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.: 02999-022Prepared 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.: 02999-022i March 2007 J:\2000\2999-022-Gen_Chem-BART\BART Report\Final Report\Gen Chem BART Report Draft 8.doc 

## Contents

1.0 Introduc tion ................................................................................................................... ......................... 1-1

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

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

2.2 Baseline Em issions ............................................................................................................. ............ 2-1

2.3 Types of Co al Used............................................................................................................. ............ 2-2

2.4 Unique Characterist ics of th e Site............................................................................................. ...... 2-2

2.5 Existing Emission Control E quipment at t he Site ........................................................................... 2-4

2.6 Presumptive BART Le vels ........................................................................................................ ...... 2-4

3.0 Consideration of Emission Control Altern atives .............................................................................. 3-1

3.1 NO X Emission Contro ls............................................................................................................. ....... 3-1 3.1.1 Post-combustion Controls ................................................................................................. 3-1 3.1.2 Combustion C ontrols ......................................................................................................... 3-1 3.1.3 NO X Control Technica l Feasibili ty ..................................................................................... 3-2

3.2 SO 2 Cont rol....................................................................................................................... ............... 3-2 3.2.1 Wet Flue Gas Desu lfurization ........................................................................................... 3-2 3.2.2 Lime Spray Drye r Absor ber............................................................................................... 3-3 3.2.3 Dry Sorbent In jection ......................................................................................................... 3 -3

4.0 Emission Reductions for BART Cost Eval uation.............................................................................. 4-1

4.1 Actual Annual Emi ssions Ba seline............................................................................................... ... 4-1

4.2 Effectiveness and Economic Analysis of NO X Emission Control Alternatives............................... 4-1 4.2.1 NOx BART Alternativ es Evaluat ed ................................................................................... 4-2 4.2.2 Costs for Boiler C NO X ...................................................................................................... 4-2 4.2.3 Boiler D NO x ....................................................................................................................... 4-3

4.3 Effectiveness and Economic Analysis of SO 2 Emission Control Alternativ es .............................. 4-3 4.3.1 SO 2 BART Alternativ es Evaluat ed .................................................................................... 4-3 4.3.2 Costs for Boiler C SO 2 ....................................................................................................... 4-4 4.3.3 Costs for Boiler D SO 2 ....................................................................................................... 4-4 4.3.4 Summary of Reductions a nd Control Co sts ..................................................................... 4-5

5.0 Selection of Cont rol Scenarios................................................................................................. ........... 5-1

5.1 Control Options Modelin g Emission Ra tes..................................................................................... 5-1

5.2 Control Scenario Opti ons for Ev aluation........................................................................................ . 5-2

6.0 Selection of the Best Altern ative for BART Control .......................................................................... 6-1ii March 2007 J:\2000\2999-022-Gen_Chem-BART\BART Report\Final Report\Gen Chem BART Report Draft 8.doc 6.1 Summary of Results ............................................................................................................. ........... 6-1

6.2 Annualized Cost for Implementing Control vs Decrease in Visibili ty Impairm ent.......................... 6-2



## List of Appendices

Appendix A Facility Design Data

Appendix B Cost Analyses for BART Control Optionsiii March 2007 J:\2000\2999-022-Gen_Chem-BART\BART Report\Final Report\Gen Chem BART Report Draft 8.doc 

## List of Tables

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

Table 4-1 Baseline Annual Average Emissions fo r 2001-2003 ............................................................... 4-1

Table 4-2 Cost Evaluation of NOx co ntrols for Bo iler C .......................................................................... 4-3

Table 4-3 Cost Evaluation of NOx co ntrols for Bo iler D .......................................................................... 4-3

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

Table 4-5 Cost Evaluation of SO 2 controls for Boiler D ........................................................................... 4-5

Table 5-1 Emission Rates for Visibility Evaluati on for Each Cons idered Opti on.................................... 5-1

Table 6-1 Tabulation of Visibility Improvemen t at Jim Bridger Wilderness Area and Annual Costs for Each Control Op tion ............................................................................. 6-1



## List of Figures

Figure 2-1 Green River Works Fac ility Plot Plan....................................................................................... 2-3 Figure 2-2 View of Power Plant Buildi ng Looking Nort hwest ................................................................... 2-5 Figure 2-3 View of Boiler C St ack Looking East ....................................................................................... 2-5 Figure 2-4 Boiler C ESP Disc harge Ple num.............................................................................................. 2-6 Figure 2-5 Boiler C ESP Disc harge Ple num.............................................................................................. 2-6 Figure 2-6 Boiler C Stack Looki ng Southwes t........................................................................................... 2-7 Figure 2-7 View From Behind Boiler C Looking To ward Boiler D (Southwes t)........................................ 2-7 Figure 5-1 General Chemical – BART Determination: 8 th Highest Modeled Visibility Impact (2001) ..... 5-3 Figure 6-1 Plot of Visibility Improvement vs. Annua lized Control Cost for BART Op tions ...................... 6-2ES-1 March 2007 J:\2000\2999-022-Gen_Chem-BART\BART Report\Final Report\Gen Chem BART Report Draft 8.doc 

## Executive Summary

The General Chemical facility in Green River, Wyomin g, (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-f ired boilers known as Boilers C and D. The Wyoming BART program requires that BART-eligible sources perf orm a site-specific BART anal ysis 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 Wy oming 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 precipit ators (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 (NO X ) and sulfur dioxide (SO 2 ). Current particulate controls are already effective with the use of ESPs and not evaluated in this report.

The controls evaluated for NO X and SO 2 include:

NO X – Combustion modifications that reduce the formation of NO X , 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 NO X Burners (LNB) – 10 to 30 percent reduction; and

• Low NO X Burners plus Separated Overfire Air (L NB+SOFA) – 25 to 45 percent reduction.

SO 2 – Both add-on controls and emission management alternatives were considered for SO 2 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

• SO 2 Emissions Management – through coal supply evaluation.

The estimated cost of the emission r eduction 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 NO X and SO 2 were used to perform CALPUFF modeling of candidate levels of visibility improvement.

BART was determined to be a combination of Low NO x Burner retrofits based on achieving significant visibility improvements at reasonable cost (in $/dv improvement) re lative to the other options . This BART will improve predicted visibility due to the BART units by about 14 to15 percent (in term s of delta-decivie ws relative to natural conditions) based on the 8 th highest and on worst-case visibility days, respectively.ES-2 March 2007 J:\2000\2999-022-Gen_Chem-BART\BART Report\Final Report\Gen Chem BART Report Draft 8.doc For SO 2 emissions BART was determined to be the use of the current low sulfur bituminous coal. This determination is made based on the excessive cost (i n $/dv improvement) of the other control options considered.1-1 March 2007 

## 1.0 Introduction

Federal regulations under 40 Code of Federal Regul ations (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 St andards and Regulations, Chapter 6, Section 9. The program requires the application of Best Available Retr ofit Technology (BART) to those existing eligible sources in order to help meet the targets for visibili ty improvement at designated Class I areas. The Wyoming Department of Environmental Quality (WDEQ) identified two coal-fired boile rs, 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 perfo rm a site-specific BART analysis including a control technology review and CALP UFF modeling to assess the visibility impact of the emission units.

The site-specific BART determination analys is includes the following components:

1. A list of demonstrated candidate retrofit controls that may apply. 2. A discussion of technical feasibility for retr ofit of each candidate technology to the boilers. 3. A ranking of the control effectiveness of each f easible retrofit technology, or site-specific BART options. 4. An evaluation of the impacts of eac h 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 eac h of the BART options or combinations of BART options;

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

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

5. An evaluation and justification of the mass e mission rates and averaging time in the context of modeled visibility improvements. 6. Special issues related to coal supply focus ed on economic impacts of mine supply operations and communities. 7. Sources subject to a Maximu m 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 anal ysis 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 st eam 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 bitumin ous coal. Boiler C has a total heat rate input of 534 million British Thermal Units per hour (MMBtu/hr) and Bo iler D is rated at 880 MMBtu/hr. Given the limited area at the site, coal is received r eady 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 boile rs are controlled by separate hot-si de electrostatic precipitators (ESP) which vent through independent stacks that penetr ate and extend above the boiler house roof.

The facility is currently operating under an operat ing 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 (NO X ) 0.7 lb/MMBtu Sulfur dioxide (SO 2 ) 1.2 lb/MMBtu

Both units are subject to Wyoming Air Quality Standar ds 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 NO X and SO 2 emissions, and data are maintained in pounds (lb)/MMBtu for each hour recorded. Pe riodic 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 particu late 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 fo r the years 2001 through 2003. These emissions represent a realistic depiction of anticipated annual em issions for the source. These baseline emissions are used later in this report as the basis for estimati ng 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. Theref ore, the facility will a ccept the permit limits as representative of maximum emissions for the 2001-2 003 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 (PM 10 ) and particulate matter with an aerodynamic diameter of 2.5 microns or less (PM 2.5 ) emission rates have been speciated from the fi lterable 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 PM 10 Fine Condensable PM 10

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 PM 10 (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 PM 10 emissions are conservatively based on the lb/hr permit limit. Actual emissions for PM 10 are not available because PM 10 is not continuously monitored. PM speciation based on the Nationa l 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, hi gh 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 proper ties of Powder River Basin (PRB) coal from Wyoming, and therefore, it represents the lowest sulfur coal avai lable. General Chemical is unaware of alternate coal supplies that can provide the required heat input and meet the required pa rticulate limits. As such, no other coal supplies are considered to be readily available to supply the facility. Emissions for th is analysis are based on maintaining the current coal supply, and those emissions are sensitive to that co al 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 we athering 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 Admin istration (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 locat ed 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 extr emely 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 direct ed upward through the stacks. As currently constructed, there is very limited vertical distance (approximately 3 f eet) 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 ES P. 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 SO 2 641 10562-3 March 2007 Figure 2-1 Green River Works Facility Plot Plan2-4 March 2007 Space within the power plant building is extremely limited. The boilers ar e located between coal conveyors and pulverizers to the south, inoperable boilers to the eas t, 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 wo uld 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, NO x 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.

SO 2 emissions are controlled by using low sulfur coal. Add-on emission controls are not used for SO 2
.

PM 10 emissions are controlled by hot-side ESPs installed with the boilers wher e the control device is installed upstream of the boiler air heater. The process c ontrols 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 provi ded in Appendix A, Table A-1 of this report.


### 2.6 Presumptive BART Levels
The presumptive BART levels listed in U.S. Environm ental Protection Agency’s (USEPA’s) BART rule apply to coal-fired electric generating units. T here 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:

• SO 2 limit is 95 percent co ntrol or 0.15 lb/MMBtu.

• NO X 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 East2-6 March 2007 Figure 2-4 Boiler C ESP Discharge Plenum

Figure 2-5 Boiler C ESP Discharge Plenum2-7 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 NO X 

### 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 (S NCR) – 30 to 50 perc ent control; and

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

Both post-combustion controls and combustion controls are c onsidered in this analysis.



### 3.1.1 Post-combustion Controls

SCR

SCR is a post-combustion control technology that in volves a catalyst bed installed between the boiler economizer and combustion air preheater in a conventional pulverized coal-f ired (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 ca talyst bed and reduces a portion of the NO X to molecular nitrogen and water. Reductions up to 80 to 90 percent can be achi eved from this technology. SCR has been used with PC boilers and is considered the most effective control for the removal of NO X emissions from PC boilers. Therefore, SCR is technically feasible to control NO X emissions from the existing PC boiler.

SNCR

SNCR is a post combustion c ontrol technology that involves ammonia or urea injection into the flue gases without the presence of a catalyst. SNCR, like SCR, involves the reaction of NO X with ammonia where a portion of the NO X is converted to molecular nitrogen and water. NO X removal efficiencies with SNCR are lower than SCR, typically from 30 to 50 percent dependi ng on the combustion process. Without the use of a catalyst or supplemental fuel injection, the NO X reduction reaction temperatur e 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 am monia added will be oxidized resulting in an increased level of NO X emissions.

SNCR with ammonia injection technology is a demonstr ated, commercially available technology. SNCR has been used with PC boilers, therefore, SNCR is technically feasible to control NO X emissions from the existing PC boiler.



### 3.1.2 Combustion Controls

Based on review of the literature and discussions with vendors, two levels of comb ustion modifications and low NOx burners 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+SOF A) for an additional 25 to 45 percent control.

Due to the small size, age, and design of the Combusti on Engineering boilers at General Chemical – Green River, as well as the NO X controls already in plac e, the retrofit of low NO X combustion control options is practically limited to the two options noted above and described below.3-2 March 2007 The low NO X burner market is a mature and cost-competitiv e business. A variety of manufactures have developed competitive LNB and LNB+SOFA systems. In a retrofit applicat ion, the applicability of various product offerings and site-specif ic cost factors vary from boiler to bo iler. For the purpose of this analysis, ENSR contacted Alstom Power.

A desktop study was conducted to evaluate the alternativ e levels of control, feasibility, emission reduction potential, and costs associated with installing NO X controls of Boilers C and D. Alstom’s LNCFSTM-P2 system (LNB) represents advancement in coal combustion te chnology for tangentially fired units. The system was developed to offer the advantages of significant NO X 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 NO X 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 ad dition of a new SOFA System. The SOFA system employs a staged combustion process that diverts secondar y 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 NO X reduction. The air is introduced into the fur nace 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 NO X 

### Control Technical Feasibility

All of the NO X control technologies described above are technically feasible.



### 3.2 SO 2 

### Control
The techniques available to control SO 2 from new coal-fired boilers, in top-down order, include:

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

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

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

• SO 2 emission reductions based on the sele ction of alternate fuel supplies.



### 3.2.1 Wet Flue Gas Desulfurization
Wet Flue Gas Desulfurization (WFGD) uses limest one, lime, or caustic reagent to react with SO 2 from the flue gas. The temperature of the flue gas is reduced to its adiabatic saturation temperature and the SO 2 is removed from the flue gas by reaction with the alkaline medium. SO 2 and other acid gases (e.g. HCl, HF) are absorbed into the scrubbing slurry, which falls into the lower secti on 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 ca lcium sulfate. The overall reactions are shown in the following equations:

CaCO 3 + SO 2 → CaSO 3 • 1/2 H 2 O + CO 2

CaSO 3 •1/2 H 2 O + 3H 2 O + O 2 → 2 CaSO 4 •2 H 2 O

Lime scrubbing is similar to limestone scrubbing in equipment and process flow, except that lime is a more reactive reagent than limestone. The re actions for lime scrubbing are as follows:3-3 March 2007 Ca(OH) 2 +SO 2 → CaSO 3 • 1/2 H 2 O + 1/2 H 2 O

Ca(OH) 2 + SO 2 + 1/2 O 2 + H 2 O → CaSO 4 •2 H 2 O

When caustic (sodium hydroxide solution) is the scrubbing agent, the SO 2 removal reactions are as follows:

Na+ + OH- + SO 2 + → Na 2 SO 3

2Na+ + 2OH- + SO 2 + → Na 2 SO 3 + H 2 O

Caustic scrubbing produces a liquid waste, and mi nimal equipment is needed as compared to lime or limestone scrubbers. If lime or limestone is used as the reagent for SO 2 removal, additional equipment is needed for preparing the lime/limestone slurry and collecti ng 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 dew atered. 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 SO 2 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 re circulated through the gas stream. WFGD controls are applied to many coal fired boilers and are considered a feasible option fo r 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 tec hnology is considered capable of remo ving as much as 95 percent SO 2 from high sulfur coals, typical reductions us ing western low sulfur coals typicall y 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 lar ge vessel as the flue gas temperature approaches the adiabatic saturation temperature. In order to allow su fficient residence time for evaporation and reaction with SO 2 , the design gas residence time in a spray dryer ab sorber 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 t he ESP must be recycled to provide efficient reagent utilization. This would increase solids loading to the ESP by a factor of 3 requiri ng 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 ar e extremely difficult to retrofit to existing boilers. For these reasons, SDA using the existing particulate control system is e liminated from further consideration. However, a new stand-alone SDA may be considered for c onstruction outside of the existing building, including a new structure, a post-SDA baghouse control, added ducting, and a new sta ck as well as the existing control equipment. That option is considered feasib le for the BART analysis.



### 3.2.3 Dry Sorbent Injection
Dry, in-duct sorbent injection (DSI) requires less capi tal 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 duc t work which is subsequently captured by the existing particulate control device (the ESP). The st ructural 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 sorbent3-4 March 2007 injected. Lime, soda ash, and Trona (sodium sesquicarbonat e) are possible reagents Lime is the least reactive reagent resulting in low efficiencies even at high injecti on rates. Trona is a very reactive reagent that can be used to achieve a range of efficiencies d epending upon the amount of sorbent injected.

A variety of manufactures have developed DSI systems. Each of the vendors contac ted cited challenges with DSI systems upstream of an existing ESP and none w ould guarantee the overall performance of the system. DSI systems using lime, soda ash, or Trona work we ll when particulate control is performed by a baghouse. However, because ESP performance is drastically af fected 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 matte r loading would require a re-design or replacement of the ESP. The vertical structure of th e existing system is a limiting factor , and given these c onstraints, 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 bas eline 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 NO X and SO 2 , the BART cost evaluation is based on actual annual emissions for 2001 through 2003. The average annual emissions for each of th e evaluated pollutants is used as reported for the three years. Table 4-1 provides the annual actual emissions for NO X , SO 2 , PM 10 and PM 2.5 . Annual emissions estimates for PM 10 and PM 2.5 are based on total reported PM and ad justed by the fractions provided in Table 1.1-6 of AP-42. From that table, PM 10 emissions are 67 percent of the total PM, and PM 2.5 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 NO x

Average 1057.4 1468.4 2001 1932.2 2964.0 2002 2139.9 2825.0 2003 1901.2 2895.1 SO 2

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 PM 10 Average 65.7 108.2 PM 2.5 Average 28.4 46.8 Note: For the purpose of control evaluation PM emissions are not speciated.



### 4.2 Effectiveness and Ec onomic Analysis of NO X 

### Emission Control Alternatives

Detailed cost data for NO X and SO 2 control options are presented in Appendix B, and are summarized below. The data include assumed components of capital and operatin g costs, as shown in each table. Aside from the standard capital and operating costs, there are additional co sts 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 (fract ional revenue stream) and the costs for demolition of existing structures and reconstruction within or near th e existing units. This anal ysis 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 di ctate 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 contro l 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 heat4-2 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 downt ime are accounted for by assuming that retrofits would be made for each boiler at different times. The cost analyses assu me natural gas costs of $10/MMBtu for operation of the natural gas fired boiler (Boiler E) and coal costs of $2/M MBtu 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 ma terial includes modifications to build ings, pipe racks, pave ment, utilities, and tanks. Table A-2 in Appendix A provides the detail s 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 NO X 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 st eam and electricity when th e existing units are being modified, and the costs for demobilization and reconstruc tion within or near the existing units. The downtime associated with installation of each system is a ssumed 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 allo w 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 maintenanc e 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 a pply to each of the installed systems, including NOx and SO 2 controls. At $94,000 per day, the cost is approxima tely $1,300,000 for each option. As an installation cost this would lead to approximately $105,000 in annua lized 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 SO 2 controls, the costs per ton would be appropriately reduced.



### 4.2.2 Costs for Boiler C NO X 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 NO x emissions to about 0.45 lb/MMBtu, which is equ ivalent to a reduction of approximately 12 percent from the annual baseline emi ssion 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 NO X emissions to about 0.32 lb/MMBtu, which is equivalent to a reduction of approximately 30 percent from the annual baseline emi ssion 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 NO x 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 NO x 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 NO x emissions to about 0.45 lb/MMBtu, which is equivalent to a reduction of approximat ely 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 (s ee Appendix B, Table B-6). The Alstom LNCFS Level 2 (LNB+SOFA) option is expected to reduce NO x emissions to about 0.32 lb/MMBtu , which is equivalent to a reduction of approximately 30 percent from the annua l 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 Ec onomic Analysis of SO 2 

### Emission Control Alternatives

4.3.1 SO 2 

### BART Alternatives Evaluated
The potential reductions and estimate d cost impacts of installing SO 2 emission reduction technology are presented in this section. The SO 2 control technology that will require additional outage time beyond a normal maintenance schedule outage is the WFGD and the spra y 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 SO 2 reduction of 90 percent with WFGD has been assumed.4-4 March 2007 The duration of the construction and inst allation 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 addi tional weeks beyond the normal 1-week maintenance turnaround outage of Boilers C and D down time to incl ude installation of the air flow control and ducting system that is required for this option.

As described in Section 4.2 above, replacement energy co sts 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 ma terial includes modifications to build ings, pipe racks, pave ment, utilities, and tanks. Estimates of demolition costs for each of the NO X 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 va lues are incorporated into the cost esti mates discussed in this Section and in the tables in Appendix B.



### 4.3.2 Costs for Boiler C SO 2 The WFGD option is expected to reduce SO 2 emissions by approximately 90 per cent 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 SO 2 emissions is estimated to be $3,900 per ton (see Appendix B, Table B-7).

The SDA option is expected to reduce SO 2 emissions by approximately 80 per cent 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 SO 2 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 SO 2 control technology.

Table 4-4 Cost Evaluation of SO 2 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 SO 2 The WFGD option is expected to reduce SO 2 emissions by approximately 90 per cent 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 SO 2 emissions is estimated to be $2,605 per ton (See Appendix B, Table B-8).

The SDA option is expected to reduce SO 2 emissions by approximately 80 per cent 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 SO 2 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 SO 2 control technology.

Table 4-5 Cost Evaluation of SO 2 controls for Boiler D

Control Technology SO 2 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 SO 2 emission reductions that are used in the cost a nalysis 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 Mo deling Emission Rates
Visibility impacts were evaluated wi th modeling based on the maximum 24-hour emission rate for the criteria pollutants. For evaluating visibility improvement as a resu lt of installing the BART options, the first step is to identify the level of improvement in the 24-hour ma ximum emissions, from the baseline to the proposed new limits. Table 5-1 lists each control option, as applied to each unit for separate NO X and SO 2 controls. The applicable emission rate and percent emissions reduc tion from the 24-hour peak emission rate used for modeling are also listed. These percent reductions ar e 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 (NO x ) 376 30% 263 C SCR (NO x ) 376 80% 75 C SNCR (NO x ) 376 50% 188 C WFGD (SO 2 ) 641 90% 64 C DFGD (SO 2 ) 641 80% 128 D LNB + SOFA (NO x ) 616 30% 431 D SCR (NO x ) 616 80% 123 D SNCR (NO x ) 616 50% 308 D WFGD (SO 2 ) 1056 90% 106 D DFGD (SO 2 ) 1056 80% 211

Emissions of PM 10 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 opti on for NOx for this analysis is the LNB+SOFA for NO X 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, th e maximum impacts are at the Jim Bridger Wilderness Area. Results of the modeling for eac h of these scenarios are provided in Table 5-2 , showing the maximum impact for each year for the baseline analysis and the im pact for each scenario for the worst case year (2001). The table lists the results for the Base Case for eac h 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 impac ts BART impacts are evaluated on the reported 8 th 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 Wi lderness 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 8 th highest impacts for these scenarios (cases) form the basis for selecting BART for these units. Figure 5-1 provides a comparative visualization of the 8 th highest impact for each Control Case for both the J im Bridger and Fitzpatrick Wilderness Areas.



### 5.2 Control Scenario Options for Evaluation
The Control Scenario options for visibility impact m odeling and economic analysis must consider a reasonable combination of equipment and control options. The eval uation 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 fo r each option. The combination of the modeling results and the economic analys es are provided in Chapter 6.5-3March 2007Figure 5-1 General Chemical – BART Determination: 8thHighest Modeled Visibility Impact (2001)General Chemical - BART Determination: 8th Highest Modeled Visibility Impact (2001)0.00.10.20.30.40.50.60.70.80.91.0 B a se Ca se Ca se 1 - L N B

C a se 2 - S NC R Cas e 3 - SCR Case 4 - DFGD C a se 5 - WFGD Cas e 6 - L N B + DFGD

Ca se 7 - L NB+ W FG D Ca se 8 - S NC R+DFG D Cas e 9 - SNCR+WF G D Case 10 - SCR+DFGD Ca se 1 1 - S C R+WFGDEmissions Scenario

Delta Deciview, (dv)Bridger WildernessFitzpatrick Wilderness6-1 March 2007 

## 6.0 Selection of the Best Alternative for BART Control

6.1 Summary of Results

The selection of BART controls is bas ed 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 98 th percentile impact at that area. Table 6-1 provides the calculated improvement in visibility for each cont rol 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 SO 2 + NO x 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-NO x D-NO x C-SO 2 D-SO 2 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 fo r 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. Result s 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 Co ntrol Cost for BART Options

Figure 6-1 also provides a depiction of the least cost en velope 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 Im plementing Control vs Decrease in Visi bility Impairment

BART Controls are selected based on the estimated co st for applying those controls and on the expected visibility improvement that would resu lt 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 + SO FA 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 8 th 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 ImprovementCost ($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 NO X LNB burners is determined to represent BA RT for Boilers C and D at the General Chemical – Green River. This conclusion is based on te chnical viability, degree of deciview improvement that can be achieved, and the cost effectiveness in $/dec iview improvement of the various Control Scenarios options evaluated.March 2007 

## Appendix A

Facility Design DataBoiler 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 SO 2 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 SO 2 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, WYBuilding Pavement Pipe Racks Utilities TanksLNBNone NA NA NA NA NA $0$0LNB+SOFANone NA NA NA NA NA $0$0SNCRAmmonia (Urea) Tank; and TruckAccess.NA $17,966.2 $35,400 $1,286 NA $54,652$114,769SCRAmmonia Tank; and Truck Access. NA $17,966.2 $35,400 $1,286 NA $54,652$114,769DSITrona Storage Silo;Pnuematic Conveyor; andLocal Control Building.$140,108 $12,592.2 $35,400 $1,286 $29,250.00 $218,636$459,135DFGDLimestone Storage Bunker;Truck Access;Processing & Control Building; andStorage Silo.$141,990 $18,192.2 $35,400 $1,286 $29,250.00 $226,117$474,846WFGDLimestone Storage Bunker;Truck Access;Processing & Control Building;Scrubber Water/WastewaterTreatment; andStorage Silo.$141,990 $16,792.2 $35,400 $1,286 $29,250.00 $224,717$471,906Element Demolition Cost Per Replacement Cost PerBuilding$0.14 CF $123 SFPavement$23.29 SY $140 CYPipe Racks$7.60 pipe/LF $16 /pipe/LFUtilities$2.57 LF $6 /LFTanks$1,450 each $27,800 eachMaterial Disposal$11.74 CYContracting15 % 15 %Contingency40 % 40 %Table A-2Demolition and Replacement Costs Boiler CSum withContracting &ContingencyFactors:(Source: RSMEANS 2006Site Work &Landscape CostData,EnvironmentalRemediationCost Data)Existing Infrastucture RemovedDemolition to NecessaryAccommodate Addition ofControlTecnologySUMMarch 2007 

## Appendix B

Cost Analyses for BART Control OptionsControl 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 3/22/2007Control 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 3/22/2007Control 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 3/22/2007Control 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 3/22/2007Control 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 3/22/2007Control 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 3/22/2007Control 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 3/22/2007Control 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 A lstom 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 126.9 317.2 Cost Effectiveness, $/ton 840 1,330

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 Engineeri ng 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 A lstom 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 176.2 440.5 Cost Effectiveness, $/ton 770 1,430

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 Engineeri ng Analysis", Midwest RPO, March 30, 2005 that indicates total costs are 2.65 times basic equipment. This factor accounts for e Capital CostControl 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 SO 2 

### 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 SO 2 

### 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 3/22/2007Control 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 SO 2 

### 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 SO 2 

### 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 3/22/2007Control 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 SO 2 

### 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 SO 2 

### 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 3/22/2007Control 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 SO 2 

### 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 SO 2 

### 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