtt 10-B_Coal Boilers_RBLC.xlsPM7/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for PM10Coal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.MO-0071Great Plains Energy 2 Coal-Fired Boiler - Unit 1 Baghouse 99.50% Primary = Secondary= 1/27/2006Iatan Station 7800 MMBtu/hr 0.0244 lb/MMBtu 0.014 lb/MMBtu 012006-019Platte County, MO sub-bituminuous coal 30-day rolling (F & C) 3-hr (F only)CO-0055Lamar Utilities Board DBA 1 Coal-Fired CFB Boiler Baghouse 99.78% Primary = Secondary= 9/28/2005Lamar Light & Power Plant 501.7 MMBtu/hr 0.012 lb/MMBtu 10% opacity 05-A-655-PPowers County, CO sub-bit or bituminous coal duration of tests 6-min avgVA-0296Virginia Polytechnical Institute & 1 Stoker Fired Boiler - Boiler 11 Baghouse not given Primary = Secondary= 9/15/2005State University 146.7 MMBtu/hr 0.018 2.6 20124Montgomery County, VAlb/MMBtu lb/hrLA-0176Louisiana Generating, LLC 1 Coal-Fired PC Boiler, Unit 4 ESP& Baghouse 99.9% Primary = Secondary= 8/22/2005Big Cajun II Power Plant 675 MW; supercritical boiler in series 0.015 lb/MMBtu 98.5 lb/hr PSD-LA-677Pointe Coupee County, LA sub-bituminuous coal annual avgPA-0249River Hill Power Company, LLC 1 Waste Coal-Fired CFB Boiler Baghouse not given Primary = Secondary= 7/21/2005Clearfield County, PA0.012 lb/MMBtu 34.45 lb/hr 17-00055Ano avg no avgPA-0248Wellington Dev/Greene Energy 2 Waste Coal-Fired CFB Boilers Baghouse 99.0% Primary = Secondary= 7/8/2005Resource Recovery Project 580 MW (gross) 525 MW (net) 0.012 lb/MMBtu 289.7 tpy 30-00150AGreene County, PAno avg 12-month rollingCO-0057 Xcel Energy (PSC of Colorado) 1 Coal-Fired PC Boiler, Unit #3 Baghouse not given Primary = Secondary= 7/5/2005Comanche Power Station 750 MW (unit #3); 7421 MMBtu/hr 0.012 lb/MMBtu 0.020 lb/MMBtu 04UNITPB1015Pueblo, CO sub-bituminuous coal F only F+CND-0021Montana Dakota Utilities/Westmoreland 1 Lignite Fired CFB Boiler Baghouse 99.91% Primary = Secondary= 6/3/2005Gascoyne Generating Station 220 MW (gross) 175 MW (net) 0.013 lb/MMBtu 0.0275 lb/MMBtu PTC 05005Bowman County, ND3-hr avg (F only) (both F & C)NV-0036Newmont Nevada Energy Investment LLC 1 Coal-Fired PC Boiler Baghouse not given Primary = Secondary= 5/5/2005TS Power Plant 200 MW; 2030 MMBtu/hr 0.12 lb/MMBtu none listed AP4911-1349Eureka County, NV24-hr rolling (F only)PA-0247Robinson Power Company LLC 1 Waste Coal-Fired CFB Boiler Baghouse 99.9% Primary = Secondary= 4/1/2005Beech Hollow Power Project 272 MW (net); 2800 MMBtu/hr 0.012 lb/MMBtu 147.2 tpy 63-00922AWashington County, PAno avg. no avgMO-0060Springfield Utilities 1 Coal-Fired PC Boiler Baghouse 99.90% Primary = Secondary= 12/15/2004Southwest Power Station 275 MW; 2724 MMBtu/hr 0.018 lb/MMBtu none listed 122004-007Greene County, MOno avg.WI-0228Wisconsin Public Service Co. 1 Coal-Fired PC Boiler; supercritical Fabric Filter not given Primary = Secondary= 10/19/2004WPS - Weston Plant 500 MW; 5173 MMBtu/hr includes back-half 0.018 lb/MMBtu none listed 04-RV-248Marathon County, WI PRB Coal; 8100 BTU/lb 3-hr avgUT-0065Intermountain Power Service Corp. 1 Coal-Fired PC Boiler Fabric Filter 99.85% Primary = Secondary= 10/15/2004Generating Station Unit #3 950 MW (gross) 0.012 lb/MMBtu 221 lb/hr DAQE-AN0327010-04Millard County, UT Bituminous Coal or Blend 3 test run avg. 24-hr blockRBLC IDEmissionLimitAtt 10-B_Coal Boilers_RBLC.xlsPM107/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for PM10Coal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.RBLC IDEmissionLimitGA-0114Temple-Inland Inc. 1 Coal-Fired Boiler ESP not given Primary = Secondary= 10/13/2004Rome Linerboard Mill 565 MMBtu/hr 0.05 lb/MMBtu none listed 2631-115-0021-V-01-4Floyd County, GAno avg.UT-0064Nevco-Sevier Power Company 1 Coal-Fired CFR Boiler Fabric Filter 99.9% Primary = Secondary= 10/12/2004Sevier Power Plant 270 MW 39 lb/hr 10% opacity DAQE-AN2529001-04Sevier County, UT24-hr rollingWV-0023Longview Power, LLC 1 Coal-Fired PC Boiler Fabric Filter 99.0% Primary = Secondary= 3/2/2004Maidsville 600 MW; 6114 MMBtu/hr 0.018 lb/MMBtu 110 lb/hr R14-0024Monongahela County, WV6-hr rolling (both F&C) no avgSC-0104Santee Cooper 2 Coal-Fired PC Boilers, #3 & #4 ESP not given Primary = Secondary= 2/5/2004Cross Generating Station Bituminous Coal & Pet Coke 0.018 lb/MMBtu none listed 0420-0030-ClBerkeley 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= 10/15/2002WA Parish Electric Generating St. Units 5 & 6 @ 7400 mmbtu/hr 0.097, .086 2878, 2509 PSD-TX-33 M1Houston, TX Unit 7 @ 6700 mmbtu/hr lb/mmbtu tpyPA-0182 Reliant Energy Inc. 2 Refused Coal-Fired CFB Boilers Fabric Filter not given Primary = Secondary= 8/26/2003Seward Power 2532 MMBtu/hr (each) 0.010 lb/MMBtu none listed PA-32-040BIndiana County, PAno avg.AR-0074 Plum Point Associates, LLC 1 Coal-Fired PC Boiler, Unit 1 Fabric Filter not given Primary = Secondary= 8/20/2003Plum Point Energy 800 MW 0.018 lb/MMBtu none listed 1995-AOP-R0Mississippi County, ARno avg.OH-0231 First Energy/Toledo Edison Company 1 Coal & Coke-Fired CFB Boiler Baghouse 99.0% Primary = Secondary= 7/31/2003Bayshore Plant 1764 MMBtu/hr 0.025 lb/MMBtu 193 tpy 04-1056Lucas County, OHno avg. no avgMT-0022 Bull Mountain Development Co. 2 Coal-Fired PC Boilers, No. 1, 2 fabric Filter 99.82% Primary = Secondary= 7/21/2003Roundup Power Project 390 MW (each); 4013 MMBtu/hr 0.015 lb/MMBtu limit may change to 3182-00Musselshell County, MT mine-mouth plant no avg. 0.012 lb/MMBtuIA-0067 Mid-American Energy Co. 1 Coal-Fired PC Boiler Baghouse 98.2% Primary = Secondary= 6/17/2003PRB coal 0.025 lb/MMBtu none listed Project 02-528Council 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= 10/8/2002Holcomb Unit #2 660 MW 0.018 lb/MMBtu none listed 0550087/C-3855Finney County, KSno avg.KY-0086 East Kentucky Power Coop, Inc. 1 Coal-Fired CFB Boiler Baghouse not given Primary = Secondary= 8/4/2002Spurlock Power Station 270 MW; 2500 MMBtu/hr 0.015 lb/MMBtu none listed V-97-050 (R1)Mason County, KY3-hr avgAtt 10-B_Coal Boilers_RBLC.xlsPM107/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for PM10Coal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.RBLC IDEmissionLimitMT-0027 Rocky Mountain Power, Inc. 1 Coal-Fired PC Boiler Multiclone w/ not given Primary = Secondary= 6/11/2002Hardin Generating Project 113 MW (nominal); 1304 MMBtu/hr Wet Scrubber 0.015 lb/MMBtu none listed 3185-00Big Horn County, MTno avg (Method 5)PA-0183 AES Beaver Valley, LLC 1 Coal-Fired CFB Boiler Baghouse not given Primary = Secondary= 11/21/20012155 MMBtu/hr 0.02 lb/MMBtu none listed PA-04-446CBeaver County, PAno avg.PR-0007 AES Puerto Rico Cogeneration Plant 2 Coal-Fired CFB Boilers ESP not given Primary = Secondary= 10/29/2001454 MW (net); 4923 MMBtu/hr 0.03 b/MMBtu 73.8 lb/hr 14Guyama, Puerto Rico Bituminous Coal; max 1% sulfur no avg no avgLA-0122 International Paper- Mansfield Mill 2 Coal Fired Boilers ESP 99.50% 0.10 lb/mmbtu 8/14/2001PSD-LA-93 (M-6)Mansfield, Louisiana 645 mmbtu/hr eachTX-0275 Reliant Energy 1 Coal Fired Boiler Fabric Filter not given 0.03 lb/mmbtu 12/21/2000W.A. Parish Electric Generating St.PSD-TX-234Thompsons, Texas 6700 mmbtu/hrTX-0275 Reliant Energy 1 Coal Fired Boiler, Unit 8 Fabric Filter not given Primary = Secondary= 12/21/2000W.A. Parish Electric Generating St. 6700 mmbtu/hr 0.03 lb/MMBtu 639 tpy PSD-TX-234Ft. Bend County, Texas Boiler also burns NG & Fuel Oil no avg. no avgMO-0050 Kansas City Power & Light Co. 1 Coal Fired PC Boiler Fabric Filter not given Primary = Secondary= 8/17/1999Hawthorn Station Tangentially Fired 0.018 lb/MMBtu none listed 888Kansas City, Missouri 384 T/H no avgFL-0178 JEA Northside Generating St. 2 Coal Fired CFB Boilers Fabric Filter not given Primary = Secondary= 7/14/1999297.5 MW; 2764 MMBtu/hr (each) or ESP 0.011 lb/MMBtu none listedPSD-FL-265Jacksonville, Florida3-hr avg (F only)MS-0036 Choctaw Generation L.P 2 Lignite-Fired CFB Boilers Baghouse not given Primary = Secondary= 8/25/19980.015 lb/MMBtu none listed 0400-00011Ackerman, 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= 6/30/19981500 mmbtu/hr (each) 0.030 lb/MMBtu none listed 98-A-507PLinn County, IA3-hr avg (F&C implied)IA-0051 Archer Daniels Midland Co. 1 Coal Fired CFB Boiler Baghouse not given Primary = Secondary= 6/30/19980.030 lb/MMBtu none listed 98-A-508PCedar Rapids, Iowa 1500 mmbtu/hr 3-hr avg (F&C implied)Att 10-B_Coal Boilers_RBLC.xlsPM107/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for PM10Coal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.RBLC IDEmissionLimitUT-0053 Deseret Generation & Transmission Co. 1 Coal-Fired PC Boiler Fabric Filter 99.8% Primary = Secondary= 3/16/1998500 MW 0.286 lb/MMBtu 0.018 gr/dscf DAQE-186-98Unitah County, UTno avg. no avgFL-0193 Central Power and Lime, Inc. 1 Coal Fired Boiler Good Combustion not given Primary = Secondary= 8/15/1995Practice 0.0135 25 PSD-FL-090DBrooksville, Florida 1850 mmbtu/hr lb/mmbtu lb/hrPA-0133 Mon Valley Energy Ltd. 1 Pulverized Coal Fired Boiler Fabric Filter 99.95% Primary = Secondary= 8/8/1995Partnership0.015 63.5 30-306-001Poland Mines, Pennsylvania966 mmbtu/hrlb/mmbtu tpyPA-0132 York County Energy Partners 1 Coal Fired CFB Boiler Fabric Filter 99.90% Primary = Secondary= 7/25/1995Spring Grove, Pennsylvania0.011 29 67-306-0072500 mmbtu/hrR lb/mmbtu lb/hrUT-0060 Deseret Generation & 1 Coal Fired Boiler Fabric Filter not given 0.03 lb/mmbtu 6/14/1995Transmission Co.DAQE-523-95Vernaz, Utah 4381 mmbtu/hrPA-0134 Northampton Generating Co. 1 Ahlstrom Coal Fired CFB Boiler Fabric Filter 99.98% Primary = Secondary= 4/14/19950.01 44.4 48-00021Northampton, Pennsylvania 1146 mmbtu/hr lb/mmbtu tpyMA-0028 Energy New Bedford 2 Coal Fired CFB Boilers Baghouse not given Primary = Secondary= 7/11/19940.018 31.64B90041New Bedford, Massachusetts 1671 mmbtu/hr each lb/mmbtu lb/hrNotes: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 BoilersAtt 10-B_Coal Boilers_RBLC.xlsPM107/10/2007Attachment 10-BRecently Issued PSD Permits not listed in Clearinghouse DatabaseBACT-PSD Sources for H2SO4Coal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.PA-0249River Hill Power Company, LLC 1 Waste Coal-Fired CFB Boiler Dry FGD System not given Primary = Secondary= 7/21/2005Clearfield County, PA0.010 lb/MMBtu 28.71 lb/hr 17-00055Ano avg no avgPA-0248Wellington Dev/Greene Energy 2 Waste Coal-Fired CFB Boilers Limestone Injection not given Primary = Secondary= 7/8/2005Resource Recovery Project 580 MW (gross) 525 MW (net) in CFB 0.006 lb/MMBtu none listed 30-00150AGreene County, PAno avgCO-0057 Xcel Energy (PSC of Colorado) 1 Coal-Fired PC Boiler, Unit #3 Lime Spray Dryer & 96% Primary = Secondary= 7/5/2005Comanche Power Station 750 MW (unit #3); 7421 MMBtu/hr Baghouse 0.0042 lb/MMBtu none listed 04UNITPB1015Pueblo, CO sub-bituminuous coal 3 test run avgND-0021Montana Dakota Utilities/Westmoreland 1 Lignite Fired CFB Boiler Limestone Injection plus not given Primary = Secondary= 6/3/2005Gascoyne Generating Station 220 MW (gross) 175 MW (net) Spray Dryer 0.0061 lb/MMBtu none listed PTC 05005Bowman County, ND3-hr rollingNV-0036Newmont Nevada Energy Investment LLC 1 Coal-Fired PC Boiler Spray Dry Scrubber & not given Primary = Secondary= 5/5/2005TS Power Plant 200 MW; 2030 MMBtu/hr Baghouse 2.06 lbs/hr none listed AP4911-1349Eureka County, NVno avgNE-0031Omaha Public Power District 1 Coal-Fired PC Boiler Dry FGD & Fabric Filter 90% Primary = Secondary= 3/9/2005Nebraska City Station Unit 2 boiler 660 MW (net) 0.0042 lb/MMBtu none listed 58343C01Otoe County, NE sub-bituminuous coal test avgMO-0060Springfield Utilities 1 Coal-Fired PC Boiler Dry FGD not given Primary = Secondary= 12/15/2004Southwest Power Station 275 MW; 2724 MMBtu/hr none listed none listed 122004-007Greene County, MOWI-0228Wisconsin Public Service Co. 1 Coal-Fired PC Boiler; supercritical Dry FGD not given Primary = Secondary= 10/19/2004WPS - Weston Plant 500 MW; 5173 MMBtu/hr 0.0050 lb/MMBtu none listed 04-RV-248Marathon County, WI PRB Coal; 8100 BTU/lb 24-hr avgUT-0065Intermountain Power Service Corp. 1 Coal-Fired PC Boiler Wet FGD & Baghouse 90% Primary = Secondary= 10/15/2004Generating Station Unit #3 950 MW (gross) 0.0044 lb/MMBtu none listed DAQE-AN0327010-04Millard County, UT Bituminous Coal or Blend 24-hr blockOK-0103 Weyerhaeuser 1 Coal-Fired CFB Boiler CFB with 90% Primary = Secondary= 10/13/2004Valliant Mill also burns combination of fuels Limestone Injection 0.0012 lb/MMBtu 0.0021 lb/MMBtu 97-057-C (M-4) PSDMcCurtain County, OKmonthly avg daily avgUT-0064Nevco-Sevier Power Company 1 Coal-Fired CFR Boiler Dry Lime Scrubber not given Primary = Secondary= 10/12/2004Sevier Power Plant 270 MW0.0024 lb/MMBtu none listed DAQE-AN2529001-04Sevier County, UT24-hr rollingRBLC IDEmissionLimitAtt 10-B_Coal Boilers_RBLC.xlsH2SO47/10/2007Attachment 10-BRecently Issued PSD Permits not listed in Clearinghouse DatabaseBACT-PSD Sources for H2SO4Coal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.RBLC IDEmissionLimitWV-0023Longview Power, LLC 1 Coal-Fired PC Boiler Dry Solid Injection w/ not given Primary = Secondary= 3/2/2004Maidsville 600 MW; 6114 MMBtu/hr Fabric Filter 0.0075 lb/MMBtu 45.8 lb/hr R14-0024Monongahela County, WV3-hr rolling no avgSC-0104Santee Cooper 2 Coal-Fired PC Boilers, #3 & #4 Wet FGD 95% Primary = Secondary= 2/5/2004Cross Generating Station Bituminous Coal & Pet Coke 0.0014 lb/MMBtu none listed 0420-0030-ClBerkeley County, SC 5700 MMBtu/hr (each) 365-day rollingAR-0074 Plum Point Associates, LLC 1 Coal-Fired PC Boiler, Unit 1 Dry FGD/Fabric Filter not given Primary = Secondary= 8/20/2003Plum Point Energy 800 MW0.0061 lb/MMBtu none listed 1995-AOP-R0Mississippi County, ARno avg.MT-0022 Bull Mountain Development Co. 2 Coal-Fired PC Boilers, No. 1, 2 Dry FGD System 90.0% Primary = Secondary= 7/21/2003Roundup Power Project 390 MW (each); 4013 MMBtu/hr 0.0064lb/MMBtu none listed 3182-00Musselshell County, MT mine-mouth plant no avgIA-0067 Mid-American Energy Co. 1 Coal-Fired PC Boiler Lime Spray Dryer 92% Primary = Secondary= 6/17/2003PRB coal Dry FGD 0.0042 lb/MMBtu none listed Project 02-528Council Bluffs, Iowa 7675 MMBtu/hr no avgKY-0084 Thoroughbred Generating Company, LLC 2 Coal-Fired PC Boilers ESP, Wet ESP, & not given Primary = Secondary= 10/11/2002Thoroughbred Generating Station 1500 MW (total); 7446 MMBtu/hr (ea) Wet FGD 4.97E-03 lb/MMBtu none listed V-02-001Muhlenburg County, KYno avgKY-0086 East Kentucky Power Coop, Inc. 1 Coal-Fired CFB Boiler Limestone Injection plus not given Primary = Secondary= 8/4/2002Spurlock Power Station 270 MW; 2500 MMBtu/hr Dry Lime Scrubber 0.005 lb/MMBtu none listed V-97-050 (R1)Mason County, KY30-day avgPR-0007 AES Puerto Rico Cogeneration Plant 2 Coal-Fired CFB Boilers Limestone Injection plus not given Primary = Secondary= 10/29/2001454 MW (net); 4923 MMBtu/hr Circulating Dry Scrubber 0.0024 lb/MMBtu 0.64 ppmvd@7% 14Guyama, Puerto Rico Bituminous Coal; max 1% sulfur no avg no avgKY-0079 Kentucky Mountain Power, LLC 2 Coal & Coal Refuse-Fired CFB Boilers Naturally Integrated not given Primary = Secondary= 5/4/2001Units 1 & 2 Desulfurization System 0.01 lb/MMBtu none listed V-00-045Knott County, KY 2550 MMBtu/hr no avg.TX-0275 Reliant Energy 1 Coal Fired Boiler, Unit 8 Fabric Filter & FGD not given Primary = Secondary= 12/21/2000W.A. Parish Electric Generating St. 6700 mmbtu/hr 0.0015 lb/MMBtu 40 tpy PSD-TX-234Ft. Bend County, Texas Boiler also burns NG & Fuel Oil no avg. no avgNotes: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 BoilersAtt 10-B_Coal Boilers_RBLC.xlsH2SO47/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for LeadCoal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.PA-0249River Hill Power Company, LLC 1 Waste Coal-Fired CFB Boiler Baghouse not given Primary = Secondary= 7/21/2005Clearfield County, PA1.4 lb/TBtu 34.0 lbs/yr 17-00055A12-month rolling 12-month rollingPA-0248Wellington Dev/Greene Energy 2 Waste Coal-Fired CFB Boilers Baghouse 90.0% Primary = Secondary= 7/8/2005Resource Recovery Project 580 MW (gross) 525 MW (net) 0.0007 lb/MMBtu 15.7 tpy 30-00150AGreene County, PAno avg 12-month rollingPA-0247Robinson Power Company LLC 1 Waste Coal-Fired CFB Boiler Baghouse not given Primary = Secondary= 4/1/2005Beech Hollow Power Project 272 MW (net); 2800 MMBtu/hr 0.014 lb/hr 0.06 tpy 63-00922AWashington County, PAno avg. no avgMO-0060Springfield Utilities 1 Coal-Fired PC Boiler Baghouse not given Primary = Secondary= 12/15/2004Southwest Power Station 275 MW; 2724 MMBtu/hr 0.31 ton/yr none listed 122004-007Greene County, MOno avg.WI-0228Wisconsin Public Service Co. 1 Coal-Fired PC Boiler; supercritical Fabric Filter not given Primary = Secondary= 10/19/2004WPS - Weston Plant 500 MW; 5173 MMBtu/hr 0.13 lb/hr none listed 04-RV-248Marathon County, WI PRB Coal; 8100 BTU/lbUT-0065Intermountain Power Service Corp. 1 Coal-Fired PC Boiler Baghouse not given Primary = Secondary= 10/15/2004Generating Station Unit #3 950 MW (gross) 0.0 lb/MMBtu none listed DAQE-AN0327010-04Millard County, UT Bituminous Coal or Blend 3 test run avgWV-0023Longview Power, LLC 1 Coal-Fired PC Boiler Fabric Filter 99.0% Primary = Secondary= 3/2/2004Maidsville 600 MW; 6114 MMBtu/hr 0.109 lb/hr none listed R14-0024Monongahela County, WV3-hr rollingSC-0104Santee Cooper 2 Coal-Fired PC Boilers, #3 & #4 ESP 99.75% Primary = Secondary= 2/5/2004Cross Generating Station Bituminous Coal & Pet Coke 1.69E-05 lb/MMBtu 0420-0030-ClBerkeley County, SC 5700 MMBtu/hr (each) no avg. none listedTX-0298 Reliant Energy Inc. 3 Coal Fired Boilers, Units 5 ,6, 7 None Indicated not given Primary = Secondary= 10/15/2003WA Parish Electric Generating St. Units 5 & 6 @ 7400 mmbtu/hr 0.43, 0.37 0.17, 0.15 PSD-TX-901,Houston, TX Unit 7 @ 6700 mmbtu/hr lb/hr tpy -902 & -33M1AR-0074 Plum Point Associates, LLC 1 Coal-Fired PC Boiler, Unit 1 Fabric Filter not given Primary = Secondary= 8/20/2003Plum Point Energy 800 MW 2.56E-05 lb/MMBtu none listed 1995-AOP-R0Mississippi County, ARno avg.RBLC IDEmissionLimitAtt 10-B_Coal Boilers_RBLC.xlsLead7/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for LeadCoal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.RBLC IDEmissionLimitIA-0067 Mid-American Energy Co. 1 Coal-Fired PC Boiler Baghouse 99.0% Primary = Secondary= 6/17/2003PRB coal 2.6E-05 lb/MMBtu none listed Project 02-528Council Bluffs, Iowa 7675 MMBtu/hr no avgTX-0342 Reliant Energy Inc. 2 Coal Fired Boilers None Indicated not given Primary = Secondary= 5/23/2001Limestone Electric Generating St.0.26 0.46 P371 (M3)Houston, TX 7863 mmbtu/hr each lb/hr tpyKY-0086 East Kentucky Power Coop, Inc. 1 Coal-Fired CFB Boiler Baghouse not given Primary = Secondary= 8/4/2002Spurlock Power Station 270 MW; 2500 MMBtu/hr 6.30E-06 lb/MMBtu none listed V-97-050 (R1)Mason County, KYno avgKY-0079 Kentucky Mountain Power, LLC 2 Coal & Coal Refuse-Fired CFB Boilers Baghouse not given Primary = Secondary= 5/4/2001Units 1 & 2 1.94E-04 lb/MMBtu none listed V-00-045Knott County, KY 2550 MMBtu/hr no avg.TX-0275 Reliant Energy 1 Coal Fired Boiler, Unit 8 Fabric Filter not given Primary = Secondary= 12/21/2000W.A. Parish Electric Generating St. 6700 mmbtu/hr 0.33 lb/hr 0.13 tpy PSD-TX-234Ft. Bend County, Texas Boiler also burns NG & Fuel Oil no avg. no avgIA-0046 Archer Daniels Midland Company 2 Coal-Fired CFB Boiler, Unit #5, #6 Baghouse not given Primary = Secondary= 6/30/19981500 mmbtu/hr (each) 0.0002 lb/MMBtu none listed 98-A-507PLinn County, IA3-month avgIA-0051 Archer Daniels Midland Co. 1 Coal Fired CFB Boiler Baghouse not given Primary = Secondary= 6/30/19980.0002 lb/MMBtu none listed 98-A-508PCedar Rapids, Iowa 1500 mmbtu/hr 3-month avgAtt 10-B_Coal Boilers_RBLC.xlsLead7/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for LeadCoal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.RBLC IDEmissionLimitMA-0028 Energy New Bedford 2 Coal Fired CFB Boilers None Indicated not given 4.70E-07 lb/mmbtu 7/11/19944B90041New Bedford, Massachusetts 1671 mmbtu/hr eachFL-0255 Cedar Bay Generating Co., LP 3 Pulverized Coal Fired CFB Boilers None Indicated not given 6.03E-05 lb/mmbtu 11/16/1993Ceder Bay CogenerationPSD-FL-137AJacksonville, Florida 132 mmbtu/hr eachVA-0213 SEI Birchwood, Inc. 1 Pulverized Coal Fired Boiler Baghouse 95% Primary = Secondary= 8/23/19930.2 0.9 40809Sealston, Virginia 2200 mmbtu/hr lb/hr tpyMA-0009 Energy New Bedford 2 Coal Fired CFB Boilers Baghouse not given 1.60E-03 lb/hr 4/30/1993Cogeneration Facility4B90041New Bedford, Massachusetts 3342 mmbtu/hrMA-0011 Taunton Energy Center 1 Coal Fired CFB Boiler Baghouse not given 3.50E-05 lb/mmbtu 4/30/19934B91044Taunton, Massachusetts 1604.4 mmbtu/hrPA-0058 North Branch Energy Partners, LP 1 Coal Fired CFB Boiler None Indicated not given 2.30E-03 lb/mmbtu 1/25/199363-306-004AMcDonald, Pennsylvania 563.5 mmbtu/hrNotes: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 BoilersAtt 10-B_Coal Boilers_RBLC.xlsLead7/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for FluoridesCoal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.MO-0071Great Plains Energy 2 Coal-Fired Boiler - Unit 1 None Indicated n/a Primary = Secondary= 1/27/2006Iatan Station 7800 MMBtu/hr 33.15 lb/hr none listed 012006-019Platte County, MO sub-bituminuous coal no avgPA-0249River Hill Power Company, LLC 1 Waste Coal-Fired CFB Boiler Spray Dry Absorber not given Primary = Secondary= 7/21/2005Clearfield County, PAwith Limestone Inj. 0.0014 lb/MMBtu 18.09 tpy 17-00055Ano avg. 12-month rollingPA-0248Wellington Dev/Greene Energy 2 Waste Coal-Fired CFB Boilers Boiler Control & 95.0% Primary = Secondary= 7/8/2005Resource Recovery Project 580 MW (gross) 525 MW (net) SDA/FDA 0.0014 lb/MMBtu 33.0 tpy 30-00150AGreene County, PAno avg 12-month rollingCO-0057 Xcel Energy (PSC of Colorado) 1 Coal-Fired PC Boiler, Unit #3 Lime Spray Dryer & 94% Primary = Secondary= 7/5/2005Comanche Power Station 750 MW (unit #3); 7421 MMBtu/hr Baghouse 0.0005 lb/MMBtu none listed 04UNITPB1015Pueblo, CO sub-bituminuous coal 3 test run avgND-0021Montana Dakota Utilities/Westmoreland 1 Lignite Fired CFB Boiler Limestone Injection plus not given Primary = Secondary= 6/3/2005Gascoyne Generating Station 220 MW (gross) 175 MW (net) Spray Dryer 0.0005 lb/MMBtu none listed PTC 05005Bowman County, ND3-hr rollingNV-0036Newmont Nevada Energy Investment LLC 1 Coal-Fired PC Boiler Spray Dry Scrubber & not given Primary = Secondary= 5/5/2005TS Power Plant 200 MW; 2030 MMBtu/hr Baghouse 1.17 lbs/hr none listed AP4911-1349Eureka County, NVno avgNE-0031Omaha Public Power District 1 Coal-Fired PC Boiler Dry FGD & Fabric Filter 90% Primary = Secondary= 3/9/2005Nebraska City Station Unit 2 boiler 660 MW (net) 0.004 lb/MMBtu none listed 58343C01Otoe County, NE sub-bituminuous coal test avgWI-0228Wisconsin Public Service Co. 1 Coal-Fired PC Boiler; supercritical Dry FGD & Fabric Filter not given Primary = Secondary= 10/19/2004WPS - Weston Plant 500 MW; 5173 MMBtu/hr 0.0002 lb/MMBtu 1.12 lb/hr 04-RV-248Marathon County, WI PRB Coal; 8100 BTU/lb no avg no avgUT-0065Intermountain Power Service Corp. 1 Coal-Fired PC Boiler Wet FGD not given Primary = Secondary= 10/15/2004Generating Station Unit #3 950 MW (gross) 0.0005 lb/MMBtu none listed DAQE-AN0327010-04Millard County, UT Bituminous Coal or Blend 3 test run avgUT-0064Nevco-Sevier Power Company 1 Coal-Fired CFR Boiler Dry Lime Scrubber & not given Primary = Secondary= 10/12/2004Sevier Power Plant 270 MW Baghouse 0.0050 lb/MMBtu none listed DAQE-AN2529001-04Sevier County, UTno avgNE-0018Hastings Utilities 1 Unit 2 Coal-Fired Boiler Spray Dryer Absorber, not given Primary = Secondary= 3/30/2004Whelan Energy Center 220 MW; 2210 MMBtu/hr PM controls 0.0004 lb/MMBtu none listed 58048Adams County, NE3-hr avgWV-0023Longview Power, LLC 1 Coal-Fired PC Boiler Dry Sorbent Injection w/ not given Primary = Secondary= 3/2/2004Maidsville 600 MW; 6114 MMBtu/hr Fabric Filter 0.0001 lb/MMBtu none listed R14-0024Monongahela County, WV3-hr rollingSC-0104Santee Cooper 2 Coal-Fired PC Boilers, #3 & #4 Wet FGD 95% Primary = Secondary= 2/5/2004Cross Generating Station Bituminous Coal & Pet Coke 0.0003 lb/MMBtu none listed 0420-0030-ClBerkeley County, SC 5700 MMBtu/hr (each) 365-day rollingTX-0298 Reliant Energy Inc. 3 Coal Fired Boilers, Units 5 ,6, 7 None Indicated not given Primary = Secondary= 10/15/2003WA Parish Electric Generating St. Units 5 & 6 @ 7400 mmbtu/hr 128, 111 104, 91 PSD-TX-901,Houston, TX Unit 7 @ 6700 mmbtu/hr lb/hr tpy -902 & -33M1AR-0074 Plum Point Associates, LLC 1 Coal-Fired PC Boiler, Unit 1 Dry FGD/Fabric Filter 90% Primary = Secondary= 8/20/2003Plum Point Energy 800 MW0.0004 lb/MMBtu none listed 1995-AOP-R0Mississippi County, ARno avg.RBLC IDEmissionLimitAtt 10-B_Coal Boilers_RBLC.xlsFluorides7/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for FluoridesCoal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.RBLC IDEmissionLimitIA-0067 Mid-American Energy Co. 1 Coal-Fired PC Boiler Lime Spray Dryer 95% Primary = Secondary= 6/17/2003PRB coal Dry FGD 0.0009 lb/MMBtu none listed Project 02-528Council Bluffs, Iowa 7675 MMBtu/hr no avgTX-0342 Reliant Energy Inc. 2 Coal Fired Boilers None Indicated not given Primary = Secondary= 5/23/2001Limestone Electric Generating St.81.4 87.40 P371 (M3)Houston, TX 7863 mmbtu/hr each lb/hr tpyKY-0084 Thoroughbred Generating Company, LLC 2 Coal-Fired PC Boilers Wet ESP, & FGD not given Primary = Secondary= 10/11/2002Thoroughbred Generating Station 1500 MW (total); 7446 MMBtu/hr (ea) 1.59E-04 lb/MMBtu none listed V-02-001Muhlenburg County, KYno avgKY-0086 East Kentucky Power Coop, Inc. 1 Coal-Fired CFB Boiler Baghouse not given Primary = Secondary= 8/4/2002Spurlock Power Station 270 MW; 2500 MMBtu/hr 4.66E-05 lb/MMBtu none listed V-97-050 (R1)Mason County, KY30-day rollingPR-0007 AES Puerto Rico Cogeneration Plant 2 Coal-Fired CFB Boilers Limestone Injection plus not given Primary = Secondary= 10/29/2001454 MW (net); 4923 MMBtu/hr Circulating Dry Scrubber 0.0005 lb/MMBtu 1.18 lb/hr 14Guyama, Puerto Rico Bituminous Coal; max 1% sulfur no avg no avgKY-0079 Kentucky Mountain Power, LLC 2 Coal & Coal Refuse-Fired CFB Boilers Baghouse not given Primary = Secondary= 5/4/2001Units 1 & 20.0053 lb/MMBtu none listed V-00-045Knott County, KY 2550 MMBtu/hr no avg.TX-0275 Reliant Energy 1 Coal Fired Boiler, Unit 8 Fabric Filter & FGD not given Primary = Secondary= 12/21/2000W.A. Parish Electric Generating St. 6700 mmbtu/hr 0.005 lb/MMBtu 29.3 tpy PSD-TX-234Ft. Bend County, Texas Boiler also burns NG & Fuel Oil no avg. no avgIA-0046 Archer Daniels Midland Company 2 Coal-Fired CFB Boiler, Unit #5, #6 Baghouse not given Primary = Secondary= 6/30/19981500 mmbtu/hr (each) 0.0012 lb/MMBtu none listed 98-A-507PLinn County, IA3-month avgIA-0051 Archer Daniels Midland Co. 1 Coal Fired CFB Boiler Baghouse not given Primary = Secondary= 6/30/19980.0012 lb/MMBtu none listed 98-A-508PCedar Rapids, Iowa 1500 mmbtu/hr 3-month avgMA-0028 Energy New Bedford 2 Coal Fired CFB Boilers None Indicated not given 2.80E-03 lb/mmbtu 7/11/19944B90041New Bedford, Massachusetts 1671 mmbtu/hr eachFL-0255 Cedar Bay Generating Co., LP 3 Pulverized Coal Fired CFB Boilers None Indicated not given 7.44E-04 lb/mmbtu 11/16/1993Ceder Bay CogenerationPSD-FL-137AJacksonville, Florida 132 mmbtu/hr eachVA-0213 SEI Birchwood, Inc. 1 Pulverized Coal Fired Boiler None Indicated not given Primary = Secondary= 8/23/19933.6 8.28 40809Sealston, Virginia 2200 mmbtu/hr lb/hr tpyPA-0058 North Branch Energy Partners, LP 1 Coal Fired CFB Boiler None Indicated not given 1.40E-03 lb/mmbtu 1/25/199363-306-004AMcDonald, Pennsylvania 563.5 mmbtu/hrNotes: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 BoilersAtt 10-B_Coal Boilers_RBLC.xlsFluorides7/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for MercuryCoal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.PA-0249River Hill Power Company, LLC 1 Waste Coal-Fired CFB Boiler not given not given Primary = Secondary= 7/21/2005Clearfield County, PA17.4 lbs/yr -- 17-00055A19% run-of-mine coalPA-0248Wellington Dev/Greene Energy 2 Waste Coal-Fired CFB Boilers not provided not given Primary = Secondary= 7/8/2005Resource Recovery Project 580 MW (gross) 525 MW (net) 20.05 lbs/yr 30-00150AGreene County, PAno avgMO-0060Springfield Utilities 1 Coal-Fired PC Boiler not provided not given Primary = Secondary= 12/15/2004Southwest Power Station 275 MW; 2724 MMBtu/hr 0.09 ton/yr none listed 122004-007Greene County, MOno avg.WI-0228Wisconsin Public Service Co. 1 Coal-Fired PC Boiler; supercritical Fabric Filter & Sorbent Injection 83% Primary = Secondary= 10/19/2004WPS - Weston Plant 500 MW; 5173 MMBtu/hr 1.7 lb/Trillion BTU none listed 04-RV-248Marathon County, WI PRB Coal; 8100 BTU/lb 12-mo rollingUT-0065Intermountain Power Service Corp. 1 Coal-Fired PC Boiler Wet FGD, Baghouse & SCR not given Primary = Secondary= 10/15/2004Generating Station Unit #3 950 MW (gross)0.0 lb/MW-hr none listed DAQE-AN0327010-04Millard County, UT Bituminous Coal or Blend 3 test run avgUT-0064Nevco-Sevier Power Company 1 Coal-Fired CFR Boiler Dry Lime Scrubber & not given Primary = Secondary= 10/12/2004Sevier Power Plant 270 MW Baghouse 0.00 lb/MMBtu none listed DAQE-AN2529001-04Sevier County, UTno avgWV-0023Longview Power, LLC 1 Coal-Fired PC Boiler SCR ,Dry Sorbent Injection w/ not given Primary = Secondary= 3/2/2004Maidsville 600 MW; 6114 MMBtu/hr Fabric Filter & 0.0146 lb/hr 0.0638 tpy R14-0024Monongahela County, WV Limestone Forced Oxidation 3-hr rolling 12-month rollingSC-0104Santee Cooper 2 Coal-Fired PC Boilers, #3 & #4 ESP, Wet FGD, SCR & not given Primary = Secondary= 2/5/2004Cross Generating Station Bituminous Coal & Pet Coke Low-NOx burners 3.6E-06 lb/MMBtu none listed 0420-0030-ClBerkeley County, SC 5700 MMBtu/hr (each) no avgIA-0067 Mid-American Energy Co. 1 Coal-Fired PC Boiler Activated Carbon 83.0% Primary = Secondary= 6/17/2003PRB coal1.7E-06 lb/MMBtu none listed Project 02-528Council Bluffs, Iowa 7675 MMBtu/hrno avg.KY-0084 Thoroughbred Generating Company, LLC 2 Coal-Fired PC Boilers ESP, Wet ESP, & not given Primary = Secondary= 10/11/2002Thoroughbred Generating Station 1500 MW (total); 7446 MMBtu/hr (ea) Wet FGD 3.21E-06 lb/MMBtu none listed V-02-001Muhlenburg County, KYno avgKY-0086 East Kentucky Power Coop, Inc. 1 Coal-Fired CFB Boiler Baghouse not given Primary = Secondary= 8/4/2002Spurlock Power Station 270 MW; 2500 MMBtu/hr 2.65E-06 lb/MMBtu none listed V-97-050 (R1)Mason County, KYno avgKY-0079 Kentucky Mountain Power, LLC 2 Coal & Coal Refuse-Fired CFB Boilers Baghouse not given Primary = Secondary= 5/4/2001Units 1 & 28.10E-05 lb/MMBtu none listed V-00-045Knott County, KY 2550 MMBtu/hrno avg.TX-0275 Reliant Energy 1 Coal Fired Boiler, Unit 8 Fabric Filter & FGD not given Primary = Secondary= 12/21/2000W.A. Parish Electric Generating St. 6700 mmbtu/hr1.71 lb/hr 0.24 tpy PSD-TX-234Ft. Bend County, Texas Boiler also burns NG & Fuel Oil no avg. no avgNotes: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 BoilersRBLC IDEmissionLimitAtt 10-B_Coal Boilers_RBLC.xlsMercury7/10/2007Attachment 10-BNSR RACT/BACT/LAER Clearinghouse DatabaseBACT-PSD Sources for Hydrogen ChlorideCoal Fired BoilersCompany Name No. of Unit & Control Control Permit Date andand Location Units Size Technology Efficiency Permit No.PA-0249River Hill Power Company, LLC 1 Waste Coal-Fired CFB Boiler Spray Dry Absorber not given Primary = Secondary= 7/21/2005Clearfield County, PA with Limestone Inj. 0.0034 lb/MMBtu 42.2 tpy 17-00055Ano avg 12-month rollingPA-0248Wellington Dev/Greene Energy 2 Waste Coal-Fired CFB Boilers not provided not given Primary = Secondary= 7/8/2005Resource Recovery Project 580 MW (gross) 525 MW (net) 0.0067 lb/MMBtu 30-00150AGreene County, PAno avgWI-0228Wisconsin Public Service Co. 1 Coal-Fired PC Boiler; supercritical Dry FGD not given Primary = Secondary= 10/19/2004WPS - Weston Plant 500 MW; 5173 MMBtu/hr 10.94 lb/hr none listed 04-RV-248Marathon County, WI PRB Coal; 8100 BTU/lb 24-hr avgUT-0065Intermountain Power Service Corp. 1 Coal-Fired PC Boiler Wet FGD not given Primary = Secondary= 10/15/2004Generating Station Unit #3 950 MW (gross) 38.13 lb/hr none listed DAQE-AN0327010-04Millard County, UT Bituminous Coal or Blend 3 test run avgUT-0064Nevco-Sevier Power Company 1 Coal-Fired CFR Boiler Dry Lime Scrubber & not given Primary = Secondary= 10/12/2004Sevier Power Plant 270 MW Baghouse 4.01 lb/hr none listed DAQE-AN2529001-04Sevier County, UTno avgWV-0023Longview Power, LLC 1 Coal-Fired PC Boiler Dry Sorbent Injection w/ not given Primary = Secondary= 3/2/2004Maidsville 600 MW; 6114 MMBtu/hr Fabric Filter 0.0001 lb/MMBtu none listed R14-0024Monongahela County, WV3-hr rollingSC-0104Santee Cooper 2 Coal-Fired PC Boilers, #3 & #4 Wet FGD 95% Primary = Secondary= 2/5/2004Cross Generating Station Bituminous Coal & Pet Coke 0.0024 lb/MMBtu none listed 0420-0030-ClBerkeley County, SC 5700 MMBtu/hr (each) no avgIA-0067 Mid-American Energy Co. 1 Coal-Fired PC Boiler Lime Spray Dryer 92% Primary = Secondary= 6/17/2003PRB coal Dry FGD 0.0029 lb/MMBtu none listed Project 02-528Council Bluffs, Iowa 7675 MMBtu/hr no avgNotes: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 BoilersRBLC IDEmissionLimitAtt 10-B_Coal Boilers_RBLC.xlsHCl7/10/2007

# ATTACHMENT 10-C

EPA REGION IV COAL-FIR ED POWER PLANT LISTINGRegion/State Company City (County) General Project DescriptionAddedCapacity(MWe)Date ofApplicationOperationalStartup Date BACT-LAER-112(g) StandardsBACT-LAER-112(g) ControlTechniquesEPA Region 1Connecticut NoneMaine NoneNew Hampshire NoneRhode Island NoneVermont NoneEPA Region 2New Jersey NoneNew York NonePuerto Rico NoneVirgin Islands NoneATTACHMENT 10-CEPA Region IV Summary of BACT Determinations for Coal Fired Power Plants (March 2005)ATTACHMENT 10-CEPA 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-applicationOnlyPennsylvania Reliant Energy,Seward Power Plant(Indiana) CFB boiler to replace existing unit, online by 2004520 30-Sep-00 NOx-0.15lb/mmBtu SNCRPennsylvania Greene Energy(WellingtonDevelopment)Greene Wellington Development of Fairmont,WV is proposing to build a 525 MWcoal mine waste fueled ResourceRecovery power project in GreenCounty, Pennsylvania. The resultingproject will be one of the cleanestsolid fuel burning facilities in theworld, utilizing state-of-the-artcirculating fluidized bed combustiontechnology (CFBC).525 2414 TPY NOx @.10 lb /mmbtu1207 TPY pm10@.5 lb/mmbtu5649 TPY SO2@.234lb/mmbtu.314 TPY Hg145 TPY H2SO4Filter Baghouse for PM,(CFB)Boiler and Dry SO2 Scrubberfor SO2 ,(SNCR) and CFBBoiler for reducing NOxPennsylvania River Hill PowerFacilityClearfield CIRCULATING FLUIDIZED BEDBOILER290 preapp 1300 TPY NOx, (bact),65 TPY VOCS(-LAER),CO 1900 TPY,.PM-10 150 TPY, H2SO4 50 TPY,4300 TPY SO2SNCR - NOX, BAGHOUSEPM10, LIMESTONEINJECTION-SO2Pennsylvania Beach Hollow Project Washington CIRCULATING FLUIDIZED BEDBOILER250 3018 TPY, SO2; 232 TPY PM-10;696 TPY NOXPennsylvania AES Beaver Valley AES proposes to install a new2,155MMBTU/HR CFB boiler and atthe same time retire four existingpulverized coal boilers. This newconfiguration will generateapproximate 180 MW, compared tothe current 125 MW.180 09-May-01 NOx-0.15lb/mmBtu SNCRVirginia NoneWest Virginia Longview Power, LLC Longview has proposed to construct a600 megawatt (MW) (net) powergeneration facility with interconnectionto Allegheny Energy Supply Companylines. The pulverized coalsupercritical boiler burning 2.5percent sulfur (nominal) bituminouscoal would operate with a oncethrough, balanced draft, single reheatsteam turbine/generator. A naturalgas-fired auxiliary boiler would beused to supply startup steam to themain boiler.600 NOx-0.08 lb/MMBtu, SO2 -0.15lb/MMBtu, PM-0.018 lb/MMBtu, CO- 0.11lb/MMBtu, H2SO4-0.0075lb/MMBtu, Hg-6.38x10e-2 TPYNOx burners and selectivecatalytic reductionWest Virginia Anker Circulating Fluidized Bed Boiler 1000 Pre-applicationOnlyATTACHMENT 10-CEPA Region IV Summary of BACT Determinations for Coal Fired Power Plants (March 2005)EPA Region 4Alabama NoneFlorida Tampa ElectricCompany- Polk PowerMulberry (Polk) 1994 PSD permit allowed constructionof an Integrated GasificationCombined Cycle (IGCC) plant. Thepermit required a NOx BACTevaluation based on data gatheredfrom the plant's operation to besubmitted 12-18 months afteroperation began. On May 10, 2001,the permitting agency issued aproposed BACT determination torequire SCR. Tampa Electricappealed the determination, and SCRwas not required in final permit.N/A 05-Dec-00 NOx - 15 ppm (syngas), 42 ppm(fuel oil)NOx - DLNFlorida JEA NorthsideGenerating StationJacksonville(Duval)Construct two new 297.5 MW CFBboilers as a repowering project toreplace two existing boilers.Allowable fuels include coal andpetroleum 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-0.03lb/hr (6-hr). [Note: Project nets outof review for SO2. SO2 emissionlimits are 0.20 lb/mmBtu (24-hr) and0.15 lb/mmBtu (30-day). Project notsubject to PSD review for SAM andPb. SAM emission limit is 1.1 lb/hr(3-hr). Pb emission limit is 0.07 lb/hr(3-hr).]NOx-CFB+SNCR, PM/PM10-FF, CO-GCP, VOC-GCP, HgCFB+FF, HF-CFB+polishingscrubber. [Note: Project notsubject to BACT for SO2, SAM,and Pb. Emission controlmethod for SO2 and SAM isCFB+polishing scrubber.Emission control for Pb is FF.]Georgia Longleaf EnergyAssociates, LLC (LSPower Development,LLC)(Early) Construct 2 new pulverized coalboilers (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-0.15lb/mmbtu (30-day), VOC-0.006lb/mmbtu (30-day), fluorides (as HF)-0.0024 lb/mmbtu (PRB) or 0.0031lb/mmbtu (CAPP), SAM-0.005lb/mmbtu (30-day), Hg-0.000006lb/MWh (CAPP) or 0.000020lb/MWh (PRB)NOx-LNB+OFA+SCR, SO2-DryScrubber, PM/PM10-Baghouse,CO-GCP, VOC-GCP,fluoridesDry Scrubber+Baghouse, SAMDry Scrubber+Baghouse, HgDry Scrubber+BaghouseATTACHMENT 10-CEPA Region IV Summary of BACT Determinations for Coal Fired Power Plants (March 2005)Kentucky Kentucky MountainPower, LLCAry (Knott) Construct coal-refuse-fired CFBboilers500 19-Apr-00 NOx-0.07 lb/mmbtu, CO-0.27lb/mmbtu, PM-0.015 lb/mmbtu, VOC0.0072 lb/mmbtu, SO2-0.13lb/mmbtu, SAM-0.010 lb/mmbtu, Be0.0000217 lb/mmbtu, Hg-0.000081lb/mmbtu, Pb-0.000194 lb/mmbtu,HF-0.0053 lb/mmbtuNOx-SNCR, CO-GCP, PMBaghouse, VOC-CFB Design,SO2-NIDS, SAM-CFB Design,Be-Baghouse, Hg-Baghouse,Pb-Baghouse, HF-BaghouseKentucky Kentucky EasternPower, LLC(Martin)Construct 2 new fluidized bedcombustors. [Project on hold as ofFeb 2003]; 500 MWeKentucky ThoroughbredGenerating Company,LLC (Peabody Energy)Graham(Muhlenberg)Construct an electric generatingfacility with 2 pulverized coal boilers(750 MWe each)1500 28-Feb-01;completerevised appl. 26-Oct-01NOx-0.08 lb/mmbtu (30-day), CO0.1 lb/mmbtu (30-day), PM-0.018lb/mmbtu (3-hr), VOC-0.0072lb/mmbtu (30-day), SO2-0.167lb/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-caseMACT limits in tpy for VOC, Hg, HCl,HF A B C M Pb CdNOx-LNB/SCR, CO-GCP, PMESP/wet ESP, VOC-GCP, SO2-wet limestone FGD, SAMFGD/wet ESP, Be-Baghouse,Hg-baghouse/FGD, HF-FGDKentuckyKentucky PioneerEnergyTrapp (Clark)Construct integrated gasificationsystem producing synthetic gas(syngas) to combust for electricitygeneration.54031-Jan-00Draft Permit: NOx-0.072 lb/mmbtu,CO-0.032 lb/mmbtu, PM-0.011lb/mmbtu, VOC-0.0044 lb/mmbtu,SO2-0.032 lb/mmbtu, SAM-0.010lb/mmbtu, Be-6.0 e-7 lb/mmbtu, Hg0.08 mg/dscf, Pb-0.02 mg/dscfDraft Permit: NOx-Diluent Inj.(steam), CO-GCP, PM-GCP,VOC-GCP, SO2-SulfurRecovery Unit, Be-GCP, HgGCP, Pb-GCPKentuckyCalla EnergyIrvine (Estill)Construct atmospheric fluidized-bedcombustion circulating-bed boilerwhich will co-fire waste coal andsyngas (from coal & biomass gasifier);110 MWe04/25/01;completerevised appl.10/01Proposed: NOx-0.07 lb/mmbtu, CO0.15 lb/mmbtu, PM-0.015 lb/mmbtu,SO2-0.15 lb/mmbtu (avg)/0.46lb/mmbtu (max), SAM-0.002lb/mmbtu, Be-0.000002.1 lb/mmbtu,Fluorides (as HF)-0.0023 lb/mmbtuProposed: NOx-AFBCdesign/SCR, CO-GCP, PM-FF,SO2-AFBC design, SAM-FF, Be-/FF, Fluorides-AFBC design/FFKentuckyKentucky WesternPower, LLCCalvert City(Marshall)Construct 2 new fluidized bedcombustors. [Project on hold as ofFeb 2003]; 500 MWe13-Jun-01[Project on hold as of Feb 2003]Kentucky East Kentucky PowerCooperative, SpurlockGenerating StationMaysville(Mason)Construct 1 new circulating fluidizedbed boiler270 24-Apr-01 NOx-0.07 lb/mmbtu (30-day), CO0.15 lb/mmbtu (30-day), PM-0.015lb/mmbtu (3-hr), SO2-0.20 lb/mmbtu(24-hr), SAM-0.0050 lb/mmbtu (alsosee comments)Proposed: NOx-SNCR, COGCP, PM-Baghouse, SO2-CFBdesign/dry lime scrubber, SAMCFB design/dry lime scrubber(also see comments)Kentucky East Kentucky PowerCooperative, SpurlockGenerating Station(Unit 4)Maysville(Mason)Construct 1 new circulating fluidizedbed boiler300 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-0.0050lb/mmbtu (?-hr), Hg-0.0000026lb/mmBtu (also see comments)Proposed: NOx-SNCR, COGCP, PM/PM10-Baghouse,SO2-CFB design/dry limescrubber, SAM-CFB design/drylime scrubber, VOC-nothingproposed, Hg-Baghouse (alsosee comments)KentuckyCash Creek(Henderson)Pulverized coal boilers, 1000 MWe[See comment]Kentucky Cash CreekGeneration, LLC(Henderson) Construct 2 new pulverized coalboilers (500 MW each)1,000 25-Nov-03revised(see comments) (see comments)Kentucky Louisville Gas &Electric Company(LG&E), TrimbleCounty GeneratingStation(Trimble) Construct 1 new pulverized coal boiler(750 MW)750 01-Dec-04revisedProposed: CO-0.10 lb/mmbtu (3-hr),PM/PM10-0.0018 lb/mmbtu (3-hr),SAM-26.6 lb/hr (3-hr), VOC-0.0032lb/mmbtu (3-hr), fluorides-no rateproposed, Hg-no rate proposedProposed: CO-GCP, PM/PM10-Baghouse, SAM-Wet ESP,VOC-GCP, fluorides-wet FGD,Hg-SCR+Baghouse+Wet FGD(also see comments)ATTACHMENT 10-CEPA Region IV Summary of BACT Determinations for Coal Fired Power Plants (March 2005)Kentucky Estill County EnergyPartnersIrvine (Estill) Construct 1 new circulating fluidizedbed boiler. Fuel will be waste easternbituminous 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% removalProposed: SO2-inherent CFBandn polishing dry scrubber,PM/PM10 - baghouse, NOxinherent CFB and SNCR, COGCP, VOC-GCP, H2SO4-inherent CFB and dry scrubberand baghouse; Hg-co-benefitfrom BACT controlsMississippi Tractebel Power Inc Choctaw Lignite Fired 462 (see comments) (see comments)North Carolina NoneSouth Carolina Santee Cooper, CrossGenerating StationCross(Berkeley)Existing electric generating facility tobe expanded with addition of twopulverized coal boilers (660 MWeeach).1,320 [See comment(1)]PM (filterable only)-0.015 lb/mmBtu(3-hr), PM10 (filterable andcondensible)-0.018 lb/mmBtu (3-hr),CO-0.16 lb/mmBtu (3-hr), VOC0.0024 lb/mmBtu (3-hour), Pb0.0000169 lb/mmBtu, Hg-0.0000036lb/mmBtu [See comments (2), (3),(4)]PM/PM10-dry ESP, CO-GCP,VOC-GCP, Pb-dry ESP, HgSCR, dry ESP, wet FGD [Seecomment (2)]Tennessee NoneATTACHMENT 10-CEPA 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/mmBtuCFB w/sorbent injection,baghousesIllinois Southern Illinois PowerCooperative, MarionPower Station(Williamson) 1st Project - 1 CFB boiler to replace 3existing coal fired generating units.2nd Project - 2 simple cyclecombustion turbines. 3rd ProjectInstallation of SCR on existing coalfired boiler120 12-Jul-00 CO-0 .015lb/mmBtu Combustion ControlsIllinois Cornbelt Energy Elkhart (Logan) Prairie Energy Power Plant. PSD forlow-emitting power plant.91 3rd quarter,2001NOx - 0.132, SO2 - 0.3 lb/mmBtu SCR, ESP, FGDIllinois Peabody - Prairie State(Washington) Peabody will build the Prairie StateEnergy Campus -- a 1,500-megawatt(MW), coal-fired electricity plant,comprised of two 750 MWepulverized coal boilers and one 400mmBtu/hr auxillary boiler -- inWashington County in southernIllinois. Construction at Prairie, if theplans pass state approval, isscheduled to start in late 2002 to early2003 and is expected to lastapproximately four years.1500 10/2001 SO2 - 0.30 lb/mmBtu, PM10 - 0.018,NOx - 0.10, CO - 0.15, VOC - 0.01,H2SO4 - 0.039SCR, wet scrubber, fabric filteror ESPIllinois Dynegy-Illinois Power Baldwin (Rando$1.5 billion, two 650 MW coal-firedboilers. 4 - 5 million tons of coal ayear by rail/barge. Adding to 2000MW from 3 existing boilers.1300 No app as of12/4/01Illinois Indeck-Elwood Elwood (Will) Two (660 MW total capacity)circulating fluidized bed boilers firingpulverized coal660 21-Mar-02 PM-.015 lb/MMBTU, SO2-.15lb/MMBTU, NOx- .10 lb/MMBTU,CO-.10 lb/MMBTU, VOC- .004lb/MMBTUBaghouse, CFB boilertechnology, limestone addtion tobed, SNCRIllinoisIllinois Energy GroupFranklin Energy CoalProjectEwing(Franklin)Two 680 MW supercritical steampulverized coal boilers, mine mouthplant136007-Jun-02SO2- .08 lb/mmBTU, NOx-.08lb/mmBTU, PM-.01 lb/mmBTUSCR, ESP, SO2 scrubberATTACHMENT 10-CEPA 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 boilersto coal.1000ApplicationReceivedIndiana Enviropower Petersburg(Pike)2 - 250 MWe CFB boilers, combustingwaste coal500 03-Aug-00Michigan NoneMinnesotaMinnesota Power &Blandin PaperCompanyAddition of 225 MWe.Ohio Dominion Energy Ashtabula 600 08-Mar-04Wisconsin Wisconsin Energy -Elm Road GeneratingStation (At existingOak Creek Facility)Oak Creek(Milwaukee)Two 615 MW supercritical pulverizedcoal boilers; construction is proposedto begin in 2004, with in-service datesof 2007, and 2009 for these units.(One 600 MW integrated gasificationcombined cycle unit was proposed,but was not approved by the WIPublic Service Comission.)1230 June 18 2002 -October 1 2003CO: 0.12 lb/mmbtu, NOx: 0.07lb/mmbtu, PM/PM10: 0.018lb/mmbtu, SO2: 0.15 lb/mmbtu,VOC: 0.0035 lb/mmbtu, Pb: 7.9lb/tbtu, Hg: 1.12 lb/tbtu, Be: 0.35lb/tbtu, HF: 0.00088 lb/mmbtu,H2SO4: 0.01lb/mmbtu, HCL: 2.56lb/mmbtuCO: LNB, NOx: LNB/SCR,PM/PM10: FF, SO2: Wet FGD,VOC: LNB, Pb/Hg/Be/HF,HCL:FF, H2SO4: FGD/Wet ESPWisconsin Wisconsin Power andLightOn-line by 2006 500Wisconsin Wisconsin PublicService CorporationWausau The Weston Unit 4 plant, planned forconstruction at the existing Westongenerating station located three milessouth of Wausau in centralWisconsin, is being built to satisfygrowing electric demand.500 July 16, 2004 CO: 0.15 lb/mmbtu, NOx: 0.06lb/mmbtu, PM/PM10: 0.020lb/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/hrCO: LNB, NOx: LNB/SCR,PM/PM10: FF, SO2: DRYFGD, VOC: LNB, Pb/Be/HF:FF, Hg: Sorbent Injection/FF,H2SO4/HCL: FGDWisconsin Manitowoc PublicUtilitiesManitowoc Construction of a 64 MW CFB firedboiler. Project will include eliminationof solid fuel burning capabilities atexisting boiler #5. Boiler #5 will retainits ability to fire natural gas as theboiler is needed at peak usageperiods. New boiler will fire coal,coke, and paper pellets as well asnatural gas at startup. The emissionreduction from the elimination of solidfuel burning capabilties at boiler #5will be used to net out of PSD for PM,SO2, VOC, NOx, Pb, H2SO4, Be, Hg,and F.64 October 13,2003CO: 0.15 lb/mmbtu, NOx: 0.155lb/mmbtu, PM/PM10: 0.03 lb/mmbtu,VOC: 0.013 lb/mmbtu, Pb: .0002lb/mmbtu, HF: 0.00173 lb/mmbtu,H2SO4: 0.0045lb/mmbtu,CO: GCP, NOx: GCP,PM/PM10: FF, SO2: LimeInjection & CFB Boiler Design,VOC: GCP, Pb/Hg/Be/HF: FF,H2SO4: CFB Boiler DesignATTACHMENT 10-CEPA 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 Riverbasin coal fired boiler to yield 550-800MW, fuel oil used for start-up. Newpower 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#/mmbtuNOx: LNB/SCR; CO: cc; SO2:dry FGD; PM/PM10: FF; VOCcc; H2SO4: dry FGD, FFLouisiana NoneNew Mexico Mustang (Peabody)Energy, MustangGenerating Station35 mi. no. ofMilan,McKinley Co.Construct 1 pulverized coal firedboiler to yield 300 MW, fuel oil or nat.gas used for start-up. Proposed withlow NOx burners w/ SCR on theboiler, dry scrubber for SO2,baghouse or ESP for PM, goodcombustion 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 #/mmbtuProposed with low NOx burnersw/ SCR on the boiler, dryscrubber for SO2, baghouse orESP for PM, good combustionfor CO and VOC.Oklahoma NoneTexas City Public Service ofSan Antonio,Calaveras LakeStationSan Antonio(Bexar)Construct 1 pulverized Powder Riverbasin coal fired boiler to yield 750MW. Natural gas as start-up fuel.Existing power plant750 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/mmbtuNOx: LNB/SCR; CO: cc; SO2:wet FGD; PM/PM10: FF, wetFGD; VOC-cc; H2SO4: wetFGD, FF; Hg: FF, wet FGD,SCRTexas LS Power, SandyCreek Energy StationReisel(McClennan)Construct 1 pulverized Powder Riverbasin coal fired boiler to yield 800MW. Fuel oil as start-up fuel. Newpower plant800 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 #/mmbtuNOx: LNB/SCR; CO: cc; SO2:dry FGD; PM/PM10: FF; VOCcc; H2SO4: dry FGD, FF; Hg:dry FGD, FFATTACHMENT 10-CEPA Region IV Summary of BACT Determinations for Coal Fired Power Plants (March 2005)EPA Region 7Iowa MidAmerican Council Bluffs Installation of one 790 MWesupercritical pulverized coal firedboiler designed for base loadoperation on Powder River Basincoal. "Unit 4" will be co-located withexisting 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 withcondensibles), 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 selectedmetals"NOx-SCR, CO-cc, PM10-FF,SO2-DLS, Pb-FF, VOC-cc, Hgactivated carbon, HAP AcidGases-DLS, Metallic HAP-FFKansas Sand Sage (colocatedat existing SunflowerHolcomb PowerStation)Holcomb(Finney)Installation of a 660 MWe (6,500mmBtu/hr) pulverized PRB coal andgas-fired boiler, along with ancillarycoal and ash handling equipment andcooling towers. Proposed with ultralow NOx burners (no SCR), dryscrubber, and baghouse660 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?), * for3 yrs after performance test;accepted "de minimis" HAP limits toavoid 112(g) reviewNOx-ULNB, CO-cc, PM10-FF,SO2-DLS, Pb-FF, VOC-ccKansas Great Plains Power,Atchison GeneratingStationAtchison(Atchison)Installation of one opposed-wall-fired,dry-bottom, boiler (8100 mmBtu/hr),subbituminous coal with No. 2 oilbackup and associated equipment,including cooling tower820 Jan '03 Proposed in Application... NOx(0.08,30d), CO (0.16), PM10(0.018), SO2 (0.12,30d), VOC(0.0036); all exceptstartup/shudown/malfunctionNOx - LNB(75%) & SCR(60%),PM10-FF(99.77%), SO2-spraydrier(94%) & low sulfur coal(5%S), CO-cc,Missouri Kansas City Power &Light, Hawthorn PowerStationKansas City(Jackson)Installation of a 570 MWe pulverizedPRB coal and gas-fired boiler (Unit 5,completely rebuilt followingcatastrophic explosion of existingunit), with SCR, dry scrubber, andbaghouse570 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 sincefinal permitting action precededDecember 20, 2000 HAP finding.NOx-SCR, CO-cc, PM10-FF,SO2-DLS, Pb-FF, VOC-ccMissouri Great Plains Power,Weston BendGenerating Station(colocated at existingKCPL, Iatan Station)Weston(Platte)Installation of one opposed-wall, drybottom boiler combusting low sulfurWyoming 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-SCR, CO-cc, PM10-FF,SO2-DLS/SDA (with PRB coal),Pb-FF, VOC-ccMissouri City Utilities ofSpringfield, SouthwestPower StationSpringfield(Greene)Construction of a new 275 MWpulverized coal (low sulfur westernsubbituminous) utility boiler andassociated equipment275 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-SCR, CO-cc, PM10-FF,SO2-DLS/SDA (with PRB coal),Pb-FF, VOC-ccNebraska Omaha Public PowerDistrictNebraska City Addition of one 660 MWn (6478mmBtu/hr) coal-fired unit at theexisting Nebraska City power station.Also includes installation of 125mmBtu/hr auxiliary boiler and 1837 hpdiesel-fired emergency generator660 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-SCR-LNB, CO-cc, PM10-FF, SO2-DLS/SDA (with PRBcoal), Pb-FF, VOC-cc, HgMACTATTACHMENT 10-CEPA Region IV Summary of BACT Determinations for Coal Fired Power Plants (March 2005)Nebraska Municipal EnergyAgency of Nebraska(colocated at existingCity of Hastings,Gerald Whelan EnergyCenter)Hastings Addition of one 220 MW (2,210.5MMBTU/hr) pulverized coal drybottom boiler, 74 MMBTU/hr auxiliaryboiler, diesel-fired 800 kW emergencygenerator, 50 hp diesel-fire fire pump220 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-SCR, CO-cc, PM10-FF,SO2-DLS/SDA (with PRB coal),Pb-FF, VOC-cc, Fl (DLS-FF)ATTACHMENT 10-CEPA Region IV Summary of BACT Determinations for Coal Fired Power Plants (March 2005)EPA Region 8ColoradoTri-State Generationand TransmissionAssociationSoutheasternColorado1200 MWe.ColoradoColorado SpringsUtilitiesColoradoSprings (ElPaso)Addition of one 150 MW CirculatingFluidized Bed coal combustion boilerwith fully integrated, multi-layeredemission controls to produce what ispredicted to be the cleanest coal plantin the world. Will demonstrate fuelflexibility for western & eastern coals,as well as waste coals.150Preapplicationmeeting only.Colorado Xcel Energy,Comanche StationPueblo(Pueblo)Addition of Unit 3, an approximately750 MW super critical pulverized coalboiler to the existing ComancheStation.750 9/10/2004Revised 1/19/05PM/PM10 - pulse jet baghouse;NOx - SCR; SO2 - dry FGD,CO/VOC - combustion control;HAPs - cobenefit control &sorbent injection for Hg.MontanaComposite Energy,Bear Creak2000Montana Bull MountainDevelopmentCompany, No.1, LLC.Roundup(Musselshell)The Power Plant will consist of twocoal-fired generating units andauxiliary equipment. Each unit willhave a pulverized coal-fired boiler andsteam turbine-generator with a grosselectrical output of 390 MW. Pollutioncontrols: dry FGD, SCR, and pulse jetbaghouse.780 16-Jan-02 PM10 (filt) - 0.015 (source test -submit emissions for considerationof lowering to 0.012 after 18 mo);NOx - 0.07 (24-hr ave) & 0.1 (1-hrave); SO2 - 0.15 (1-hr ave) & 0.12(24-hr ave); CO - 0.15 (sourcetest); VOC - 0.003 (no ave); SAM -0.0064 (sourPM/PM10 - pulse jet baghouse;NOx - SCR; SO2 - dry FGD;CO/VOC - combustion control.Montana Rocky MountainPower, Inc. (Bison)Hardin,MontanaPulverized coal-fired boiler (1968vintage) with a heat input of up to1,304 MMBtu/hr to produce up to900,000 pounds of steam pounds perhour.113116 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-hrave, 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 - multiclone & wetventuri scrubber,baghouse;NOx - SCR; SO2 - wet venturiscrubberdry scrubber;CO/VOC - combustion control.North DakotaGreat River EnergyApplied for some funding under ND'sLignite Vision 21 Project500North Dakota Montana-DakotaUtilities,Westmoreland PowerInc.Gascoyne (BowNew power plant consisting of onecirculating fluidized bed boiler burninglignite from an adjacent mine with thefollowing pollution controls: fabric filterbaghouse, selective non-catalyticreduction (SNCR), dry lime scrubberwith limestone injection.175 14-May-04South Dakota NoneUtah Intermountain PowerService CorpDelta (Millard) Add Unit 3 to existing power plant(pulverized coal fired) with fabric filterbaghouse, low NOx burners andSCR, forced oxidation wet limestoneFGD system, and combustioncontrols (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/MMBtuequiv - 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) - 6.0E-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 - Fabric filterbaghouse; NOx - SCR; SO2 -wet FGD; CO/VOC -combustion control; HAPs -cobenefit controlsATTACHMENT 10-CEPA Region IV Summary of BACT Determinations for Coal Fired Power Plants (March 2005)Utah NEVCO Energy Sevier (Sevier) New power plant consisting of onecirculating fluidized bed boiler with thefollowing pollution controls: fabric filterbaghouse, selective non-catalyticreduction (SNCR), dry lime scrubberwith limestone injection, combustioncontrols (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 orM29); HCl - 4.01 lb/hr (M26A)PM/PM10 - Baghouse with bagleak detectors; NOx - SNCR;SO2 - dry lime scrubber;CO/VOC - combustion control;HAPs - cobenefit controlsUtah PacifiCorp - Hunter Castle Dale(Emery)Add Unit 4 to existing power plant(pulverized coal fired) with fabric filterbaghouse, low NOx burners andSCR, and forced oxidation wet limescrubber system, and combustioncontrols (CO & VOC).575 14-Nov-03Utah (Tribal Land) Deseret Generation &Transmission -BonanzaBonanza(Uintah)Add one circulating fluidized bedboiler (waste coal) to existing powerplant with fabric filter baghouse,selective non-catalytic reduction(SNCR), limestone injection, andcombustion controls (CO and VOC).110 14-Apr-04Wyoming Independent EnergyGroup of Black HillsCorporation @ WygenUnit 1Gillette Pulverized coal fired ElectricGenerating Plant80 04-Jun-96 PM(filt): 0.02, SO2:0.20(2-hr rolling),0.17 (30-day), NOx: 0.22(30-dayrolling), 0.2(365-day rolling), CO:0.15, 0.015PM-ESP, NOx-LNB/OFA, SO2-CDS, VOC/CO-CombustioncontrolWyoming Black Hills Power andLight (WYGEN 2)Gillette Pulverized Coal Fired ElectricGenerating Plant500 26-Apr-02 PM/PM10 (filt): 0.012 (source test);SO2: 0.1 (30-day ave) 0.15 (3-hrblock); NOx: 0.07 (30 day); CO:0.15 (source test), VOC: 0.01(source test). Limits in lb/MMBtu.PM10 - multiclone & wet venturiscrubber; NOx - SCR; SO2 -Spray dryer/absorber; CO/VOC-combustion control.WyomingNorth Amercian PowerGroupWright274WyomingZiegler Coal HoldingWright240EPA Region 9Arizona Unisource Energy @Tuscon Electric'sSpringerville StationTucson 2 - 360 MW units, final committmentto procede, July 2001, online 2004and 2005720New Mexico (NavaSTEAG Power -Desert Rock EnergyFacility25 miles SW ofFarmington,NM2 x 750 MW greenfield, mine mouthplant1500 25-Feb-04New Mexico (NavaBHP Billiton -Cottonwood EnergyCenterFour Cornersarea, NMOne 550 MW coal-fired sub-criticalboiler, 495 net.495 23-Mar-04 NOx (0.06 lb/mmbtu), CO (0.14lb/mmbtu), SO2 (0.06 lb/mmbtu),VOC (0.0072 lb/mmbtu), PM10 (0.02lb/mmbtu)NOx - LNB and SCR, SO2 -limestone wet FGD, PM -baghouseCalifornia NoneHawaii NoneNevadaDuke Energy(White Pine)2 - 650 MW coal-fired unitsConceptualNevada LS Power White Pinearea near UTborder1000 MW 1000 ConceptualNevada Sempra Energy -Granite Fox PowerGerlach(Washoe)1450 MW greenfield plant 1450Nevada Newmont Mining, TSPower PlantEureka County 200 MW pulverized coal-fired boiler(four oil-fired combustion turbines tobe used for back-up power).200 01-Oct-04 NOx (0.067 lb/MMBTU, 30-dayrolling average); CO (0.15lb/MMBTU, 24-rolling average); SO2(0.09 lbs/MMBTU 24-hr rollingaverage); PM/PM10 0.038lbs/MMBTU (24-hr rolling average)Low-NOx burners and SCR;combustion controls; Low-sulfurcoal and Dry Scrubber; fabricfiltersAmerican Samoa NoneGuam NoneATTACHMENT 10-CEPA Region IV Summary of BACT Determinations for Coal Fired Power Plants (March 2005)EPA Region 10Alaska Arctic Slope RegionalCorporationPoint Lay(North SlopeBorough)Greenfield coal-fired power plant atmine mouth.Alaska Golden Valley ElectricAssociationHealy (DenaliBorough)Retrofit existing Department of EnergyClean Coal Technology pulverizedcoal boiler to a conventional system.The boiler has been idle since 1999.50 None submittedIdaho Sempra EnergyResourcesKing Hill(ElmoreCounty)Coal-fired power plant is beingconsidered.? None submittedIdahoUndeterminedShoshoneBannockReservationoutsidePocatello(Bannock)Coal-fired power plant using PRB coal550None submittedIdahoSoutheast IdahoEnergy LLCPower Countyand Fort HallIndianReservationoutsidePocatelloIGCC520None submitted01-Jan-10OregonPortland GeneralElectricBoardman(Morrow)Additional coal-fired power generationat existing coal-fired power plant.Oregon PacifiCorp ? ? 500 None submittedWashington Composite Power Richland(BentonCounty)Develop former Washington PublicPower Supply System sites 1&4.2500 None submittedWashingtonUS Electric PowerBlaine(WhatcomCounty)Earliest on-line projection is April2004.

# ATTACHMENT 10-D

RACT / BACT / LAER CLEARINGHOUSE DATA FOR OIL-FIRED BOILERSFACILITY STATE PERMITNUMBERPERMITDATEDESCRIPTION EMISSIONLIMITLb/MMBtuCONTROL DESCRIPTION BASISRiver Hill Power Company PA 17-00055A 7/21/2005 Auxiliary Boiler -- -- 0.09 Low-NOx Burners and FGR OTHERMN Municipal Power Agency - FairbaultEnergy ParkMN 13100071-001 7/15/2004 Auxiliary Boiler 40 MMBTUH 0.058 Low-NOx Burners and FGR BACT-PSDNebraska Public Power District - BeatricePower StationNE 76739C01 6/22/2004 Auxiliary Boiler 73.3 MMBTUH 0.10 None Identified BACT-PSDBiomass Energy, LLC - South Point Power OH 07-00534 1/5/2004 Auxiliary Boiler 227 MMBTUH 0.19 None Identified OTHERUS DOE - Hanford WA PSD-02-01 11/13/2003 Fire-tube boilers 50.2 MMBTUH 0.09 Low-NOx Burners and FGR BACT-PSDAbbott Laboratories - Sturgis Plant MI 64-03 9/16/2003 Boiler 98.51 MMBTUH 0.14 Low-NOx Burners and FGR BACT-PSDColumbia Energy Center SC 0460-0024-CE 7/3/2003 Fuel Oil Boiler 550 MMBTUH 0.12 Low-NOx Burners and FGR BACT-PSDCity of Harrisonburg - HarrisonburgResource Recovery FacilityVA 81016 3/24/2003 Boiler No. 2 43.2 MMBTUH 6.17 lb/hr Low-NOx Burners and FGR OTHERThoroughbred Generating Company, LLC KY V-02-001 10/11/2002 Auxiliary Boiler 300 MMBTUH 0.12Good Operating Practices;Limited to < 500 hrs/yrBACT-PSDLongview Fibre Company WA PSD-01-03 12/10/2001 Power Boilers 12, 13 444 MMBTUH 0.73 None Identified OTHERLongview Fibre Company WA PSD-01-03 12/10/2001 Power Boiler #16 525 MMBTUH 0.73 None Identified OTHERLongview Fibre Company WA PSD-01-03 12/10/2001 Power Boiler #20 900 MMBTUH 0.30 None Identified OTHERLongview Fibre Company WA PSD-01-03 12/10/2001 Power Boiler #17 591 MMBTUH 0.73 None Identified OTHERCentral Soya Company, Inc. OH 03-13369 11/29/2001 Boiler 91.2 MMBTUH 0.106 Low-NOx burners BACT-PSDAES Red Oak, LLC NJ 10001 10/24/2001 Auxiliary Boiler 99.0 MMBTUH 0.10 Limited to 3600 hrs/yr LAERInternational Paper - Mansfield Mill LA PSD-LA-93 (M-6) 8/14/2001 Power Boilers 645 MMBTUH 0.30Low-NOx Burners, CMS for O2NOx EmissionsBACT-PSDColumbia Energy Center SC 0460-0024 4/9/2001 Auxiliary Boiler 350 MMBTUH 0.12 Low-NOx Burners and FGR BACT-PSDGrays Ferry Cogen Partnership PA 97019 3/21/2001 Auxiliary Boiler 1119 MMBTUH 0.15 Low-NOx Burners BACT-PSDMobile Energy, LLC - Hog Bayou AL 503-8066-X003 6/7/2000 Oil Backup 378 MMBTUH 0.15 Low-NOx Burners and FGR BACT-PSDDegussa Corporation AL 503-5011-X046 9/29/1997 Boiler 355 MMBTUH 0.12 Low-NOx Burners and FGR BACT-PSDRayonier Specialty Pulp Products GA 2631-151-12433 6/16/1007 Boiler 338 MMBTUH 0.10 Low-NOx Burners and FGR BACT-PSDPedrickton Cogeneration Plant NJ 096453,55,57 9/19/1995Auxiliary Boilers, 2 -Kerosene262 MMBTUH 0.15 Low-NOx Burners and FGR BACT-PSDTHROUGHPUTRACT/BACT/LAER Clearinghouse Results for Oil-Fired Boilers (NOx)Attachment 10-DAtt 10-D_OilFired Boilers_RBLC.xlsNOx7/10/2007FACILITY STATE PERMITNUMBERPERMITDATEBOILER TYPE EMISSIONLIMITlb/MMBtuCONTROL DESCRIPTION BASISRiver Hill Power Company PA 17-00055A 7/21/2005 Auxiliary Boiler -- -- 0.077 None Identified OTHERMirant Mid-Atlantic, LLC - Dickerson MDCPCN CASE NO.888811/5/2004 Auxiliary Boiler 60 MMBTUH 0.150Good Combustion Practices, CleanFuelBACT-PSDMN Municipal Power Agency - FairbaultEnergy ParkMN 13100071-001 7/15/2004 Auxiliary Boiler 40 MMBTUH 0.036 Good Combustion BACT-PSDBiomass Energy, LLC - South Point Power OH 07-00534 1/5/2004 Auxiliary Boiler 227 MMBTUH 0.12 None Identified BACT-PSDColumbia Energy Center SC 0460-0024-CE 7/3/2003 Fuel Oil Boiler 550 MMBTUH 0.04Good Combustion Practices, CleanFuelBACT-PSDCity of Harrisonburg - HarrisonburgResource Recovery FacilityVA 81016 3/24/2003 Boiler No. 2 43.2 MMBTUH 3.56 lb/hrGood Combustion Practices, CleanFuelBACT-PSDThoroughbred Generating Company, LLC KY V-02-001 10/11/2002 Auxiliary Boiler 300 MMBTUH 0.06Good Operating Practices; Limitedto < 500 hrs/yrBACT-PSDLongview Fibre Company WA PSD-01-03 12/10/2001 Power Boilers 12, 13 444 MMBTUH 2.0 None Identified OTHERLongview Fibre Company WA PSD-01-03 12/10/2001 Power Boiler #16 525 MMBTUH 1.0 None Identified OTHERLongview Fibre Company WA PSD-01-03 12/10/2001 Power Boiler #20 900 MMBTUH 1.0 None Identified OTHERLongview Fibre Company WA PSD-01-03 12/10/2001 Power Boiler #17 591 MMBTUH 1.0 None Identified OTHERCentral Soya Company, Inc. OH 03-13369 11/29/2001 Boiler 91.2 MMBTUH 0.140 None Identified BACT-PSDAES Red Oak, LLC NJ 10001 10/24/2001 Auxiliary Boiler 99.0 MMBTUH 0.10 Good Combustion Practices BACT-PSDInternational Paper - Mansfield Mill LA PSD-LA-93 (M-6) 8/14/2001 Power Boilers 645 MMBTUH 0.036 Good Combustion Practices BACT-PSDColumbia Energy Center SC 0460-0024 4/9/2001 Auxiliary Boiler 350 MMBTUH 0.04 Good Combustion Practices BACT-PSDGrays Ferry Cogen Partnership PA 97019 3/21/2001 Auxiliary Boiler 1119 MMBTUH 0.04 Good Combustion Practices BACT-PSDMobile Energy, LLC - Hog Bayou AL 503-8066-X003 6/7/2000 Oil Backup 378 MMBTUH 0.16 Good Combustion Practices BACT-PSDDegussa Corporation AL 503-5011-X046 9/29/1997 Boiler 355 MMBTUH 0.09 Good Combustion BACT-PSDRayonier Specialty Pulp Products GA 2631-151-12433 6/16/1007 Boiler 338 MMBTUH 0.12 Good Combustion Control BACT-PSDPedrickton Cogeneration Plant NJ 096453,55,57 9/19/1995Auxiliary Boilers, 2 -Kerosene262 MMBTUH 0.164 Good Combustion Control BACT-PSDTHROUGHPUTRACT/BACT/LAER Clearinghouse Results for Oil-Fired Boilers (CO)Attachment 10-DAtt 10-D_OilFired Boilers_RBLC.xlsCO7/10/2007FACILITY STATE PERMITNUMBERPERMITDATEBOILER TYPE EMISSIONLIMITlb/MMBtuCONTROL DESCRIPTION BASISRiver Hill Power Company PA 17-00055A 7/21/2005 Auxiliary Boiler -- -- 0.203 None Identified OTHERMirant Mid-Atlantic, LLC - Dickerson MDCPCN CASE NO.888811/5/2004 Auxiliary Boiler 60 MMBTUH 0.050Good Combustion Practices, CleanFuelBACT-PSDMN Municipal Power Agency - Fairbault EnergyParkMN 13100071-001 7/15/2004 Auxiliary Boiler 40 MMBTUH 0.051 Fuel Sulfur Limited to 0.05 wt. % S BACT-PSDBiomass Energy, LLC - South Point Power OH 07-00534 1/5/2004 Auxiliary Boiler 227 MMBTUH 0.0125 Fuel Sulfur Limited to 0.05 wt. % S BACT-PSDColumbia Energy Center SC 0460-0024-CE 7/3/2003 Fuel Oil Boiler 550 MMBTUH 0.06 Low Sulfur Fuels BACT-PSDCity of Harrisonburg - Harrisonburg ResourceRecovery FacilityVA 81016 3/24/2003 Boiler No. 2 43.2 MMBTUH 2.19 lb/hrGood Combustion Practices, CleanFuelBACT-PSDThoroughbred Generating Company, LLC KY V-02-001 10/11/2002 Auxiliary Boiler 300 MMBTUH 0.05Good Operating Practices; Limited to< 500 hrs/yrBACT-PSDLongview Fibre Company WA PSD-01-03 12/10/2001 Power Boilers 12, 13 444 MMBTUH 0.24 None Identified OTHERLongview Fibre Company WA PSD-01-03 12/10/2001 Power Boiler #16 525 MMBTUH 0.59 Low Sulfur Fuels OTHERLongview Fibre Company WA PSD-01-03 12/10/2001 Power Boiler #20 900 MMBTUH 0.25 Low Sulfur Fuels OTHERLongview Fibre Company WA PSD-01-03 12/10/2001 Power Boiler #17 591 MMBTUH 0.59 Low Sulfur Fuels OTHERCentral Soya Company, Inc. OH 03-13369 11/29/2001 Boiler 91.2 MMBTUH 0.21Fuel Sulfur Content Not to Exceed0.5% by wt.BACT-PSDAES Red Oak, LLC NJ 10001 10/24/2001 Auxiliary Boiler 99.0 MMBTUH 0.0507 Low Sulfur Fuels BACT-PSDInternational Paper - Mansfield Mill LA PSD-LA-93 (M-6) 8/14/2001 Power Boilers 645 MMBTUH 0.8Fuel Sulfur Content Not to Exceed0.7% by wt.BACT-PSDColumbia Energy Center SC 0460-0024 4/9/2001 Auxiliary Boiler 350 MMBTUH 0.0616 Low Sulfur Fuels BACT-PSDGrays Ferry Cogen Partnership PA 97019 3/21/2001 Auxiliary Boiler 1119 MMBTUH 0.215 Good Combustion Practices, Low SulfBACT-PSDRayonier Specialty Pulp Products GA 2631-151-12433 6/16/1007 Boiler 338 MMBTUH NA Fuel Sulfur Limited to 0.05 wt. % S OTHERPedrickton Cogeneration Plant NJ 096453,55,57 9/19/1995Auxiliary Boilers, 2 -Kerosene262 MMBTUH 0.04 Fuel Sulfur Limited to 0.04 wt. % S BACT-PSDTHROUGHPUTRACT/BACT/LAER Clearinghouse Results for Oil-Fired Boilers (SO2)Attachment 10-DAtt 10-D_OilFired Boilers_RBLC.xlsSO27/10/2007FACILITY STATE PERMITNUMBERPERMITDATEBOILER TYPE EMISSIONLIMITLb/MMBtuCONTROL DESCRIPTION BASISRiver Hill Power Company PA 17-00055A 7/21/2005 Auxiliary Boiler -- -- 0.005 None Identified LAERMN Municipal Power Agency - FairbaultEnergy ParkMN 13100071-001 7/15/2004 Auxiliary Boiler 40 MMBTUH 0.003 Good Combustion BACT-PSDColumbia Energy Center SC 0460-0024-CE 7/3/2003 Fuel Oil Boiler 550 MMBTUH 0.004 Good Combustion Practices BACT-PSDCity of Harrisonburg - HarrisonburgResource Recovery FacilityVA 81016 3/24/2003 Boiler No. 2 43.2 MMBTUH 0.23 lb/hr Good Combustion Practices BACT-PSDThoroughbred Generating Company, LLC KY V-02-001 10/11/2002 Auxiliary Boiler 300 MMBTUH 0.03Good Operating Practices; Limited to <500 hrs/yrBACT-PSDCentral Soya Company, Inc. OH 03-13369 11/29/2001 Boiler 91.2 MMBTUH 0.0140 None Identified BACT-PSDAES Red Oak, LLC NJ 10001 10/24/2001 Auxiliary Boiler 99.0 MMBTUH 0.0050 Low Sulfur Fuels LAERInternational Paper - Mansfield Mill LA PSD-LA-93 (M-6) 8/14/2001 Power Boilers 645 MMBTUH 100 LB/HR Good Combustion Practices BACT-PSDColumbia Energy Center SC 0460-0024 4/9/2001 Auxiliary Boiler 350 MMBTUH 1.75 LB/HR Good Combustion Practices BACT-PSDGrays Ferry Cogen Partnership PA 97019 3/21/2001 Auxiliary Boiler 1119 MMBTUH 0.01 Good Combustion Practices BACT-PSDMobile Energy, LLC - Hog Bayou AL 503-8066-X003 6/7/2000 Oil Backup 378 MMBTUH 0.005 Good Combustion Practices BACT-PSDPedrickton Cogeneration Plant NJ 096453,55,57 9/19/1995AuxiliaryBoilers, 2 -Kerosene262 MMBTUH 0.023 Good Combustion Practices BACT-PSDTHROUGHPUTRACT/BACT/LAER Clearinghouse Results for Oil-Fired Boilers (VOC)Attachment 10-DAtt 10-D_OilFired Boilers_RBLC.xlsVOC7/10/2007FACILITY STATE PERMITNUMBERPERMITDATEBOILER TYPE EMISSIONLIMITlb/MMBtuCONTROL DESCRIPTION BASISRiver Hill Power Company PA 17-00055A 7/21/2005 Auxiliary Boiler -- -- 0.030 None Identified OTHEROmaha Public Power District - Nebraska CityStationNE 58343C01 3/9/2005 Auxiliary Boiler #2 -- -- 0.001Fuel Sulfur Limited to 0.05 wt. %S; limited to 500 hrs/yrBACT-PSDMirant Mid-Atlantic, LLC - Dickerson MDCPCN CASE NO.888811/5/2004 Auxiliary Boiler 60 MMBTUH 0.050Good Combustion Practices,Clean FuelBACT-PSDMN Municipal Power Agency - FairbaultEnergy ParkMN 13100071-001 7/15/2004 Auxiliary Boiler 40 MMBTUH 0.024Good Combustion Practices,Clean FuelBACT-PSDBiomass Energy, LLC - South Point Power OH 07-00534 1/5/2004 Auxiliary Boiler 227 MMBTUH 0.040Fuel Sulfur Limited to 0.05 wt. %SBACT-PSDUS DOE - Hanford WA PSD-02-01 11/13/2003 Fire-tube boilers 50.2 MMBTUH 0.020Ultra Low Sulfur Fuel and GoodCombustion PracticesBACT-PSDColumbia Energy Center SC 0460-0024-CE 7/3/2003 Fuel Oil Boiler 550 MMBTUH 0.024 Good Combustion Practices BACT-PSDCity of Harrisonburg - Harrisonburg ResourceRecovery FacilityVA 81016 3/24/2003 Boiler No. 2 43.2 MMBTUH 0.62 lb/hr Good Combustion Practices BACT-PSDThoroughbred Generating Company, LLC KY V-02-001 10/11/2002 Auxiliary Boiler 300 MMBTUH 0.06Good Operating Practices;Limited to < 500 hrs/yrBACT-PSDLongview Fibre Company WA PSD-01-03 12/10/2001 Power Boilers 12, 13 444 MMBTUH 0.10 None Identified OTHERLongview Fibre Company WA PSD-01-03 12/10/2001 Power Boiler #16 525 MMBTUH 0.21 None Identified OTHERLongview Fibre Company WA PSD-01-03 12/10/2001 Power Boiler #20 900 MMBTUH 0.093 None Identified OTHERLongview Fibre Company WA PSD-01-03 12/10/2001 Power Boiler #17 591 MMBTUH 0.20 None Identified OTHERCentral Soya Company, Inc. OH 03-13369 11/29/2001 Boiler 91.2 MMBTUH 0.0054Fuel Sulfur Content Not toExceed 0.5% by wt.BACT-PSDAES Red Oak, LLC NJ 10001 10/24/2001 Auxiliary Boiler 99.0 MMBTUH 0.040 None Identified BACT-PSDInternational Paper - Mansfield Mill LA PSD-LA-93 (M-6) 8/14/2001 Power Boilers 645 MMBTUH 0.1 Single-stage dust collector/ESP BACT-PSDColumbia Energy Center SC 0460-0024 4/9/2001 Auxiliary Boiler 350 MMBTUH 0.03 Good Combustion Practices BACT-PSDGrays Ferry Cogen Partnership PA 97019 3/21/2001 Auxiliary Boiler 1119 MMBTUH 0.0032 Good Combustion Practices BACT-PSDMobile Energy, LLC - Hog Bayou AL 503-8066-X003 6/7/2000 Oil Backup 378 MMBTUH 0.01 Good Combustion Practices BACT-PSDRayonier Specialty Pulp Products GA 2631-151-12433 6/16/1007 Boiler 338 MMBTUH 0.05Fuel Sulfur Limited to 0.05 wt. %SBACT-PSDPedrickton Cogeneration Plant NJ 096453,55,57 9/19/1995Auxiliary Boilers, 2 -Kerosene262 MMBTUH 0.02 Good Combustion Practices BACT-PSDTHROUGHPUTRACT/BACT/LAER Clearinghouse Results for Oil-Fired Boilers (PM-PM10)Attachment 10-DAtt 10-D_OilFired Boilers_RBLC.xlsPM-PM107/10/2007FACILITY STATE PERMITNUMBERPERMITDATEBOILER TYPE EMISSION LIMIT CONTROL DESCRIPTION BASISColumbia Energy Center SC 0460-0024 4/9/2001 Auxiliary Boiler 350 MMBTUH 10 LB/HRLow Sulfur Fuel & CombustionControlsBACT-PSDPedrickton CogenerationPlantNJ 096453,55,57 9/19/1995AuxiliaryBoilers, 2 -Kerosene262 MMBTUH 0.0033 Lb/MMBtuLow Sulfur Fuel & CombustionControlsBACT-PSDTHROUGHPUTRACT/BACT/LAER Clearinghouse Results for Oil-Fired Boilers (H2SO4)Attachment 10-DAtt 10-D_OilFired Boilers_RBLC.xlsH2SO47/10/2007

# ATTACHMENT 10-E

RACT / BACT / LAER CLEARINGHOUSE DATA FOR DIESEL-FIRED

ENGINES > 500 HPFACILITY STATE PERMIT NUMBER PERMIT DATE DESCRIPTIONCONTROL DESCRIPTION BASISKANSAS CITY PUBLICUTILITIES - NEARMAN CREEKSTATION KS C-570 10/18/2005 EMERGENCY BLACK START GENERATOR 2800 KW 84.8 LB/HR GOOD COMBUSTION CONTROL BACT-PSDARIZONA CLEAN FUELS YUMALLC AZ 1001205 4/14/2005 FIRE WATER PUMP ENGINES 5.46 MMBTU/H 4 GR/KW-HR NONE INDICATED - LIMIT IS FOR NOX + NMHC BACT-PSDARIZONA CLEAN FUELS YUMALLC AZ 1001205 4/14/2005 EMERGENCY GENERATOR 10.9 MMBTU/H 6.4 GR/KW-HR NONE INDICATED - LIMIT IS FOR NOX + NMHC BACT-PSDJOHN DEERE PRODUCTENGINEERING CENTER IAPROJECT NUMBER 00-648 3/23/2005 TEST CELL 24.5 gal/h 1.52 LB/MMBTU GOOD COMBUSTION PRACTICES BACT-PSDFIRST QUALITY TISSUE, LLC PA 18-315-001 10/20/2004 FIRE PUMP 575 hp 0.031 LB/HP-HBACT-PSDPSI ENERGY-MADISONSTATION OH 14-04682 8/24/2004 EMERGENCY DIESEL GENERATOR, 2 17.21 MMBTU/H 55.07 LB/HBACT-PSDFAIRBAULT 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 PRACTICES BACT-PSDU.S. ARMY - PINE BLUFFARSENAL AR 1113-AOP-R0 2/17/2004 EMERGENCY GENERATORS (2) 2500 KW 33.9 LB/HR NONE INDICATED BACT-PSDACE ETHANOL - STANLEY WI 03-DCF-184 1/21/2004 IC ENGINE, DIESEL GENERATOR SET, B70 1850 BHP 13 G/HP-HLIMIT ON HOURS OF OPERATION (16.7 HRS/MO, 12MO. AVG.) BACT-PSDMANKATO ENERGY CENTER MN 01300098-001 12/4/2003 INTERNAL COMBUSTION ENGINE, LARGE 1850 HP 12.7 G/B-HP-H GOOD COMBUSTION BACT-PSDDUTCH HARBOR SEAFOODPROCESSING FACILITY AK 433CP01(MOD) 10/10/2003 IC ENGINE, GENERATOR, FUEL OIL, (3) 2220 KW 42.3 LB/H WATER INJECTION, LOW NOX DESIGN BACT-PSDUSAF EARECKSON AIRSTATION AK 307CP01 9/29/2003 IC ENGINE, DIESEL, (2) 3000 KW 9.7 LB/H SCR BACT-PSDUSAF EARECKSON AIRSTATION AK 307CP01 9/29/2003 IC ENGINESGOOD COMBUSTION PRACTICES BACT-PSDDUKE ENERGY WASHINGTONCOUNTY LLC OH 06-06792 8/14/2003 EMERGENCY DIESEL-FIRED GENERATOR 600 KW 12.4 LB/H LOW SULFUR FUEL, COMBUSTION CONTROL BACT-PSDINGENCO - CHARLES CITYPLANT VA 51998 6/20/2003 IC ENGINES, (48) 550 HP 2.4 LB/MMBTUAIR TO FUEL RATIO CONTROL, TURBOCHARGING,AND CHARGE AIR COOLING SYSTEMS. THE AIR TOFUEL RATIO SHALL BE CONTROLLED BY ASEPARATE ENGINE CONTROL MODULE FOR EACHENGINE. N/ACOMPANY IA PROJECT 02-528 6/17/2003 EMERGENCY GENERATOR 97.73 GAL/HR 1.71 LB/MMBTU GOOD COMBUSTION PRACTICES BACT-PSDSTEPHENS 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) BACT-PSDCARDINAL FG CO./ CARDINALGLASS PLANT OK 2002-487-C PSD 3/18/2003IC ENGINES, EMERGENCY GENERATORS(2) 2000 KW 2.035 LB/MMBTUENGINE DESIGN AND LIMIT ON HOURS OFOPERATION (<500 H/YR) BACT-PSDPACIFIC BELL CA 16290 2/1/2003 IC ENGINES 2935 HP 6.9 G/B-HP-HLAERROQUETTE AMERICA IA 56-01-009 1/31/2003 IC ENGINE, DIESEL 710 HP 3.1 LB/MMBTU GOOD COMBUSTION PRACTICES BACT-PSDBRIDGESTONE/FIRESTONENORTH AMERICAN TIRE NC 01660T42 1/24/2003IC ENGINES, AIR COMPRESSORS, DIESEL,(5) 4.46 MMBTU/H 7.8 LB/H IGNITION TIMING RETARD BACT-PSDSTERNE ELECTRICGENERATING FACILITY TX PSD-TX-1015 12/6/2002 EMERGENCY GENERATOR 1350 HP 41.9 LB/HBACT-PSDORCHARD PARK GENERATINGSTATION PA 28-05031 11/8/2002 ENGINE-GENERATOR 8086 B-HP 1.5 G/B-HP-HLEAN BURN, SCR, LOW EMISSION COMBUSTIONCONTROL Other Case-by-CaseCITY OF PELLA IA PROJ. NO. 01-238 9/25/2002 IC ENGINES, DIESEL, (14) 144 G/H 1.71 LB/MMBTU COMBUSTION AIR CHILLER Other Case-by-CaseUNIVERSITY OF CINCINNATI OH 14-05108 8/15/2002DIESEL FIRED ENGINES (2), 2 MW, 2922BHP 19.17 MMBTU/H 40.92 LB/HBACT-PSDHAWKEYE GENERATING, LLC IA 01-687 7/23/2002 EMERGENCY GENERATOR 18500 GALLONS/YR 10.61 LB/H GCP, TIMING RETARD BACT-PSDGENOVA OK I POWERPROJECT OK 2001-223-C PSD 6/13/2002 DIESEL ENGINE, BACKUP GENERATOR 750 KW 3.01 LB/MMBTU ENGINE DESIGN AND LIMITATION OF HOURS BACT-PSDSCE&G - JASPER COUNTYGENERATING FACILITY SC 1360-0026-CA-CC 5/23/2002 GENERATOR, EMERGENCY,DIESEL FUEL 2000 KW 59.5 LB/HBACT-PSDPHELPS 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 OtherCase-by-CaseREDBUD POWER PLT OK 2000-090-C M-1 PSD 5/6/2002DIESEL ENGINE, EMERGENCYGENERATOR 1818 HP 0.024 LB/B-HP-H BACT-PSDTHROUGHPUTRACT/BACT/LAER Clearinghouse Results for Diesel-Fired Engines > 500 HP (NOX)Attachment 10-EEMISSION LIMITAtt 10-E_Diesel-Fired IC Engines over 500HP_RBLC.xlsNOx7/10/2007FACILITY STATE PERMIT NUMBER PERMIT DATE DESCRIPTIONCONTROL DESCRIPTION BASISTHROUGHPUTRACT/BACT/LAER Clearinghouse Results for Diesel-Fired Engines > 500 HP (NOX)Attachment 10-EEMISSION LIMITGREATER DES MOINESENERGY CENTER IA 77-13-002 4/10/2002 EMERGENCY GENERATOR 700 KW 22.69 LB/H RETARDED INGITION TIMING (3-4 DEGREES) BACT-PSDDUKE ENERGY-JACKSONFACILITY AR1998-AOP-R0 (34-0259) 4/1/2002 GENERATOR, DIESEL-FIRED 671 HP 14 G/B-HP-H GOOD OPERATING PRACTICE BACT-PSDAES RED OAK LLC NJ 10001 10/24/2001 EMERGENCY GENERATOR 49 MMBTU/H 159.65 LB/H LIMITED USE LAERFORT BRAGG NC 04379T21 8/20/2001 IC ENGINES, DIESEL, (17) 44.4 T/YREACH GENERATOR USED IN PEAK SHAVING MODESHALL OPERATE NO MORE THAN 250 H/YR. BACT-PSDMANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001CATERPILLAR BACK-UP DIESEL AIRCOMPRESSORS, 2 775 HP EACH 38.6 LB/H PREVENTATIVE MAINTENANCE BACT-PSDMANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001AUXILIARY DIESEL GENERATORS NO.1 &NO.2 1100 HP EACH 34 LB/H PREVENTATIVE MAINTENANCE BACT-PSDMANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001ADMINISTRATION BUILDING DIESELGENERATOR 587 HP 18.1 LB/H PREVENTATIVE MAINTENANCE BACT-PSDPSEG WATERFORD ENERGYLLC OH 06-06739 3/29/2001 EMERGENCY GENERATOR 1000 KW 0.82 T/YRBACT-PSDDUKE ENERGY HOT SPRINGS AR 1936-AOP-R0 12/29/2000 GENERATORS, (2) DIESEL 600 KW 14 G/B-HP-H CLEAN FUEL, COMBUSTION CONTROL. BACT-PSDCOTTONWOOD ENERGYPROJECT TX PSD-965 12/15/2000 FIRE WATER PUMP 10.39 LB/HBACT-PSDCOTTONWOOD ENERGYPROJECT TX PSD-965 12/15/2000 EMERGENCY DIESEL GENERATOR 12.4 LB/HBACT-PSDBADGER GENERATING CO LLC WI 99-RV-143 9/20/2000 DIESEL ENGINE, GENERATOR (4) 3.5 MMBTU/H 15.44 LB/HGOOD COMBUSTION PRACTICES. PERMIT LIMITSSET IN LB/H, NOT G/BHP-H. BACT-PSDBADGER GENERATING CO LLC WI 99-RV-143 9/20/2000 DIESEL ENGINE, EMERGENCY FIRE PUMP 3.8 MMBTU/H 16.76 LB/HGOOD COMBUSTION PRACTICES, EQUIPMENTUSAGE LIMITS. PERMIT LIMITS IN LB/H, NO LIMITSSET IN G/BHP-H BACT-PSDOKEMO MOUNTAIN INC. VT OP-99-013 9/5/2000 GENERATOR, FUEL OIL 1480 BHP 1.6 G/B-HP-H SCR RACTBRAZOS VALLEY ELECTRICGENERATING FACILITY TX PSD-TX-966 8/23/2000 EMERGENCY GENERATOR 1350 hp 41.9 LB/HN/ABRAZOS VALLEY ELECTRICGENERATING FACILITY TX PSD-TX-966 8/23/2000 FIRE WATER PUMP 300 hp 9.3 LB/HN/AFORD ELECTRONICS ANDREFRIGERATION, LLC PA PA-46-0036A 6/19/2000 DIESEL ENGINES 2 MW 20.8 LB/HJOHNSON MATHEY QXH1020-145 SCR AND 3DEGREE IGNITION RETARD. HOURLY LIMIT FOREACH ENGINE, ANNUAL FOR ALL FIVE ENGINES. Other Case-by-CaseMILL RIVER LUMBER, LTD. VTAOP-95-081B 6/8/2000 ELECTRIC GENERATION- CATERPILLAR 1023 HP 1.7 LB/H SCR W/OXIDATION CATALYST. NO REGULATORY Other Case-by-CaseDILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 IC ENGINES, DIESEL 21000000 KW-H/YR 21.9 LB/H LEAN BURN/LOW NOX PACKAGE BACT-PSDDILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #3 350 KWFOLLOW POWER GENERATION LIMITS ASSPECIFIED IN PROCESS NOTES. Other Case-by-CaseDILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #5 750 KWFOLLOW POWER GENERATION LIMITS ASSPECIFIED IN THE PROCESS NOTES. Other Case-by-CaseDILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #6 1000 KWFOLLOW POWER GENERATION LIMITS ASSPECIFIED IN THE PROCESS NOTES. Other Case-by-CaseDILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #8 835 KWFOLLOW THE POWER GENERATION LIMITSSPECIFIED IN THE PROCESS NOTES. Other Case-by-CaseDILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #9 835 KWFOLLOW POWER GENERATION LIMITS ASSPECIFIED IN THE PROCESS NOTES. Other Case-by-CaseDILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR, #10 1135 KWFOLLOW POWER GENERATION LIMITS ASSPECIFIED IN THE PROCESS NOTES. Other Case-by-CaseAtt 10-E_Diesel-Fired IC Engines over 500HP_RBLC.xlsNOx7/10/2007FACILITY STATE PERMIT NUMBER PERMIT DATE DESCRIPTIONCONTROL DESCRIPTION BASISTHROUGHPUTRACT/BACT/LAER Clearinghouse Results for Diesel-Fired Engines > 500 HP (NOX)Attachment 10-EEMISSION LIMITDILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #11 1050 KW 24.9 LB/HFOLLOW POWER GENERATION LIMITS ASSPECIFIED IN THE PROCESS NOTES. OPERATELEAN BURN/ LOW NOX ENGINE DESIGN WITH ASEPARATE AFTERCOOLER LOOP ANDELECTRONIC CONTROLS SET FOR LOW EMISSIONSTRATEGY. BACT-PSDDILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #12 1050 KW 24.9 LB/HFOLLOW POWER GENERATION LIMITS ASSPECIFIED IN THE PROCESS NOTES. OPERATELEAN BURN/ LOW NOX ENGINE DESIGN WITH ASEPARATE AFTERCOOLER LOOP ANDELECTRONIC CONTROLS SET FOR LOW EMISSIONSTRATEGY. BACT-PSDDILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #13 1050 KW 24.9 LB/HFOLLOWPOWERGENERATIONLIMITSASSPECIFIED IN THE PROCESS NOTES. OPERATE BACT-PSDKENAI REFINERY AK 9923-AC010 3/21/2000 UPPER TANK FARM CAT 3412DT, P708C 660 HP 3.1 LB/MMBTU NONE INDICATED. N/AKENAI REFINERY AK 9923-AC010 3/21/2000 EMERGENCY GENERATOR, CF-G-70003 2 MW 7 G/KW-HAFTER-COOLING COMBINED WITH HIGHPRESSURE FUEL INJECTION PUMPS ANDCYLINDER DESIGN TO ENSURE CLEAN BURN INTHE CYLINDER. BACT-PSDKENAI REFINERY AK 9923-AC010 3/21/2000 EMERGENCY GENERATOR, CF-G-70004 2 MW 7 G/KW-HAFTER-COOLING COMBINED WITH HIGHPRESSURE FUEL INJECTION PUMPS ANDCYLINDER DESIGN TO ENSURE CLEAN BURN INTHE CYLINDER. BACT-PSDSAN JUAN REPOWERINGPROJECT PR 5 3/2/2000 AUXILIARY DIESEL GENERATOR 5000 KW 168 LB/H (AS NO2) GOOD COMBUSTION CONTROL BACT-PSDARCHER GENERATINGSTATIONTXPSD-TX-9371/3/2000EMERGENCY ELECTRICAL GENERATOR2000 KW 46.8 LB/HBACT-PSDAtt 10-E_Diesel-Fired IC Engines over 500HP_RBLC.xlsNOx7/10/2007FACILITY STATE PERMIT NUMBER PERMITDATEDESCRIPTIONCONTROL DESCRIPTION BASISKANSAS CITY PUBLIC UTILITIES- NEARMAN CREEK STATIONKS C-570 10/18/2005EMERGENCY BLACK STARTGENERATOR 2800 KW 7.01 LB/HR GOOD ENGINE DESIGN BACT-PSDARIZONA CLEAN FUELS YUMALLCAZ 1001205 4/14/2005 FIRE WATER PUMP ENGINES 5.46 MMBTU/H 3.5 GR/KW-HR NONE INDICATED. BACT-PSDARIZONA CLEAN FUELS YUMALLCAZ 1001205 4/14/2005 EMERGENCY GENERATOR 10.9 MMBTU/H 3.5 GR/KW-HR NONE INDICATED BACT-PSDFIRST QUALITY TISSUE, LLC PA 18-315-001 10/20/2004 FIRE PUMP 575 hp 0.0067 LB/HP-H BACT-PSDPSI ENERGY-MADISONSTATION OH 14-04682 8/24/2004 EMERGENCY DIESEL GENERATOR, 2 17.21 MMBTU/H 14.63 LB/H BACT-PSDFAIRBAULT ENERGY PARK MN 13100071-001 7/15/2004 IC ENGINE, LARGE, FUEL OIL (1) 670 HP 0.76 LB/MMBTU GOOD COMBUSTION. BACT-PSDLONGVIEW POWER LLC -MAIDSVILLE WV R14-0024 3/2/2004 EMERGENCY GENERATOR 1801 HP 8.85 LB/HR GOOD COMBUSTION PRACTICES BACT-PSDACE ETHANOL - STANLEY WI 03-DCF-184 1/21/2004IC ENGINE, DIESEL GENERATOR SET,B70 1850 BHP 1 G/HP-H LIMITED OPERATION, DESIGN BACT-PSDMANKATO ENERGY CENTER MN 01300098-001 12/4/2003INTERNAL COMBUSTION ENGINE,LARGE 1850 HP 1 G/B-HP-H GOOD COMBUSTION BACT-PSDUSAF EARECKSON AIRSTATION AK 307CP01 9/29/2003 IC ENGINE, DIESEL, (2) 3000 KW 4.4 LB/H SCR OXIDATION CATALYST BACT-PSDDUKE ENERGY WASHINGTONCOUNTY LLC OH 06-06792 8/14/2003EMERGENCY DIESEL-FIREDGENERATOR 600 KW 15.2 LB/HLOW SULFUR FUEL, COMBUSTIONCONTROL BACT-PSDINGENCO - CHARLES CITYPLANT VA 51998 6/20/2003 IC ENGINES, (48) 550 HP 3.3 LB/MMBTULIMITING THE TREATED LANDFILL GASHEAT INPUT RATION TO 50% AND ALANDFILL GAS TREATMENT SYSTEM. Other Case-by-CaseMIDAMERICAN ENERGYCOMPANY IA PROJECT 02-528 6/17/2003 EMERGENCY GENERATOR 97.73 GAL/HR 0.85 LB/MMBTU GOOD COMBUSTION PRACTICES BACT-PSDSTEPHENS ENERGY OK 2001-157-C M-1 PSD 3/21/2003 DIESEL 749 BHP 2.66 LB/MMBTU COMBUSTION PRACTICES BACT-PSDGLASS PLANT OK 2002-487-C PSD 3/18/2003 GENERATORS (2) 2000 KW 0.202 LB/MMBTU OF OPERATION (<500 H/YR) BACT-PSDPACIFIC BELL CA 16290 2/1/2003 IC ENGINES 2935 HP 8.5 G/B-HP-H LAERSTERNE ELECTRICGENERATING FACILITY TX PSD-TX-1015 12/6/2002 EMERGENCY GENERATOR 1350 HP 9.02 LB/H BACT-PSDUNIVERSITY OF CINCINNATI OH 14-05108 8/15/2002DIESEL FIRED ENGINES (2), 2 MW,2922 BHP 19.17 MMBTU/H 1.73 LB/H BACT-PSDHAWKEYE GENERATING, LLC IA 01-687 7/23/2002 EMERGENCY GENERATOR 18500 GALLONS/YR 0.22 LB/H GCP, TIMING RETARD BACT-PSDGENOVA OK I POWER PROJECT OK 2001-223-C PSD 6/13/2002DIESEL ENGINE, BACKUPGENERATOR 750 KW 0.31 LB/MMBTU ENGINE DESIGN BACT-PSDSCE&G - JASPER COUNTYGENERATING FACILITY SC 1360-0026-CA-CC 5/23/2002GENERATOR, EMERGENCY,DIESELFUEL 2000 KW 15.8 LB/H BACT-PSDPHELPS DODGE TYRONE, INC NM PSD-NM-2488A 5/20/2002IC ENGINES, NON-DUAL FUEL MODE,(15) 3090 HP/H 9.4 LB/H GOOD OPERATING PRACTICES Other Case-by-CaseREDBUD POWER PLT OK 2000-090-C M-1 PSD 5/6/2002DIESEL ENGINE, EMERGENCYGENERATOR 1818 HP 0.055 LB/B-HP-H ENGINE DESIGN BACT-PSDGREATER DES MOINESENERGY CENTER IA 77-13-002 4/10/2002 EMERGENCY GENERATOR 700 KW 2.86 LB/H BACT-PSDDUKE ENERGY-JACKSONFACILITY AR 1998-AOP-R0 (34-0259) 4/1/2002 GENERATOR, DIESEL-FIRED 671 HP 8.5 G/B-HP-H GOOD OPERATING PRACTICE BACT-PSDAES RED OAK LLC NJ 10001 10/24/2001 EMERGENCY GENERATOR 49 MMBTU/H 1.11 LB/H GOOD COMBUSTION PRACTICE BACT-PSDTHROUGHPUTAttachment 10-ERACT/BACT/LAER Clearinghouse Results for Diesel-Fired Engines > 500 HP (CO)EMISSION LIMITAtt 10-E_Diesel-Fired IC Engines over 500HP_RBLC.xlsCO7/10/2007FACILITY STATE PERMIT NUMBER PERMITDATEDESCRIPTIONCONTROL DESCRIPTION BASISTHROUGHPUTAttachment 10-ERACT/BACT/LAER Clearinghouse Results for Diesel-Fired Engines > 500 HP (CO)EMISSION LIMITMANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001CATERPILLAR BACK-UP DIESEL AIRCOMPRESSORS, 2 775 HP EACH 5.4 LB/H PREVENTATIVE MAINTENANCE BACT-PSDMANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001AUXILIARY DIESEL GENERATORSNO.1 & NO.2 1100 HP EACH 10.6 LB/H PREVENTATIVE MAINTENANCE BACT-PSDMANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001ADMINISTRATION BUILDING DIESELGENERATOR 587 HP 3.9 LB/H PREVENTATIVE MAINTENANCE BACT-PSDPSEG WATERFORD ENERGYLLC OH 06-06739 3/29/2001 EMERGENCY GENERATOR 1000 KW 0.22 T/YR BACT-PSDDUKE ENERGY HOT SPRINGS AR 1936-AOP-R0 12/29/2000 GENERATORS, (2) DIESEL 600 KW 31 G/B-HP-H PROPER COMBUSTION. BACT-PSDCOTTONWOOD ENERGYPROJECT TX PSD-965 12/15/2000 FIRE WATER PUMP 2.24 LB/H BACT-PSDCOTTONWOOD ENERGYPROJECT TX PSD-965 12/15/2000 EMERGENCY DIESEL GENERATOR 2.67 LB/H BACT-PSDBADGER GENERATING CO LLC WI 99-RV-143 9/20/2000 DIESEL ENGINE, GENERATOR (4) 3.5 MMBTU/H 3.33 LB/HGOOD COMBUSTION PRACTICES.PERMIT LIMITS SET IN LB/H, NOT G/BHPH. BACT-PSDBADGER GENERATING CO LLC WI 99-RV-143 9/20/2000DIESEL ENGINE, EMERGENCY FIREPUMP 3.8 MMBTU/H 3.61 LB/HGOOD COMBUSTION PRACTICES,EQUIPMENT USAGE LIMITS. PERMITLIMITS SET IN LB/H, NO LIMITS IN G/B-HPH. BACT-PSDOKEMO MOUNTAIN INC. VT OP-99-013 9/5/2000 GENERATOR, FUEL OIL 1480 BHP 0.6 G/B-HP-HSCR OXIDATION CATALYST WITH UREAINJECTION, NO REGULATORY BASIS Other Case-by-CaseBRAZOS VALLEY ELECTRICGENERATING FACILITY TX PSD-TX-966 8/23/2000 EMERGENCY GENERATOR 1350 hp 9.02 LB/H N/ABRAZOS VALLEY ELECTRICGENERATING FACILITY TX PSD-TX-966 8/23/2000 FIRE WATER PUMP 300 hp 2 LB/H N/AFORD ELECTRONICS ANDREFRIGERATION, LLC PA PA-46-0036A 6/19/2000 DIESEL ENGINES 2 MW 34 LB/HHOURLY LIMIT FOR EACH ENGINE,ANNUAL FOR ALL FIVE ENGINES. Other Case-by-CaseMILL RIVER LUMBER, LTD. VT AOP-95-081B 6/8/2000ELECTRIC GENERATIONCATERPILLAR 3412C 1023 HP 0.6 LB/HSCR OXIDATION CATALYST WITH UREAINJECTION. NO REGULATORY BASIS,LIMIT BASED ON MANUFACTURER'SGUARANTEE. Other Case-by-CaseDILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #11 1050 KW 90 T/12 MO PERIODCOMPLY WITH POWER GENERATIONLIMIT AS SPECIFIED IN THE PROCESSNOTES. Other Case-by-CaseDILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #12 1050 KW 90 T/12 MO PERIODCOMPLY WITH POWER GENERATIONLIMITS AS SPECIFIED IN PROCESSNOTES. Other Case-by-CaseDILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #13 1050 KW 90 T/12 MO PERIODCOMPLY WITH POWER GENERATIONLIMITS AS SPECIFIED IN PROCESSNOTES. Other Case-by-CaseKENAI REFINERY AK 9923-AC010 3/21/2000UPPER TANK FARM CAT 3412DT,P708C 660 HP 0.81 LB/MMBTU NONE INDICATED. Other Case-by-CaseKENAI REFINERY AK 9923-AC010 3/21/2000EMERGENCY GENERATOR, CF-G70003 2 MW 1.95 G/KW-HGOOD OPERATIONAL PRACTICES ANDMAINTENANCE BACT-PSDKENAI REFINERY AK 9923-AC010 3/21/2000EMERGENCY GENERATOR, CF-G70004 2 MW 1.95 G/KW-HGOOD OPERATIONAL PRACTICES ANDMAINTENANCE BACT-PSDSAN JUAN REPOWERINGPROJECT PR 5 3/2/2000 AUXILIARY DIESEL GENERATOR 5000 KW 44.6 LB/H GOOD COMBUSTION PRACTICES BACT-PSDARCHER GENERATINGSTATION TX PSD-TX-937 1/3/2000EMERGENCY ELECTRICALGENERATOR 2000 KW 34.9 LB/H BACT-PSDAtt 10-E_Diesel-Fired IC Engines over 500HP_RBLC.xlsCO7/10/2007FACILITY STATE PERMIT NUMBER PERMITDATEDESCRIPTIONCONTROL DESCRIPTION BASISKANSAS CITY PUBLIC UTILITIES -NEARMAN CREEK STATIONKS C-57010/18/2005EMERGENCY BLACK STARTGENERATOR2800 KW 1.2 LB/HRGOOD COMBUSTION CONTROLBACT-PSDPSI ENERGY-MADISON STATIONOH 14-04682 8/24/2004EMERGENCY DIESEL GENERATOR,217.21 MMBTU/H 8.61 LB/HSULFUR LIMITED TO 0.05 % BY WEIGHT.OPERATIONS LIMITED TO 499 HOUR PERYEARBACT-PSDFAIRBAULT ENERGY PARKMN 13100071-001 7/15/2004IC ENGINE, LARGE, FUEL OIL(1)670 HP 0.051 LB/MMBTULOW SULFUR FUEL.BACT-PSDLONGVIEW POWER LLC -MAIDSVILLEWV R14-0024 3/2/2004EMERGENCY GENERATOR1801 HP 6.5 LB/HRFUEL SULFUR CONTENT LIMITED TO 0.05% SBACT-PSDU.S. ARMY - PINE BLUFF ARSENALAR 1113-AOP-R0 2/17/2004EMERGENCY GENERATORS (2)2500 KW 0.6 LB/HRFUEL SULFUR CONTENT LIMITED TO 0.05% SBACT-PSDMANKATO ENERGY CENTERMN 01300098-001 12/4/2003INTERNAL COMBUSTION ENGINE,LARGE1850 HP 0.59 G/B-HP-HLOW SULFUR FUELBACT-PSDDUTCH HARBOR SEAFOODPROCESSING FACILITYAK 433CP01(MOD) 10/10/2003IC ENGINE, GENERATOR, FUEL OIL,(3)2220 KWLOW SULFUR FUEL: SULFUR RESTRICTIONOF 0.24% S BY WT FOR A JET A AND DIESELNO. 2 FUEL BLEND.BACT-PSDUSAF EARECKSON AIR STATIONAK 307CP01 9/29/2003IC ENGINESLOW SULFUR FUEL: < 0.3% S BY WTBACT-PSDDUKE ENERGY WASHINGTONCOUNTY LLCOH 06-06792 8/14/2003EMERGENCY DIESEL-FIREDGENERATOR600 KW 0.4 LB/HLOW SULFUR FUEL, COMBUSTION CONTROLBACT-PSDINGENCO - CHARLES CITY PLANTVA 51998 6/20/2003IC ENGINES, (48)550 HP 0.5 LB/MMBTUGOOD COMBUSTION PRACTICESRACTMIDAMERICAN ENERGY COMPANYIA PROJECT 02-528 6/17/2003EMERGENCY GENERATOR97.73 GAL/HR 0.052 LB/MMBTUGOOD COMBUSTION PRACTICES AND LOWSULFUR FUELBACT-PSDDUKE ENERGY STEPHENS, LLCSTEPHENS ENERGYOK 2001-157-C M-1 PSD 3/21/2003IC ENGINE, BACKUP GENERATOR,DIESEL749 BHP 0.3 LB/HUSE OF LOW SULFUR DIESEL FUEL(< 0.05%S BY WT)BACT-PSDGLASS PLANTOK 2002-487-C PSD 3/18/2003GENERATORS (2)2000 KW 0.05 LB/MMBTULOW SULFUR FUEL, < 0.05% SBACT-PSDPACIFIC BELLCA 16290 2/1/2003IC ENGINES2935 HP 0.16 G/B-HP-H LAERBRIDGESTONE/FIRESTONE NORTHAMERICAN TIRENC 01660T42 1/24/2003IC ENGINES, AIR COMPRESSORS,DIESEL, (5)4.46 MMBTU/H 2.3 LB/MMBTU Other Case-by-CaseSTERNE ELECTRIC GENERATINGFACILITYTX PSD-TX-1015 12/6/2002EMERGENCY GENERATOR1350 HP 2.77 LB/HDISTILLATE FUEL OIL CONTAINING NO MORETHAN 0.2 WEIGHT PERCENT OF SULFUR.BACT-PSDUNIVERSITY OF CINCINNATIOH 14-05108 8/15/2002DIESEL FIRED ENGINES (2), 2 MW,2922 BHP19.17 MMBTU/H 0.043 LB/MMBTUSULFUR CONTENT OF DIESEL FUEL LESSTHAN 0.05 PERCENT.BACT-PSDSCE&G - JASPER COUNTYGENERATING FACILITYSC 1360-0026-CA-CC 5/23/2002GENERATOR, EMERGENCY,DIESELFUEL2000 KW 0.9 LB/HLOW SULFUR (0.05%) DIESELBACT-PSDPHELPS DODGE TYRONE, INCNM PSD-NM-2488A 5/20/2002IC ENGINES, NON-DUAL FUELMODE, (15)3090 HP/HFUEL SULFUR LIMIT: LOW SULFUR DIESEL(<0.05% S BY WT)Other Case-by-CaseREDBUD POWER PLTOK 2000-090-C M-1 PSD 5/6/2002DIESEL ENGINE, EMERGENCYGENERATOR1818 HP 0.4 LB/MMBTU BACT-PSDDUKE ENERGY-JACKSON FACILITYAR 1998-AOP-R0 (34-0259) 4/1/2002GENERATOR, DIESEL-FIRED671 HPFUELS LIMIT: 0.05% S BY WTBACT-PSDAES RED OAK LLCNJ 10001 10/24/2001EMERGENCY GENERATOR49 MMBTU/H 2.45 LB/HLOW SULFUR FUELBACT-PSDFORT BRAGGNC 04379T21 8/20/2001IC ENGINES, DIESEL,(17)2.3 LB/MMBTU Other Case-by-CaseTHROUGHPUTAttachment 10-ERACT/BACT/LAER Clearinghouse Results for Diesel-Fired Engines > 500 HP (SO2)EMISSION LIMITAtt 10-E_Diesel-Fired IC Engines over 500HP_RBLC.xlsSO27/10/2007FACILITY STATE PERMIT NUMBER PERMITDATEDESCRIPTIONCONTROL DESCRIPTION BASISTHROUGHPUTAttachment 10-ERACT/BACT/LAER Clearinghouse Results for Diesel-Fired Engines > 500 HP (SO2)EMISSION LIMITMANSFIELD MILLLA PSD-LA-93 (M-6) 8/14/2001CATERPILLAR BACK-UP DIESEL AIRCOMPRESSORS, 2775 HP EACH 1.6 LB/HPREVENTATIVE MAINTENANCEBACT-PSDMANSFIELD MILLLA PSD-LA-93 (M-6) 8/14/2001AUXILIARY DIESEL GENERATORSNO.1 & NO.21100 HP EACH 2.2 LB/HPREVENTATIVE MAINTENANCEBACT-PSDMANSFIELD MILLLA PSD-LA-93 (M-6) 8/14/2001ADMINISTRATION BUILDING DIESELGENERATOR587 HP 1.2 LB/HPREVENTATIVE MAINTENANCEBACT-PSDPSEG WATERFORD ENERGY LLCOH 06-06739 3/29/2001EMERGENCY GENERATOR1000 KW 0.01 T/YRLOW SULFUR FUELBACT-PSDCOTTONWOOD ENERGY PROJECTTX PSD-965 12/15/2000FIRE WATER PUMP0.69 LB/HBACT-PSDCOTTONWOOD ENERGY PROJECTTX PSD-965 12/15/2000EMERGENCY DIESEL GENERATOR0.82 LB/HBACT-PSDBADGER GENERATING CO LLCWI 99-RV-143 9/20/2000DIESEL ENGINE, GENERATOR (4)3.5 MMBTU/H 1.02 LB/HSULFUR CONTENT <= .05% BY WT. PERMITLIMITS ARE FUEL SULFUR CONTENT LIMITAND LB/H LIMIT, NOT G/BHP-H.BACT-PSDBADGER GENERATING CO LLCWI 99-RV-143 9/20/2000DIESEL ENGINE, EMERGENCY FIREPUMP3.8 MMBTU/H 1.1 LB/HTHE USE OF DIESEL FUEL HAVING A SULFURCONTENT OF .05% BY WT., AND EQUIPMENTUSAGE LIMITS. PERMIT LIMITS ARE FUELSULFUR CONTENT LIMITS AND LB/H LIMIT,NO LIMIT IN G/BHP-H.BACT-PSDBRAZOSVALLEYELECTRICGENERATING FACILITYTX PSD-TX-966 8/23/2000EMERGENCY GENERATOR1350 hp 2.77 LB/HFUEL SULFUR LIMIT: < 0.3 WT % SBACT-PSDBRAZOSVALLEYELECTRICGENERATING FACILITYTX PSD-TX-966 8/23/2000FIRE WATER PUMP300 hp 0.62 LB/HFUEL SULFUR LIMITS: < 0.3 WT % SBACT-PSDFORDELECTRONICSANDREFRIGERATION, LLCPA PA-46-0036A 6/19/2000DIESEL ENGINES2 MW 4 LB/HHOURLYLIMITFOREACHENGINE,ANNUALFOR ALL FIVE ENGINES. EMISSION LIMITSOther Case-by-CaseNORTH COOK INLET UNITAK 0023-AC007 6/6/2000CATERPILLAR D-398 ENGINES NO. 1AND 2500 KW EACH 500 PPMUSE NATURAL GAS WITH A HYDROGENSULFIDE CONTENT NOT TO EXCEED 200 PPMAND FUEL OIL WITH A SULFUR CONTENTNOT TO EXCEED 0.25% BY WEIGHTN/ADILLINGHAM POWER PLANTAK 0025-AC003 5/8/2000DIESEL ELECTRIC GENERATOR #3350 KW 63.3 T/12 MO. PERIODTHE SULFUR CONTENT OF THE FUEL OILBURNED MUST NOT EXCEED 0.50 PERCENTBY WEIGHT AT ANY TIME. FOLLOW THEPOWER GENERATION LIMITS AS SPECIFIEDIN THE PROCESS NOTES.Other Case-by-CaseDILLINGHAM POWER PLANTAK 0025-AC003 5/8/2000DIESEL ELECTRIC GENERATOR #4500 KW 63.3 T/12 MO PERIODTHE SULFUR CONTENT OF THE FUEL OILBURNED MUST NOT EXCEED 0.50 PERCENTBY WEIGHT AT ANY TIME.Other Case-by-CaseDILLINGHAM POWER PLANTAK 0025-AC003 5/8/2000DIESEL ELECTRIC GENERATOR #5750 KW 63.3 T/12 MO PERIODTHE SULFUR CONTENT OF THE FUEL OILBURNED MUST NOT EXCEED 0.50 PERCENTBY WEIGHT AT ANY TIME. FOLLOW THEPOWER GENERATION LIMITS AS SPECIFIEDIN THE PROCESS NOTES.Other Case-by-CaseDILLINGHAM POWER PLANTAK 0025-AC003 5/8/2000DIESEL ELECTRIC GENERATOR #61000 KW 63.3 T/12 MO. PERIODTHE SULFUR CONTENT OF THE FUEL OILBURNED MUST NOT EXCEED 0.50 PERCENTBY WEIGHT AT ANY TIME. FOLLOW THEPOWER GENERATION LIMITS AS SPECIFIEDIN THE PROCESS NOTES.Other Case-by-CaseAtt 10-E_Diesel-Fired IC Engines over 500HP_RBLC.xlsSO27/10/2007FACILITY STATE PERMIT NUMBER PERMITDATEDESCRIPTIONCONTROL DESCRIPTION BASISTHROUGHPUTAttachment 10-ERACT/BACT/LAER Clearinghouse Results for Diesel-Fired Engines > 500 HP (SO2)EMISSION LIMITDILLINGHAM POWER PLANTAK 0025-AC003 5/8/2000DIESEL ELECTRIC GENERATOR #8835 KW 63.3 T/12 MO PERIODTHE SULFUR CONTENT OF THE FUEL OILBURNED MUST NOT EXCEED 0.50 PERCENTBY WEIGHT AT ANY TIME. FOLLOW THEPOWER GENERATION LIMITS AS SPECIFIEDIN THE PROCESS NOTES.Other Case-by-CaseDILLINGHAM POWER PLANTAK 0025-AC003 5/8/2000DIESEL ELECTRIC GENERATOR #9835 KW 63.3 T/12 MO. PERIODTHE SULFUR CONTENT OF THE FUEL OILBURNED MUST NOT EXCEED 0.50 PERCENTBY WEIGHT AT ANY TIME. FOLLOW THEPOWER GENERATION LIMITS AS SPECIFIEDIN THE PROCESS NOTES.Other Case-by-CaseDILLINGHAM POWER PLANTAK 0025-AC003 5/8/2000DIESEL ELECTRIC GENERATOR, #101135 KW 63.3 T/12 MO. PERIODTHE SULFUR CONTENT OF THE FUEL OILBURNED MUST NOT EXCEED 0.50 PERCENTBY WEIGHT AT ANY TIME. FOLLOW THEPOWER GENERATION LIMITS AS SPECIFIEDIN THE PROCESS NOTES.Other Case-by-CaseDILLINGHAM POWER PLANTAK 0025-AC003 5/8/2000DIESEL ELECTRIC GENERATOR #111050 KW 63.3 T/12 MO PERIODTHE SULFUR CONTENT OF THE FUEL OILBURNED MUST NOT EXCEED 0.50 PERCENTBY WEIGHT AT ANY TIME. FOLLOW THEPOWER GENERATION LIMITS AS SPECIFIEDIN THE PROCESS NOTES.Other Case-by-CaseDILLINGHAM POWER PLANTAK 0025-AC003 5/8/2000DIESEL ELECTRIC GENERATOR #121050 KW 63.3 T/12 MO. PERIODTHE SULFUR CONTENT OF THE FUEL OILBURNED MUST NOT EXCEED 0.50 PERCENTBY WEIGHT AT ANY TIME. FOLLOW THEPOWER GENERATION LIMITS AS SPECIFIEDIN THE PROCESS NOTES.Other Case-by-CaseDILLINGHAM POWER PLANTAK 0025-AC003 5/8/2000DIESEL ELECTRIC GENERATOR #131050 KW 63.3 T/12 MO PERIODTHE SULFUR CONTENT OF THE FUEL OILBURNED MUST NOT EXCEED 0.50 PERCENTBY WEIGHT AT ANY TIME. FOLLOW THEPOWER GENERATION LIMITS AS SPECIFIEDIN THE PROCESS NOTES.Other Case-by-CaseLAKEFIELD JUNCTION LPGENERATING STATIONMN 09100058-002 5/4/2000GENERATOR, BLACK-START2 MW 0.5 LB/MMBTULOW SULFUR FUEL; LIMITED OPERATION TO1,000 H/ROLLING 12-MOBACT-PSDKENAI REFINERYAK 9923-AC010 3/21/2000UPPER TANK FARM CAT 3412DT,P708C660 HP 500 PPMFUEL SULFUR CONTENT LIMITS ASFOLLOWS: DIESEL, 0.35% SULFUR; NATURALGAS, 0.01% SULFUR; LPG, 0.01% SULFUR;REFINERY GAS, 168 PPMV H2S.BACT-PSDKENAI REFINERYAK 9923-AC010 3/21/2000EMERGENCY GENERATOR, CF-G700032 MWUSE ONLY FUEL GAS WITH A HYDROGENSULFIDE CONTENT NOT TO EXCEED 200 PPMAND USE DISTILLATE FUEL OIL WITH ASULFUR CONTENT NOT TO EXCEED 0.15%.BACT-PSDKENAI REFINERYAK 9923-AC010 3/21/2000EMERGENCY GENERATOR, CF-G700042 MWUSE ONLY FUEL GAS WITH A HYDROGENSULFIDE CONTENT NOT TO EXCEED 200 PPMAND USE DISTILLATE FUEL OIL WITH ASULFUR CONTENT NOT TO EXCEED 0.15%.Other Case-by-CaseSAN JUAN REPOWERING PROJECTPR 5 3/2/2000AUXILIARY DIESEL GENERATOR5000 KW 2.65 LB/HGOOD COMBUSTION CONTROLBACT-PSDARCHER GENERATING STATIONTX PSD-TX-937 1/3/2000EMERGENCY ELECTRICALGENERATOR2000 KW 1.9 LB/HBACT-PSDAtt 10-E_Diesel-Fired IC Engines over 500HP_RBLC.xlsSO27/10/2007FACILITY STATE PERMIT NUMBER PERMITDATEDESCRIPTION CONTROL DESCRIPTION BASISPSI ENERGY-MADISON STATION OH 14-04682 8/24/2004 EMERGENCY DIESEL GENERATOR, 2 17.21 MMBTU/H 1.55 LB/H BACT-PSDFAIRBAULT ENERGY PARK MN 13100071-001 7/15/2004 IC ENGINE, LARGE, FUEL OIL(1)670 HP 0.1 LB/MMBTU GOOD COMBUSTION. BACT-PSDLONGVIEW POWER LLC - MAIDSVILLE WV R14-0024 3/2/2004 EMERGENCY GENERATOR1801 HP 1.21 LB/HR GOOD COMBUSTION PRACTICES BACT-PSDACE ETHANOL - STANLEY WI 03-DCF-184 1/21/2004IC ENGINE, DIESEL GENERATOR SET,B70 1850 BHP 0.12 G/HP-H LIMITED OPERATION, DESIGN BACT-PSDMANKATO ENERGY CENTERMN 01300098-001 12/4/2003INTERNAL COMBUSTION ENGINE,LARGE 1850 HP 0.12 G/B-HP-H GOOD COMBUSTION BACT-PSDDUKE ENERGY WASHINGTON COUNTY LLC OH 06-06792 8/14/2003EMERGENCY DIESEL-FIREDGENERATOR 600 KW 1.76 LB/HLOW SULFUR FUEL, COMBUSTIONCONTROL BACT-PSDINGENCO - CHARLES CITY PLANT VA 51998 6/20/2003 IC ENGINES,(48)550 HP 0.4 LB/MMBTU GOOD COMBUSTION PRACTICES. N/AMIDAMERICAN ENERGY COMPANYIA PROJECT 02-528 6/17/2003 EMERGENCY GENERATOR97.73 GAL/HR 0.09 LB/MMBTU GOOD COMBUSTION PRACTICES BACT-PSDDUKE ENERGY STEPHENS, LLC STEPHENSENERGYOK 2001-157-C M-1 PSD 3/21/2003IC ENGINE, BACKUP GENERATOR,DIESEL 749 BHP 1.7 LB/H BACT IS GOOD ENGINE DESIGN BACT-PSDCARDINAL FG CO./ CARDINAL GLASS PLANT OK2002-487-C PSD 3/18/2003IC ENGINES, EMERGENCYGENERATORS(2)2000 KW 2.17 LB/HENGINE DESIGN AND LIMIT ONHOURS OF OPERATION(<500 H/YR)BACT-PSDPACIFIC BELL CA 16290 2/1/2003 IC ENGINES 2935 HP 1 G/B-HP-H LAERSTERNE ELECTRIC GENERATING FACILITY TX PSD-TX-1015 12/6/2002 EMERGENCY GENERATOR1350 HP 3.33 LB/H BACT-PSDUNIVERSITY OF CINCINNATI OH 14-05108 8/15/2002DIESEL FIRED ENGINES (2), 2 MW, 2922BHP 19.17 MMBTU/H 1.04 LB/H BACT-PSDHAWKEYE GENERATING, LLC IA 01-687 7/23/2002 EMERGENCY GENERATOR18500 GALLONS/YR0.07 LB/H GCP, TIMING RETARD BACT-PSDSCE&G - JASPER COUNTY GENERATINGFACILITYSC 1360-0026-CA-CC 5/23/2002GENERATOR, EMERGENCY,DIESELFUEL 2000 KW 1.7 LB/H LAERREDBUD POWER PLT OK2000-090-C M-1 PSD 5/6/2002DIESEL ENGINE, EMERGENCYGENERATOR 1818 HP 0.0007 LB/B-HP-H ENGINE DESIGN BACT-PSDDUKE ENERGY-JACKSON FACILITYAR 1998-AOP-R0(34-0259)4/1/2002 GENERATOR, DIESEL-FIRED 671 HP 1.1 G/B-HP-H GOOD OPERATING PRACTICE BACT-PSDAES RED OAK LLC NJ 10001 10/24/2001 EMERGENCY GENERATOR49 MMBTU/H 12.04 LB/H GOOD COMBUSTION LAERMANSFIELD MILL LA PSD-LA-93(M-6)8/14/2001CATERPILLAR BACK-UP DIESEL AIRCOMPRESSORS, 2 775 HP EACH 1.9 LB/H PREVENTATIVE MAINTENANCE BACT-PSDMANSFIELD MILL LA PSD-LA-93(M-6)8/14/2001AUXILIARY DIESEL GENERATORS NO.1& NO.2 1100 HP EACH 2.7 LB/H PREVENTATIVE MAINTENANCE BACT-PSDMANSFIELD MILL LA PSD-LA-93(M-6)8/14/2001ADMINISTRATION BUILDING DIESELGENERATOR 587 HP 1.4 LB/H PREVENTATIVE MAINTENANCE BACT-PSDPSEG WATERFORD ENERGY LLC OH 06-06739 3/29/2001 EMERGENCY GENERATOR1000 KW 0.02 T/YRBACT-PSDDUKE ENERGY HOT SPRINGSAR 1936-AOP-R0 12/29/2000 GENERATORS,(2)DIESEL 600 KW 1.1 G/B-HP-H PROPER COMBUSTION PRACTICE BACT-PSDCOTTONWOOD ENERGY PROJECTTX PSD-965 12/15/2000 FIRE WATER PUMP 0.84 LB/H BACT-PSDCOTTONWOOD ENERGY PROJECTTX PSD-965 12/15/2000 EMERGENCY DIESEL GENERATOR 1.01 LB/H BACT-PSDBADGER GENERATING CO LLC WI 99-RV-143 9/20/2000 DIESEL ENGINE, GENERATOR(4)3.5 MMBTU/H 1.26 LB/HGOOD COMBUSTION PRACTICES.PERMIT LIMITS SET IN LB/H, NOTG/BHP-H. Other Case-by-CaseBADGER GENERATING CO LLC WI 99-RV-143 9/20/2000DIESEL ENGINE, EMERGENCY FIREPUMP 3.8 MMBTU/H 1.37 LB/HGOOD COMBUSTION PRACTICES,EQUIPMENT USAGE LIMITS. PERMITLIMITS SET IN LB/H, NO LIMITS ING/BHP-H. BACT-PSDBRAZOS VALLEY ELECTRIC GENERATINGFACILITYTX PSD-TX-966 8/23/2000 EMERGENCY GENERATOR1350 hp 3.39 LB/H N/ABRAZOS VALLEY ELECTRIC GENERATINGFACILITYTX PSD-TX-966 8/23/2000 FIRE WATER PUMP 300 hp 0.75 LB/H N/AFORD ELECTRONICS AND REFRIGERATION,LLC PA PA-46-0036A 6/19/2000 DIESEL ENGINES 2 MW 0.46 LB/HHOURLY LIMIT FOR EACH ENGINE,ANNUAL FOR ALL FIVE ENGINES.EMISSION LIMITS AVAILABLE ONLYIN LB/H AND T/YR. Other Case-by-CaseSAN JUAN REPOWERING PROJECT PR 5 3/2/2000AUXILIARY DIESEL GENERATOR 5000 KW 4.3 LB/HGOOD COMBUSTION; LIMITEDOPERATION BACT-PSDARCHER GENERATING STATION TX PSD-TX-937 1/3/2000EMERGENCY ELECTRICALGENERATOR 2000 KW 2.9 LB/H BACT-PSDTHROUGHPUTRACT/BACT/LAER Clearinghouse Results for Diesel-Fired Engines > 500 HP (VOC)Attachment 10-EEMISSION LIMITAtt 10-E_Diesel-Fired IC Engines over 500HP_RBLC.xlsVOC7/10/2007FACILITY STATE PERMIT NUMBER PERMITDATEDESCRIPTION CONTROL DESCRIPTION BASISARIZONA CLEAN FUELS YUMA LLCAZ 1001205 4/14/2005 FIRE WATER PUMP ENGINES 5.46 MMBTU/H 0.2 GR/KW-HR NONE INDICATED. BACT-PSDARIZONA CLEAN FUELS YUMA LLCAZ 1001205 4/14/2005 EMERGENCY GENERATOR 10.9 MMBTU/H 0.2 GR/KW-HR NONE INDICATED BACT-PSDFAIRBAULT ENERGY PARK MN 13100071-001 7/15/2004 IC ENGINE, LARGE, FUEL OIL (1) 670 HP 0.1 LB/MMBTUCLEAN FUEL AND GOODCOMBUSTION. BACT-PSDACE ETHANOL - STANLEY WI 03-DCF-184 1/21/2004IC ENGINE, DIESEL GENERATOR SET,B70 1850 BHP 0.07 G/HP-HUSE OF VERY LOW SULFUR DIESELFUEL (0.05 WT % S). BACT-PSDMANKATO ENERGY CENTER MN 01300098-001 12/4/2003INTERNAL COMBUSTION ENGINE,LARGE 1850 HP 0.07 G/B-HP-H GOOD COMBUSTION BACT-PSDDUKE ENERGY WASHINGTON COUNTYLLC OH 06-06792 8/14/2003EMERGENCY DIESEL-FIREDGENERATOR 600 KW 0.72 LB/HLOW SULFUR FUEL, COMBUSTIONCONTROL BACT-PSDINGENCO - CHARLES CITY PLANT VA 51998 6/20/2003 IC ENGINES, (48) 550 HP 0.2 LB/MMBTU GOOD COMBUSTION PRACTICES. N/AMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 EMERGENCY GENERATOR 97.73 GAL/HR 0.14 LB/MMBTU GOOD COMBUSTION PRACTICES BACT-PSDROQUETTE AMERICA IA 56-01-009 1/31/2003 IC ENGINE, DIESEL 710 HP 0.069 LB/MMBTULOW ASH FUELS, GOODCOMBUSTION PRACTICES BACT-PSDHAWKEYE GENERATING, LLC IA 01-687 7/23/2002 EMERGENCY GENERATOR 18500 GALLONS/YR 0.34 LB/H GCP, TIMING RETARD BACT-PSDSCE&G - JASPER COUNTY GENERATINGFACILITY SC 1360-0026-CA-CC 5/23/2002GENERATOR, EMERGENCY,DIESELFUEL 2000 KW 1.9 LB/HCLEAN FUEL(LOW SULFUR DIESEL),GOOD COMBUSTION PRACTICES BACT-PSDAES RED OAK LLC NJ 10001 10/24/2001 EMERGENCY GENERATOR 49 MMBTU/H 2.67 LB/H LIMITED USE BACT-PSDDUKE ENERGY HOT SPRINGS AR 1936-AOP-R0 12/29/2000 GENERATORS, (2) DIESEL 600 KW 1.8 LB/H CONTROLS BACT-PSDKLAMATH FALLS COGENERATION OR 18-0003 12/29/2000 EMERGENCY GENERATOR 6 MMBTU/H 0.1 GR/SCF N/ABADGER GENERATING CO LLC WI 99-RV-143 9/20/2000 DIESEL ENGINE, GENERATOR (4) 3.5 MMBTU/H 0.35 LB/HGOOD COMBUSTION PRACTICES.FUEL < 0.05 % BY WT. SULFUR.PERMIT LIMITS SET IN LB/H, NOTG/BHP-H. BACT-PSDBADGER GENERATING CO LLC WI 99-RV-143 9/20/2000DIESEL ENGINE, EMERGENCY FIREPUMP 3.8 MMBTU/H 0.38 LB/HGOOD COMBUSTION PRACTICES,USE OF FUEL < 0.05% S BY WT.,EQUIPMENT USAGE LIMIT. BACT-PSDFORD ELECTRONICS ANDREFRIGERATION, LLC PA PA-46-0036A 6/19/2000 DIESEL ENGINES 2 MW 1.2 LB/HHOURLY LIMIT FOR EACH ENGINE,ANNUAL FOR ALL FIVE ENGINES. Other Case-by-CaseNORTH COOK INLET UNIT AK 0023-AC007 6/6/2000CATERPILLAR D-398 ENGINES NO. 1AND 2 500 KW EACH 0.05 GR/DSCF NONE INDICATED N/ATHROUGHPUTRACT/BACT/LAER Clearinghouse Results for Diesel-Fired Engines > 500 HP (PM)Attachment 10-EEMISSION LIMITAtt 10-E_Diesel-Fired IC Engines over 500HP_RBLC.xlsPM7/10/2007FACILITY STATE PERMIT NUMBER PERMITDATEDESCRIPTION CONTROL DESCRIPTION BASISTHROUGHPUTRACT/BACT/LAER Clearinghouse Results for Diesel-Fired Engines > 500 HP (PM)Attachment 10-EEMISSION LIMITDILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #3 350 KW 0.05 GR/DSCF NONE INDICATED N/ADILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #4 500 KW 0.05 GR/DSCF NONE INDICATED N/ADILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #5 750 KW 0.05 GR/DSCF NONE INDICATED N/ADILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #6 1000 KW 0.05 GR/DSCF NONE INDICATED N/ADILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #8 835 KW 0.05 GR/DSCF NONE INDICATED N/ADILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #9 835 KW 0.05 GR/DSCF NONE INDICATED N/ADILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR, #10 1135 KW 0.05 GR/DSCF NONE INDICATED N/ADILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #11 1050 KW 0.05 GR/DSCF NONE INDICATED N/ADILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #12 1050 KW 0.05 GR/DSCF NONE INDICATED N/ADILLINGHAM POWER PLANT AK 0025-AC003 5/8/2000 DIESEL ELECTRIC GENERATOR #13 1050 KW 0.05 GR/DSCF NONE INDICATED N/AKENAI REFINERY AK 9923-AC010 3/21/2000UPPER TANK FARM CAT 3412DT,P708C 660 HP 0.3627 LB/MMBTU NONE INDICATED. N/AKENAI REFINERY AK 9923-AC010 3/21/2000EMERGENCY GENERATOR, CF-G70003 2 MW 0.0573 LB/MMBTUGOOD OPERATIONAL PRACTICESAND MAINTENANCE. BACT-PSDKENAI REFINERY AK 9923-AC010 3/21/2000EMERGENCY GENERATOR, CF-G70004 2 MW 0.0573 LB/MMBTUGOOD OPERATIONAL PRACTICESAND MAINTENANCE BACT-PSDAtt 10-E_Diesel-Fired IC Engines over 500HP_RBLC.xlsPM7/10/2007FACILITY STATE PERMIT NUMBER PERMITDATEDESCRIPTION CONTROL DESCRIPTION BASISOmaha Public Power District - Nebraska CityStation NE 58343C01 3/9/2005 Auxiliary Boiler #2-- --0.001 GR/DSCFFUEL SULFUR LIMITED TO 0.05 WT. %S; LIMITED TO 500 HRS/YRBACT-PSDPSI ENERGY-MADISON STATION OH 14-04682 8/24/2004 EMERGENCY DIESEL GENERATOR, 2 17.21 MMBTU/H 0.27 T/YR BACT-PSDLONGVIEW POWER LLC - MAIDSVILLE WV R14-0024 3/2/2004 EMERGENCY GENERATOR 1801 HP 1.13 LB/HR GOOD COMBUSTION PRACTICES BACT-PSDU.S. ARMY - PINE BLUFF ARSENAL AR 1113-AOP-R0 2/17/2004 EMERGENCY GENERATORS (2) 2500 KW 1.1 LB/HR NONE INDICATED BACT-PSDMANKATO ENERGY CENTER MN 01300098-001 12/4/2003INTERNAL COMBUSTION ENGINE,LARGE 1850 HP 0.07 G/B-HP-H GOOD COMBUSTION BACT-PSDDUTCH HARBOR SEAFOOD PROCESSINGFACILITY AK 433CP01(MOD) 10/10/2003 IC ENGINE, GENERATOR, FUEL OIL, (3) 2220 KWGOOD COMBUSTION PRACTICE,OPACITY LIMITS BACT-PSDINGENCO - CHARLES CITY PLANT VA 51998 6/20/2003 IC ENGINES, (48) 550 HP 0.2 LB/MMBTU GOOD COMBUSTION PRACTICES N/AMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 EMERGENCY GENERATOR 97.73 GAL/HR 0.14 LB/MMBTU GOOD COMBUSTION PRACTICES BACT-PSDDUKE ENERGY STEPHENS, LLC STEPHENSENERGY OK 2001-157-C M-1 PSD 3/21/2003IC ENGINE, BACKUP GENERATOR,DIESEL 749 BHP 0.124 LB/MMBTUCOMBUSTION CONTROL ANDGOOD ENGINE DESIGN BACT-PSDCARDINAL FG CO./ CARDINAL GLASS PLANT OK 2002-487-C PSD 3/18/2003IC ENGINES, EMERGENCYGENERATORS (2) 2000 KW 0.0444 LB/MMBTU ENGINE DESIGN BACT-PSDPACIFIC BELL CA 16290 2/1/2003 IC ENGINES 2935 HP 0.1 G/B-HP-H LAERSTERNE ELECTRIC GENERATING FACILITY TX PSD-TX-1015 12/6/2002 EMERGENCY GENERATOR 1350 HP 2.97 LB/H BACT-PSDUNIVERSITY OF CINCINNATI OH 14-05108 8/15/2002( )2922 BHP 19.17 MMBTU/H 0.23 LB/H BACT-PSDHAWKEYE GENERATING, LLC IA 01-687 7/23/2002 EMERGENCY GENERATOR 18500 GALLONS/YR 0.34 LB/H GCP, TIMING RETARD BACT-PSDGENOVA OK I POWER PROJECT OK 2001-223-C PSD 6/13/2002 DIESEL ENGINE, BACKUP GENERATOR 750 KW 0.033 LB/MMBTUCOMBUSTION CONTROL ANDGOOD ENGINE DESIGN BACT-PSDGREATER DES MOINES ENERGY CENTER IA 77-13-002 4/10/2002 EMERGENCY GENERATOR 700 KW 0.95 LB/H Other Case-by-CaseDUKE ENERGY-JACKSON FACILITY AR 1998-AOP-R0 (34-0259) 4/1/2002 GENERATOR, DIESEL-FIRED 671 HP 1.5 LB/H GOOD OPERATING PRACTICE BACT-PSDMANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001CATERPILLARBACK-UPDIESELAIRCOMPRESSORS, 2 775 HP EACH 1.7 LB/H PREVENTATIVE MAINTENANCE BACT-PSDMANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001AUXILIARYDIESELGENERATORSNO.1& NO.2 1100 HP EACH 2.4 LB/H PREVENTATIVE MAINTENANCE BACT-PSDMANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001ADMINISTRATIONBUILDINGDIESELGENERATOR 587 HP 1.3 LB/H PREVENTATIVE MAINTENANCE BACT-PSDPSEG WATERFORD ENERGY LLC OH 06-06739 3/29/2001 EMERGENCY GENERATOR 1000 KW 0.01 T/YR BACT-PSDCOTTONWOOD ENERGY PROJECT TX PSD-965 12/15/2000 FIRE WATER PUMP 0.74 LB/H BACT-PSDCOTTONWOOD ENERGY PROJECT TX PSD-965 12/15/2000 EMERGENCY DIESEL GENERATOR 0.88 LB/H BACT-PSDBRAZOS VALLEY ELECTRIC GENERATINGFACILITY TX PSD-TX-966 8/23/2000 EMERGENCY GENERATOR 1350 hp 2.97 LB/H N/ABRAZOS VALLEY ELECTRIC GENERATINGFACILITY TX PSD-TX-966 8/23/2000 FIRE WATER PUMP 300 hp 0.66 LB/H N/ASAN JUAN REPOWERING PROJECT PR 5 3/2/2000 AUXILIARY DIESEL GENERATOR 5000 KW 7.18 LB/HLIMITED OPERATION, GOODCOMBUSTION PRACTICES BACT-PSDARCHER GENERATING STATION TX PSD-TX-937 1/3/2000EMERGENCY ELECTRICALGENERATOR 2000 KW 2.07 LB/H BACT-PSDAGRIMARK/ CABOT INC. (AMC) VT AOP-99-014 1/3/2000 IC ENGINE, DIESEL 250 KW 0.5 LB/MMBTU BACT-PSDAGRIMARK/ CABOT INC. (AMC) VT AOP-99-014 1/3/2000 IC ENGINE, DIESEL 100 KW 0.5 LB/MMBTU BACT-PSDTHROUGHPUTRACT/BACT/LAER Clearinghouse Results for Diesel-Fired Engines > 500 HP (PM10)Attachment 10-EEMISSION LIMITAtt 10-E_Diesel-Fired IC Engines over 500HP_RBLC.xlsPM107/10/2007FACILITY STATE PERMITNUMBERPERMITDATEDESCRIPTION CONTROL DESCRIPTION BASISARCHER GENERATINGSTATION TX PSD-TX-937 1/3/2000EMERGENCY ELECTRICALGENERATOR 2000 KW 0.29 LB/H None Listed BACT-PSDTHROUGHPUTRACT/BACT/LAER Clearinghouse Results for Diesel-Fired Engines > 500 HP (H2SO4)Attachment 10-EEMISSION LIMITAtt 10-E_Diesel-Fired IC Engines over 500HP_RBLC.xlsH2SO47/10/2007

# ATTACHMENT 10-F

RACT / BACT / LAER CLEARINGHOUSE DATA FOR MATERIAL HANDLING

OPERATIONSRBLC CODE FACILITY STATE PERMIT NUMBER PERMIT DATE PROCESS TYPECONTROL DESCRIPTION BASIS90.011MONTANA DAKOTA UTILITIES/WESTMORELANDPOWER - GASCOYNE GENERATING STATIONND PTC 05005 6/3/2005COAL HANDLING 0.005 GR/DSCF BAGHOUSES; 3 HR AVG. BACT-PSDCoal Handling,AUBURN NUGGET IN 033-19475-00092 5/31/2005COAL CAR UNLOADING 0.0052 GR/DSCF BAGHOUSES BACT-PSDProcessing, 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 BACT-PSDPreparation,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 BACT-PSDCleaningSANTEE COOPER CROSS GENERATINGSTATION SC 0420-0030-CI 2/5/2004 COAL HANDLING 26,280,000 T/YR 1.4 LB/H BAGHOUSE Other Case-by-CaseCARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 SOLID FUEL HANDLING - COAL AND COKE 0.89 LB/HWORK PRACTICES THAT MINIMIZE OR ELIMINATE VISIBLEEMISSIONS OF FUGITIVE DUST. BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 STACKER CONVEYORCHEMICAL DUST SUPPRESSANT BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 TRANSFER TO ACTIVE PILECHEMICAL DUST SUPPRESSANT BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 BUCKET RECLAIMCHEMICAL DUST SUPPRESSANT BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 RAIL UNLOADINGCHEMICAL DUST SUPPRESSANT BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 ACTIVE COAL PILE 311155 SQ FT CHEMICAL DUST SUPPRESSANT BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 INACTIVE COAL STORAGE PILE 1196459 SQ FT CHEMICAL DUST SUPPRESSANT BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 RAIL UNLOADING COAL STOCKOUT PILE 28224 SQ FT CHEMICAL DUST SUPPRESSANT BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 ROTARY CAR DUMPER 3500 TONS/HR 0.005 GR/DSCF BAGHOUSE BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 TRANSFER CONVEYING BAY 1800 TONS/HR 0.005 GR/DSCF BAGHOUSE BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 TRANSFER HOUSE 2 3500 TONS/HR 0.005 GR/DSCF BAGHOUSE BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 TRANSFER HOUSE 4 3600 TONS/HR 0.005 GR/DSCF BAGHOUSE BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 SILOS 900 TONS/HR 0.005 GR/DSCF BAGHOUSE BACT-PSDTHOROUGHBRED GENERATING STATION KY V-02-001 10/11/2002 COAL HANDLING AND STORAGE 99 % REDUCTIONENCLOSURES/PARTIAL ENCLOSURES, BAGHOUSE, BINFILTERS, LOW-PRESSURE DROP AND TELESCOPICCHUTES BACT-PSDBLACK HILLS CORPORATION - WYGEN 2 WY CT-3030 9/25/2002 COAL HANDLING EQUIPMENT 0.009 GR/DSCF FABRIC FILTER BACT-PSDCONSOLIDATION COAL -BUCHANAN PREPPLANT VA 10945 9/26/2001 COAL HANDLING 138 MMBTU/H 0.025 GR/DSCF VENTURI SCRUBBER BACT-PSDCONSOLIDATION COAL -BUCHANAN PREPPLANT VA 10945 9/26/2001 COAL HANDLING-2 253 MMBTU/H 0.025 GR/DSCF VENTURI SCRUBBER BACT-PSDENERGY SERVICES OF MANITOWOC WI 00-RV-092 6/26/2001 FUEL HANDLING 0.004 GR/DSCFPULSE-JET BAGHOUSES, ENCLOSED CONVEYORS, DUSTSUPPRESSION BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING OVERLAND CONVEYOR 4.3 LB/H PARTIAL ENCLOSURE BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 (2) FUEL HANDLING ACTIVE STORAGE PILES A&B 3.24 T/YRWATER SPRAY & UNDERGROND RECLAIM VENT TOBAGHOUSE BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING INACTIVE STORAGE PILE 18.4 T/YR WATERING BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING EMERGENCY STORAGE PILE 0.42 T/YR TELESCOPING CHUTE & WATER SPRAY BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING STACKING HOPPER 0.63 LB/H WATER SPRAY BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001FUEL HANDLING STACKING HOPPER CONVEYOR1A0.37 LB/H PARTIAL ENCLOSURE BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING RAIL CAR UNLOADER 0.63 LB/H PARTIAL ENCLOSURE & WATER SPRAY BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001FUEL HANDLING RAIL CAR UNLOADERCONVEYOR 1B0.19 LB/H PARTIAL ENCLOSURE BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING ACTIVE STORAGE PILE 2 T/YR NONE INDICATED BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING CONVEYOR NO 2 0.16 LB/H PARTIAL ENCLOSURE BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING CONVEYOR NO 3 0.12 LB/H NONE INDICATED BACT-PSDHAVERHILL NORTH COKE COMPANY OH 07-00466 2/27/2001LOAD IN AND LOAD OUT OF COKE/COALSTORAGE PILES4 T/YRLOAD-IN COAL, COKE, AND COKE BREEZE W/ STACKINGTUBE; LOAD-IN COAL W/WATER SPRAYS/DUSTSUPPRESSANT; LOAD-OUT COAL UNDER PILE GRAVITYFEED AND WATER SPRAY; LOAD-OUT COKE W/ UNDERPILE GRAVITY FEED. BACT-PSDHAVERHILL NORTH COKE COMPANY OH 07-00466 2/27/2001 COAL HANDLING, CONVEYING, AND TRANSFER 6602850 T/YR 7.95 T/YRRAIL CAR BOTTOM DUMPING AND ENCLOSED; BELTCONVEYORS ENCLOSED; WET AND/OR CHEMICALSUPPRESSION BACT-PSDSUWANNEE AMERICAN CEMENT COMPANY,INC. FL 1210465-001-AC 6/1/2000 COAL MILL0.01 GR/DSCF BAGHOUSE BACT-PSDCHAPPARRAL STEEL MIDLOTHIAN STEEL MILL TX PSD-TX-138 (M5) 4/24/2000RAILCAR LOADING FROM PELLETIZERSILO/BAGHOUSE DUST 0.0006 LB/H NONE INDICATED Other Case-by-CaseHOLNAM, FLORENCE CO 98-FR-0895 7/29/1999 UNLOADING & CONVEYING, COAL TO STOCKPILE 1.94 T/YRNEG PRESSURE AND BAGHOUSE. STANDARD EMISSIONUNITS NOT AVAILABLE. N/AHOLNAM, FLORENCE CO 98-FR-0895 7/29/1999 COAL STOCKPILE 0.45 T/YR SURFACE MOISTURE N/ATHROUGHPUTRACT/BACT/LAER Clearinghouse for Material Handling OperationsAttachment 10-FEMISSION LIMITAtt 10-F_Material Handling_RBLC.xlsPM7/10/2007RBLC CODE FACILITY STATE PERMIT NUMBER PERMIT DATE PROCESS TYPECONTROL DESCRIPTION BASISTHROUGHPUTRACT/BACT/LAER Clearinghouse for Material Handling OperationsAttachment 10-FEMISSION LIMITHOLNAM, FLORENCE CO 98-FR-0895 7/29/1999RECLAIMING, CONVEYING, & TRANS COAL TOCOAL SCREEN0.19 T/YRBAGHOUSE. PERMIT MODIFICATION TRIGGERED BACTREVIEW OF CO ONLY. PM LIMITS IN STANDARD EMISSIONUNITS NOT AVAILABLE. N/AHOLNAM, FLORENCE CO 98-FR-0895 7/29/1999 SCREENING AND CRUSHING OVERSIZE COAL 0.19 T/YRBAGHOUSE. PERMIT MODIFICATION TRIGGERED BACTREVIEW OF CO ONLY. PM LIMITS IN STANDARD EMISSIONUNITS NOT AVAILABLE. N/AHOLNAM, FLORENCE CO 98-FR-0895 7/29/1999TRANS & CONVEYING - CRUSHED COAL TOTRANSFER TOWER 0.02 T/YRBAGHOUSE. PERMIT MODIFICATION TRIGGERED BACTREVIEW OF CO ONLY. PM LIMITS IN STANDARD EMISSIONUNITS NOT AVAILABLE. N/AHOLNAM, FLORENCE CO 98-FR-0895 7/29/1999 TRANSFER, COAL, TRANSFER TOWER TO SILO 0.02 T/YRBAGHOUSE. PERMIT MODIFICATION TRIGGERED BACTREVIEW OF CO ONLY. PM LIMITS IN STANDARD EMISSIONUNITS NOT AVAILABLE. N/ANORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 RAW COAL/COKE BIN 0.08 LB/H BAGHOUSE & SPRAY COAL/COKE PILES Other Case-by-CaseNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 MAT STORAGE, CRUSHED COAL/COKE BIN 0.01 LB/H BAGHOUSE AND SPRAY PILE Other Case-by-CaseNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999MAT HANDLING, COAL/COKE DROP PT TOHOPPER (MT08)0.19 LB/H PARTIAL ENCLOSURE AND WATER SPRAY Other Case-by-CaseNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999MATERIAL HANDLING, COAL/COKE DROP POINTTO STACKER0.47 LB/H PARTIAL ENCLOSURE AND WATER SPRAY. Other Case-by-CaseNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999MATERIAL HANDLING, COAL/COKE DROP POINTTO PILE0.47 LB/H PARTIAL ENCLOSURE AND WATER SPRAY Other Case-by-CaseNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999MATERIAL HANDLING, COAL/COKE DROP TOHOPPER (MT05)0.47 LB/H PARTIAL ENCLOSURE AND WATER SPRAY Other Case-by-CaseNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999MATERIAL HANDLING COAL/COKE DROP FEEDERTO BELT0.19 LB/H PARTIAL ENCLOSURE AND WATER SPRAY Other Case-by-CaseNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999MATERIAL HANDLING COAL/COKE DROP BELT TOBELT0.19 LB/H COVERED CONVEYOR BELTS Other Case-by-CaseNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999MAT HANDLING, COAL/COKE RECEIVING DROP TOHOPPER0.07 LB/H PARTIAL ENCLOSURE AND WATER SPRAY. Other Case-by-CaseNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999MAT HANDLING, COAL/COKE UNLOADINGCONVEYOR BELT 0.01 LB/H COVERED CONVEYOR BELT Other Case-by-CaseNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999MAT HANDLING COAL/COKE CONVEYOR TOSTACKER0.01 LB/H COVERED CONVEYOR BELT Other Case-by-CaseNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999MATERIAL HANDLING, COAL/COKE STACKER TOPILE0.01 LB/H PARTIAL ENCLOSURES, WATER SPRAYS BACT-PSDNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999MAT HANDLING COAL/COKE CONVEYOR TO COALGRINDING0.01 LB/H COVERED CONVEYOR BELT Other Case-by-CaseNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999MAT HANDLING COAL/COKE CONVEYOR TO MILLFEED BIN0.01 LB/H COVERED CONVEYOR BELT Other Case-by-CaseNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 MATERIAL STORAGE, COAL/COKE PILES 0.55 LB/H SPRAY THE C/C PILES Other Case-by-CaseCOLSTRIP ENERGY LIMITED PARTNERSHIP MT 2035-03 3/20/1998 ELECTRIC GENERATION, MATERIAL TRANSFER 0 6 LB/H BAGHOUSE BACT-PSDTWO ELK GENERATION PARTNERS, LIMITEDPARTNERSHIP WY CT-1352 2/27/1998 DUMP POCKET, COAL 3000 SCFM 0.01 GR/DSCF BAGHOUSE BACT-PSDTWO ELK GENERATION PARTNERS, LIMITEDPARTNERSHIP WY CT-1352 2/27/1998 SILO, COAL 6000 SCFM 0.01 GR/DSCF BAGHOUSE BACT-PSDTWO ELK GENERATION PARTNERS, LIMITEDPARTNERSHIP WY CT-1352 2/27/1998 CRUSHER, CONE, SECONDARY COAL 6000 SCFM 0.01 GR/DSCF 6000 SCFM BAGHOUSE BACT-PSDTWO ELK GENERATION PARTNERS, LIMITEDPARTNERSHIP WY CT-1352 2/27/1998 SILO, BOILER, PLANT COAL 8500 SCFM 0.01 GR/DCSF 8500 SCFM BAGHOUSE BACT-PSDCONSOLIDATED PENNSYLVANIA COAL CO.,BAILY MINES PA 30-0072B 12/19/1997 THERMAL COAL DRYER NO. 1 27 MMTPY 0.031 GR/DSCF VENTURI SCRUBBER BACT-PSDCONSOLIDATED PENNSYLVANIA COAL CO.,BAILY MINES PA 30-0072B 12/19/1997 THERMAL COAL DRYER NO. 2 27 MMTPY 0.02 GR/DSCF VENTURI SCRUBBER BACT-PSDENCOAL CORPORATION-ENCOAL NORTHROCHELLE FACILITY WY CT-1324 10/10/1997 STORAGE, PROCESS DERIVED FUEL 0 0.01 GR/DSCF SCRUBBER 40000 DSCFM BACT-PSDAtt 10-F_Material Handling_RBLC.xlsPM7/10/2007RBLC CODE FACILITY STATE PERMIT NUMBER PERMIT DATE PROCESS TYPECONTROL DESCRIPTION BASISTHROUGHPUTRACT/BACT/LAER Clearinghouse for Material Handling OperationsAttachment 10-FEMISSION LIMITWYGEN, INC. - WYGEN UNIT ONE WY CT-1236 9/6/1996 BOILER BUILDING 0 0.01 GR/DSCF BAGHOUSE BACT-PSD90.019 ARKANSAS LIME COMPANY AR 0045-AOP-R3 8/30/2005 LIME DISCHARGE, SN-32Q #3 0.01 GR/DSCF BAGHOUSE BACT-PSDLime,MONTANA DAKOTA UTILITIES/WESTMORELANDPOWER - GASCOYNE GENERATING STATION ND PTC 05005 6/3/2005MATERIAL HANDLING, LIME & LIMESTONEHANDLING0.005 GR/DSCF BAGHOUSES; 3-HR AVG.; ADDITIONAL 5% OPACITY LIMIT BACT-PSDLimestoneSANTEE COOPER CROSS GENERATINGSTATION SC 0420-0030-CI 2/5/2004 LIMESTONE HANDLING 230000 T/YR 0.022 GR/DSCF BAGHOUSE BACT-PSDHandling,SANTEE COOPER CROSS GENERATINGSTATION SC 0420-0030-CI 2/5/2004 LIMESTONE STORAGE PILE 0.29 LB/HBACT-PSDKilns,SANTEE COOPER CROSS GENERATINGSTATION SC 0420-0030-CI 2/5/2004 LIMESTONE TRUCK UNLOADING 0.02 LB/HBACT-PSDStorage, 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 BACT-PSDManufacturing CARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 KILN DUST HANDLING 0.5 T/YR WATERING OF DUST AND BAGHOUSE. BACT-PSDCARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 MATERIAL STORAGE PILES 0.61 T/YRWATER APPLICATIONS AND DAILY INSPECTIONS OF EACHSTORAGE PILE. BACT-PSDCARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 LIMESTONE MATERIAL HANDLING 4.34 T/YR WATER APPLICATION. BACT-PSDCARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 LIME MATERIAL HANDLING #2 1.38 LB/H BAGHOUSE. BACT-PSDCARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 LIME MATERIAL HANDLING #1 1.05 LB/H BAGHOUSE. BACT-PSDCARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 COMMON PRODUCT HANDLING 1.77 LB/HWORK PRACTICES THAT MINIMIZE OR ELIMINATE VISIBLEEMISSIONS OF FUGITIVE DUST. BACT-PSDCARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 PRODUCT STORAGE/LOADOUT #2 1.3 LB/HWORK PRACTICES THAT MINIMIZE OR ELIMINATE VISIBLEEMISSIONS OF FUGITIVE DUST. BACT-PSDCARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 PRODUCT STORAGE/LOADOUT #1 0.62 LB/HWORK PRACTICES THAT MINIMIZE OR ELIMINATE VISIBLEEMISSIONS OF FUGITIVE DUST. BACT-PSDFIRST 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 BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 LIME FILTER SEPARATOR 100 TONS/HR 0.01 GR/DSCF BAGHOUSE BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 UREA SILO 60 TONS 0.01 GR/DSCF VENT BAG FILTER BACT-PSDTHOROUGHBRED GENERATING STATION KY V-02-001 10/11/2002 FGD REAGENT PREP HANDLING, LIME 400 T/H 0.05 G/DSCM ENCLOSURES AND FILTERS BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001LIMESTONE HANDLING RAILCAR UNLOADINGFACILITY0.6 LB/H WATER SPRAY BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 LIMESTONE HANDLING STORAGE PILE 0.42 T/YRPARTIAL ENCLOSURE, TELESCOPING CHUTE,UNDERGROUND RECLAIM BACT-PSDKENTUCKY MOUNTAIN POWER, LLC KY V-00-045 5/4/2001 MATERIAL HANDLING, LIMESTONE PREP SYSTEM 220 T/H 0.05 GR/DSCMENCLOSURE AND BAGHOUSE FOR TRUCK DUMP ANDFEED & CONVEY POINTS, BAGHOUSE FOR SURGE BINSAND SILOS Other Case-by-CaseKENTUCKY MOUNTAIN POWER, LLC KY V-00-045 5/4/2001 MILL/DRYER, LIMESTONE 10 MMBTU/H 0.05 GR/DSCM BAGHOUSE Other Case-by-CaseRELIANT ENERGY - W.A. PARISH ELECTRICGENERATING STATION TX PSD-TX-234 12/21/2000 RAILCAR UNLOADING, LH1 500 T/H 30 LB/HPERMANENTLY MOUNTED SPRAY NOZZLES, PAVEDROADS CLEANED BY SWEEPING OR WASHING,SPRINKLING OF ROADS WITH WATER/ CHEMICALS. Other Case-by-CaseRELIANT ENERGY - W.A. PARISH ELECTRICGENERATING STATION TX PSD-TX-234 12/21/2000 TRACK HOPPERS, LH1A 500 T/H* 0.54 LB/HPERMANENTLY MOUNTED SPRAY NOZZLES, PAVEDROADS WITH CLEANING/SWEEPING, WATER/CHEMICALSPRAY ON ROADS. Other Case-by-CaseRELIANT ENERGY - W.A. PARISH ELECTRICGENERATING STATION TX PSD-TX-234 12/21/2000 STOCKPILE, LH2 500 T/H* 0.13 T/YR NONE INDICATED Other Case-by-CaseTEXAS LIME COMPANY TX PSD-TX-54 8/2/1999 DUST BIN LOADOUT DUST COLLECTOR, 6-AS-3 0.36 LB/H DUST COLLECTOR Other Case-by-CaseTEXAS LIME COMPANY TX PSD-TX-54 8/2/1999 DUST BIN COLLECTOR, 6-AS-2 0.13 LB/H DUST COLLECTOR Other Case-by-CaseNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 SHIFTABLE QUARRY BELT DROP POINT 0.29 LB/H PARTIAL ENCLOSURE AND SPRAYING. Other Case-by-CaseNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 QUARRY BELT DROP POINT (FUTURE) 0.29 LB/H COVERED AND SPRAYED Other Case-by-CaseNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999QUARRY CONVEYOR BELT TO LIMESTONESTORAGE DROP PT. 0.29 LB/H COVERED AND SPRAYED Other Case-by-CaseNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 MOBILE CRUSHER 0.65 LB/HOther Case-by-CaseNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 LIMESTONE STORAGE BUILDING VENT 0.1 LB/H FULLY ENCLOSED BUILDING FOR LIME STORAGE Other Case-by-CaseNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999QUARRY CONVEYOR BELT TO LIMESTONESTORAGE0.01 LB/H COVERED CONVEYOR Other Case-by-CaseNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 QUARRY BELT (SHIFTABLE) 0.13 LB/H COVERED CONVEYOR BELT Other Case-by-CaseNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 QUARRY BELT (FUTURE) 0.19 LB/H COVERED CONVEYOR BELT Other Case-by-CaseAtt 10-F_Material Handling_RBLC.xlsPM7/10/2007RBLC CODE FACILITY STATE PERMIT NUMBER PERMIT DATE PROCESS TYPECONTROL DESCRIPTION BASISTHROUGHPUTRACT/BACT/LAER Clearinghouse for Material Handling OperationsAttachment 10-FEMISSION LIMITNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 LIMESTONE CONVEYOR BELT TO FEED BINS 0.01 LB/H COVERED CONVEYOR BELT Other Case-by-CaseTWO ELK GENERATION PARTNERS, LIMITEDPARTNERSHIP WY CT-1352 2/27/1998 SILO, LIME 3000 SCFM 0.01 GR/DSCF 3000 SCFM BAGHOUSE BACT-PSDENCOAL CORPORATION-ENCOAL NORTHROCHELLE FACILITY WY CT-1324 10/10/1997 SILO, LIME STORAGE 0 0.01 GR/DSCF BAGHOUSE 3500 DSCFM BACT-PSD99.120 TOLEDO EDISON CO. - BAYSHORE PLANT OH 04-1056 7/31/2003COKE AND FLY ASH TRANSFERRING ANDCONVEYING 730000 t/yr 12 T/YR FABRIC FILTER AND ADEQUATE ENCLOSURE --Ash Handling, MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003FLYASH/FGD WASTE VACUUM SYSTEMEXHAUSTER 40.44 TONS/HR 0.005 GR/DSCF BAGHOUSE BACT-PSDStorage, MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 FLYASH/FGD WASTE STORAGE SILO 2000 TONS 0.005 GR/DSCF VENT BAG FILTER BACT-PSDDisposal ALAMO CEMENT COMPANY II, LTD TX PSD-TX-145 (M1) 6/29/2001 FLYASH BINE, N-20 0.17 LB/H BAGHOUSE Other Case-by-CaseRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001WASTE HANDLING FLY ASH TRUCK LOADINGOPERATION3.38 LB/H TELESCOPING CHUTE, VACUUM RECOVERY BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001WASTE HANDLING FLY ASH BAG LOADINGOPERATION0.11 LB/H VACUUM RECOVERY BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 BOTTOM ASH TRUCK LOADING 0.94 LB/H WET MATERIAL BACT-PSDRELIANT ENERGY - W.A. PARISH ELECTRICGENERATING STATION TX PSD-TX-234 12/21/2000 FLY ASH TANK, WH2 75 T/H 0.43 LB/H BAGHOUSE Other Case-by-CaseTWO ELK GENERATION PARTNERS, LIMITEDPARTNERSHIP WY CT-1352 2/27/1998 SILO, FLY ASH 4000 SCFM 0.01 GR/DSCF 4000 SCFM BAGHOUSE BACT-PSDTWO ELK GENERATION PARTNERS, LIMITEDPARTNERSHIP WY CT-1352 2/27/1998 HANDLING BUILDING, FLY ASH 5000 SCFM 0.01 GR/DSCF 5000 SCFM BAGHOUSE BACT-PSDENCOAL CORPORATION-ENCOAL NORTHROCHELLE FACILITY WY CT-1324 10/10/1997 BIN, ASH STORAGE 0 0.01 GR/DSCF BAGHOUSE, 3500 DSCFM BACT-PSDWYGEN, INC. - WYGEN UNIT ONE WY CT-1236 9/6/1996 FLY ASH HANDLING BUILDING 0 0.01 GR/DSCF BAGHOUSE BACT-PSDWYGEN, INC. - WYGEN UNIT ONE WY CT-1236 9/6/1996 SILO, FLY ASH STORAGE 0 0.01 GR/DSCF BAGHOUSE BACT-PSD99.140R.J. REYNOLDS TOBACCO COMPANY -TOBACCOVILLE FACILITY NC 00745-TV12 7/1/2003 PAVED ROADS-- SEE CONTROLS/P2RACT IS PAVING ALL MAIN ROADS AND MOSTMAINTENANCE ROADS, INSTALLATION OF CURBS WITHGUTTER,ENCLOSED TRAILERS/TRUCKS BACT-PSDPaved Roads MIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 HAUL ROADS 46 TRUCKS/DAYWATER FLUSHING FOLLOWED BY SWEEPING; 80%EFFICIENCY ASSUMED BACT-PSDWOLD TRONA COMPANY, INC. WY MD-455 4/27/2000 FUGITIVE EMISSIONS - ROAD DUST 41.3 T/YR PAVED ROADS Other Case-by-CaseCHAPPARRAL STEEL MIDLOTHIAN STEEL MILL TX PSD-TX-138 (M5) 4/24/2000 IN-PLANT VEHICLE TRAFFIC 34.8 T/YR CHEMICAL AND WATER SPRAY Other Case-by-CaseHOLNAM, FLORENCE CO 98-FR-0895 7/29/1999 PAVED ROADS, CEMENT PRODUCT HAULOUT 1.6 T/YR CONTROL PLAN Other Case-by-CaseINTERNATIONAL PAPER LUMBER MILL TX PSD-TX-892 9/28/1998 HR-FUG HAUL ROAD FUGITIVES 2.76 LB/HPLANT ROADS SHALL BE PAVED WITH A COHESIVE HARDSURFACE WHICH CAN BE CLEANED BY SWEEPING ORWASHING. ALL ROADS SHALL BE SPRINKLED WITHWATER AND/OR ENVIRONMENTALLY SENSITIVECHEMICALS AS NEEDED TO CONTROL PM. N/ACAPITOL CEMENT DIVISION TX PSD-TX-120M3 9/16/1998 PAVED ROADS (F-TR-1) 10.37 T/YRPLANT ROADS SHALL BE PAVED AND CLEANED. QUARRYROADS SHALL BE SPRINKLED WITH WATER AND/ORCHEMICALS TO MAINTAIN COMPLIANCE WITH ALL TNRCCRULES AND REGULATIONS. N/ASPRINGFIELD PLANT OR 202125 6/4/1998 ROAD AND PARKING LOTS 27 LB/DOther Case-by-CaseDESERET GENERATION AND TRANSMISSIONCO. UT DAQE-523-95 6/14/1995 ROADS (PAVED)CONTROLLED BY DUST CONTROL PLAN. NO EMISSIONRATE LIMIT. BACT-PSD99.150Unpaved RoadRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 PLANT ROADS17.42 T/YR WATER SPRAY BACT-PSDSUN COKE COMPANY - HAVERHILL NORTHCOKE COMPANY OH 07-00466 2/27/2001 ROADWAYS AND PARKING 8.01 T/YRWATERING AS SUFFICIENT FREQUENCY TO ENSURECOMPLIANCE BACT-PSDTEMPLE INLAND PINELAND MANUFACTURINGCOMPLEX TX PSD-TX-924 8/6/2000 HAUL ROADS, EPN119 7.53 LB/H WATER AS NEEDED Other Case-by-CaseCHAPPARRAL STEEL MIDLOTHIAN STEEL MILL TX PSD-TX-138 (M5) 4/24/2000 SLAG ROAD EMISSIONS, S38 21.26 T/YR NONE INDICATED BACT-PSDCAPITOL CEMENT DIVISION TX PSD-TX-120M3 9/16/1998 UNPAVED ROADS (PT. F-L-1) 25.34 T/YRQUARRY ROADS SHALL BE SPRINKLED WITH WATERAND/OR CHEMICALS, AS NECESSARY TO MAINTAINCOMPLIANCE WITH ALL TNRCC RULES ANDREGULATIONS. N/ADESERET GENERATION AND TRANSMISSIONCO. UT DAQE-523-95 6/14/1995 ROADS (UNPAVED)WATER SPRAYED AND/OR CHEMICALLY TREATED. NOEMISSION RATE LIMITS BACT-PSD99.190 ACE ETHANOL, LLC - STANLEY WI 03-DCF-184 1/21/2004 FUGITIVE EMISSIONS - TRUCK TRAFFIC -- SEE CONTROLS/P2NO EMISSION RATE LIMITS. THE PERMITTEE SHALL CLEANTHE ROADS, SCALES, PADS AND OTHER AREAS ASNEEDED TO PREVENT FUGITIVE DUST EMISSIONS BACT-PSDOther FugitiveDust SourcesAtt 10-F_Material Handling_RBLC.xlsPM7/10/2007RBLC CODE FACILITY STATE PERMIT NUMBER PERMIT DATE PROCESS TYPECONTROL DESCRIPTION BASIS90.011 ARKANSAS LIME COMPANY AR 0045-AOP-R3 8/30/2005 COAL/COKE BIN VENT, SN-33Q #3 0.015 GR/DSCF DUST COLLECTOR BACT-PSDCoal Handling,NEWMONT NEVADA ENERGY INVESTMENT LLCTS POWER PLANTNV AP4911-1349 5/5/2005COAL HANDLING OPERATIONS0.10 GR/DSCF FABRIC FILTER DUST COLLECTOR BACT-PSDProcessing, IRON DYNAMICS, INC. (IDI) IN 033-19160-00076 4/13/2005 COAL DRYER 25 mmbtu/h 0.01 GR/DSCF BAGHOUSE BACT-PSDPreparation, ISLAND CREEK COAL - VP #8 GARDEN PLANT VA 10704 11/2/2004 COAL PROCESSING PLANT - THERMAL DRYER 153 btu/h 0.019 GR/DSCF WETVENTURI SCRUBBER BACT-PSDCleaningISLAND 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 BACT-PSDRED TRAIL ENERGY, LLC - RICHARDTON PLANT ND 4004 8/4/2004 COAL HANDLING 27 T/H 0.004 GR/DSCF BAGHOUSE BACT-PSDCARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 SOLID FUEL HANDLING - COAL AND COKE 0.31 T/YRWORK PRACTICES THAT MINIMIZE OR ELIMINATE VISIBLE EMISSIONSOF FUGITIVE DUST. BACT-PSDPLUM POINT ENERGY AR 1995-AOP-R0 8/20/2003 MATERIAL HANDLING, COAL, PARTIALLY INCLOSED 0.1 LB/H PARTIAL ENCLOSURES BACT-PSDPLUM POINT ENERGY AR 1995-AOP-R0 8/20/2003 MATERIAL HANDLING, COAL, SUPPRESSION 0.1 LB/H WATER SPRAYS, DUST SUPPRESSANTS, ETC BACT-PSDPLUM POINT ENERGY AR 1995-AOP-R0 8/20/2003 MATERIAL HANDLING, COAL, BAGHOUSES 0.1 LB/H BAGHOUSES BACT-PSDBULL MOUNTAIN, NO. 1, LLC - ROUNDUPPOWER PROJECT MT 3182-00 7/21/2003 MATERIAL TRANSFER, COAL HANDLING TRANSFER POINTS 0.01 GR/DSCF DUST SUPPRESSION SYSTEMS AND ENCLOSURES. BAGHOUSE BACT-PSDBULL MOUNTAIN, NO. 1, LLC - ROUNDUPPOWER PROJECT MT 3182-00 7/21/2003 ACTIVE COAL STORAGE PILE98 % REDUCTION WIND FENCE AND DUST SUPPRESSION; WORK PRACTICE LIMITS BACT-PSDBULL MOUNTAIN, NO. 1, LLC - ROUNDUPPOWER PROJECT MT 3182-00 7/21/2003 INACTIVE COAL STORAGE PILE 98 % REDUCTION WIND FENCE, DUST SUPPRESSION, PILE COMPACTION BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 STACKER CONVEYORCHEMICAL DUST SUPPRESSANT BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 TRANSFER TO ACTIVE PILECHEMICAL DUST SUPPRESSANT BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 BUCKET RECLAIMCHEMICAL DUST SUPPRESSANT BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 RAIL UNLOADINGCHEMICAL DUST SUPPRESSANT BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 ACTIVE COAL PILE 311155 SQ FT CHEMICAL DUST SUPPRESSANT BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 INACTIVE COAL STORAGE PILE 1196459 SQ FT CHEMICAL DUST SUPPRESSANT BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 RAIL UNLOADING COAL STOCKOUT PILE 28224 SQ FT CHEMICAL DUST SUPPRESSANT BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 ROTARY CAR DUMPER 3500 TONS/HR 0.005 GR/DSCF BAGHOUSE BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 TRANSFER CONVEYING BAY 1800 TONS/HR 0.005 GR/DSCF BAGHOUSE BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 TRANSFER HOUSE 2 3500 TONS/HR 0.005 GR/DSCF BAGHOUSE BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 TRANSFER HOUSE 4 3600 TONS/HR 0.005 GR/DSCF BAGHOUSE BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 SILOS 900 TONS/HR 0.005 GR/DSCF BAGHOUSE BACT-PSDGCC DACOTAH SD 28.1101-PSD 4/10/2003 COAL SURGE BIN TOP (2) 400 T/H 0.01 GR/DSCF FABRIC FILTER BACT-PSDGCC DACOTAH SD 28.1101-PSD 4/10/2003 COAL TUNNEL TO COAL STACKER 400 T/H 0.01 GR/DSCF FABRIC FILTER BACT-PSDGCC DACOTAH SD 28.1101-PSD 4/10/2003 COAL TRANSFER 400 T/H 0.01 GR/DSCF FABRIC FILTER BACT-PSDGCC DACOTAH SD 28.1101-PSD 4/10/2003 COAL DRYER - FK PUMP 20 T/H 0.01 GR/DSCF FABRIC FILTER BACT-PSDGCC DACOTAH SD 28.1101-PSD 4/10/2003 COAL HOPPER TO CONVEYOR 400 T/H 0.01 GR/DSCF FABRIC FILTER BACT-PSDROCKY MOUNTAIN POWER, LLC - HARDINGENERATOR PROJECT MT 3185-00 6/11/2002 MATERIAL TRANSFER, COAL HANDLING TRANSFER POINTS 0.01 GR/DSCFDUST SUPPRESSION SYSTEMS AND ENCLOSURES, VENTED TOBAGHOUSE Other Case-by-CaseCONSOLIDATION COAL -BUCHANAN PREPPLANT VA 10945 9/26/2001 COAL HANDLING 138 MMBTU/H 0.019 GR/DSCF VENTUI SCRUBBER BACT-PSDCONSOLIDATION COAL -BUCHANAN PREPPLANT VA 10945 9/26/2001 COAL HANDLING-2 253 MMBTU/H 0.019 GR/DSCF VENTURI SCRUBBER BACT-PSDINTERNATIONAL 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, PULVERIZER INSIDE BUILDING BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING LIGNITE MINE TRANSFER SILO 2.23 LB/H BAGHOUSE BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING OVERLAND CONVEYOR 2.04 LB/H PARTIAL ENCLOSURE BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING TRANSFER TOWER NO. 4 1.37 LB/H BAGHOUSE BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING TRANSFER TOWER NO 1Y 3.43 LB/H BAGHOUSE BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 (2) FUEL HANDLING ACTIVE STORAGE PILES A&B RECLAIM 1.03 LB/H BAGHOUSE BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING CRUSHER HOUSE 2.66 LB/H BAGHOUSE BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING TRANSFER TOWER NO 2 1.46 LB/H BAGHOUSE BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING TRANSFER TOWER NO 3 2.74 LB/H BAGHOUSE BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING OUTBOARD TOWER NO 1 0.26 LB/H BAGHOUSE BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING SILOS GALLERY A-D (4) UNIT 1&2 2.49 LB/H BAGHOUSE BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 (2) FUEL HANDLING ACTIVE STORAGE PILES A&B 1.56 T/YR WATER SPRAY & UNDERGROUND RECLAIMVENT TO BAGHOUSE BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING INACTIVE STORAGE PILE 9.02 T/YR WATERINGBACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING EMERGENCY STORAGE PILE 0.21 T/YR TELESCOPING CHUTE & WATER SPRAY BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING STACKING HOPPER 0.3 LB/H WATER SPRAY BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING STACKING HOPPER VAULT 0.13 LB/H BAGHOUSE BACT-PSDTHROUGHPUTRACT/BACT/LAER Clearinghouse for Material Handling OperationsAttachment 10-FEMISSION LIMITAtt 10-F_Material Handling_RBLC.xlsPM107/10/2007RBLC CODE FACILITY STATE PERMIT NUMBER PERMIT DATE PROCESS TYPECONTROL DESCRIPTION BASISTHROUGHPUTRACT/BACT/LAER Clearinghouse for Material Handling OperationsAttachment 10-FEMISSION LIMITRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING STACKING HOPPER CONVEYOR 1A 0.17 LB/H PARTIAL ENCLOSURE BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING RAIL CAR UNLOADER 0.3 LB/H PARTIAL ENCLOSURE & WATER SPRAY BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING RAIL CAR UNLOADER VAULT 0.17 LB/H BAGHOUSE BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING RAIL CAR UNLOADER CONVEYOR 1B 0.09 LB/H PARTIAL ENCLOSURE BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING ACTIVE STORAGE PILE RECLAIM 0.17 LB/H BAGHOUSE & WATERSPRAY BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING ACTIVE STORAGE PILE 0.98 T/YR NONE INDICATED BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING CONVEYOR NO 2 0.07 LB/H PARTIAL ENCLOSURE BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING TRANSFER STATION NO 1 0.13 LB/H BAGHOUSE BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING CONVEYOR NO 3 0.06 LB/H NONE INDICATED BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING TRIPPER TOWER NO 2 0.17 LB/H BAGHOUSE BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 FUEL HANDLING TRANSFER STATION NO 3 0.09 LB/H BAGHOUSE BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 (2) FUEL HANDLING LIME ADDITION SILOS A & B 0.63 LB/H BAGHOUSE BACT-PSDSUN COKE COMPANY - HAVERHILL NORTHCOKE COMPANY OH 07-00466 2/27/2001 LOAD IN AND LOAD OUT OF COKE/COAL STORAGE PILES 1.98 T/YRLOAD-IN COAL, COKE, AND COKE BREEZE W/ STACKING TUBE; LOADIN COAL W/WATER SPRAYS/DUST SUPPRESSANT; LOAD-OUT COALUNDER PILE GRAVITY FEED AND WATER SPRAY; LOAD-OUT COKE W/UNDER PILE GRAVITY FEED. BACT-PSDSUN COKE COMPANY - HAVERHILL NORTHCOKE COMPANY OH 07-00466 2/27/2001 COAL HANDLING, CONVEYING, AND TRANSFER 6602850 T/YR 3.77 T/YRRAIL CAR BOTTOM DUMPING AND ENCLOSED; BELT CONVEYORSENCLOSED; WET AND/OR CHEMICAL SUPPRESSION BACT-PSDSUWANNEE AMERICAN CEMENT COMPANY,INC. FL 1210465-001-AC 6/1/2000 COAL MILL0.01 GR/DSCF BAGHOUSE BACT-PSDCHAPPARRAL 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 Other Case-by-CaseHOLNAM, FLORENCE CO 98-FR-0895 7/29/1999 UNLOADING & CONVEYING, COAL TO STOCKPILE 1.85 T/YRNEG PRESSURE AND BAGHOUSE. STANDARD EMISSION UNITS NOTAVAILABLE.N/AHOLNAM, FLORENCE CO 98-FR-0895 7/29/1999 COAL STOCKPILE0.33 T/YR SURFACE MOISTURE N/AHOLNAM, FLORENCE CO 98-FR-0895 7/29/1999 RECLAIMING, CONVEYING, & TRANS COAL TO COAL SCREEN 0.19 T/YRBAGHOUSE. PERMIT MODIFICATION TRIGGERED BACT REVIEW OF COONLY. PM LIMITS IN STANDARD EMISSION UNITS NOT AVAILABLE. N/AHOLNAM, FLORENCE CO 98-FR-0895 7/29/1999 SCREENING AND CRUSHING OVERSIZE COAL 0.19 T/YRBAGHOUSE. PERMIT MODIFICATION TRIGGERED BACT REVIEW OF COONLY. PM LIMITS IN STANDARD EMISSION UNITS NOT AVAILABLE. N/AHOLNAM, FLORENCE CO 98-FR-0895 7/29/1999TRANS & CONVEYING - CRUSHED COAL TO TRANSFERTOWER0.02 T/YRBAGHOUSE. PERMIT MODIFICATION TRIGGERED BACT REVIEW OF COONLY. PM LIMITS IN STANDARD EMISSION UNITS NOT AVAILABLE. N/AHOLNAM, FLORENCE CO 98-FR-0895 7/29/1999 TRANSFER, COAL, TRANSFER TOWER TO SILO 0.02 T/YRBAGHOUSE. PERMIT MODIFICATION TRIGGERED BACT REVIEW OF COONLY. PM LIMITS IN STANDARD EMISSION UNITS NOT AVAILABLE. N/ALONE STAR INDUSTRIES, INC. IN 133-10159 4/16/1999 CEMENT MANUFACTURING, COAL MILL 40 T/YR 0.01 GR/DSCF FABRIC FILTER BACT-PSDNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 RAW COAL/COKE BIN0.08 LB/H BAGHOUSE & SPRAY COAL/COKE PILES BACT-PSDNORTH 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 BACT-PSDNORTH 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 SPRAY BACT-PSDNORTH 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 SPRAY BACT-PSDNORTH 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 SPRAY BACT-PSDNORTH 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 SPRAY BACT-PSDNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 MATERIAL HANDLING COAL/COKE DROP FEEDER TO BELT 0.09 LB/HBACT-PSDNORTH 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 BACT-PSDNORTH 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 SPRAY. BACT-PSDNORTH 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 SPRAY BACT-PSDNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 MAT HANDLING COAL/COKE CONVEYOR TO STACKER 0.01 LB/H COVERED CONVEYOR BELT BACT-PSDNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 MATERIAL HANDLING, COAL/COKE STACKER TO PILE 0.01 LB/H ENCLOSURE, WATER SPRAY BACT-PSDNORTH 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 BACT-PSDNORTH 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 BACT-PSDAtt 10-F_Material Handling_RBLC.xlsPM107/10/2007RBLC CODE FACILITY STATE PERMIT NUMBER PERMIT DATE PROCESS TYPECONTROL DESCRIPTION BASISTHROUGHPUTRACT/BACT/LAER Clearinghouse for Material Handling OperationsAttachment 10-FEMISSION LIMITNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 MATERIAL STORAGE, COAL/COKE PILES 0.28 LB/H SPRAY THE C/C PILES BACT-PSDDESERET GENERATION AND TRANSMISSIONCOMPANY UT DAQE-186-98 3/16/1998 CONVEYOR COAL 475 T/H 925.76 T/YBACT-PSDCARGILL, INC IA 83-A-090-S2, ET AL 2/24/1997 COAL BUNKER II-CUSTOM FABRICATED 0.129 LB/HFABRIC FILTERS. STANDARD EMISSION LIMIT ESTIMATED FROMPERMIT PROCESS DATA. Other Case-by-CaseCARGILL, INC IA 83-A-090-S2, ET AL 2/24/1997 COAL BUNKER III-CUSTOM FABRICATED 0.129 LB/HFABRIC FILTER. STANDARD EMISSION LIMIT ESTIMATED FROM PERMITPROCESS DATA. Other Case-by-CaseCARGILL, INC IA 83-A-090-S2, ET AL 2/24/1997 COAL CONVEYING ASPIRATION 0.6 LB/HFABRIC FILTER. STANDARD EMISSION LIMIT ESTIMATED FROM PERMITPROCESS DATA. Other Case-by-CaseCARGILL, INC IA 83-A-090-S2, ET AL 2/24/1997 COAL BUNKER I0.129 LB/HFABRIC FILTER. STANDARD EMISSION UNITS ESTIMATED USINGPERMIT PROCESS DATA. BASIS OF LIMIT: OTHER (NAAQS) Other Case-by-CaseCARGILL, INC IA 83-A-090-S2, ET AL 2/24/1997 COAL DUMPING SHED1.541 LB/HFABRIC FILTER. STANDARD EMISSION LIMIT CALCULATED FROMPERMIT PROCESS DATA. BASIS OF LIMIT : OTHER - NAAQS Other Case-by-CaseASH GROVE CEMENT COMPANY UT DAQE-958-96 10/24/1996 COAL DELIVERY SYSTEM1.08 LB/H BAGHOUSE BACT-PSD90.019 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 BACT-PSDLime, 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 BACT-PSDLimestone 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 METHOD 9 BACT-PSDHandling, CARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 KILN DUST HANDLING0.21 T/YR WATERING OF DUST AND BAGHOUSEKilns, CARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 MATERIAL STORAGE PILES0.4 T/YRWATER APPLICATIONS AND DAILY INSPECTIONS OF EACH STORAGEPILE.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/YRWORK PRACTICES THAT MINIMIZE OR ELIMINATE VISIBLE EMISSIONSOF FUGITIVE DUST.CARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 PRODUCT STORAGE/LOADOUT #2 1.13 T/YRWORK PRACTICES THAT MINIMIZE OR ELIMINATE VISIBLE EMISSIONSOF FUGITIVE DUST.CARMEUSE LIME - MAPLE GROVE FACILITY OH 03-13527 10/14/2003 PRODUCT STORAGE/LOADOUT #1 0.3 T/YRWORK PRACTICES THAT MINIMIZE OR ELIMINATE VISIBLE EMISSIONSOF 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 - ROUNDUPPOWER PROJECT MT 3182-00 7/21/2003 MATERIAL TRANSFER, LIME HANDLING TRANSFER POINTS 0.01 GR/DSCF PNEUMATIC TRANSFERS AND BAGHOUSEMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 LIME STORAGE SILO 2000 TONS/HR 0.01 GR/DSCF VENT BAG FILTER BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 LIME FILTER SEPARATOR 100 TONS/HR 0.01 GR/DSCF BAGHOUSE BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 UREA SILO 60 TONS 0.01 GR/DSCF VENT BAG FILTER BACT-PSDROCKY MOUNTAIN POWER - HARDINGENERATOR PROJECT MT 3185-00 6/11/2002 MATERIAL TRANSFER, LIME HANDLING TRANSFER POINTS 0.01 GR/DSCF DUST SUPPRESSION SYSTEMS AND ENCLOSURES, BAGHOUSERELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 LIMESTONE HANDLING RAILCAR UNLOADING FACILITY 0.3 LB/H WATER SPRAYRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 LIMESTONE HANDLING UNLOADER & HOPPER VAULT 1.29 LB/H BAGHOUSERELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 LIMESTONE HANDLING SHUTTLE CONVEYOR 0.77 LB/H BAGHOUSERELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 LIMESTONE HANDLING RECLAIM 0.51 LB/H BAGHOUSERELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 LIMESTONE HANDLING TRANSFER TOWER 1.71 LB/H BAGHOUSERELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 LIMESTONE HANDLING0.61 LB/H BAGHOUSERELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 LIMESTONE HANDLING STORAGE PILE 0.21 T/YRPARTIAL ENCLOSURE, TELESCOPING CHUTE, UNDERGROUNDRECLAIMRELIANT ENERGY - W.A. PARISH ELECTRICGENERATING STATION TX PSD-TX-234 12/21/2000 RAILCAR UNLOADING, LH1 500 T/H 15 LB/HPERMANENTLY MOUNTED SPRAY NOZZLES, PAVED ROADS CLEANEDBY SWEEPING/WASHING, WATER/CHEMICAL SPRAY OF ROADS. Other Case-by-CaseRELIANT ENERGY - W.A. PARISH ELECTRICGENERATING STATION TX PSD-TX-234 12/21/2000 TRACK HOPPERS, LH1A 500 T/H* 0.27 LB/HPERMANENTLY MOUNTED SPRAY NOZZLES, PAVED ROADS WITHCLEANING/SWEEPING, CHEMICAL/WATER SPRAY ON ROADS. Other Case-by-CaseRELIANT ENERGY - W.A. PARISH ELECTRICGENERATING STATION TX PSD-TX-234 12/21/2000 STOCKPILE, LH2 500 T/H* 0.06 T/YR NONE INDICATED Other Case-by-CaseRELIANT ENERGY - W.A. PARISH ELECTRICGENERATING STATION TX PSD-TX-234 12/21/2000 STORAGE PILE RECLAIM, CONVEYOR, CRUSHER; LH5 500 T/H* 2.1 LB/HENCLOSED CONVEYORS. LOADING STOCKPILE USING TELESCOPICCHUTE. UNDERGROUND RECLAIM SYSTEM. Other Case-by-CaseRELIANT ENERGY - W.A. PARISH ELECTRICGENERATING STATION TX PSD-TX-234 12/21/2000 STORAGE SILO, LH6 500 T/H* 0.39 LB/H BAGHOUSE Other Case-by-CaseMEADWESTVACO KENTUCKY LP - WICKLIFFECARBON PLANT KY V-99-009 (R1) 11/16/1999 LIME STORAGE AND FEED SYSTEM 0.3 LB/H CARTRIDGE FILTER BACT-PSDNUCOR STEEL CORPORATION AR 1139-AOP-R5 9/9/1999 LIME SILO0.005 GR/DSCF FABRIC FILTER BACT-PSDTEXAS LIME COMPANY TX PSD-TX-54 8/2/1999 DUST BIN LOADOUT DUST COLLECTOR, 6-AS-3 0.36 LB/H DUST COLLECTOR Other Case-by-CaseTEXAS LIME COMPANY TX PSD-TX-54 8/2/1999 DUST BIN COLLECTOR, 6-AS-2 0.13 LB/H DUST COLLECTOR Other Case-by-CaseLONE STAR INDUSTRIES, INC. IN 133-10159 4/16/1999 CEMENT MANUFACTURING, SECONDARY CRUSHER 400 T/H 0.015 GR/DSCF BAGHOUSE. PM10 = TOTAL FILTERABLE PMGCC DACOTAH SD 28.1101-PSD 4/10/2003 GYPSUM RAW SHED (2) 350 T/H 0.01 GR/DSCF FABRIC FILTER BACT-PSDAtt 10-F_Material Handling_RBLC.xlsPM107/10/2007RBLC CODE FACILITY STATE PERMIT NUMBER PERMIT DATE PROCESS TYPECONTROL DESCRIPTION BASISTHROUGHPUTRACT/BACT/LAER Clearinghouse for Material Handling OperationsAttachment 10-FEMISSION LIMITNORTH 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 3/4/1999QUARRY CONVEYOR BELT TO LIMESTONE STORAGE DROPPT.0.29 LB/H SPRAYED AND COVEREDNORTH TEXAS CEMENT COMPANY TX PSD-TX-893 3/4/1999 MOBILE CRUSHER0.65 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 STORAGENORTH 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 TRANSMISSIONCOMPANY 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/HFABRIC FILTER. STANDARD EMISSION UNITS HAVE BEEN ESTIMATEDFROM PERMIT PROCESS DATA.CARGILL, INC IA 83-A-090-S2, ET AL 2/24/1997 LIME PRECOAT STORAGE 9000 T/MO 0.032 LB/HFABRIC FILTER. STANDARD EMISSIONS ESTIMATED FROM PERMITDATA BASIS OF LIMIT: OTHER- NAAQS99.120NEWMONT NEVADA ENERGY INVESTMENT LLCTS POWER PLANT NV AP4911-1349 5/5/2005 ASH, LIME AND CARBON SILOS 0.02 GR/DSCF BIN VENT FILTERS BACT-PSDAsh Handling, PLUM POINT ENERGY AR 1995-AOP-R0 8/20/2003 MATERIAL HANDLING, FLYASH, BAGHOUSES 0.1 LB/H BAGHOUSE BACT-PSDStorage, PLUM POINT ENERGY AR 1995-AOP-R0 8/20/2003 MATERIAL HANDLING, FLY ASH, SUPPRESSION 0.1 LB/H DUST SUPPRESSION - WATER SPRAYS BACT-PSDDisposal 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 FABRICFILTER AND ADEQUATE ENCLOSURE --BULL MOUNTAIN, NO. 1, LLC - ROUNDUPPOWER PROJECT MT 3182-00 7/21/2003 MATERIAL HANDLING, FLY ASH HANDLING TRANSFER POINT 0.01 GR/DSCF VACUUM PRESSURE SYSTEM AND BAGHOUSEBACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 FLYASH/FGD WASTE VACUUM SYSTEM EXHAUSTER 40.44 TONS/HR 0.005 GR/DSCF BAGHOUSE BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 FLYASH/FGD WASTE STORAGE SILO 2000 TONS 0.005 GR/DSCF VENT BAG FILTER BACT-PSDROCKY MOUNTAIN POWER, INC. - HARDINGENERATOR PROJECT MT 3185-00 6/11/2002 MATERIAL TRANSFER, FLY ASH HANDLING TRANSFER POINT 0.01 GR/DSCF DUST SUPPRESSION SYSTEMS AND ENCLOSURES, BAGHOUSE Other Case-by-CaseINTERNATIONAL 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 BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 (2) WASTE HANDLING FLY ASH SILOS NO 1 & 2 1.59 LB/H BAGHOUSE BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 WASTE HANDLING FLY ASH TRUCK LOADING OPERATION 1.65 LB/H TELESCOPING CHUTE, VACUUM RECOVERY BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 WASTE HANDLING FLY ASH BAG LOADING OPERATION 0.05 LB/H VACUUM RECOVERY BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 (3) WASTE HANDLING FLY ASH SILOS A,B,&C 1.15 LB/H BAGHOUSE BACT-PSDRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 BOTTOM ASH TRUCK LOADING 0.47 LB/H WET MATERIAL BACT-PSDTEMPLE INLAND PINELAND MANUFACTURINGCOMPLEX TX PSD-TX-924 8/6/2000 ASH PICKUP, EPN930.47 LB/H BAGFILTER Other Case-by-CaseLONE 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 PM BACT-PSD99.140 STEELCOOR, INC. - BLUEWATER PROJECT AR 2062-AOP-R0 7/22/2004 ROADWAY EMISSIONS26.9 T/YR APPLICATION OF WETTING AGENT BACT-PSDPaved Roads PLUM POINT ENERGY AR 1995-AOP-R0 8/20/2003 ROAD DUST0.2 LB/H DUST SUPPRESSION - WATERING, DUST SUPPRESSANTS BACT-PSDMIDAMERICAN ENERGY COMPANY IA PROJECT 02-528 6/17/2003 HAUL ROADS 46 TRUCKS/DAYWATER FLUSHING FOLLOWED BY SWEEPING; 80% EFFICIENCYASSUMEDBACT-PSDARKANSAS STEEL ASSOCIATES AR 35-AOP-R3 1/5/2001 PAVED ROADS6.9 T/YR WATER APPLICATON TO CONTROL FUGITIVE EMISSIONS BACT-PSDCHAPPARRAL STEEL MIDLOTHIAN STEEL MILL TX PSD-TX-138 (M5) 4/24/2000 IN-PLANT VEHICLE TRAFFIC 12.5 T/YR CHEMICAL AND WATER SPRAY Other Case-by-CaseHOLNAM, FLORENCE CO 98-FR-0895 7/29/1999 PAVED ROADS, CEMENT PRODUCT HAULOUT 1.2 T/YR CONTROL PLAN Other Case-by-CaseINTERNATIONAL PAPER LUMBER MILL TX PSD-TX-892 9/28/1998 HR-FUG HAUL ROAD FUGITIVES 1.24 LB/HPLANT ROADS SHALL BE PAVED WITH A COHESIVE HARD SURFACEWHICH CAN BE CLEANED BY SWEEPING OR WASHING. ALL ROADSSHALL BE SPRINKLED WITH WATER AND/OR ENVIRONMENTALLYSENSITIVE CHEMICALS AS NEEDED TO CONTROL PM. N/ACAPITOL CEMENT DIVISION TX PSD-TX-120M3 9/16/1998 PAVED ROADS (F-TR-1)0.86 T/YRPLANT ROADS SHALL BE PAVED AND CLEANED. QUARRY ROADSSHALL BE SPRINKLED WITH WATER AND/OR CHEMICALS, ASNECESSARY, TO MAINTAIN COMPLIANCE WITH ALL TNRCC RULES ANDREGULATIONS. N/ACON AGRA SOYBEAN PROCESSING CO. IN 129-8541-00039 8/14/1998 FUGITIVE DUSTROADS ARE PAVED, REGULAR PROGRAM OR ROAD SWEEPINGAND/OR ROAD WETTING AS NEEDED. BACT-PSDSPRINGFIELD PLANT OR 202125 6/4/1998 ROAD AND PARKING LOTS11 LB/DOther Case-by-CaseLAFARGE CORPORATION MO 0897-019 8/20/1997 PAVED HAUL ROADS(EP 95) 60969.6 VMT 0 SEE CONTROLS/P2 WATER FLUSHING FOLLOWED BY VACUUM SWEEPING BACT-PSDBUNGE CORPORATION IA 97-A-419, ET-AL. 5/20/1997 ROADWAY AREA SOURCE, PAVED 0.055 LB/H HARD SURFACE PAVEMENT BACT-PSD99.150 RECMIX OF PA, INC. KY V-03-051 8/6/2004 UNPAVED ROAD0.78 T/YR WATERING - 70% REDUCTION TAKEN INTO ACCOUNT IN CALCULATION BACT-PSDUnpaved RoadsPLUM POINT ENERGY AR 1995-AOP-R0 8/20/2003 ROAD DUST0.3 LB/H DUST SUPPRESSION - WATERING, DUST SUPPRESSANTS BACT-PSDINTERNATIONAL PAPER - MANSFIELD MILL LA PSD-LA-93 (M-6) 8/14/2001 HAUL ROADS18.5 LB/HWET SUPPRESSION ON UNPAVED ROADS TWICE PER 8 HOURSPERIOD DURING DAYLIGHT HOURS (EXCEPT WHEN RAINING) BACT-PSDAtt 10-F_Material Handling_RBLC.xlsPM107/10/2007RBLC CODE FACILITY STATE PERMIT NUMBER PERMIT DATE PROCESS TYPECONTROL DESCRIPTION BASISTHROUGHPUTRACT/BACT/LAER Clearinghouse for Material Handling OperationsAttachment 10-FEMISSION LIMITRELIANT ENERGY - LIMESTONE ELECTRICGENERATING STATION TX PSD-TX-371 (M3) 5/23/2001 PLANT ROADS8.71 T/YR WATER SPRAY BACT-PSDSUN COKE COMPANY - HAVERHILL NORTHCOKE COMPANY OH 07-00466 2/27/2001 ROADWAYS AND PARKING1.56 T/YR WATERING AS SUFFICIENT FREQUENCY TO ENSURE COMPLIANCE BACT-PSDNUCOR STEEL IN 107-12143-00038 1/19/2001 TRANSPORTATION ON ROADS 16.8 LB/MILESPEED LIMITS, VACUUMING/SWEEPING EVERY 14 DAYS. DUSTSUPPRESSANT ON UNPAVED ROADS AT A RATE OF 0.16 GAL/YD2ONCE PER MONTH. EMISSION UNIT IS LB SILT PER MILE BACT-PSDARKANSAS STEEL ASSOCIATES AR 35-AOP-R3 1/5/2001 UNPAVED ROADS6.9 T/YR WATER APPLICATON TO CONTROL FUGITIVE EMISSIONS BACT-PSDTEMPLE INLAND PINELAND MANUFACTURINGCOMPLEX TX PSD-TX-924 8/6/2000 HAUL ROADS, EPN1193.45 LB/H WATER AS NEEDED Other Case-by-CaseCHAPPARRAL STEEL MIDLOTHIAN STEEL MILL TX PSD-TX-138 (M5) 4/24/2000 SLAG ROAD EMISSIONS, S38 10.63 T/YR NONE INDICATED Other Case-by-CaseCAPITOL CEMENT DIVISION TX PSD-TX-120M3 9/16/1998 UNPAVED ROADS (PT. F-L-1) 11.4 T/YRQUARRY ROADS SHALL BE SPRINKLED WITH WATER AND/ORCHEMICALS, AS NECESSARY, TO COMPLY WITH ALL TNRCC RULESAND REGULATIONS. N/ALAFARGE CORPORATION MO 0897-019 8/20/1997 UNPAVED HAUL ROADS(EP 96) 33025.2 VMT 0 SEE CONTROLS/P2USE OF EMULSION AT MANUFACTURER'S SPECIFIED APPLICATIONRATE (SURFACTANT, DUST SUPPRESSANT) BACT-PSD99.190LOUISIANA-PACIFIC CORPORATION - URANIAPLANT LA PSD-LA-578 12/7/2000 PLANT ROADWAY FUGITIVES 0.02 LB/H NONE INDICATED BACT-PSDOther Fugitive RIO GRANDE PORTLAND CEMENT CORP. CO 98PB0893 9/25/2000 RAW MATERIAL TRANSFER, ROAD DUST -- SEE CONTROLS/P2CE = 85-90%. TREATMENT OF UNPAVED HAUL SURFACES WITHCHEMICAL STABILIZERS AND REGULAR WATERING. REGULARINSPECTION AND CLEANING OF PAVED HAUL SURFACES. USE OFSURFACTANTS IN SPRAY WATERS. NO LIMIT SET FOR FUGITIVEEMISSIONBACT-PSDDust SourcesAtt 10-F_Material Handling_RBLC.xlsPM107/10/2007