Prepared for: 

General Chemical Soda Ash Partners 

Green River, Wyoming 

BART Analysis for the General 

Chemical Green River Works 

ENSR Corporation 

March 2007 

Document No.: 02999-022 
Prepared for: 

General Chemical Soda Ash Partners 

Green River, Wyoming 

BART Analysis for the General 

Chemical Green River Works 

_________________________________ 

Prepared By 

_________________________________ 

Reviewed By 

ENSR Corporation 

March 2007 

Document No.: 02999-022 
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Contents 

1.0 Introduction ............................................................................................................................................ 1-1

2.0 Background Data ................................................................................................................................... 2-1

2.1 Emission Units and Useful Life ....................................................................................................... 2-1

2.2 Baseline Emissions ......................................................................................................................... 2-1

2.3 Types of Coal Used......................................................................................................................... 2-2

2.4 Unique Characteristics of the Site................................................................................................... 2-2

2.5 Existing Emission Control Equipment at the Site ........................................................................... 2-4

2.6 Presumptive BART Levels .............................................................................................................. 2-4

3.0 Consideration of Emission Control Alternatives .............................................................................. 3-1

3.1 NOX Emission Controls.................................................................................................................... 3-1

3.1.1 Post-combustion Controls ................................................................................................. 3-1

3.1.2 Combustion Controls ......................................................................................................... 3-1

3.1.3 NOX Control Technical Feasibility ..................................................................................... 3-2

3.2 SO2 Control...................................................................................................................................... 3-2

3.2.1 Wet Flue Gas Desulfurization ........................................................................................... 3-2

3.2.2 Lime Spray Dryer Absorber............................................................................................... 3-3

3.2.3 Dry Sorbent Injection ......................................................................................................... 3-3

4.0 Emission Reductions for BART Cost Evaluation.............................................................................. 4-1

4.1 Actual Annual Emissions Baseline.................................................................................................. 4-1

4.2 Effectiveness and Economic Analysis of NOX Emission Control Alternatives............................... 4-1

4.2.1 NOx BART Alternatives Evaluated ................................................................................... 4-2

4.2.2 Costs for Boiler C NOX ...................................................................................................... 4-2

4.2.3 Boiler D NOx....................................................................................................................... 4-3

4.3 Effectiveness and Economic Analysis of SO2 Emission Control Alternatives .............................. 4-3

4.3.1 SO2 BART Alternatives Evaluated .................................................................................... 4-3

4.3.2 Costs for Boiler C SO2 ....................................................................................................... 4-4

4.3.3 Costs for Boiler D SO2 ....................................................................................................... 4-4

4.3.4 Summary of Reductions and Control Costs ..................................................................... 4-5

5.0 Selection of Control Scenarios............................................................................................................ 5-1

5.1 Control Options Modeling Emission Rates..................................................................................... 5-1

5.2 Control Scenario Options for Evaluation......................................................................................... 5-2

6.0 Selection of the Best Alternative for BART Control.......................................................................... 6-1
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6.1 Summary of Results ........................................................................................................................ 6-1

6.2 Annualized Cost for Implementing Control vs Decrease in Visibility Impairment.......................... 6-2

List of Appendices 

Appendix A Facility Design Data

Appendix B Cost Analyses for BART Control Options
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List of Tables 

Table 2-1 Boilers C and D Maximum 24-Hour Emission Rates .............................................................. 2-2

Table 4-1 Baseline Annual Average Emissions for 2001-2003............................................................... 4-1

Table 4-2 Cost Evaluation of NOx controls for Boiler C .......................................................................... 4-3

Table 4-3 Cost Evaluation of NOx controls for Boiler D .......................................................................... 4-3

Table 4-4 Cost Evaluation of SO2 controls for Boiler C ........................................................................... 4-4

Table 4-5 Cost Evaluation of SO2 controls for Boiler D ........................................................................... 4-5

Table 5-1 Emission Rates for Visibility Evaluation for Each Considered Option.................................... 5-1

Table 6-1 Tabulation of Visibility Improvement at Jim Bridger Wilderness Area 

and Annual Costs for Each Control Option ............................................................................. 6-1

List of Figures 

Figure 2-1 Green River Works Facility Plot Plan....................................................................................... 2-3

Figure 2-2 View of Power Plant Building Looking Northwest ................................................................... 2-5

Figure 2-3 View of Boiler C Stack Looking East ....................................................................................... 2-5

Figure 2-4 Boiler C ESP Discharge Plenum.............................................................................................. 2-6

Figure 2-5 Boiler C ESP Discharge Plenum.............................................................................................. 2-6

Figure 2-6 Boiler C Stack Looking Southwest........................................................................................... 2-7

Figure 2-7 View From Behind Boiler C Looking Toward Boiler D (Southwest)........................................ 2-7

Figure 5-1 General Chemical – BART Determination: 8th Highest Modeled Visibility Impact (2001) ..... 5-3

Figure 6-1 Plot of Visibility Improvement vs. Annualized Control Cost for BART Options ...................... 6-2
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Executive Summary 

The General Chemical facility in Green River, Wyoming, (General Chemical – Green River) has been identified 

as a Best Available Retrofit Technology (BART)-eligible source by the Wyoming Department of Environmental 

Quality (WDEQ). The affected units include two coal-fired boilers known as Boilers C and D. The Wyoming 

BART program requires that BART-eligible sources perform a site-specific BART analysis including a control 

technology review and CALPUFF modeling to assess the visibility impact of the emission units. This report 

complies with the regulations as stipulated in Wyoming Air Quality Standards and Regulations Chapter 6, 

Section 9. 

Boilers C and D provide process steam and electric power generation to the trona mining complex at this 

facility. These units are co-located with other process equipment and buildings which support the mining and 

ore processing operations. The boilers and existing electrostatic precipitators (ESP) are located within a 

multi-floor power plant. Each boiler’s flue gas vents through its own stack which penetrate the roof. This 

site-specific configuration constrains the ability to retrofit certain add-on control options for oxides of nitrogen 

(NOX) and sulfur dioxide (SO2). Current particulate controls are already effective with the use of ESPs and not 

evaluated in this report. 

The controls evaluated for NOX and SO2 include: 

NOX – Combustion modifications that reduce the formation of NOX, such as various forms of staged 

combustion, and add-on post combustion control represent candidate control technologies for retrofit to the 

boilers including: 

• Selective catalytic reduction – 80 to 90 percent reduction; 

• Selective non-catalytic reduction – 30 to 50 percent reduction; 

• Low NOX Burners (LNB) – 10 to 30 percent reduction; and 

• Low NOX Burners plus Separated Overfire Air (LNB+SOFA) – 25 to 45 percent reduction. 

SO2 – Both add-on controls and emission management alternatives were considered for SO2 reduction. The 

technologies evaluated in this BART determination include the following: 

• Wet Flue Gas Desulfurization – 90 to 98 percent reduction. 

• Lime Spray Dryer Absorber – 70 to 90 percent control; 

• Dry Sorbent Injection – 10 to 85 percent control; and 

• SO2 Emissions Management – through coal supply evaluation. 

The estimated cost of the emission reduction alternatives in annualized cost (dollars/year) was determined for 

BART alternatives deemed feasible candidates for retrofit to Boilers C and D. Various individual control options 

and combinations of control options for NOX and SO2 were used to perform CALPUFF modeling of candidate 

levels of visibility improvement. 

BART was determined to be a combination of Low NOx Burner retrofits based on achieving significant visibility 

improvements at reasonable cost (in $/dv improvement) relative to the other options. This BART will improve 

predicted visibility due to the BART units by about 14 to15 percent (in terms of delta-deciviews relative to 

natural conditions) based on the 8th highest and on worst-case visibility days, respectively. 
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For SO2 emissions BART was determined to be the use of the current low sulfur bituminous coal. This 

determination is made based on the excessive cost (in $/dv improvement) of the other control options 

considered.
1-1 March 2007

1.0 Introduction 

Federal regulations under 40 Code of Federal Regulations (CFR) 51 Appendix Y provide guidance and 

regulatory authority for conducting a visibility impairment analysis for designated eligible sources. The 

regulations are provided in Wyoming Air Quality Standards and Regulations, Chapter 6, Section 9. The 

program requires the application of Best Available Retrofit Technology (BART) to those existing eligible 

sources in order to help meet the targets for visibility improvement at designated Class I areas. The Wyoming 

Department of Environmental Quality (WDEQ) identified two coal-fired boilers, Boilers C and D, at the General 

Chemical facility in Green River, Wyoming, (General Chemical – Green River) as two BART-eligible emission 

units . The Wyoming BART program requires that BART-eligible sources perform a site-specific BART 

analysis including a control technology review and CALPUFF modeling to assess the visibility impact of the 

emission units. 

The site-specific BART determination analysis includes the following components: 

1. A list of demonstrated candidate retrofit controls that may apply. 

2. A discussion of technical feasibility for retrofit of each candidate technology to the boilers. 

3. A ranking of the control effectiveness of each feasible retrofit technology, or site-specific BART 

options. 

4. An evaluation of the impacts of each site-specific BART option, including: 

• An estimate of the annualized cost for each of the BART options; 

• An analysis of the incremental cost for each option; 

• An evaluation of the impacts on visibility for each of the BART options or combinations of BART 

options; 

• An evaluation of the non-air quality impacts of each BART option; and 

• An evaluation of the energy impacts of each BART option. 

5. An evaluation and justification of the mass emission rates and averaging time in the context of 

modeled visibility improvements. 

6. Special issues related to coal supply focused on economic impacts of mine supply operations and 

communities. 

7. Sources subject to a Maximum Achievable Control Technology (MACT) standard may provide a 

limited discussion of controls related to the MACT-regulated pollutants. 

The regulation further requires a formal choice of BART based on the above data, plus the degree of 

improvement in visibility (impacts), which may be reasonably anticipated to result from the installation or 

implementation of the proposed BART. Economic analysis and impacts on facility operation may be 

considered in the final BART decision-making process. 
2-1 March 2007

2.0 Background Data 

2.1 Emission Units and Useful Life 

There are no near-term limitations on the useful life of Boiler C and D. These units, along with the other 

non-BART eligible gas-fired boiler provide on-site steam and electric power for mining and ore processing 

operations. The boiler house containing all three boilers is located within a compact area at the facility. Boilers 

C and D are tangentially fired using low sulfur bituminous coal. Boiler C has a total heat rate input of 

534 million British Thermal Units per hour (MMBtu/hr) and Boiler D is rated at 880 MMBtu/hr. Given the limited 

area at the site, coal is received ready for firing, without on site long-term storage, pre-sizing, or coal blending. 

Both boilers are equipped with in-line pulverizers that introduce the coal directly into the combustion zone. 

Particulate emissions from both boilers are controlled by separate hot-side electrostatic precipitators (ESP) 

which vent through independent stacks that penetrate and extend above the boiler house roof. 

The facility is currently operating under an operating permit number 30-123-1 issued by the WDEQ. The 

emission limits for the units are as follows: 

Particulate Matter (PM) 0.10 lb/MMBtu 

Oxides of nitrogen (NOX) 0.7 lb/MMBtu 

Sulfur dioxide (SO2) 1.2 lb/MMBtu 

Both units are subject to Wyoming Air Quality Standards and Regulations (WAQSR) Chapter 5, Section 2 and 

40 CFR Part 60 Subpart D – Standards of Performance for Fossil-Fuel Fired Steam Generators. Both units are 

equipped with continuous emission monitoring systems (CEMS) for NOX and SO2 emissions, and data are 

maintained in pounds (lb)/MMBtu for each hour recorded. Periodic monitoring via Method 5 source testing is 

conducted to demonstrate compliance with the PM limits, and a Compliance Assurance Monitoring (CAM) plan 

has been proposed for demonstrating continuous compliance with the PM limits. The two coal-fired boilers are 

also subject to the Boiler MACT standards (40 CFR 63 Subpart DDDD), which requires limits on PM or trace 

metals. In complying with this requirement, the facility will opt to meet the limits on “selected metal” and retain 

the emission limit on particulate matter for both units. 

2.2 Baseline Emissions 

The BART Air Modeling Protocol issued by WDEQ in September, 2006 defines visibility impairing baseline 

emissions as the maximum 24-hour emission rates for the years 2001 through 2003. These emissions 

represent a realistic depiction of anticipated annual emissions for the source. These baseline emissions are 

used later in this report as the basis for estimating annual emission reductions for the various control 

technologies evaluated and determining the annualized costs to achieve those reductions. Although data are 

provided on an hourly basis in terms of lb/MMBtu, no emissions data are available for hourly mass (lb/hour) 

emission rates. A detailed review of the data indicates that over this period, it is likely that the maximum 

24 hour emission rate is less than the permitted limits, but the difference between the permit limits and the 

estimated 24-hour emission rates is very small. Therefore, the facility will accept the permit limits as 

representative of maximum emissions for the 2001-2003 period and serve as the basis for determining 

baseline (pre-BART) emission rates. The permit limits are shown in Table 2-1. The particulate matter with an 

aerodynamic diameter of 10 microns or less (PM10) and particulate matter with an aerodynamic diameter of 2.5 

microns or less (PM2.5) emission rates have been speciated from the filterable PM emission limit (50 lb/hour for 

the C boiler and 80 lb/hour for the D boiler) following a method for developed by the National Park Service, Air 

Resources Division (http://www2.nature.nps.gov/air/Permits/ect/index.cfm). 
2-2 March 2007

Table 2-1 Boilers C and D Maximum 24-Hour Emission Rates 

Filterable PM10

Fine Condensable PM10

Boiler 

total 

(lb/hr) 

coarse 

(lb/hr) 

fine 

total 

(lb/hr) 

fine 

soil 

(lb/hr) 

EC 

(lb/hr) 

total

(lb/hr) 

nonsulfate 

inorg. 

(lb/hr) 

H2SO4

(lb/hr) 

organic 

(lb/hr) 

Total 

PM10 

(lb/hr) 

Total 

Fine 

Soil 

(lb/hr) 

C 50 27.77 22.21 21.39 0.82 7.34 0 5.87 1.47 57.34 21.39 

D 80 44.44 35.55 34.24 1.32 11.74 0 9.39 2.35 91.74 34.24 

Note: Filterable PM10 emissions are conservatively based on the lb/hr permit limit. Actual emissions for PM10 are not available because PM10 is not continuously 

monitored. PM speciation based on the National Park Service, Air Resources Division (http://www2.nature.nps.gov/air/Permits/ect/index.cfm) method. 

2.3 Types of Coal Used 

General Chemical – Green River utilizes low sulfur, high heating value bituminous coal. Typically, the coal 

contains only about 0.42 to 0.51 percent sulfur with a high heating value of 12,700 Btu/lb. The sulfur content of 

this coal rivals the low sulfur properties of Powder River Basin (PRB) coal from Wyoming, and therefore, it 

represents the lowest sulfur coal available. General Chemical is unaware of alternate coal supplies that can 

provide the required heat input and meet the required particulate limits. As such, no other coal supplies are 

considered to be readily available to supply the facility. Emissions for this analysis are based on maintaining 

the current coal supply, and those emissions are sensitive to that coal quality. As discussed below, this 

condition implies that alternate coal supplies are not directly relevant for consideration as BART controls for 

this facility. 

The more friable PRB coal generates dust through weathering much more quickly than bituminous coal 

increasing the risk of spontaneous combustion in and around material handling systems and silos. The 

potential for changes in fugitive dust emissions may require redesign to avoid periodic spontaneous 

combustion to comply with Mine Safety and Health Administration (MSHA) regulations. Therefore, a change in 

coal supply is not a feasible BART control option. 

2.4 Unique Characteristics of the Site 

General Chemical – Green River Boilers C and D are located on a small portion of the mining facility as shown 

in Figure 2-1. The location of each unit and its stack within the boiler house is shown in the Figure 2-1 which 

shows that space for emission control equipment is extremely limited. As the flue gas leaves the boiler it 

descends to the lower levels of the boiler house and passes through the ESPs for each unit. After passing 

through the ESPs, the discharge of the flue gas is then directed upward through the stacks. As currently 

constructed, there is very limited vertical distance (approximately 3 feet) between the existing air heater and 

the intake to each ESP as shown in Figure 2-2 prohibiting the construction of ductwork or installation of 

equipment between the air heater heat exchanger and the ESP. Post combustion, add-on control device that 

would need to be configured after the ESP and include a new stack; thus, the footprint of such a device would 

include the device itself, any ancillary equipment, and a new stack.

Permitted Emission Rate 

(lb/hour) 

Pollutant Boiler C Boiler D 

NOx 376 616 

SO2 641 1056 
2-3 March 2007

Figure 2-1 Green River Works Facility Plot Plan 
2-4 March 2007

Space within the power plant building is extremely limited. The boilers are located between coal conveyors and 

pulverizers to the south, inoperable boilers to the east, and ancillary plant equipment to the north. Additionally, 

the inoperable boilers are in a part of the boiler house containing large amounts of friable asbestos. The 

facility’s’ asbestos management plan requires leaving it encapsulated in place. Directly adjacent to the 

disabled boiler area is a complex of pipe racks that would need to be relocated to accommodate any eastward 

expansion. 

The ESP is located to the North of the unit inside the boiler house. Figures 2-3 through 2-7 show a series of 

photographs with a description of the view. 

2.5 Existing Emission Control Equipment at the Site 

Currently, NOx emissions for the existing units are reduced by tangential firing, overfire air, and low excess air. 

These controls were part of the boiler installation and were applied in order to comply with the 1971 New 

Source Performance Standard (NSPS). Boiler C was installed in 1973 and Boiler D was installed in 1975. No 

improvements or modifications have been installed to improve the NOx control efficiency of the existing 

equipment. 

SO2 emissions are controlled by using low sulfur coal. Add-on emission controls are not used for SO2. 

PM10 emissions are controlled by hot-side ESPs installed with the boilers where the control device is installed 

upstream of the boiler air heater. The process controls on both ESPs have been upgraded recently and 

provide improved performance of the existing ESPs. 

Unit design data for the C and D Boilers are provided in Appendix A, Table A-1 of this report. 

2.6 Presumptive BART Levels 

The presumptive BART levels listed in U.S. Environmental Protection Agency’s (USEPA’s) BART rule apply to 

coal-fired electric generating units. There are no presumptive limits for non-EGU boilers, such as the General 

Chemical – Green River boilers that are the focus of this study. Presumptive BART levels can be considered 

for non electric generating units, and are included in the subsequent analyses. Those presumptive BART limits 

are as follows: 

• SO2 limit is 95 percent control or 0.15 lb/MMBtu. 

• NOX limit is 0.28 lb/MMBtu. 
2-5 March 2007

Figure 2-2 View of Power Plant Building Looking Northwest 

Figure 2-3 View of Boiler C Stack Looking East 
2-6 March 2007

Figure 2-4 Boiler C ESP Discharge Plenum 

Figure 2-5 Boiler C ESP Discharge Plenum 
2-7 March 2007

Figure 2-6 Boiler C Stack Looking Southwest 

Figure 2-7 View From Behind Boiler C Looking Toward Boiler D (Southwest) 
3-1 March 2007

3.0 Consideration of Emission Control Alternatives 

3.1 NOX Emission Controls 

The techniques available to control NOx from new coal-fired boilers, in top-down order, include: 

• Selective catalytic reduction (SCR) – 80 to 90 percent control; 

• Selective non-catalytic reduction (SNCR) – 30 to 50 percent control; and 

• Combustion modifications and low NOx burners – 10 to 45 percent control. 

Both post-combustion controls and combustion controls are considered in this analysis. 

3.1.1 Post-combustion Controls 

SCR 

SCR is a post-combustion control technology that involves a catalyst bed installed between the boiler 

economizer and combustion air preheater in a conventional pulverized coal-fired (PC) boiler. The temperature 

range of the flue gas at this point is between 650 to 750 degrees Fahrenheit (°F). Ammonia is injected into the 

flue gas upstream of a precious metal catalyst bed and reduces a portion of the NOX to molecular nitrogen and 

water. Reductions up to 80 to 90 percent can be achieved from this technology. SCR has been used with PC 

boilers and is considered the most effective control for the removal of NOX emissions from PC boilers. 

Therefore, SCR is technically feasible to control NOX emissions from the existing PC boiler. 

SNCR 

SNCR is a post combustion control technology that involves ammonia or urea injection into the flue gases 

without the presence of a catalyst. SNCR, like SCR, involves the reaction of NOX with ammonia where a 

portion of the NOX is converted to molecular nitrogen and water. NOX removal efficiencies with SNCR are 

lower than SCR, typically from 30 to 50 percent depending on the combustion process. Without the use of a 

catalyst or supplemental fuel injection, the NOX reduction reaction temperature must be tightly controlled 

between 1,600 and 2,200°F (between 1,600 and 1,800°F for optimum efficiency). Below 1,600°F ammonia will 

not fully react, resulting in unreacted ammonia that is emitted into the atmosphere, (referred to as ammonia 

slip). If the temperature rises above 2,200°F, the ammonia added will be oxidized resulting in an increased 

level of NOX emissions. 

SNCR with ammonia injection technology is a demonstrated, commercially available technology. SNCR has 

been used with PC boilers, therefore, SNCR is technically feasible to control NOX emissions from the existing 

PC boiler. 

3.1.2 Combustion Controls 

Based on review of the literature and discussions with vendors, two levels of combustion modifications and low 

NOxburners have been identified as available for retrofit of tangentially fired boilers equipped with overfire air: 

• Low NOx Burners (LNB) for an additional 10 to 30 percent control; and 

• Low NOx Burners + Separated Overfire Air (LNB+SOFA) for an additional 25 to 45 percent control. 

Due to the small size, age, and design of the Combustion Engineering boilers at General Chemical – Green 

River, as well as the NOX controls already in place, the retrofit of low NOX combustion control options is 

practically limited to the two options noted above and described below. 
3-2 March 2007

The low NOX burner market is a mature and cost-competitive business. A variety of manufactures have 

developed competitive LNB and LNB+SOFA systems. In a retrofit application, the applicability of various 

product offerings and site-specific cost factors vary from boiler to boiler. For the purpose of this analysis, 

ENSR contacted Alstom Power. 

A desktop study was conducted to evaluate the alternative levels of control, feasibility, emission reduction 

potential, and costs associated with installing NOX controls of Boilers C and D. Alstom’s LNCFSTM-P2 system 

(LNB) represents advancement in coal combustion technology for tangentially fired units. The system was 

developed to offer the advantages of significant NOX reduction through simple nozzle tip replacement. There 

are three main components to the LNCFSTM-P2 system; the P2 coal nozzle tip and vaned close coupled 

overfire air (VCCOFA), and concentric firing system (CFS) air nozzle tips. 

The LNCFSTM Level II (LNB+SOFA) is a more aggressive NOX reduction firing system which also could be 

retrofitted to the General Chemical – Green River boilers. The system utilizes the same general components 

described for LNCFSTM P2 system above, with the addition of a new SOFA System. The SOFA system 

employs a staged combustion process that diverts secondary air from the main windbox and injects it into the 

furnace above the main firing zone. This staged combustion process is one of the first principles of aggressive 

NOX reduction. The air is introduced into the furnace through a dedicated SOFA windbox mounted above the 

main windbox. Typically, the SOFA windboxes are corner-mounted, but this can vary based upon the 

particular geometry of the boiler and local interferences. 

3.1.3 NOX Control Technical Feasibility 

All of the NOX control technologies described above are technically feasible. 

3.2 SO2 Control 

The techniques available to control SO2 from new coal-fired boilers, in top-down order, include: 

• Lime or limestone based wet flue gas desulfurization – 90 to 98 percent control; 

• Lime spray dryer absorber – 70 to 90 percent control; 

• Dry sorbent injection – 10 to 80 percent control; and 

• SO2 emission reductions based on the selection of alternate fuel supplies. 

3.2.1 Wet Flue Gas Desulfurization 

Wet Flue Gas Desulfurization (WFGD) uses limestone, lime, or caustic reagent to react with SO2 from the flue 

gas. The temperature of the flue gas is reduced to its adiabatic saturation temperature and the SO2 is removed 

from the flue gas by reaction with the alkaline medium. SO2 and other acid gases (e.g. HCl, HF) are absorbed 

into the scrubbing slurry, which falls into the lower section of the vessel known as the reaction tank. Finely 

ground limestone and make-up water is added to the reaction tank to neutralize and regenerate the scrubbing 

slurry. 

Limestone scrubbing introduces limestone slurry with the water in the scrubber. The sulfur dioxide is absorbed, 

neutralized, and partially oxidized to calcium sulfite and calcium sulfate. The overall reactions are shown in the 

following equations: 

CaCO3 + SO2 → CaSO3 • 1/2 H2O + CO2

CaSO3 •1/2 H2O + 3H2O + O2 → 2 CaSO4 •2 H2O 

Lime scrubbing is similar to limestone scrubbing in equipment and process flow, except that lime is a more 

reactive reagent than limestone. The reactions for lime scrubbing are as follows: 
3-3 March 2007

Ca(OH)2 +SO2 → CaSO3• 1/2 H2O + 1/2 H2O 

Ca(OH)2 + SO2 + 1/2 O2 + H2O → CaSO4•2 H2O 

When caustic (sodium hydroxide solution) is the scrubbing agent, the SO2 removal reactions are as follows: 

Na+ + OH- + SO2 + → Na2SO3

2Na+ + 2OH- + SO2 + → Na2SO3 + H2O 

Caustic scrubbing produces a liquid waste, and minimal equipment is needed as compared to lime or 

limestone scrubbers. If lime or limestone is used as the reagent for SO2 removal, additional equipment is 

needed for preparing the lime/limestone slurry and collecting and concentrating the resultant sludge. Calcium 

sulfite sludge is difficult to mechanically dewater and is typically stabilized with fly ash for landfilling. Calcium 

sulfate sludge is stable and is readily mechanically dewatered. To produce calcium sulfate, an air injection 

blower is needed to supply the oxygen for the second reaction to occur. 

The process is most effective in reducing SO2 emissions resulting from combustion of high sulfur coals. In 

addition, the water consumption in a WFGD system is high as water due to stack losses to the atmosphere. 

Make-up water is added to the reaction tank and is recirculated through the gas stream. WFGD controls are 

applied to many coal fired boilers and are considered a feasible option for these units, but the installation 

would require a separate building and new stack due to the constraints of the existing design and the existing 

building structure. 

3.2.2 Lime Spray Dryer Absorber 

The lime-based spray dryer absorber (SDA) is often selected when water consumption and sludge disposal 

constraints exist. While SDA technology is considered capable of removing as much as 95 percent SO2 from 

high sulfur coals, typical reductions using western low sulfur coals typically range from 70 to 90 percent. In 

order to apply this process at the General Chemical – Green River facility, the SDA would need to be upstream 

of a particulate control device so that the sorbent can be removed from the flue gas. In the spray dryer, water 

droplets containing lime are gradually evaporated in a large vessel as the flue gas temperature approaches the 

adiabatic saturation temperature. In order to allow sufficient residence time for evaporation and reaction with 

SO2, the design gas residence time in a spray dryer absorber is approximately 10 seconds. Consequently, the 

spray dryer absorber vessel would be approximately 35 feet diameter by 60 feet high for both boilers. In 

addition, the unreacted lime mixed with ash from the ESP must be recycled to provide efficient reagent 

utilization. This would increase solids loading to the ESP by a factor of 3 requiring additional ESP capacity and 

a complete reconstruction of the ash handling system. While SDA’s are considered state-of-the-art for new 

facilities burning western coal, they are extremely difficult to retrofit to existing boilers. For these reasons, SDA 

using the existing particulate control system is eliminated from further consideration. However, a new 

stand-alone SDA may be considered for construction outside of the existing building, including a new structure, 

a post-SDA baghouse control, added ducting, and a new stack as well as the existing control equipment. That 

option is considered feasible for the BART analysis. 

3.2.3 Dry Sorbent Injection 

Dry, in-duct sorbent injection (DSI) requires less capital equipment, less physical space and less modification 

to existing ductwork compared to a spray dryer absorber. The advantages of this option include direct injection 

of sorbent material into the existing flue gas duct work which is subsequently captured by the existing 

particulate control device (the ESP). The structural limitations will affect the ability of the plant to install this 

technology. 

Despite the lower capital costs, reagent costs are much higher than other control technologies and control 

efficiency is lower when compared to a spray dryer absorber depending upon the type and quantity of sorbent 
3-4 March 2007

injected. Lime, soda ash, and Trona (sodium sesquicarbonate) are possible reagents Lime is the least reactive 

reagent resulting in low efficiencies even at high injection rates. Trona is a very reactive reagent that can be 

used to achieve a range of efficiencies depending upon the amount of sorbent injected. 

A variety of manufactures have developed DSI systems. Each of the vendors contacted cited challenges with 

DSI systems upstream of an existing ESP and none would guarantee the overall performance of the system. 

DSI systems using lime, soda ash, or Trona work well when particulate control is performed by a baghouse. 

However, because ESP performance is drastically affected by the increased particulate loading and the 

characteristics of the particulate, the vendors do not recommend use of DSI in this case. The use of the 

existing ESPs for control of additional particulate matter loading would require a re-design or replacement of 

the ESP. The vertical structure of the existing system is a limiting factor, and given these constraints, the DSI 

option is not feasible for installation into existing equipment at this site. 
4-1 March 2007

4.0 Emission Reductions for BART Cost Evaluation 

4.1 Actual Annual Emissions Baseline 

The estimated reduction in emissions from the annual baseline is used to evaluate the potential costs and 

benefits of each technically feasible retrofit technology. While the visibility analysis uses the potential 24-hour 

allowable emissions for NOX and SO2, the BART cost evaluation is based on actual annual emissions for 2001 

through 2003. The average annual emissions for each of the evaluated pollutants is used as reported for the 

three years. Table 4-1 provides the annual actual emissions for NOX, SO2, PM10 and PM2.5. Annual emissions 

estimates for PM10 and PM2.5 are based on total reported PM and adjusted by the fractions provided in 

Table 1.1-6 of AP-42. From that table, PM10 emissions are 67 percent of the total PM, and PM2.5 emissions are 

29 percent of the total emission rates. 

Table 4-1 Baseline Annual Average Emissions for 2001-2003 

 Data provided in ton/year

Pollutant Year C Boiler D Boiler 

2001 1015.9 1436.2

2002 1147.2 1441.9

2003 1009.2 1527.1

NOx

Average 1057.4 1468.4

2001 1932.2 2964.0

2002 2139.9 2825.0

2003 1901.2 2895.1

SO2

Average 1991.1 2894.7

2001 82.4 135.4

2002 113.8 218.8

2003 98.0 130.3

PM

Average 98.1 161.5

PM10 Average 65.7 108.2

PM2.5 Average 28.4 46.8

Note: For the purpose of control evaluation PM emissions are not speciated. 

4.2 Effectiveness and Economic Analysis of NOX Emission Control Alternatives 

Detailed cost data for NOX and SO2 control options are presented in Appendix B, and are summarized below. 

The data include assumed components of capital and operating costs, as shown in each table. Aside from the 

standard capital and operating costs, there are additional costs associated with modifications to existing units 

at this site. These are the costs for replacement energy to provide steam and electricity when the existing units 

are being modified, the costs of lost production (fractional revenue stream) and the costs for demolition of 

existing structures and reconstruction within or near the existing units. This analysis assumes that lost 

production revenue would not be included in the cost of installation. The lost revenue would be based on the 

marginal return (sales minus costs) for product, but market conditions dictate the magnitude of this cost, and 

with this uncertainty it is not included here. 

For operating while one of the units is down for installation of a new control device, the facility would use the 

natural gas fired E-boiler. The E-boiler can generate up to 350,000 lbs/hour of steam, while the C and D 

boilers generate up to 400,000 and 880,000 lbs/hour of steam, respectively. The E-boiler has a heat input 

rating of 490 MMBtu/hour, the C boiler has a heat input rating of 534 MMBtu/hour and the D boiler has a heat 
4-2 March 2007

input rating of 880 MMBtu/hour. The E-boiler can therefore replace only a portion of the C and D boiler steam 

demand. 

Replacement energy costs during downtime are accounted for by assuming that retrofits would be made for 

each boiler at different times. The cost analyses assume natural gas costs of $10/MMBtu for operation of the 

natural gas fired boiler (Boiler E) and coal costs of $2/MMBtu for a cost differential of $8/MMBtu. Therefore the 

cost of the replacement steam is $94,000 per day (490 MMBtu/hr X $8/MMBtu X 24 hr/day) for either unit. The 

downtimes and costs for each unit are discussed below for each option. 

Since the existing units are housed in existing structures at the facility, those structures would need to be 

modified or removed to accommodate any installation of major control equipment devices. The level of 

demolition and removal of structural material includes modifications to buildings, pipe racks, pavement, utilities, 

and tanks. Table A-2 in Appendix A provides the details of the demolition costs for C boiler and Table A-3 

provides demolition costs for D boiler. The tables list the associated costs for each component of the 

demolition, and are summarized for each of the control options that involve this form of site preparation. These 

values are incorporated into the cost estimates as “site preparation” discussed in this Section and in the tables 

in Appendix B. 

4.2.1 NOx BART Alternatives Evaluated 

Detailed cost data for NOX control options are presented in Appendix B, and are summarized below. The data 

include assumed components of capital and operating costs, as shown in each table. Aside from the standard 

capital and operating costs, there are additional costs associated with modifications to existing units this site. 

These are the costs for replacement energy to provide steam and electricity when the existing units are being 

modified, and the costs for demobilization and reconstruction within or near the existing units. The downtime 

associated with installation of each system is assumed to be 2-weeks beyond the normal turnaround time. 

As noted above, SCR and SNCR are feasible, but would need to be constructed outside the existing structure, 

and include a new stack. The duration of the construction and installation of either system is in the range of a 

total of 26 weeks with 3 weeks of unit outage time (including turnaround) to allow the new system to be 

installed on each unit. As such, it is estimated that installation of the SCR and SNCR systems would require 

2 additional weeks beyond the normal 1-week maintenance turnaround outage of Boilers C and D down time 

to include installation of the air flow control and ducting system that is required for this option. 

The replaced energy cost for the 2 week period would apply to each of the installed systems, including NOx 

and SO2 controls. At $94,000 per day, the cost is approximately $1,300,000 for each option. As an installation 

cost this would lead to approximately $105,000 in annualized costs for each pollutant, for each combination of 

controls that would be installed. The estimate is based on a 30 year period at 7 percent interest. Costs per ton 

of NOx removed would be $100 per ton for the C Boiler and $72 per ton for the D boiler. For a combined 

installation of NOx and SO2 controls, the costs per ton would be appropriately reduced. 

4.2.2 Costs for Boiler C NOX

SCR is expected to reduce NOx by 80 percent or 845.9 tons per year (tpy) and is estimated to be $2,700 per 

ton (see Appendix B, Table B-1). SNCR is expected to reduce NOx by 50 percent or 528.7 tpy and is also 

estimated to be $2,700 per ton (see Appendix B, Table B-3). The Alstom LNCFS P2 (LNB) option is expected 

to reduce NOx emissions to about 0.45 lb/MMBtu, which is equivalent to a reduction of approximately 12 

percent from the annual baseline emission rate. This equates to an annual reduction from baseline emissions 

of about 126.9 tpy, at an estimated cost of $840 per ton (see Appendix B, Table B-5). The Alstom LNCFS 

Level 2 (LNB+SOFA) option is expected to reduce NOX emissions to about 0.32 lb/MMBtu, which is equivalent 

to a reduction of approximately 30 percent from the annual baseline emission rate. This equates to an annual 

reduction from baseline emissions of 317.2 tpy, at an estimated annualized cost of $1,330 per ton (see 

Appendix B, Table B-5). 
4-3 March 2007

Table 4-2 below summarizes the total cost, annualized costs and incremental cost per ton of each evaluated 

NOx control technology. 

Table 4-2 Cost Evaluation of NOx controls for Boiler C 

Control 

Technology 

NOx controlled 

(tpy) Annualized Cost ($)

Cost Effectiveness 

($/ton) 

Incremental 

Cost ($/ton) 

SCR 845.9 $2,322,500 $2700 $2,802 

SNCR 528.7 $1,433,600 $2700 $4,783 

LNB + SOFA 317.2 $422,000 $1330 $1,661 

LNB 126.9 $106,000 $840 $840 

4.2.3 Boiler D NOx

SCR is expected to reduce NOx by 80 percent or 1174.7 tpy and is estimated to be $2,900 per ton (see 

Appendix B, Table B-2). SNCR is expected to reduce NOx by 50 percent 734.2 tpy and is estimated to be 

$2,000 per ton (see Appendix B, Table B-4). The Alstom LNCFS P2 (LNB) option is expected to reduce NOx 

emissions to about 0.45 lb/MMBtu, which is equivalent to a reduction of approximately 12 percent from the 

annual baseline emission rate. This equates to an annual reduction from baseline emissions of about 

176.2 tpy, at an estimated cost of $770 per ton (see Appendix B, Table B-6). The Alstom LNCFS Level 2 

(LNB+SOFA) option is expected to reduce NOx emissions to about 0.32 lb/MMBtu, which is equivalent to a 

reduction of approximately 30 percent from the annual baseline emission rate. This equates to an annual 

reduction from baseline emissions of 440.5 tpy, at an estimated annualized cost of $1,430 per ton (see 

Appendix B, Table B-6). 

Table 4-3 below summarizes the total cost, annualized costs and incremental cost per ton of each evaluated 

NOx control technology. 

Table 4-3 Cost Evaluation of NOx controls for Boiler D 

Control 

Technology 

NOx controlled 

(tpy) Annualized Cost ($)

Cost Effectiveness 

($/ton) 

Incremental 

Cost ($/ton) 

SCR 1174.7 $3,386,900 $2900 $4,314 

SNCR 734.2 $1,486,600 $2000 $2,913 

LNB + SOFA 440.5 $631,000 $1430 $1,873 

LNB 176.2 $136,000 $770 $770 

4.3 Effectiveness and Economic Analysis of SO2 Emission Control Alternatives 

4.3.1 SO2 BART Alternatives Evaluated 

The potential reductions and estimated cost impacts of installing SO2 emission reduction technology are 

presented in this section. The SO2 control technology that will require additional outage time beyond a normal 

maintenance schedule outage is the WFGD and the spray dryer absorber. Further discussion of these 

technologies follows. 

As noted above, WFGD and SDA are feasible, but would need to be constructed outside the existing structure, 

and include a new stack. Both Alstom Power and Allied Environmental Solution (Allied) provided input into the 

cost for installing a WFGD system. Due to the small size of the General Chemical boilers, and non-ideal 

gas/solids residence time, a realistic SO2 reduction of 90 percent with WFGD has been assumed. 
4-4 March 2007

The duration of the construction and installation of either system is in the range of a total of 26 weeks with 3 

weeks of unit outage time to allow the new system to be installed on each unit. As such, it is estimated that 

installation of each system would require 2 additional weeks beyond the normal 1-week maintenance 

turnaround outage of Boilers C and D down time to include installation of the air flow control and ducting 

system that is required for this option. 

As described in Section 4.2 above, replacement energy costs for each boiler outage to install WFGD or SDA 

would be $1,316,000 based on $94,000 per day for 14 days. The added annualized cost for this energy 

replacement would amount to about $53 per ton for C boiler and $36 per ton for the D boiler. 

Since the existing units are housed in existing structures at the facility, those structures would need to be 

modified or removed to accommodate any installation of major control equipment devices. The level of 

demolition and removal of structural material includes modifications to buildings, pipe racks, pavement, utilities, 

and tanks. Estimates of demolition costs for each of the NOX control options are provided in Appendix A Table 

A-2 for the C Boiler and in Table A-3 for the D Boiler. The tables list the associated costs for each component 

of the demolition. These values are incorporated into the cost estimates discussed in this Section and in the 

tables in Appendix B. 

4.3.2 Costs for Boiler C SO2

The WFGD option is expected to reduce SO2 emissions by approximately 90 percent from the annual baseline 

emission rate. This equates to an annual reduction from baseline emissions of 1,792 tpy, at an estimated 

annualized cost of $7,028,300 per year. The equivalent cost effectiveness to reduce SO2 emissions is 

estimated to be $3,900 per ton (see Appendix B, Table B-7). 

The SDA option is expected to reduce SO2 emissions by approximately 80 percent from the annual baseline 

emission rate. This equates to an annual reduction from baseline emissions of 1592.9 tpy, at an estimated 

annualized cost of $5,133,800 per year. The equivalent cost effectiveness to reduce SO2 emissions is 

estimated to be $3,200 per ton (see Appendix B, Table B-9). 

Table 4-4 below summarizes the total cost, annualized costs and incremental cost per ton of each evaluated 

SO2 control technology. 

Table 4-4 Cost Evaluation of SO2 controls for Boiler C 

Control 

Technology 

SO2 controlled 

(tpy) Annualized Cost ($)

Cost Effectiveness 

($/ton) 

Incremental 

Cost ($/ton) 

WFGD 1792.0 $7,028,300 $3900 $9515 

SDA 1592.9 $5,133,800 $3200 $3200 

4.3.3 Costs for Boiler D SO2

The WFGD option is expected to reduce SO2 emissions by approximately 90 percent from the annual baseline 

emission rate. This equates to an annual reduction from baseline emissions of 2,605.2 tpy, at an estimated 

annualized cost of $7,043,700 per year. The equivalent cost effectiveness to reduce SO2 emissions is 

estimated to be $2,605 per ton (See Appendix B, Table B-8). 

The SDA option is expected to reduce SO2 emissions by approximately 80 percent from the annual baseline 

emission rate. This equates to an annual reduction from baseline emissions of 2315.8 tpy, at an estimated 

annualized cost of $5,149,200 per year. The equivalent cost effectiveness to reduce SO2 emissions is 

estimated to be $2,200 per ton (See Appendix B, Table B-10). 
4-5 March 2007

Table 4-5 below summarizes the total cost, annualized costs and incremental cost per ton of each evaluated 

SO2 control technology. 

Table 4-5 Cost Evaluation of SO2 controls for Boiler D 

Control 

Technology 

SO2 controlled 

(tpy) Annualized Cost ($)

Cost Effectiveness 

($/ton) 

Incremental 

Cost ($/ton) 

WFGD 2605.2 $7,043,700 $2,704 $6,546 

SDA 2315.8 $5,149,200 $2,200 $2,200 

4.3.4 Summary of Reductions and Control Costs 

The SO2 emission reductions that are used in the cost analysis are based on the data presented above, and 

the relevant emission reduction associated with the each technology are carried forward for detailed review in 

the visibility analysis. 
5-1 March 2007

5.0 Selection of Control Scenarios 

5.1 Control Options Modeling Emission Rates 

Visibility impacts were evaluated with modeling based on the maximum 24-hour emission rate for the criteria 

pollutants. For evaluating visibility improvement as a result of installing the BART options, the first step is to 

identify the level of improvement in the 24-hour maximum emissions, from the baseline to the proposed new 

limits. Table 5-1 lists each control option, as applied to each unit for separate NOX and SO2 controls. The 

applicable emission rate and percent emissions reduction from the 24-hour peak emission rate used for 

modeling are also listed. These percent reductions are different than the percents from annual baseline used 

in the cost analysis, but represent the same emission rates achieved. 

Table 5-1 Emission Rates for Visibility Evaluation for Each Considered Option 

Unit Control Option 

Baseline Peak 

24-hour Emission 

(lb/hour) 

Reduction from 

Baseline Peak (%) 

Future Peak 

24-hour Emission 

(lb/hour) 

C LNB + SOFA (NOx) 376 30% 263 

C SCR (NOx) 376 80% 75 

C SNCR (NOx) 376 50% 188 

C WFGD (SO2) 641 90% 64 

C DFGD (SO2) 641 80% 128 

D LNB + SOFA (NOx) 616 30% 431 

D SCR (NOx) 616 80% 123 

D SNCR (NOx) 616 50% 308 

D WFGD (SO2) 1056 90% 106 

D DFGD (SO2) 1056 80% 211 

Emissions of PM10 were based on the current emission limit for both units. That limit is 0.10 lb/MMBtu for total 

PM. The analysis further adjusts that emission rate as discussed in Table 2-1 of this report. No adjustments to 

those emission rates were made as part of this analysis, because the current electrostatic precipitators are 

determined to represent the state of the art or equivalent control on the affected units. 

The baseline modeling visibility impact was determined for each modeling year for each of the above control 

options, excluding LNB only. The initial control option for NOx for this analysis is the LNB+SOFA for NOX

controls. 

In accord with BART guidance, the CALPUFF Method 6 modeling setup was used to evaluate results of 

impacts on visibility at the nearby Class I areas. Impacts were assessed at the Jim Bridger Wilderness Area 

and ad the Fitzpatrick Wilderness Area. In all cases, the maximum impacts are at the Jim Bridger Wilderness 

Area. Results of the modeling for each of these scenarios are provided in Table 5-2, showing the maximum 

impact for each year for the baseline analysis and the impact for each scenario for the worst case year (2001). 

The table lists the results for the Base Case for each of the three modeling years, using the percent change 

based on the 20 percent cleanest days at each of the Class I areas. 

Results for the Base Case show the maximum impacts BART impacts are evaluated on the reported 8th

highest impact for each of the three years. The results showed that the maximum number of days with impacts 

above 5 percent and 10 percent at the Jim Bridger Wilderness Area occurred in 2001. The impacts for that 

year have formed the basis for evaluating each of the options. 
5-2 March 2007

As can be seen from the table, the maximum impacts are reduced with the successive control scenarios, 

except that Case 3 is slightly less than Case 4. The 8th highest impacts for these scenarios (cases) form the 

basis for selecting BART for these units. Figure 5-1 provides a comparative visualization of the 8th highest 

impact for each Control Case for both the Jim Bridger and Fitzpatrick Wilderness Areas. 

5.2 Control Scenario Options for Evaluation 

The Control Scenario options for visibility impact modeling and economic analysis must consider a reasonable 

combination of equipment and control options. The evaluation of the visibility improvement due to the BART 

options was conducted by grouping the choices in order of increasing controls for individual pollutants and for 

combinations of control technologies as follows: 

Base Case: No additional controls; 

Option 1: LNB + SOFA 

Option 2: SNCR 

Option 3: SCR 

Option 4: DFGD 

Option 5: WFGD 

Option 6: LNB + SOFA + DFGD 

Option 7: LBN + SOFA + WFGD 

Option 8: SNCR + DFGD 

Option 9: SNCR + WFGD 

Option 10: SCR + DFGD 

Option 11: SCR + WFGD 

For this consideration, the optional controls were applied to each boiler for each option. The combination of the 

modeling results and the economic analyses are provided in Chapter 6. 
5-3 

Figure 5-1 General Chemical – BART Determination: 8th Highest Modeled Visibility Impact (2001) 

General Chemical - BART Determination: 8th Highest Modeled Visibility Impact (20

0.00.10.20.30.40.50.60.70.80.91.0

Base Case Case 1 - LNB Case 2 - SNCR Case 3 - SCR Case 4 - DFGD Case 5 - WFGD Case 6 - LNB+DFGD Case 7 - LNB+WFGD Case 8 - SNCR+DFGD Case 9 - SNCR+WFGD Case 10 - SCR+

Emissions Scenario

Delta Deciview, (dv)

Bridger WildeFitzpatrick W
6-1 March 2007

6.0 Selection of the Best Alternative for BART Control 

6.1 Summary of Results 

The selection of BART controls is based on the annualized costs for controls and the extent of improvement in 

visibility at Class I areas. For this analysis the improvement is based on impacts at the Jim Bridger Wilderness 

Area only, and is based on the 98th percentile impact at that area. Table 6-1 provides the calculated 

improvement in visibility for each control option, taken from the results in Table 5-2. The cost associated with 

each of the controls is also provided in Table 5-2, summarized from the data provided in Appendix B cost 

analyses. 

Table 6-1 Tabulation of Visibility Improvement at Jim Bridger Wilderness Area and Annual 

Costs for Each Control Option 

 Modeled dV Delta dV Annualized Cost 

Case Max Impact 8th-highest Max 8th Highest SO2 + NOx Per dV 

Base 2.19 0.84 

1 1.86 0.72 0.33 0.12 $1,053,000 $8,775

2 1.64 0.64 0.55 0.20 $2,920,100 $14,601

3 1.32 0.53 0.87 0.31 $5,709,400 $18,417

4 1.86 0.59 0.33 0.25 $10,283,000 $41,132

5 1.80 0.53 0.39 0.31 $14,072,000 $45,394

6 1.43 0.45 0.76 0.39 $11,336,000 $29,067

7 1.36 0.40 0.83 0.44 $15,125,000 $34,375

8 1.13 0.36 1.06 0.48 $13,203,100 $27,506

9 1.06 0.31 1.13 0.53 $16,992,100 $32,061

10 0.66 0.22 1.53 0.62 $15,992,400 $25,794

11 0.59 0.17 1.60 0.67 $19,781,400 $29,524

Annualized Cost for Controls for Each Case 

(Data obtained from tables in Appendix B) 

 C-NOx D-NOx C-SO2 D-SO2 Total 

1 422,000 631,000 1,053,000

2 1,433,600 1,486,500 2,920,100

3 2,322,500 3,386,900 5,709,400

4 5,133,800 5,149,200 10,283,000

5 7,028,300 7,043,700 14,072,000

6 422,000 631,000 5,133,800 5,149,200 11,336,000

7 422,000 631,000 7,028,300 7,043,700 15,125,000

8 1,433,600 1,486,500 5,133,800 5,149,200 13,203,100

9 1,433,600 1,486,500 7,028,300 7,043,700 16,992,100

10 2,322,500 3,386,900 5,133,800 5,149,200 15,992,400

11 2,322,500 3,386,900 7,028,300 7,043,700 19,781,400

The calculated annualized cost for visibility improvement for each of the control options is also provided in that 

table, based on the combined data for 2001. The results are given in thousands of dollars for a delta deciview 

(threshold of perceptibility) improvement. The data are also depicted in Figure 6-1, which shows the range of 

improvement and cost for each of the options. Results of modeling for other years for the baseline and BART 

options are provided separately in the computer modeling archive. 
6-2 March 2007

Figure 6-1 Plot of Visibility Improvement vs. Annualized Control Cost for BART Options 

Figure 6-1 also provides a depiction of the least cost envelope for the considered options. As can be seen 

from that depiction, the costs associated with Case 1 (LNB + SOFA) and Case 10 (LNB + SOFA + Dry 

Scrubber) form the least cost envelope. In considering this depiction, the SNCR and SCR options are all above 

the envelope; and the wet scrubber options are also above that envelope. 

6.2 Annualized Cost for Implementing Control vs Decrease in Visibility Impairment 

BART Controls are selected based on the estimated cost for applying those controls and on the expected 

visibility improvement that would result from any of the applicable controls. For this analysis, BART is selected 

as the installation of LNB plus SOFA based on the following considerations. 

(1) Annualized operating costs. Table 6-1 shows the annualized costs doubling and tripling for each of 

the first incremental options that are considered, from 1 million to 3 million and doubling after that. All 

of the combined options (Cases 6 though 11) are between $10 million and $20 million. 

(2) Cost effectiveness. As seen in Tables 4-1 through 4-4 the cost effectiveness for LNB + SOFA are 

within the generally acceptable range of less than $2,000 per ton. The incremental costs for step-wise 

increases in controls are also relatively high. 

(3) The improvements in visibility, when considered at the perceptible 1 dV level, are very small for 

controls beyond the LNB + SOFA option. As seen in Table 5-2 there are only 4 days above 1 dV 

impact with Case 1 controls, and the impact for the 8th highest level is below 1 dV. The more 

expensive controls would lead to only four days of reduced perceptible impacts on visibility. 

Cost Analysis of Deciview Improvement at Jim 

Bridger WA

$0

$5,000

$10,000

$15,000

$20,000

$25,000

$30,000

$35,000

$40,000

$45,000

$50,000

0.00 0.20 0.40 0.60 0.80

Deciview Improvement

Cost ($1,000)
6-3 March 2007

(4) The least cost envelope, as applied in Figure 6-1 shows that Cases 1 and 10 provide the envelope 

for visibility reductions. The annualized cost for Case 10 is over $15 million, and is considered 

excessive for this application. 

The retrofit of low NOX LNB burners is determined to represent BART for Boilers C and D at the General 

Chemical – Green River. This conclusion is based on technical viability, degree of deciview improvement that 

can be achieved, and the cost effectiveness in $/deciview improvement of the various Control Scenarios 

options evaluated. 
March 2007

Appendix A 

Facility Design Data 
Boiler C

Year Built 1973

Manufacturer Combustion Engineering

Rating 534 MMBtu/hr

400 klb/hr Steam

Fuel Low-Sulfur Bituminous Coal

Firing Tangentially Fired

Air Pollution Control Hot-Side ESP

Soda Ash Coal Conditioning

SO2 Emissions 1.3 lb/MMBtu Maximum

618 lb/hr Maximum

1.1 lb/MMBtu Average

542 lb/hr Average

NOx Emissions 0.68 lb/MMBtu Maximum

315 lb/hr Maximum

0.58 lb/MMBtu Average

284 lb/hr Average

Exhaust Tepmerature 320 o

F

Boiler D

Year Built 1975

Manufacturer Combustion Engineering

Rating 880 MMBtu/hr

660 klb/hr Steam

Fuel Low-Sulfur Bituminous Coal

Firing Tangentially Fired

Air Pollution Control Hot-Side ESP

Soda Ash Coal Conditioning

SO2 Emissions 1.4 lb/MMBtu Maximum

646 lb/hr Maximum

0.93 lb/MMBtu Average

553 lb/hr Average

NOx Emissions 0.83 lb/MMBtu Maximum

408 lb/hr Maximum

0.47 lb/MMBtu Average

219 lb/hr Average

Exhaust Tepmerature 320 o

F

Table A-1

Boiler Data Sheet

General Chemical - Green River, WY
Building Pavement Pipe Racks Utilities Tanks

LNB None NA NA NA NA NA 

LNB+SOFA None NA NA NA NA NA 

SNCR Ammonia (Urea) Tank; and Truck Access. NA $17,966.2 $35,400 $1,286 NA 

SCR Ammonia Tank; and Truck Access. NA $17,966.2 $35,400 $1,286 NA 

DSI

Trona Storage Silo;Pnuematic Conveyor; andLocal Control Building.

$140,108 $12,592.2 $35,400 $1,286 $29,250.00 

DFGD

Limestone Storage Bunker;Truck Access;Processing & Control Building; andStorage Silo.

$141,990 $18,192.2 $35,400 $1,286 $29,250.00 

WFGD

Limestone Storage Bunker;Truck Access;Processing & Control Building; Scrubber Water/Wastewater Treatment; andStorage Silo.

$141,990 $16,792.2 $35,400 $1,286 $29,250.00 

Element Demolition Cost Per Replacement Cost Per

Building $0.14 CF $123 SF

Pavement $23.29 SY $140 CY

Pipe Racks $7.60 pipe/LF $16 /pipe/LF

Utilities $2.57 LF $6 /LF

Tanks $1,450 each $27,800 each

Material Disposal $11.74 CY

Contracting 15 % 15 %

Contingency 40 % 40 %

Table A-2

Demolition and Replacement Costs Boiler C

Factors: 

(Source: RS 

MEANS 2006 

Site Work & 

Landscape Cost 

Data, 

Environmental 

Remediation 

Cost Data)

Existing Infrastucture Removed

Demolition to Necessary 

Accommodate Addition of 

Control 

Tecnology 
March 2007

Appendix B 

Cost Analyses for BART Control Options 
Control Efficiency (%) 80.0

Facility Input Data

Item Value

Operating Schedule

 Shifts per day 3

 Hours per day 24

 Days per week 7

 Total Hours per year 8760

Economic Life, years 30

Interest Rate (%) 7

Source(s) Controlled Boiler C

Temperature (F) 750

Total Flowrate (acfm) 220,000

NOX From PC Operation (lb/hr) 315

NOx Emissions (tpy) from boiler 1,057.4

Site Specific Electricity Cost ($/kWh) 0.090

Site Specific Operating Labor Cost ($/hr) $37.00

Site Specific Maint. Labor Cost ($/hr) $37.00

Capital Costs

Value Basis

Direct Costs

1.) Purchased Equipment Cost

 a.) Equipment cost + auxiliaries $4,005,000 Vendor Quotes, A

 b.) Instrumentation $400,500 0.10 x A

 c.) Sales taxes $280,400 0.07 x A

 d.) Freight $200,300 0.05 x A

 Total Purchased equipment cost, (PEC) $4,886,200 B = 1.22 x A

2.) Direct installation costs

 a.) Foundations and supports $390,900 0.08 x B

 b.) Handling and erection $684,100 0.14 x B

 c.) Electrical $195,400 0.04 x B

 d.) Piping $97,700 0.02 x B

 e.) Insulation for ductwork $48,900 0.01 x B

 f.) Painting $48,900 0.01 x B

 Total direct installation cost $1,465,900 0.30 x B

3.) Site preparation $114,769 Demo Cost Sheet

4.) Stack $4,800,000 CUECost

5.) Replacement Energy Costs $1,316,000 14 days down

 Total Direct Cost, DC $12,582,900 1.30B + SP + Bldg.

Indirect Costs (installation)

5.) Engineering $488,600 0.10 x B

6.) Construction and field expenses $244,300 0.05 x B

7.) Contractor fees $488,600 0.10 x B

8.) Start-up $97,700 0.02 x B

9.) Performance test $48,900 0.01 x B

10.) Contingencies $146,600 0.03 x B

 Total Indirect Cost, IC $1,514,700 0.31B + Other

Total Capital Investment (TCI) = DC + IC $14,097,600 1.61B + SP + Bldg. + Other

Table B-1

Selective Catalytic Reduction - NOx Controls

Boiler C 

General Chemical BART Appendix Tables (2).xls

B-1 NOX- SCR 1 of 2 3/22/2007
Control Efficiency (%) 80.0

Table B-1

Selective Catalytic Reduction - NOx Controls

Boiler C 

Annual Costs

Item Value Basis Source

1) Electricity

Fan Power Requirement (kW) 200 Estimate

Electric Power Cost ($/kWh) 0.09

 Cost ($/yr) $157,680

2) Operating Costs 

Operating Labor Requirement (hr/shift) 0.5 1/2 hour per shift Estimate

 Unit Cost ($/hr) $37.00 Facility Data Estimate

 Labor Cost ($/yr) $20,200

3) Ammonia Costs ($/lb) $0.13 Estimate

 Hourly Requirerment (Lbs/hour) 284

 Annual requirement (Lbs/year) 2,483,933.04

 Total Ammonia Costs ($/year) $310,492

Total Operating Costs $488,372 Estimate

4) Supervisory Labor

 Cost ($/yr) $3,030 15% Operating Labor OAQPS

5) Maintenance

 Maintenance Labor Req. (hr/year) 182.5 1/2 hour per day Estimate

 Catalyst Replacement Labor Req. (hr/yr) 426.7 8 men for 160 hours every 3 yrs Estimate

 Unit Cost ($/hr) $37.00 Facility Data Estimate

 Labor Cost ($/yr) $22,540

 Material Cost ($/yr) $22,540 100% of Maintenance Labor OAQPS

 Total Cost ($/yr) $45,080

6) Catalyst Replacement

 Catalyst Cost ($) $150,000 Catalyst modules Estimate

 Sales Tax ($) $0 0% Sales Tax

 Catalyst Life (yrs) 3 n Estimate

 Interest Rate (%) 7 i

 CRF 0.38 Ammortization of Catalyst OAQPS

 Annual Cost ($/yr) $57,160 (Volume)(Unit Cost)(CRF)

7) Indirect Annual Costs

 Overhead $40,990 60% of O&M Costs OAQPS

 Administration $281,950 2% of Total Capital Investment OAQPS

 Property Tax $140,980 1% of Total Capital Investment OAQPS

 Insurance $140,980 1% of Total Capital Investment OAQPS

 Capital Recovery $1,123,990 30 yr life; 7% interest (-cat. cost) OAQPS

Total Indirect ($/yr) $1,728,890

Total Annualized Cost ($/yr) $2,322,500

Total Controlled (tpy) 845.9

Cost Effectiveness ($/ton) $2,700

General Chemical BART Appendix Tables (2).xls

B-1 NOX- SCR 2 of 2 3/22/2007
Control Efficiency (%) 80.0

Facility Input Data

Item Value

Operating Schedule

 Shifts per day 3

 Hours per day 24

 Days per week 7

 Total Hours per year 8760

Economic Life, years 30

Interest Rate (%) 7

Source(s) Controlled Boiler D

Temperature (F) 750

Total Flowrate (acfm) 350,000

NOX From PC Operation (lb/hr) 691

NOx Emissions (tpy) from boiler 1,468.4

Site Specific Electricity Cost ($/kWh) 0.090

Site Specific Operating Labor Cost ($/hr) $37.00

Site Specific Maint. Labor Cost ($/hr) $37.00

Capital Costs

Value Basis

Direct Costs

1.) Purchased Equipment Cost

 a.) Equipment cost + auxiliaries $6,600,000 Vendor Quotes, A

 b.) Instrumentation $660,000 0.10 x A

 c.) Sales taxes $462,000 0.07 x A

 d.) Freight $330,000 0.05 x A

 Total Purchased equipment cost, (PEC) $8,052,000 B = 1.22 x A

2.) Direct installation costs

 a.) Foundations and supports $644,200 0.08 x B

 b.) Handling and erection $1,127,300 0.14 x B

 c.) Electrical $322,100 0.04 x B

 d.) Piping $161,000 0.02 x B

 e.) Insulation for ductwork $80,500 0.01 x B

 f.) Painting $80,500 0.01 x B

 Total direct installation cost $2,415,600 0.30 x B

3.) Site preparation $114,769 Demo Cost Sheet

4.) Stack $4,800,000 CUECost

5.) Replacement Energy Costs $1,316,000 14 days down

 Total Direct Cost, DC $16,698,400 1.30B + SP + Bldg.

Indirect Costs (installation)

5.) Engineering $805,200 0.10 x B

6.) Construction and field expenses $402,600 0.05 x B

7.) Contractor fees $805,200 0.10 x B

8.) Start-up $161,000 0.02 x B

9.) Performance test $80,500 0.01 x B

10.) Contingencies $241,600 0.03 x B

 Total Indirect Cost, IC $2,496,100 0.31B + Other

Total Capital Investment (TCI) = DC + IC $19,194,500 1.61B + SP + Bldg. + Other

Table B-2

Selective Catalytic Reduction - NOx Controls

Boiler D

General Chemical BART Appendix Tables (2).xls

B-2 NOX- SCR 1 of 2 3/22/2007
Control Efficiency (%) 80.0

Table B-2

Selective Catalytic Reduction - NOx Controls

Boiler D

Annual Costs

Item Value Basis Source

1) Electricity

Fan Power Requirement (kW) 300 Estimate

Electric Power Cost ($/kWh) 0.09

 Cost ($/yr) $236,520

2) Operating Costs 

Operating Labor Requirement (hr/shift) 0.5 1/2 hour per shift Estimate

 Unit Cost ($/hr) $37.00 Facility Data Estimate

 Labor Cost ($/yr) $20,200

3) Ammonia Costs ($/lb) $0.13 Estimate

 Hourly Requirerment (Lbs/hour) 622

 Annual requirement (Lbs/year) 5,451,355.01

 Total Ammonia Costs ($/year) $681,419

Total Operating Costs $938,139 Estimate

4) Supervisory Labor

 Cost ($/yr) $3,030 15% Operating Labor OAQPS

5) Maintenance

 Maintenance Labor Req. (hr/year) 182.5 1/2 hour per day Estimate

 Catalyst Replacement Labor Req. (hr/yr) 426.7 8 men for 160 hours every 3 yrs Estimate

 Unit Cost ($/hr) $37.00 Facility Data Estimate

 Labor Cost ($/yr) $22,540

 Material Cost ($/yr) $22,540 100% of Maintenance Labor OAQPS

 Total Cost ($/yr) $45,080

6) Catalyst Replacement

 Catalyst Cost ($) $150,000 Catalyst modules Estimate

 Sales Tax ($) $0 0% Sales Tax

 Catalyst Life (yrs) 3 n Estimate

 Interest Rate (%) 7 i

 CRF 0.38 Ammortization of Catalyst OAQPS

 Annual Cost ($/yr) $57,160 (Volume)(Unit Cost)(CRF)

7) Indirect Annual Costs

 Overhead $40,990 60% of O&M Costs OAQPS

 Administration $383,890 2% of Total Capital Investment OAQPS

 Property Tax $191,950 1% of Total Capital Investment OAQPS

 Insurance $191,950 1% of Total Capital Investment OAQPS

 Capital Recovery $1,534,730 30 yr life; 7% interest (-cat. cost) OAQPS

Total Indirect ($/yr) $2,343,510

Total Annualized Cost ($/yr) $3,386,900

Total Controlled (tpy) 1174.7

Cost Effectiveness ($/ton) $2,900

General Chemical BART Appendix Tables (2).xls

B-2 NOX- SCR 2 of 2 3/22/2007
Control Efficiency (%) 50.0

Facility Input Data

Item Value

Operating Schedule

 Shifts per day 3

 Hours per day 24

 Days per week 7

 Total Hours per year 8760

Economic Life, years 30

Interest Rate (%) 7

Source(s) Controlled Boiler C

Temperature (F) 750

Total Flowrate (acfm) 220,000

NOX From PC Operation (lb/hr) 315

NOx Emissions (tpy) from boiler 1,057.4

Site Specific Electricity Cost ($/kWh) 0.090

Site Specific Operating Labor Cost ($/hr) $37.00

Site Specific Maint. Labor Cost ($/hr) $37.00

Capital Costs

Value Basis

Direct Costs

1.) Purchased Equipment Cost

 a.) Equipment cost + auxiliaries $667,500 Vendor Quotes, A

 b.) Instrumentation $66,800 0.10 x A

 c.) Sales taxes $46,700 0.07 x A

 d.) Freight $33,400 0.05 x A

 Total Purchased equipment cost, (PEC) $814,400 B = 1.22 x A

2.) Direct installation costs

 a.) Foundations and supports $65,200 0.08 x B

 b.) Handling and erection $114,000 0.14 x B

 c.) Electrical $32,600 0.04 x B

 d.) Piping $16,300 0.02 x B

 e.) Insulation for ductwork $8,100 0.01 x B

 f.) Painting $8,100 0.01 x B

 Total direct installation cost $244,300 0.30 x B

3.) Site preparation $114,769 Demo Cost Sheet

4.) Stack $4,800,000 CUECost

5.) Replacement Energy Costs $1,316,000 14 days down

 Total Direct Cost, DC $7,289,500 1.30B + SP + Bldg.

Indirect Costs (installation)

5.) Engineering $81,400 0.10 x B

6.) Construction and field expenses $40,700 0.05 x B

7.) Contractor fees $81,400 0.10 x B

8.) Start-up $16,300 0.02 x B

9.) Performance test $8,100 0.01 x B

10.) Contingencies $24,400 0.03 x B

 Total Indirect Cost, IC $252,300 0.31B + Other

Total Capital Investment (TCI) = DC + IC $7,541,800 1.61B + SP + Bldg. + Other

Table B-3

Selective Non-Catalytic Reduction - NOx Controls

Boiler C

General Chemical BART Appendix Tables_3-22-07.xls

B-3 NOX- SNCR 1 of 2 3/22/2007
Control Efficiency (%) 50.0

Table B-3

Selective Non-Catalytic Reduction - NOx Controls

Boiler C

Annual Costs

Item Value Basis Source

1) Electricity

Pump Power Requirement (kW) 50 Estimate

Electric Power Cost ($/kWh) 0.09

 Cost ($/yr) $39,420

2) Operating Costs 

Operating Labor Requirement (hr/shift) 0.5 1/2 hour per shift Estimate

 Unit Cost ($/hr) $37.00 Facility Data Estimate

 Labor Cost ($/yr) $20,200

3) Ammonia Costs ($/lb) $0.20 $400/ton

 Hourly Requirerment (Lbs/hour) 214

 Annual requirement (Lbs/year) 1,877,249.00

 Total Ammonia Costs ($/year) $375,450

Total Operating Costs $435,070 Estimate

4) Supervisory Labor

 Cost ($/yr) $3,030 15% Operating Labor OAQPS

5) Maintenance

 Maintenance Labor Req. (hr/year) 182.5 1/2 hour per day Estimate

 Catalyst Replacement Labor Req. (hr/yr) 426.7 8 men for 160 hours every 3 yrs Estimate

 Unit Cost ($/hr) $37.00 Facility Data Estimate

 Labor Cost ($/yr) $22,540

 Material Cost ($/yr) $22,540 100% of Maintenance Labor OAQPS

 Total Cost ($/yr) $45,080

6) Indirect Annual Costs

 Overhead $40,990 60% of O&M Costs OAQPS

 Administration $150,840 2% of Total Capital Investment OAQPS

 Property Tax $75,420 1% of Total Capital Investment OAQPS

 Insurance $75,420 1% of Total Capital Investment OAQPS

 Capital Recovery $607,770 30 yr life; 7% interest (-cat. cost) OAQPS

Total Indirect ($/yr) $950,440

Total Annualized Cost ($/yr) $1,433,600

Total Controlled (tpy) 528.7

Cost Effectiveness ($/ton) $2,700

General Chemical BART Appendix Tables_3-22-07.xls

B-3 NOX- SNCR 2 of 2 3/22/2007
Control Efficiency (%) 50.0

Facility Input Data

Item Value

Operating Schedule

 Shifts per day 3

 Hours per day 24

 Days per week 7

 Total Hours per year 8760

Economic Life, years 30

Interest Rate (%) 7

Source(s) Controlled Boiler D

Temperature (F) 750

Total Flowrate (acfm) 350,000

NOX From PC Operation (lb/hr) 691

NOx Emissions (tpy) from boiler 1,468.4

Site Specific Electricity Cost ($/kWh) 0.090

Site Specific Operating Labor Cost ($/hr) $37.00

Site Specific Maint. Labor Cost ($/hr) $37.00

Capital Costs

Value Basis

Direct Costs

1.) Purchased Equipment Cost

 a.) Equipment cost + auxiliaries $1,100,000 Vendor Quotes, A

 b.) Instrumentation $110,000 0.10 x A

 c.) Sales taxes $77,000 0.07 x A

 d.) Freight $55,000 0.05 x A

 Total Purchased equipment cost, (PEC) $1,342,000 B = 1.22 x A

2.) Direct installation costs

 a.) Foundations and supports $107,400 0.08 x B

 b.) Handling and erection $187,900 0.14 x B

 c.) Electrical $53,700 0.04 x B

 d.) Piping $26,800 0.02 x B

 e.) Insulation for ductwork $13,400 0.01 x B

 f.) Painting $13,400 0.01 x B

 Total direct installation cost $402,600 0.30 x B

3.) Site preparation $114,769 Demo Cost Sheet

4.) Stack $4,800,000 CUECost

5.) Replacement Energy Costs $1,316,000 14 days down

 Total Direct Cost, DC $7,975,400 1.30B + SP + Bldg.

Indirect Costs (installation)

5.) Engineering $134,200 0.10 x B

6.) Construction and field expenses $67,100 0.05 x B

7.) Contractor fees $134,200 0.10 x B

8.) Start-up $26,800 0.02 x B

9.) Performance test $13,400 0.01 x B

10.) Contingencies $40,300 0.03 x B

 Total Indirect Cost, IC $416,000 0.31B + Other

Total Capital Investment (TCI) = DC + IC $8,391,400 1.61B + SP + Bldg. + Other

Table B-4

Selective Non-Catalytic Reduction - NOx Controls

Boiler D

General Chemical BART Appendix Tables_3-22-07.xls

B-4 NOX- SNCR 1 of 2 3/22/2007
Control Efficiency (%) 50.0

Table B-4

Selective Non-Catalytic Reduction - NOx Controls

Boiler D

Annual Costs

Item Value Basis Source

1) Electricity

Pump Power Requirement (kW) 50 Estimate

Electric Power Cost ($/kWh) 0.09

 Cost ($/yr) $39,420

2) Operating Costs 

Operating Labor Requirement (hr/shift) 0.5 1/2 hour per shift Estimate

 Unit Cost ($/hr) $37.00 Facility Data Estimate

 Labor Cost ($/yr) $20,200

3) Ammonia Costs ($/lb) $0.13 Estimate

 Hourly Requirerment (Lbs/hour) 298

 Annual requirement (Lbs/year) 2,606,915.48

 Total Ammonia Costs ($/year) $325,864

Total Operating Costs $385,484 Estimate

4) Supervisory Labor

 Cost ($/yr) $3,030 15% Operating Labor OAQPS

5) Maintenance

 Maintenance Labor Req. (hr/year) 182.5 1/2 hour per day Estimate

 Catalyst Replacement Labor Req. (hr/yr) 426.7 8 men for 160 hours every 3 yrs Estimate

 Unit Cost ($/hr) $37.00 Facility Data Estimate

 Labor Cost ($/yr) $22,540

 Material Cost ($/yr) $22,540 100% of Maintenance Labor OAQPS

 Total Cost ($/yr) $45,080

6) Indirect Annual Costs

 Overhead $40,990 60% of O&M Costs OAQPS

 Administration $167,830 2% of Total Capital Investment OAQPS

 Property Tax $83,910 1% of Total Capital Investment OAQPS

 Insurance $83,910 1% of Total Capital Investment OAQPS

 Capital Recovery $676,230 30 yr life; 7% interest (-cat. cost) OAQPS

Total Indirect ($/yr) $1,052,870

Total Annualized Cost ($/yr) $1,486,500

Total Controlled (tpy) 734.2

Cost Effectiveness ($/ton) $2,000

General Chemical BART Appendix Tables_3-22-07.xls

B-4 NOX- SNCR 2 of 2 3/22/2007
Alstom 

LNCFS P2

Alstom LNCFS 

Level 2 Basis

Basic Equipment 136,170 $ 961,200 $ Note 1

Total Installed Cost not 

Including Lost Revenue $ 360,851 $ 2,547,180 Note 2 

Increased Carbon Loss 

(Loss on Ignition) $ - $ 40,000 Possible 50% increase for LNCFS Level 2

Urea

Operating Labor 32,850 $ 32,850 $ 1 hr/shift at $30/hr

Supervisor 4,928 $ 4,928 $ 15% of operating labor - Note 3

Maintenance Labor 2,887 $ 20,377 $ 0.8% of total installed cost - Note 4

Maintenance Materials 4,330 $ 30,566 $ 1.2% of total installed cost Note 4

Overhead $ 26,997 $ 53,233 60% of oper, maint. & supv labor + maint. 

mtl costs - Note 3

Property Tax - $ - $ 1% of total installed costs - Note 3

Insurance - $ - $ 2% of total installed costs - Note 3

Administration - $ - $ 2% of total installed costs - Note 3

Capital Recovery 34,064 $ 240,454 $ 7%, 20 years - Note 3

Total Annual Cost 106,000 $ 422,000 $ 

NOx Emissions before 

Control, ton/yr 1,057.4 1,057.4 

Realistic maximum future emissions 

based on maximum 12-months during the 

last 5 years

Emission Reduction 12% 30% Based on information from Alstom

Emission Reduction, ton/yr 317.2 126.9 

Cost Effectiveness, $/ton 1,330 840 

Incremental Cost $ 316,000

Incremental NOx Reduction, 

ton/yr 190

Incremental Cost 

Effectiveness, $/ton 1,660

1

2

3

4

5 EPA Air Pollution Control Cost Manual, Sixth Edition, Section 4, Pages 1-3 and 1-25. EPA/452/B-002-001. January 2002.

Table B-5

Combustion Modifications and Low NOx Burners

Boiler C

Total installed costs for Alstom options are based on low NOx burner factors from "Best Available Retrofit Technology Engineering 

Analysis", Midwest RPO, March 30, 2005 that indicates total costs are 2.65 times basic equipment. This factor accounts for e

Capital Cost

"Best Available Retrofit Technology Engineering Analysis", Midwest RPO, March 30, 2005.

Based on EPA's CUECOST program.

Basic equipment for Alstom options are from Alstom Power budgetary costs of $255/MMBtu/hr for LNCFS P2 and 

$1,800/MMBtu/hr for LNCFS Level 2.

Annual Costs, $/yr

Cost Effectiveness
Alstom 

LNCFS P2

Alstom LNCFS 

Level 2 Basis

Basic Equipment 224,400 $ 1,584,000 $ Note 1

Total Installed Cost not 

Including Lost Revenue $ 594,660 $ 4,197,600 Note 2 

Increased Carbon Loss 

(Loss on Ignition) $ - $ 40,000 Possible 50% increase for LNCFS Level 2

Urea

Operating Labor 32,850 $ 32,850 $ 1 hr/shift at $30/hr

Supervisor 4,928 $ 4,928 $ 15% of operating labor - Note 3

Maintenance Labor 4,757 $ 33,581 $ 0.8% of total installed cost - Note 4

Maintenance Materials 7,136 $ 50,371 $ 1.2% of total installed cost Note 4

Overhead $ 29,802 $ 73,038 60% of oper, maint. & supv labor + maint. 

mtl costs - Note 3

Property Tax - $ - $ 1% of total installed costs - Note 3

Insurance - $ - $ 2% of total installed costs - Note 3

Administration - $ - $ 2% of total installed costs - Note 3

Capital Recovery 56,136 $ 396,253 $ 7%, 20 years - Note 3

Total Annual Cost 136,000 $ 631,000 $ 

NOx Emissions before 

Control, ton/yr 1,468.4 1,468.4 

Realistic maximum future emissions 

based on maximum 12-months during the 

last 5 years

Emission Reduction 12% 30% Based on information from Alstom

Emission Reduction, ton/yr 440.5 176.2 

Cost Effectiveness, $/ton 1,430 770 

Incremental Cost $ 495,000

Incremental NOx Reduction, 

ton/yr 264

Incremental Cost 

Effectiveness, $/ton 1,870

1

2

3

4

5 EPA Air Pollution Control Cost Manual, Sixth Edition, Section 4, Pages 1-3 and 1-25. EPA/452/B-002-001. January 2002.

"Best Available Retrofit Technology Engineering Analysis", Midwest RPO, March 30, 2005.

Based on EPA's CUECOST program.

Basic equipment for Alstom options are from Alstom Power budgetary costs of $255/MMBtu/hr for LNCFS P2 and 

$1,800/MMBtu/hr for LNCFS Level 2.

Annual Costs, $/yr

Cost Effectiveness

Table B-6

Combustion Modifications and Low NOx Burners

Boiler D

Total installed costs for Alstom options are based on low NOx burner factors from "Best Available Retrofit Technology Engineering 

Analysis", Midwest RPO, March 30, 2005 that indicates total costs are 2.65 times basic equipment. This factor accounts for e

Capital Cost
Control Efficiency (%) 90.0

Facility Input Data

Item Value

Operating Schedule

 Shifts per day 3

 Hours per day 24

 Days per week 7

 Total Hours per year 8760

Economic Life, years 30

Interest Rate (%) 7

Source(s) Controlled Tangentially Fired Boiler C

Temperature (F) 320

Total Flowrate (acfm) 220,000

SO2 from PC Operation (lb/hr) 617.8

SO2 Emissions (tpy) from boiler 1,991.1

Site Specific Electricity Cost ($/kWh) 0.090

Site Specific Operating Labor Cost ($/hr) $37.00

Site Specific Maint. Labor Cost ($/hr) $37.00

Capital Costs

Value Basis

Direct Costs

1.) Purchased Equipment Cost

 a.) Equipment cost + auxiliaries $13,000,000 Vendor Quotes, A

 b.) Instrumentation $1,300,000 0.10 x A

 c.) Sales taxes $910,000 0.07 x A

 d.) Freight $650,000 0.05 x A

 Total Purchased equipment cost, (PEC) $15,860,000 B = 1.22 x A

2.) Direct installation costs

 a.) Foundations and supports $1,268,800 0.08 x B

 b.) Handling and erection $2,220,400 0.14 x B

 c.) Electrical $634,400 0.04 x B

 d.) Piping $317,200 0.02 x B

 e.) Insulation for ductwork $158,600 0.01 x B

 f.) Painting $158,600 0.01 x B

 Total direct installation cost $4,758,000 0.30 x B

3.) Site preparation $471,906 Demo Cost Sheet

4.) Stack $4,800,000 CUECost

5.) Replacement Energy Costs $1,316,000 14 days down

 Total Direct Cost, DC $27,205,900 1.30B + SP + Bldg.

Indirect Costs (installation)

5.) Engineering $1,586,000 0.10 x B

6.) Construction and field expenses $793,000 0.05 x B

7.) Contractor fees $1,586,000 0.10 x B

8.) Start-up $317,200 0.02 x B

9.) Performance test $158,600 0.01 x B

10.) Contingencies $475,800 0.03 x B

 Total Indirect Cost, IC $4,916,600 0.31B + Other

Total Capital Investment (TCI) = DC + IC $32,122,500 1.61B + SP + Bldg. + Other

Table B-7

Wet Scrubber SO2 Controls 

Boiler C

General Chemical BART Appendix Tables_3-22-07.xls

B-7 SO2 Wet Scrubber 1 of 2 3/22/2007
Table B-7

Wet Scrubber SO2 Controls 

Boiler C

Annual Costs

Item Value Basis Source

1) Electricity

Fan Power Requirement (kW) 900 CUECost

Other Power requirements (kW) 100 CUECost

Electric Power Cost ($/kWh) 0.09 Estimate

 Cost ($/yr) $788,400

2) Operating Costs 

Operating Labor Requirement (hr/shift) 12 12 manhours per shift Estimate

 Unit Cost ($/hr) $37.00 Facility Data Estimate

 Labor Cost ($/yr) $484,850

Limestone Costs ($/ton) $18 Unit Cost $/lb Estimate

 Hourly Requirerment (Lbs/hour) 430

 Annual requirement (tons/year) 1,882 CUECost

 Total Limestone Costs ($/year) $33,869

Water Requirements (1000 Gal/hour) 1.2 CUECost

 Water cost ($/1000 gal) $0.10

 Annual Water Cost ($/year) $1,051

Disposal Costs ($/ton) $12

 Tons Disposal required (Ton/year) 4,700

 Disposal Costs ($/year) $56,400

Total Operating Costs $1,364,570 Estimate

3) Supervisory Labor

 Cost ($/yr) $72,730 15% Operating Labor OAQPS

4) Maintenance

 Maintenance Labor Req. (hr/year) 11,680.0 32 manhours per day Estimate

 Unit Cost ($/hr) $37.00 Facility Data Estimate

 Labor Cost ($/yr) $432,160

 Material Cost ($/yr) $432,160 100% of Maintenance Labor OAQPS

 Total Cost ($/yr) $864,320

5) Equipment Replacement 0 No Equipment Replacement 

6) Indirect Annual Costs

 Overhead $853,140 60% of O&M Costs OAQPS

 Administration $642,450 2% of Total Capital Investment OAQPS

 Property Tax $321,230 1% of Total Capital Investment OAQPS

 Insurance $321,230 1% of Total Capital Investment OAQPS

 Capital Recovery $2,588,640 30 yr life; 7% interest OAQPS

Total Indirect ($/yr) $4,726,690

Total Annualized Cost ($/yr) $7,028,300

Total Controlled (tpy) 1792.0

Cost Effectiveness ($/ton) $3,900

General Chemical BART Appendix Tables_3-22-07.xls

B-7 SO2 Wet Scrubber 2 of 2 3/22/2007
Control Efficiency (%) 90.0

Facility Input Data

Item Value

Operating Schedule

 Shifts per day 3

 Hours per day 24

 Days per week 7

 Total Hours per year 8760

Economic Life, years 30

Interest Rate (%) 7

Source(s) Controlled Tangentially Fired Boiler D

Temperature (F) 320

Total Flowrate (acfm) 350,000

SO2 from PC Operation (lb/hr) 1,191.0

SO2 Emissions (tpy) from boiler 2,894.7

Site Specific Electricity Cost ($/kWh) 0.090

Site Specific Operating Labor Cost ($/hr) $37.00

Site Specific Maint. Labor Cost ($/hr) $37.00

Capital Costs

Value Basis

Direct Costs

1.) Purchased Equipment Cost

 a.) Equipment cost + auxiliaries $13,000,000 Vendor Quotes, A

 b.) Instrumentation $1,300,000 0.10 x A

 c.) Sales taxes $910,000 0.07 x A

 d.) Freight $650,000 0.05 x A

 Total Purchased equipment cost, (PEC) $15,860,000 B = 1.22 x A

2.) Direct installation costs

 a.) Foundations and supports $1,268,800 0.08 x B

 b.) Handling and erection $2,220,400 0.14 x B

 c.) Electrical $634,400 0.04 x B

 d.) Piping $317,200 0.02 x B

 e.) Insulation for ductwork $158,600 0.01 x B

 f.) Painting $158,600 0.01 x B

 Total direct installation cost $4,758,000 0.30 x B

3.) Site preparation $471,906 Demo Cost Sheet

4.) Stack $4,800,000 CUECost

5.) Replacement Energy Costs $1,316,000 14 days down

 Total Direct Cost, DC $27,205,900 1.30B + SP + Bldg.

Indirect Costs (installation)

5.) Engineering $1,586,000 0.10 x B

6.) Construction and field expenses $793,000 0.05 x B

7.) Contractor fees $1,586,000 0.10 x B

8.) Start-up $317,200 0.02 x B

9.) Performance test $158,600 0.01 x B

10.) Contingencies $475,800 0.03 x B

 Total Indirect Cost, IC $4,916,600 0.31B + Other

Total Capital Investment (TCI) = DC + IC $32,122,500 1.61B + SP + Bldg. + Other

Table B-8

Wet Scrubber SO2 Controls 

Boiler D

General Chemical BART Appendix Tables_3-22-07.xls

B-8 SO2 Wet Scrubber 1 of 2 3/22/2007
Table B-8

Wet Scrubber SO2 Controls 

Boiler D

Annual Costs

Item Value Basis Source

1) Electricity

Fan Power Requirement (kW) 900 CUECost

Other Power requirements (kW) 100 CUECost

Electric Power Cost ($/kWh) 0.09 Estimate

 Cost ($/yr) $788,400

2) Operating Costs 

Operating Labor Requirement (hr/shift) 12 12 manhours per shift Estimate

 Unit Cost ($/hr) $37.00 Facility Data Estimate

 Labor Cost ($/yr) $484,850

Limestone Costs ($/ton) $18 Unit Cost $/lb Estimate

 Hourly Requirerment (Lbs/hour) 625

 Annual requirement (tons/year) 2,735 CUECost

 Total Limestone Costs ($/year) $49,239

Water Requirements (1000 Gal/hour) 1.2 CUECost

 Water cost ($/1000 gal) $0.10

 Annual Water Cost ($/year) $1,051

Disposal Costs ($/ton) $12

 Tons Disposal required (Ton/year) 4,700

 Disposal Costs ($/year) $56,400

Total Operating Costs $1,379,940 Estimate

3) Supervisory Labor

 Cost ($/yr) $72,730 15% Operating Labor OAQPS

4) Maintenance

 Maintenance Labor Req. (hr/year) 11,680.0 32 manhours per day Estimate

 Unit Cost ($/hr) $37.00 Facility Data Estimate

 Labor Cost ($/yr) $432,160

 Material Cost ($/yr) $432,160 100% of Maintenance Labor OAQPS

 Total Cost ($/yr) $864,320

5) Equipment Replacement 0 No Equipment Replacement 

6) Indirect Annual Costs

 Overhead $853,140 60% of O&M Costs OAQPS

 Administration $642,450 2% of Total Capital Investment OAQPS

 Property Tax $321,230 1% of Total Capital Investment OAQPS

 Insurance $321,230 1% of Total Capital Investment OAQPS

 Capital Recovery $2,588,640 30 yr life; 7% interest OAQPS

Total Indirect ($/yr) $4,726,690

Total Annualized Cost ($/yr) $7,043,700

Total Controlled (tpy) 2605.2

Cost Effectiveness ($/ton) $2,704

General Chemical BART Appendix Tables_3-22-07.xls

B-8 SO2 Wet Scrubber 2 of 2 3/22/2007
Control Efficiency (%) 80.0

Facility Input Data

Item Value

Operating Schedule

 Shifts per day 3

 Hours per day 24

 Days per week 7

 Total Hours per year 8760

Economic Life, years 30

Interest Rate (%) 7

Source(s) Controlled Tangentially Fired Boiler C

Temperature (F) 320

Total Flowrate (acfm) 220,000

SO2 from PC Operation (lb/hr) 617.8

SO2 Emissions (tpy) from boiler 1,991.1

Site Specific Electricity Cost ($/kWh) 0.090

Site Specific Operating Labor Cost ($/hr) $37.00

Site Specific Maint. Labor Cost ($/hr) $37.00

Capital Costs

Value Basis

Direct Costs

1.) Purchased Equipment Cost

 a.) Equipment cost + auxiliaries $5,000,000 Vendor Quotes, A

 b.) Instrumentation $500,000 0.10 x A

 c.) Sales taxes $350,000 0.07 x A

 d.) Freight $250,000 0.05 x A

 Total Purchased equipment cost, (PEC) $6,100,000 B = 1.22 x A

2.) Direct installation costs

 a.) Foundations and supports $488,000 0.08 x B

 b.) Handling and erection $854,000 0.14 x B

 c.) Electrical $244,000 0.04 x B

 d.) Piping $122,000 0.02 x B

 e.) Insulation for ductwork $61,000 0.01 x B

 f.) Painting $61,000 0.01 x B

 Total direct installation cost $1,830,000 0.30 x B

3.) Site preparation $474,846 Demo Cost Sheet

4.) Stack $4,800,000 CUECost

5.) Replacement Energy Costs $1,316,000 14 days down

 Total Direct Cost, DC $14,520,800 1.30B + SP + Bldg.

Indirect Costs (installation)

5.) Engineering $610,000 0.10 x B

6.) Construction and field expenses $305,000 0.05 x B

7.) Contractor fees $610,000 0.10 x B

8.) Start-up $122,000 0.02 x B

9.) Performance test $61,000 0.01 x B

10.) Contingencies $183,000 0.03 x B

 Total Indirect Cost, IC $1,891,000 0.31B + Other

Total Capital Investment (TCI) = DC + IC $16,411,800 1.61B + SP + Bldg. + Other

Table B-9

Dry Scrubber SO2 Controls 

Boiler C

General Chemical BART Appendix Tables_3-22-07.xls

B-9 SO2 Dry Scrubber 1 of 2 3/22/2007
Table B-9

Dry Scrubber SO2 Controls 

Boiler C

Annual Costs

Item Value Basis Source

1) Electricity

Fan Power Requirement (kW) 900 CUECost

Other Power requirements (kW) 100 CUECost

Electric Power Cost ($/kWh) 0.09 Estimate

 Cost ($/yr) $788,400

2) Operating Costs 

Operating Labor Requirement (hr/shift) 12 12 manhours per shift Estimate

 Unit Cost ($/hr) $37.00 Facility Data Estimate

 Labor Cost ($/yr) $484,850

Limestone Costs ($/ton) $18 Unit Cost $/lb Estimate

 Hourly Requirerment (Lbs/hour) 420

 Annual requirement (tons/year) 1,882 CUECost

 Total Limestone Costs ($/year) $33,869

Water Requirements (1000 Gal/hour) 1.2 CUECost

 Water cost ($/1000 gal) $0.10

 Annual Water Cost ($/year) $1,051

Disposal Costs ($/ton) $12

 Tons Disposal required (Ton/year) 4,700

 Disposal Costs ($/year) $56,400

Total Operating Costs $1,364,570 Estimate

3) Supervisory Labor

 Cost ($/yr) $72,730 15% Operating Labor OAQPS

4) Maintenance

 Maintenance Labor Req. (hr/year) 11,680.0 32 manhours per day Estimate

 Unit Cost ($/hr) $37.00 Facility Data Estimate

 Labor Cost ($/yr) $432,160

 Material Cost ($/yr) $432,160 100% of Maintenance Labor OAQPS

 Total Cost ($/yr) $864,320

5) Equipment Replacement 0 No Equipment Replacement 

6) Indirect Annual Costs

 Overhead $853,140 60% of O&M Costs OAQPS

 Administration $328,240 2% of Total Capital Investment OAQPS

 Property Tax $164,120 1% of Total Capital Investment OAQPS

 Insurance $164,120 1% of Total Capital Investment OAQPS

 Capital Recovery $1,322,570 30 yr life; 7% interest OAQPS

Total Indirect ($/yr) $2,832,190

Total Annualized Cost ($/yr) $5,133,800

Total Controlled (tpy) 1592.9

Cost Effectiveness ($/ton) $3,200

General Chemical BART Appendix Tables_3-22-07.xls

B-9 SO2 Dry Scrubber 2 of 2 3/22/2007
Control Efficiency (%) 80.0

Facility Input Data

Item Value

Operating Schedule

 Shifts per day 3

 Hours per day 24

 Days per week 7

 Total Hours per year 8760

Economic Life, years 30

Interest Rate (%) 7

Source(s) Controlled Tangentially Fired Boiler D

Temperature (F) 320

Total Flowrate (acfm) 350,000

SO2 from PC Operation (lb/hr) 1,191.0

SO2 Emissions (tpy) from boiler 2,894.7

Site Specific Electricity Cost ($/kWh) 0.090

Site Specific Operating Labor Cost ($/hr) $37.00

Site Specific Maint. Labor Cost ($/hr) $37.00

Capital Costs

Value Basis

Direct Costs

1.) Purchased Equipment Cost

 a.) Equipment cost + auxiliaries $5,000,000 Vendor Quotes, A

 b.) Instrumentation $500,000 0.10 x A

 c.) Sales taxes $350,000 0.07 x A

 d.) Freight $250,000 0.05 x A

 Total Purchased equipment cost, (PEC) $6,100,000 B = 1.22 x A

2.) Direct installation costs

 a.) Foundations and supports $488,000 0.08 x B

 b.) Handling and erection $854,000 0.14 x B

 c.) Electrical $244,000 0.04 x B

 d.) Piping $122,000 0.02 x B

 e.) Insulation for ductwork $61,000 0.01 x B

 f.) Painting $61,000 0.01 x B

 Total direct installation cost $1,830,000 0.30 x B

3.) Site preparation $474,846 Demo Cost Sheet

4.) Stack $4,800,000 CUECost

5.) Replacement Energy Costs $1,316,000 14 days down

 Total Direct Cost, DC $14,520,800 1.30B + SP + Bldg.

Indirect Costs (installation)

5.) Engineering $610,000 0.10 x B

6.) Construction and field expenses $305,000 0.05 x B

7.) Contractor fees $610,000 0.10 x B

8.) Start-up $122,000 0.02 x B

9.) Performance test $61,000 0.01 x B

10.) Contingencies $183,000 0.03 x B

 Total Indirect Cost, IC $1,891,000 0.31B + Other

Total Capital Investment (TCI) = DC + IC $16,411,800 1.61B + SP + Bldg. + Other

Table B-10

Dry Scrubber SO2 Controls 

Boiler D

General Chemical BART Appendix Tables_3-22-07.xls

B-10 SO2 Dry Scrubber 1 of 2 3/22/2007
Table B-10

Dry Scrubber SO2 Controls 

Boiler D

Annual Costs

Item Value Basis Source

1) Electricity

Fan Power Requirement (kW) 900 CUECost

Other Power requirements (kW) 100 CUECost

Electric Power Cost ($/kWh) 0.09 Estimate

 Cost ($/yr) $788,400

2) Operating Costs 

Operating Labor Requirement (hr/shift) 12 12 manhours per shift Estimate

 Unit Cost ($/hr) $37.00 Facility Data Estimate

 Labor Cost ($/yr) $484,850

Limestone Costs ($/ton) $18 Unit Cost $/lb Estimate

 Hourly Requirerment (Lbs/hour) 420

 Annual requirement (tons/year) 2,735 CUECost

 Total Limestone Costs ($/year) $49,239

Water Requirements (1000 Gal/hour) 1.2 CUECost

 Water cost ($/1000 gal) $0.10

 Annual Water Cost ($/year) $1,051

Disposal Costs ($/ton) $12

 Tons Disposal required (Ton/year) 4,700

 Disposal Costs ($/year) $56,400

Total Operating Costs $1,379,940 Estimate

3) Supervisory Labor

 Cost ($/yr) $72,730 15% Operating Labor OAQPS

4) Maintenance

 Maintenance Labor Req. (hr/year) 11,680.0 32 manhours per day Estimate

 Unit Cost ($/hr) $37.00 Facility Data Estimate

 Labor Cost ($/yr) $432,160

 Material Cost ($/yr) $432,160 100% of Maintenance Labor OAQPS

 Total Cost ($/yr) $864,320

5) Equipment Replacement 0 No Equipment Replacement 

6) Indirect Annual Costs

 Overhead $853,140 60% of O&M Costs OAQPS

 Administration $328,240 2% of Total Capital Investment OAQPS

 Property Tax $164,120 1% of Total Capital Investment OAQPS

 Insurance $164,120 1% of Total Capital Investment OAQPS

 Capital Recovery $1,322,570 30 yr life; 7% interest OAQPS

Total Indirect ($/yr) $2,832,190

Total Annualized Cost ($/yr) $5,149,200

Total Controlled (tpy) 2315.8

Cost Effectiveness ($/ton) $2,200

General Chemical BART Appendix Tables_3-22-07.xls

B-10 SO2 Dry Scrubber 2 of 2 3/22/2007