DEPARTMENT OF ENVIRONMENTAL QUALITY

AIR QUALITY DIVISION

Application Analysis

AP-10837

October 14, 2010

NAME OF FIRM: General Chemical (Soda Ash) Partners

NAME OF FACILITY: Green River Works

FACILITY LOCATION: Sections 4-6, T18N, R109W and

Sections 29-33, T19N, R109W

Sweetwater County, Wyoming

TYPE OF OPERATION: Trona Mine and Sodium Products Plant

RESPONSIBLE OFFICIAL: Randy Pitts, Plant Manager

MAILING ADDRESS: PO Box 551

Green River, WY 82935-0551

TELEPHONE NUMBER: (307) 875-3350

REVIEWING ENGINEER: Cole Anderson, Air Quality Engineer

1.0 PURPOSE OF APPLICATION

On June 7, 2010, General Chemical (Soda Ash) Partners (General Chemical) submitted a request to 

authorize the use of existing low NOx burners (LNB) with new separated overfire air (SOFA) or an 

equivalent performing technology in place of the BART-determined control technology, LNB with 

existing overfire air, on two (2) coal-fired boilers at the Green River Works facility. Based on new 

information from Alstom Power, General Chemical no longer considers it technically feasible to achieve

a NOx emission rate of 0.32 lb/MMBtu, 30-day rolling average, using just LNB with existing overfire

(OFA). LNB with existing OFA was determined to be the Best Available Retrofit Technology (BART)

for these two (2) units, Boilers C and D, based on a comprehensive BART analysis conducted for each of 

the units. The BART determination and analysis were done in accordance with the requirements of 

Chapter 6, Section 9 of the Wyoming Air Quality Standards and Regulations (WAQSR). A map of 

General Chemical Green River Works‟ location is attached as Appendix A.

On June 22, 2010, General Chemical submitted additional documentation from Alstom Power addressing 

the feasibility of achieving the BART NOx emissions levels using LNB with existing overfire air.
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2.0 RELEVANT PERMIT HISTORY

Air Quality Permit MD-6046 was issued on August 7, 2009 to General Chemical for the installation of 

new LNB with existing OFA on the two (2) coal-fired boilers in accordance with the Division‟s BART 

determination. Installation of the control equipment was to occur no later than December 31, 2011 for 

Boiler C and no later than December 31, 2012 for Boiler D. New BART NOx limits, effective upon 

startup of each of unit after installation of new LNB and completion of the required initial performance 

tests, are presented in Table 1.

Table 1: MD-6046 NOx Emissions Limits

Unit lb/MMBtu lb/hr tpy

Boiler C 0.32 (30-day rolling) 170.9 (30-day rolling) 748.5

Boiler D 0.32 (30-day rolling) 281.6 (30-day rolling) 1,233.4

3.0 SOURCE DESCRIPTIONS

General Chemical‟s two (2) existing coal-fired boilers, C and D, are co-located at the facility power plant 

building. Burning low sulfur bituminous coal, they supply power and process steam to mining and ore 

processing operations. Both boilers are tangentially fired using in-line coal pulverizers. Boiler C was 

installed in 1973 and Boiler D was installed in 1975. Each boiler is currently equipped with a hot-side 

electrostatic precipitator (ESP) to control particulate emissions. Existing low NOx burners, overfire air 

and low excess air are currently used to reduce NOx emissions from the boilers. Boiler firing rates and 

existing air pollution controls are show in Table 2.

Table 2: Current Configuration of Boilers C and D

Source

Firing Rate 

(MMBtu/hour) Existing Controls

Boiler C 534 LNB, Overfire air, dry ESP

Boiler D 880 LNB, Overfire air, dry ESP

4.0 CHAPTER 6, SECTION 9 – BEST AVAILABLE RETROFIT TECHNOLOGY

4.1 DESCRIPTION OF BART

BART is an emission limit based on the application of a continuous emission reduction technology for 

each visibility impairing pollutant emitted by a source. It is established on a case-by-case basis taking 

into consideration six factors: (1) the available retrofit control options; (2) any pollution control 

equipment in use at the source; (3) the costs of compliance with control options; (4) the remaining useful 

life of the facility; (5) the energy and non-air quality environmental impacts of control options; and (6) 

the visibility impacts analysis. A BART determination must address air pollution control measures for 

each emissions unit or pollutant emitting activity subject to review.
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Each boiler was addressed under BART using the methodology prescribed in 40 CFR part 51, subpart Y, 

as required in WAQSR Chapter 6 Section 9(c)(i). This methodology is comprised of five basic steps:

Step 1: Identify all1available retrofit control technologies

Step 2: Eliminate technically infeasible options

Step 3: Evaluate control effectiveness of remaining control technologies

Step 4: Evaluate impacts and document the results

Step 5: Evaluate visibility impacts

The Division acknowledges that BART is intended to identify retrofit technology for existing sources and 

is not the same as a top down control analysis required for new sources under the Prevention of 

Significant Deterioration (PSD) rules known as Best Available Control Technology (BACT). Although 

BART is not the same as BACT, it is possible that BART may be equivalent to BACT on a case-by-case 

basis.

The five steps were applied to each coal-fired boiler, Boilers C and D, to determine pollutant-specific 

BART control measures for NOx and PM. All five steps were also applied to SO2 emissions from the two 

boilers, but a pollutant-specific control technology and associated emissions limit were not determined to 

be BART as these sources are subject to Wyoming‟s Regional SO2 Milestone and Backstop Trading 

Program contained in Chapter 14, Sections 2 and 3, of the WAQSR.

4.2 EXISTING BART DETERMINATION FOR NOx

The Division originally published a proposed BART determination for NOx, PM, and SO2 on August 12, 

2008, and accepted public comment on the proposal until October 20, 2008 (69 days). A public hearing 

was held on September 11, 2008 at Western Wyoming Community College, in Rock Springs, Wyoming, 

to afford the public and interested parties the opportunity to present comments on the Division‟s proposed 

determinations.

The original NOx determination was based on a BART analysis of selective catalytic reduction (SCR), 

selective non-catalytic reduction (SNCR), and combustion modifications, including new LNB with 

existing overfire air and new LNB with SOFA. Use of new LNB with SOFA to achieve an emission rate 

of 0.49 lb/MMBtu, on a 30-day rolling average, was originally determined to be BART for NOx for each 

of the boilers. Corresponding mass emission rate limits (lb/hr and tpy) were also established as part of the 

Division‟s BART determination. After the close of the public comment period, General Chemical was 

requested by the Division to address lower NOx emission levels. On December 15, 2008, General 

Chemical submitted a response to the Division‟s request. General Chemical analyzed emission levels of 

0.32 lb/MMBtu from the application of new low NOx burners with existing OFA on each of the two 

boilers and emission levels of 0.28 lb/MMBtu from the application of new LNB with SOFA. Updated 

cost information for each control technology and revised CALPUFF visibility modeling were included in 

General Chemical‟s response. The Division issued a revised NOx BART analysis, dated August 7, 2009, 

which addressed lower NOx emission rates analyzed by General Chemical and after considering all 

statutory factors in their entirety, established a new BART determination for NOx consisting of the 

following:

 

1

Footnote 12 of 40 CFR 51 Subpart Y defines the intended use of „all‟ by stating “...you must identify the most stringent option 

and a reasonable set of options for analysis that reflects a comprehensive list of available technologies.”
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Boiler C: New LNB with existing OFA and meeting NOx emission limits of 0.32 lb/MMBtu (30-

day rolling average), 170.9 lb/hr (30-day rolling average) and 748.5 tpy as BART for 

NOx.

Boiler D: New LNB with existing OFA and meeting NOx emission limits of 0.32 lb/MMBtu (30-

day rolling average), 281.6 lb/hr (30-day rolling average) and 1,233.4 tpy as BART for 

NOx.

New LNB with existing OFA was determined to be BART for Boilers C and D for NOx based, in part, on 

the following conclusions:

1. New LNB with existing OFA on Boiler C was cost effective with a capital cost of $1,121,750 and 

a $483 per ton of NOx removed average cost effectiveness over a twenty year operational life. 

New LNB with existing OFA on Boiler D was cost effective with a capital cost of $1,188,000 and 

a $362 per ton of NOx removed average cost effectiveness over a twenty year operational life.

2. Combustion control using new LNB with existing OFA does not require non-air quality 

environmental mitigation for the use of chemical reagents (i.e., ammonia or urea) and there is a 

minimal energy impact.

3. Visibility impacts were addressed in a comprehensive visibility analysis covering all three 

visibility impairing pollutants and associated control options. Cumulative 3-year averaged 

visibility improvement from the baseline summed across the two Class I areas achieved by 

installing new LNB with existing OFA on both Boilers C and D, is 0.47 Δdv.

4. Annual NOx emission reduction from installing new LNB with existing OFA on the boilers was 

419 tons from Boiler C and 582 tons from Boiler D. Applying new LNB with SOFA to the 

boilers further reduced emissions by 93 tons from Boiler C and 155 tons from Boiler D, which 

yield minimal visibility improvement across the two Class I areas.

New LNB with SOFA, SNCR, and SCR were not determined to be BART for Boilers C and D for NOx

based, in part, on the following conclusions:

1. The cost of compliance for installing LNB with SOFA on Boilers C and D is significantly higher 

than LNB with existing OFA. Capital costs for installing LNB with SOFA on Boiler C is 

$5,837,180 and $7,487,600 on Boiler D. Annual operating costs associated with operating LNB 

with SOFA on Boiler C are $190,893 higher than the operating costs for LNB with existing OFA. 

Annual operating costs for LNB with SOFA on Boiler D are $241,587 higher than the operating 

costs for LNB with existing OFA.

2. Additional cumulative 3-year averaged visibility improvement across the two Class I areas gained 

by installing new LNB with SOFA instead of new LNB with existing OFA on both Boilers C and 

D is just 0.04 Δdv.

3. The cost of compliance for installing SNCR on each boiler is higher than LNB with existing 

OFA. Capital costs for SNCR on Boiler C is $7,541,800 and $8,391,400 for Boiler D. Annual 

operating cost for SNCR is $825,850 for Boiler C and $810,234 for Boiler D.
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4. The cost of compliance for installing SCR on each boiler is higher than LNB with existing OFA. 

Capital costs for SCR on Boiler C is $14,097,600 and $19,194,500 for Boiler D. Annual 

operating cost for SCR is $1,298,542 for Boiler C and $1,852,189 for Boiler D.

5. Additional non-air quality environmental mitigation is required for the use of chemical reagents 

when either SNCR or SCR is used to reduced NOx emissions from the boilers.

6. Operation of SNCR requires an estimated 50 kW of additional power to operate. SCR on Boiler 

C requires 200 kW of additional power and Boiler D requires 300 kW.

The Division concluded that installation and operation of the BART-determined NOx controls, new LNB 

with existing OFA, on Boilers C and D to meet the corresponding emission limits on a continuous basis,

satisfy the statutory requirements of BART. Under the Air Quality Permit MD-6046, BART controls are 

required to be installed on Boiler C by December 31, 2011 and on Boiler D by December 31, 2012.

4.3 REVISED BART DETERMINATION FOR NOx

4.3.1 INTRODUCTION

After issuance of Air Quality Permit MD-6046, General Chemical has been working with Alston Power 

to develop a proposal for retrofitting the existing boilers to achieve the new BART NOx emissions limits. 

In February of 2010, Alstom Power performed an onsite investigation of the existing boilers‟ performance 

that included combustion tuning for each boiler. General Chemical reviewed the results from the onsite 

investigation and concluded that installing new LNB with existing OFA on each of the boilers could not 

achieve the 0.32 lb/MMBtu, 30-day rolling average, NOx BART limit. Since the BART-determined 

control level is no longer achievable with the identified BART control technology, General Chemical is 

proposing to use existing LNB with new SOFA instead. General Chemical proposes to use the existing 

LNB and install new SOFA by December 31, 2014 for Boiler C and December 31, 2015 for Boiler D. 

The associated NOx emissions control level of 0.28 lb/MMBtu, 30-day rolling average, which was 

addressed in the revised NOx BART analysis, dated August 7, 2009, is also proposed as the new control 

level. General Chemical is requesting the ability to install an equivalent performing technology, as new 

emissions control technology may be a viable solution in the future (2014 or 2015).

4.3.2 STEP 1: IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

General Chemical identified four control technologies to control NOx emissions: (1) new LNB with 

existing OFA, (2) existing LNB with new SOFA, (3) SNCR, and (4) SCR. New LNB with existing OFA 

and existing LNB with new SOFA are two combustion control technologies that reduce NOx emissions by 

controlling the combustion process within the boiler. These two technologies effectively control NOx

emissions by reducing the amount of oxygen directly accessible to the fuel during initial combustion and 

by enhancing air-fuel mixing after initial combustion to complete the combustion process. SNCR and 

SCR are add-on controls that provide a chemical conversion mechanism for NOx to form molecular 

nitrogen (N2) in the flue gas after combustion occurs. These four technologies are proven emissions

controls commonly used on coal-fired boilers.
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1. New Low NOx Burners with Existing Overfire Air – LNB technologies rely on a combination of 

fuel staging and combustion air control to suppress the formation of thermal NOx. Fuel staging 

occurs in the very beginning of combustion, where the pulverized coal is injected through the 

burner into the furnace. Careful control of the fuel-air mixture leaving the burner can limit the 

amount of oxygen available to the fuel during combustion creating a fuel-rich zone that reduces 

the nitrogen to molecular nitrogen (N2) rather than using oxygen in the combustion air to oxidize 

the nitrogen to NOx.

2. Existing Low NOx Burners with New Separated Overfire Air – SOFA can be used with existing 

LNB technology to further control the combustion process inside the boiler. The addition of 

separated overfire air provides additional NOx control by injecting air into the lower temperature 

combustion zone, above the LNB, where thermal NOx is less likely to form. This allows 

complete combustion of the fuel, or burnout, under more controlled conditions.

3. Selective Non-Catalytic Reduction – SNCR involves the injection of a reducing agent such as 

ammonia or urea into the flue gas stream. The reduction chemistry takes place without the aid of 

a catalyst. SNCR systems rely on appropriate injection temperatures, proper mixing of the 

reagent and flue gas, and prolonged retention time in place of the catalyst. SNCR operates at 

higher temperatures than SCR. The effective temperature range for SNCR is 1,600 to 2,100F. 

SNCR systems are very sensitive to temperature changes and typically have lower NOx emissions 

reduction (up to fifty or sixty percent) and may emit ammonia out of the exhaust stack when too 

much ammonia is added to the system.

4. Selective Catalytic Reduction – SCR is a post combustion control technology, similar to SNCR,

were vaporized ammonia or urea is injected into the flue gas upstream of a catalyst. NOx

entrained in the flue gas is reduced to molecular nitrogen (N2) and water. The use of a catalyst 

facilitates the reaction at an exhaust temperature range of 300 to 1,100F, depending on the 

application and type of catalyst used. When catalyst temperatures are not in the optimal range for 

the reduction reaction or when too much ammonia is injected into the process, unreacted 

ammonia can be released to the atmosphere through the stack. This release is commonly referred 

to as ammonia slip. A well controlled SCR system typically emits less ammonia than a 

comparable SNCR control system.

In addition to applying these control technologies separately, they can be combined to increase overall 

NOx reduction. For example, the application of SCR on power plant boilers often includes installing LNB 

with some form of advanced overfire air to reduce NOx emissions by 90% or more. General Chemical 

addressed the application of each control technology separately. Emission reductions were determined 

using baseline emissions and the applied control technology.

4.3.3 STEP 2: ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

General Chemical did not eliminate any of the four individual control technologies as technically 

infeasible. All four technologies are proven emission reduction technologies with several examples of 

each in operation.
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4.3.4 STEP 3: EVALUATE EFFECTIVENESS OF REMAINING CONTROL 

TECHNOLOGIES

The Division considers the control effectiveness of a proposed control technology to be equivalent to the 

BART-determined permit limit. The limit is based on continuous compliance when the control 

equipment is well maintained and operated in a manner consistent with good air pollution control 

practices for minimizing emissions. In order to demonstrate continuous compliance with the permit limit 

it is important to consider that even well maintained and operated equipment will have some emissions 

variability. Complex emission control equipment, such as existing LNB with new SOFA, generally have 

inherent variability that must be considered when establishing the limit. Otherwise, the source will be out 

of compliance even though the equipment is operated and maintained as well as possible.

General Chemical reviewed literature and reports from Alstom Power to determine achievable emission 

rates for each NOx emissions control technology. General Chemical‟s December 15, 2008 submittal, in 

response to the Division‟s request to address lower NOx emission levels, proposed emissions rate of 0.32 

lb/MMBtu and 0.28 lb/MMBtu for new LNB with existing OFA and new LNB with SOFA, respectively. 

As mentioned earlier, General Chemical has been working with Alstom Power to install the BARTdetermined controls of new LNB with existing OFA and subsequently learned that this control technology 

will not meet an emission rate of 0.32 lb/MMBtu, based on a 30-day rolling average. General Chemical 

has also learned from Alstom Power that the existing LNB and OFA systems are capable of controlling 

NOx emissions better than previously anticipated. Installing SOFA on each boiler, in addition to the 

existing LNB and OFA system, is expected to significantly reduce NOx emissions and meet an emissions 

rate of 0.28 lb/MMBtu, 30-day rolling average. Based on these recent findings, General Chemical 

proposes to install SOFA and use the existing LNB to control NOx, in place of the using new LNB with 

existing OFA. The Division will no longer consider new LNB with existing OFA a feasible option, based 

on the reported control levels.

The proposed emission reductions for SCR and SNCR from General Chemical‟s original BART analysis 

are included in this analysis. Installing SNCR was determined to reduce NOx emissions by 50%. Based 

on the permitted baseline value of 0.70 lb/MMBtu, the resulting NOx emission rate is 0.35 lb/MMBtu for 

each boiler. Applying SCR to each of the boilers is anticipated to reduced NOx emissions by 80%. Based 

on the permitted baseline value of 0.70 lb/MMBtu, the resulting NOx emission rate is 0.14 lb/MMBtu. 

Revised achievable emission rates from the four proposed control technologies are shown in Table 3.
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Table 3: Controlled NOx Emission Rates Per Boiler

Control Technology

Boiler C

Resulting NOx

Emission Rate 

(lb/MMBtu) / (lb/hr)

Boiler D

Resulting NOx

Emission Rate 

(lb/MMBtu) / (lb/hr)

Existing LNB with OFA 0.70 (a) / 374.0 0.70 (a) / 616.0

Existing LNB with new SOFA 0.28 (b) / 149.5 0.28 (b) / 246.4

SNCR 0.35 (c)/ 188.0 0.35 (c)/ 308.0

SCR 0.14 (c)/ 75.0 0.14 (c)/ 123.0

(a) 40 CFR part 60, subpart D limit

(b) Proposed emission rate

(c) Calculated by dividing the proposed lb/hr emission rate by the boiler‟s maximum heat input

The above emission rates were used in the comprehensive visibility analysis, but not in the cost analysis

completed in Step 4. Baseline emission rates for the costing analyses were based on a 3-year average of 

actual emissions from the BART baseline period, 2001-2003. Reduction efficiencies for SNCR and SCR 

were applied to the 3-year averaged baseline emission rate to calculate emission reductions. NOx

emissions reductions for existing LNB with new SOFA were calculated based on the difference between 

the baseline emission rate and the achievable emission rate of 0.28 lb/MMBtu.

4.3.5 STEP 4: EVALUATE IMPACTS AND DOCUMENT RESULTS

General Chemical evaluated the economic, environmental, and energy impacts associated with the four 

proposed control options for Boilers C and D. General Chemical researched industry literature, contacted 

vendors for cost information and used the EPA Air Pollution Control Cost Manual, Sixth Edition to 

calculate control costs. A vendor quote was provided in the December 15, 2008 response for the capital 

costs of installing LNB with existing OFA. Costs associated with proposed NOx control options are 

presented below.

General Chemical noted in the original analysis that, while all four technologies are technically feasible, 

space for emission control equipment is extremely limited. Post combustion add-on controls, SNCR and 

SCR, require significant changes to the facility to accommodate the foot print of the control, any ancillary 

equipment, and a new stack. Equipment costing for these options include demolition costs and installing 

a new stack.
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General Chemical noted in their December 15, 2008, response that “[t]he level of boiler work required to 

install each of these systems varies significantly [LNB with existing OFA vs. LNB with SOFA]. 

Installation of LNB is a matter of changing the existing burners and replacing them with burners with a 

different configuration in the same space. Installation of LNB+SOFA requires extensive modification of 

the boiler windbox where new air ports are installed, air supply provided, and operator interface control 

provided.” (Response to Comment for the BART Analysis-General Chemical Green River Works, pg. 3-1). 

Boiler modifications significantly increase the time necessary to install SOFA and increase the amount of 

time the unit is shutdown.

In addition to the typical purchase, installation, and operational costs associated with installing emission 

controls, General Chemical included costs related to site preparation and auxiliary energy costs associated 

with generating additional steam to supplement lost steam production when each of the existing boilers is 

shutdown to install the emission controls. Site preparation costs are included in the capital costs for each 

control option and account for additional structural modification and demolition work required to retrofit 

the existing boilers, since the installation of the emission control equipment was not accounted for in the 

original plant design. Auxiliary energy costs were included in the revised application, as well as in the 

original application for the installation of SNCR and SCR, to account for lost steam production as each of 

the units is shutdown for modification. Makeup steam can be generated by Boiler E, a 490 MMBtu/hr 

natural-gas fired boiler. However due to the size of the boiler, the plant will operate on reduced steam 

demand when firing Boiler E. General Chemical included auxiliary energy costs, reported as lost revenue 

in the costing analysis, for installing LNB with existing OFA and LNB with SOFA in their December 15, 

2008 response. The same differential energy cost basis that was originally proposed for installation of 

SNCR and SCR, $8/MMBtu ($94,000/day), was used to calculate energy costs associated with the revised 

LNB options. However, the replacement energy cost included in the economic costs for installing new 

LNB with existing OFA was based on firing Boiler E for one week ($658,000), while energy cost for the 

installation of LNB with SOFA was based on five weeks ($3,290,000). The Division notes that five 

weeks downtime is notably higher than anticipated, especially when compared to the reported two-week 

downtime required for installing SCR.

General Chemical based the capital recovery factor (CRF) and annual cost of control of SNCR and SCR 

on a 7% interest rate and a control life of 30 years. General Chemical used 7% interest rate and a control 

life of 20 years to annualize costs for existing LNB with new SOFA. The Division will use the same 

control life of 30 years to compare all three NOx emissions controls. Labor and service costs associated 

with SNCR and SCR were estimated at $37 per hour, while $30 per hour was used to calculate labor and 

service costs for LNB with new SOFA.

Several different metrics can be considered when evaluating the cost-benefit relationships of different 

emission control technologies. In 40 CFR part 51 Appendix Y two metrics are specifically mentioned: 

cost effectiveness and incremental cost effectiveness. Through the application of BACT, the Division has 

extensive experience using cost effectiveness (i.e., dollars per ton of pollutant removed) to evaluate 

different control technologies. Incremental cost effectiveness is also used extensively by the Division 

when comparing emission controls under the BACT process. While the BART and the BACT processes 

are not necessarily equivalent, control determinations from either process are based on cost effectiveness 

and incremental cost effectiveness and are indicative of the economic costs to control emissions. In 

addition to providing cost effectiveness and incremental cost effectiveness results, General Chemical 

provided cost information in terms of cost of applying emission controls and the level of visibility 

improvement achieved (i.e., dollars per deciviews). While this metric can illustrate the control cost and 
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visibility improvement differences between control options, it is not commonly used to assess the overall 

effectiveness of pollution control equipment. When performing the presumptive BART limits analyses

for electric generating units (EGUs) for NOx and SO2, EPA addressed cost effectiveness and incremental 

cost effectiveness separate from visibility improvement. EPA did not use the dollars per deciview metric 

to compare control options. Visibility improvements from the application of the analyzed control 

measures used to establish presumptive levels were addressed in a separate visibility analysis. As 

discussed in the comprehensive visibility analysis presented later in this analysis as Step 5: Evaluate 

visibility impacts, the Division evaluated the amount of anticipated visibility improvement gained by the 

application of additional emission control technology. The Division considered capital cost, annual cost, 

cost effectiveness, and incremental cost effectiveness in the evaluation of each proposed NOx emission 

control. Economic and environmental costs for additional NOx controls on Boilers C and D are 

summarized in Tables 4-7.

Table 4: Boiler C Economic Costs

Cost Baseline

Option 1: 

LNB w/ SOFA

Option 2: 

SNCR

Option 3: 

SCR

Control Equipment Capital Cost $0 $5,837,180 $7,541,800 $14,097,600 

Capital Recovery Factor N/A 0.0806 0.0806 0.0806

Annual Capital Recovery Costs $0 $470,477 $607,870 $1,136,267 

Annual O&M Costs $0 $287,234 (a) $825,850 $1,298,542 

Annual Cost of Control $0 $757,711 $1,433,720 $2,434,809 

(a) Labor rate of $30/hour was used for LNB options instead of $37/hour which was used for SCR and SNCR

Table 5: Boiler C Environmental Costs

Baseline Option 1: 

LNB w/ SOFA

Option 2: 

SNCR

Option 3: 

SCR

Annual NOx Emission (tpy) 1,167 (a) 655 (b) 584 (c) 233 (c)

Percent Control from Baseline 0 44% 50% 80%

Annual NOx Reduction from Baseline (tpy) 0 512 584 934

Annual Cost of Control $0 $757,711 $1,433,720 $2,434,809

Cost per ton of Reduction N/A $1,480 $2,455 $2,607

Incremental Cost per ton of Reduction N/A $1,480 $9,389 $2,860 

(a) Annual baseline emissions based on 3-year average of actual NOx emissions from the boiler for calendar years 

2001-2003

(b) Annual emissions based on 0.28 lb/MMBtu times the maximum heat input for 8,760 hours

(c) Annual emissions based on percent control times the 3-year average of actual NOx emissions for calendar years 

2001-2003
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Table 6: Boiler D Economic Costs

Cost Baseline Option 1: LNB w/ SOFA

Option 2: 

SNCR

Option 3: 

SCR

Control Equipment Capital Cost $0 $7,487,600 $8,391,400 $19,194,500 

Capital Recovery Factor N/A 0.0806 0.0806 0.0806

Annual Capital Recovery Costs $0 $603,501 $676,347 $1,547,077 

Annual O&M Costs $0 $340,048 (a) $810,234 $1,852,189 

Annual Cost of Control $0 $943,549 $1,486,581 $3,399,266 

(a) Labor rate of $30/hour was used for LNB options instead of $37/hour which was used for SCR and SNCR

Table 7: Boiler D Environmental Costs

Baseline Option 1: 

LNB w/ SOFA

Option 2: 

SNCR

Option 3: 

SCR

Annual NOx Emission (tpy) 1,816 (a) 1,079 (b) 908 (c) 363 (c)

Percent Control from Baseline 0 41% 50% 80%

Annual NOx Reduction from Baseline (tpy) 0 737 908 1,453

Annual Cost of Control $0 $943,549 $1,486,581 $3,399,266

Cost per ton of Reduction N/A $1,280 $1,637 $2,340 

Incremental Cost per ton of Reduction N/A $1,280 $3,176 $3,510 

(a) Annual baseline emissions based on 3-year average of actual NOx emissions from the boiler for calendar years 

2001-2003

(b) Annual emissions based on 0.28 lb/MMBtu times the maximum heat input for 8,760 hours

(c) Annual emissions based on percent control times the 3-year average of actual NOx emissions for calendar years 

2001-2003

The Division considers the cost effectiveness and incremental cost effectiveness reasonable for all three

proposed NOx BART technologies. The final step in the NOx BART determination process for Boilers C 

and D, Step 5: Evaluate visibility impacts, is addressed in a comprehensive visibility analysis covering all 

three visibility impairing pollutants (i.e., NOx, PM, and SO2). The visibility analysis follows below.

4.3.6 STEP 5: VISIBILITY IMPROVEMENT DETERMINATION

The fifth of five factors that must be considered for a BART determination analysis, as required by 40 

CFR part 51 - Appendix Y, is the degree of Class I area visibility improvement that results from the 

possible options for control technology. This factor was evaluated for the General Chemical Green River 

facility by using an EPA-approved dispersion modeling system (CALPUFF) to predict the change in 

Class I area visibility. The visibility modeling is described in detail below.
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Bridger Wilderness Area (WA) and Fitzpatrick WA are the two closest Class I areas to the General 

Chemical Green River Works facility, as shown in Figure 1 below. Bridger WA is located approximately 

120 kilometers (km) northeast of General Chemical and Fitzpatrick WA is located approximately 154 km 

northeast of the facility.

Only those Class I areas most likely to be impacted by the Green River Works facility sources were 

modeled, as determined by source/Class I area locations, distances to each Class I area, and professional 

judgment considering meteorological and terrain factors. Areas greater than 300 km from Green River 

were excluded from consideration. All source-Class I area distances from Green River to Bridger WA 

and Fitzpatrick WA exceed 50 km and are less than 300 km, thus falling within the range of 

recommended CALPUFF application. If impacts are less than the BART threshold for the Class I areas 

modeled, it can be reasonably assumed that areas at a greater distance and in directions of less frequent 

plume transport will not experience significant impacts. 

Because of the results of the Division‟s screening modeling used to determine sources subject to BART, 

General Chemical was required to conduct a refined BART analysis that included CALPUFF visibility 

modeling for the facility. The modeling approach followed the requirements described in the Division‟s 

BART modeling protocol, BART Air Modeling Protocol - Individual Source Visibility Assessments for 

BART Control Analyses (WDEQ-AQD, September 2006).
General Chemical – Green River Works

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Figure 1: General Chemical Green River Works and Class I Areas

4.3.6.1 CALPUFF SYSTEM

Predicted visibility impacts from General Chemical‟s BART sources were determined with the EPA 

CALPUFF modeling system, which is the EPA-preferred modeling system for long-range transport. As 

described in the EPA Guideline on Air Quality Models (Appendix W of 40 CFR part 51), long-range 

transport is defined as modeling with source-receptor distances greater than 50 km. Because all modeled 

areas are located more than 50 km from the facility, the CALPUFF system was appropriate for use.
General Chemical – Green River Works

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The CALPUFF modeling system consists of a meteorological data pre-processor (CALMET), an air 

dispersion model (CALPUFF), and post-processor programs (POSTUTIL, CALSUM, CALPOST). The 

CALPUFF model was developed as a non-steady-state air quality modeling system for assessing the 

effects of time- and space-varying meteorological conditions on pollutant transport, transformation, and 

removal. 

CALMET is a diagnostic wind model that develops hourly wind and temperature fields in a threedimensional, gridded modeling domain. Meteorological inputs to CALMET can include surface and 

upper-air observations from multiple meteorological monitoring stations. Additionally, the CALMET 

model can utilize gridded analysis fields from various mesoscale models such as MM5 to better represent 

regional wind flows and complex terrain circulations. Associated two-dimensional fields such as mixing 

height, land use, and surface roughness are included in the input to CALMET. The CALMET model 

allows the user to “weight” various terrain influence parameters in the vertical and horizontal directions 

by defining the radius of influence for surface and upper-air stations. 

CALPUFF is a multi-layer, Lagrangian puff dispersion model. CALPUFF can be driven by the threedimensional wind fields developed by the CALMET model (refined mode), or by data from a single 

surface and upper-air station in a format consistent with the meteorological files used to drive steady-state 

dispersion models. All far-field modeling assessments described here were completed using the 

CALPUFF model in a refined mode.

CALSUM is a post-processing program that can operate on multiple CALPUFF output files to combine 

the results for further post-processing. POSTUTIL is a post-processing program that processes 

CALPUFF concentrations and wet/dry flux files. The POSTUTIL model operates on one or more output 

data files from CALPUFF to sum, scale, and/or compute species derived from those that are modeled, and 

outputs selected species to a file for further post-processing. CALPOST is a post-processing program that 

can read the CALPUFF (or POSTUTIL or CALSUM) output files and calculate the impacts to visibility. 

All of the refined CALPUFF modeling was conducted with the version of the CALPUFF system that was 

recognized as the EPA-approved release at the time of the development of the Division‟s modeling 

protocol. Version designations of the key programs are listed in the table below.

Table 8: Key Programs in CALPUFF System

Program Version Level

CALMET 5.53a 040716

CALPUFF 5.711a 040716

CALPOST 5.51 030709
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4.3.6.2 METEOROLOGICAL DATA PROCESSING (CALMET)

As required by the Division‟s modeling protocol, the CALMET model was used to construct an initial 

three-dimensional windfield using data from the MM5 model. Surface and upper-air data were input to 

CALMET to adjust the initial windfield, but because of the relative scarcity of wind observations in the 

modeling domain, the influence of the observations on the initial windfield was minimized. Because the 

MM5 data were afforded a high degree of influence on the CALMET windfields, the Division obtained 

MM5 data at 12-km resolution that spanned the years 2001-2003. Locations of the observations that were 

input to CALMET, including surface, upper-air, and precipitation stations, are shown in Figure 2. Default 

settings were used in the CALMET input files for most of the technical options. The following table lists 

the key user-defined CALMET settings that were selected. 

Table 9: Key User-Defined CALMET Settings

Variable Description Value 

PMAP Map projection LCC 

DGRIDKM Grid spacing (km) 4 

NZ Number of layers 10 

ZFACE Cell face heights (m) 0, 20, 40, 100, 140, 320, 

580, 1020, 1480, 2220, 3400 

RMIN2 Minimum distance for extrapolation -1 

IPROG Use gridded prognostic model output 14 

RMAX 1 Maximum radius of influence (surface 

layer, km) 

30 

RMAX 2 Maximum radius of influence (layers 

aloft, km) 

50 

TERRAD Radius of influence for terrain (km) 15 

R1 Relative weighting of first guess wind 

field and observations (km) 

5 

R2 Relative weighting aloft (km) 25 
General Chemical – Green River Works

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Figure 2: Observations Input to CALMET

4.3.6.3 CALPUFF MODELING SETUP

To allow chemical transformations within CALPUFF using the recommended chemistry mechanism 

(MESOPUFF II), the model required input of background ozone and ammonia concentrations. For 

ozone, hourly data collected from the following stations were used:

 Rocky Mountain National Park (NP), Colorado

 Craters of the Moon National Monument, Idaho

 Highland, Utah

 Thunder Basin, Wyoming

 Yellowstone NP, Wyoming

 Centennial, Wyoming

 Pinedale, Wyoming

-500 -400 -300 -200 -100 0 100 200 300 400 500

LCC E (km)

-300

-200

-100

0

100

200

300

400

KWX

AIA

AKO

APA

ASE

BFF

BIL

BPI

BTM

BYG

BYI

BZN

CAG

CPR CDR

CUT

CYS

D07

DEN

DGW

DLN

EEO

EVW

GCC

GEY

GJT

IDA

IEN

ITR

LAR

LGU

LIC

LND

LVM

LXV

OGD

P60

PHP

PIH

PUC

RAP

RIL

RIW

RKS

RWL

RXE

SHR

SLC

SNY

TOR

VEL

WRL

RAP

DEN

SLC

RIW

GenChem

Precip Station = green

Surface Station = white 3-letter

Upper-Air = red 3-letter
General Chemical – Green River Works

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For any hour that was missing ozone data from all stations, a default value of 44 parts per billion (ppb) 

was used by the model as a substitute. For ammonia, a domain-wide background value of 2 ppb was 

used.

Latitude and longitude coordinates for Class I area discrete receptors were taken from the National Park 

Service (NPS) Class I Receptors database and converted to the appropriate Lambert Conformal Conic 

coordinates. Figures 3 and 4 show the receptor configurations that were used for Bridger WA and

Fitzpatrick WA. Receptor spacing for the three modeled areas is approximately 1.3 km in the east-west 

direction and approximately 1.8 km in the north-south direction. 

Figure 3: Receptors for Bridger WA
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Figure 4: Receptors for Fitzpatrick WA

4.3.6.4 CALPUFF INPUTS – BASELINE AND CONTROL OPTIONS

The first step in the refined modeling analysis was to perform visibility modeling for current (baseline) 

operations at the facility. Baseline source release parameters and emissions are shown in the table below, 

followed by a table with data for the various control options. 

For all cases, particulate emissions were divided between fine particulate (PMF) and coarse particulate 

(PMC) and modeled accordingly within CALPUFF and CALPOST.

The percentage reductions from the modeled baseline emissions for the various control options are shown 

below:

 Low NOx burners (LNB) and separated overfire air (SOFA): 60% reduction in NOx

 Selective catalytic reduction (SCR): 80% reduction in NOx

 Selective non-catalytic reduction (SNCR): 50% reduction in NOx
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In response to comments received on the initial BART determinations for the facility, the Division 

requested that General Chemical evaluate additional state-of-the-art control levels that could be achieved 

for NOx emissions. General Chemical submitted additional modeling that included evaluations of: 1) new 

LNB along with the existing OFA systems at a NOx emission rate based on 0.32 lb/MMBtu for each 

boiler, and 2) new LNB along with separated OFA with a NOx emission rate based on 0.28 lb/MMBtu for 

each boiler. The Division reviewed the modeling, which consisted of year 2001 modeling for each of the 

two control options, and expanded the modeling to include all three years of available meteorological 

data. Table 10 presents the model inputs that were used to represent the baseline scenario for Boilers C 

and D, and Table 11 presents the inputs that were used to model the additional control scenarios.

Table 10: Source Parameters and Emissions for the Baseline Scenario

Parameter

Baseline

Coal-Fired Boiler C 

(GR-2-L)

Coal-Fired Boiler D

(GR-3-W)

NOx Control – overfire air, low excess air

PM Control – “hot-side” ESP 

SO2 Control – no add-on controls

Heat Input (MMBtu/hr) 534 880

Base Elevation (m) 1928 1928

Stack Height (m) 47.55 47.55

Stack Diameter (m) 3.05 3.05

Stack Temperature (K) 452.6 460.9

Exit Velocity (m/s) 15.98 25.12

SO2 Emissions (lb/MMBtu) 1.2 1.2

SO2 Emissions (lb/hr) 640.8 1056.0

H2SO4 Emissions (lb/hr) 5.87 9.39

NOx Emissions (lb/MMBtu) 0.7 0.7

NOx Emissions (lb/hr) 374.0 616.0

PM Coarse Emissions (lb/hr) 27.77 44.44

PM Fine Emissions (lb/hr) 21.39 34.24

Elemental Carbon Emissions (lb/hr) 0.82 1.32

Organic Carbon Emissions (lb/hr) 1.47 2.35

ESP = electrostatic precipitator

H2SO4 = sulfuric acid

K = Kelvin

lb/hr = pounds per hour

lb/MMBtu = pounds per million British thermal units

m/s = meters per second

MMBtu/hr = million British thermal units per hour

NOx = nitrogen oxides

PM = particulate matter

SO2 = sulfur dioxide
General Chemical – Green River Works

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Table 11: Source Parameters and Emissions for Additional Modeling Scenarios

Parameter

Control Scenario 1:

Existing LNB 

with new SOFA (a)

Control Scenario 2:

SNCR

Control Scenario 3:

SCR

Coal-Fired 

Boiler C

(GR-2-L)

Coal-Fired 

Boiler D

(GR-3-W)

Coal-Fired 

Boiler C

(GR-2-L)

Coal-Fired 

Boiler D

(GR-3-W)

Coal-Fired 

Boiler C

(GR-2-L)

Coal-Fired 

Boiler D

(GR-3-W)

Base Elevation (m) 1928 1928 1928 1928 1928 1928

Stack Height (m) 47.55 47.55 47.55 47.55 47.55 47.55

Stack Diameter (m) 3.05 3.05 3.05 3.05 3.05 3.05

Stack Temperature (K) 452.6 460.9 452.6 460.9 452.6 460.9

Exit Velocity (m/s) 15.98 25.12 15.98 25.12 15.98 25.12

SO2 Emissions (lb/hr) 641.0 1056.0 641.0 1056.0 641.0 1056.0

H2SO4 Emissions (lb/hr) 5.87 9.39 5.87 9.39 5.87 9.39

NOx Emissions (lb/hr) 149.5 246.4 188.0 308.0 75.0 123.0

PM Coarse Emissions (lb/hr) 27.77 44.44 27.77 44.44 27.77 44.44

PM Fine Emissions (lb/hr) 21.39 34.24 21.39 34.24 21.39 34.24

Elemental Carbon (lb/hr) 0.82 1.32 0.82 1.32 0.82 1.32

Organic Emissions (lb/hr) 1.47 2.35 1.47 2.35 1.47 2.35

(a) General Chemical modeling scenario A submitted in response to Division‟s request to address lower NOxlevels achieved by LNB with new SOFA.

H2SO4 = sulfuric acid 

K = Kelvin

lb/hr = pounds per hour

LNB = low NOx burners

m = meters

m/s = meters per second

NOx = nitrogen oxides

OFA = overfire air

SOFA = separated overfire air

PM = particulate matter

SO2 = sulfur dioxide
General Chemical – Green River Works

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4.3.6.5 CALPUFF VISIBILITY POST-PROCESSING (CALPOST)

The changes in visibility were modeled using Method 6 within the CALPOST post-processor. Method 6 

requires input of monthly relative humidity factors [f(RH)] for each Class I area. Monthly f(RH) factors 

that were used for Bridger WA and Fitzpatrick WA are shown in the table below. 

Table 12: Relative Humidity Factors for CALPOST

Month Bridger WA & Fitzpatrick WA

January 2.50

February 2.30

March 2.30

April 2.10

May 2.10

June 1.80

July 1.50

August 1.50

September 1.80

October 2.00

November 2.50

December 2.40

According to the final BART rule, natural background conditions as a reference for determination of the 

modeled Δdv change should be representative of the 20 percent best natural visibility days in a given 

Class I area. EPA BART guidance provides the 20 percent best days deciview values for each Class I 

area on an annual basis, but does not provide the individual species concentration data required for input 

to CALPOST.

Species concentrations corresponding to the 20 percent best days were calculated for each Class I area by 

scaling back the annual average (natural background) concentrations given in Table 2-1 of the EPA 

document Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Rule. A 

separate scaling factor was derived for each Class I area such that, when multiplied by the guidance table 

annual concentrations, the 20 percent best days deciview values for that particular Class I area would be 

calculated. 

The scaling procedure is illustrated here for Bridger WA. From Appendix B in the EPA natural visibility 

guidance document, the deciview value for the 20 percent best days at Bridger WA is 1.96 dv. To obtain 

the speciated background concentrations representative of the 20 percent best days, the deciview value 

(1.96 dv) was first converted to light extinction. The relationship between deciviews and light extinction 

is expressed as follows:

dv = 10 ln (bext/10) or bext = 10 exp (dv/10)

where: bext = light extinction expressed in inverse megameters (Mm-1).
General Chemical – Green River Works

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Using this relationship with the known deciview value of 1.96, one obtains an equivalent light extinction 

value of 12.17 Mm-1. Next, the annual average natural visibility concentrations were set equal to a total 

extinction value of 12.17 Mm-1. The relationship between total light extinction and the individual 

components of the light extinction is as follows:

bext = (3)f(RH)[ammonium sulfate] + (3)f(RH)[ammonium nitrate] + (0.6)[coarse mass] + (4)[organic 

carbon] + (1)[soil] + (10)[elemental carbon] + bray

where:

 bracketed quantities represent background concentrations in μg/m3

 values in parenthesis represent scattering efficiencies

 f(RH) is the relative humidity adjustment factor (applied to hygroscopic species only)

 bray is light extinction due to Rayleigh scattering (10 Mm-1used for all Class I areas)

Substituting the annual average natural background concentrations, the average f(RH) for Bridger WA, 

and including a coefficient for scaling, one obtains:

12.17 = (3)(2.1)[0.12]X + (3)(2.1)[0.1]X + (0.6)[3.0]X + (4)[0.47]X + (1)[0.5]X + (10)[0.02]X + 10

In the equation above, X represents a scaling factor needed to convert the annual average natural 

background concentrations to values representative of the 20 percent best days. Solving for X provides a 

value of 0.376. Table 13 presents the annual average natural background concentrations, the calculated 

scaling factor, and the calculated background concentrations for the 20 percent best days for Bridger WA. 

Table 13: Calculated Background Components for Bridger WA

Component

Annual Average for 

West Region (μg/m3)

Calculated Scaling 

Factor

20% Best Days for 

Bridger WA

(μg/m3)

Ammonium Sulfate 0.12 0.376 0.045

Ammonium Nitrate 0.10 0.376 0.038

Organic Carbon 0.47 0.376 0.176

Elemental Carbon 0.02 0.376 0.008

Soil 0.50 0.376 0.188

Coarse Mass 3.00 0.376 1.127

The scaled aerosol concentrations were averaged for Bridger WA and Fitzpatrick WA because of their 

geographical proximity and similar annual background visibility. The 20 percent best days aerosol 

concentrations for all three Class I areas in question are listed in Table 14.
General Chemical – Green River Works

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Table 14: Natural Background Aerosol Concentrations (μg/m3)

Aerosol

Component Fitzpatrick WA & Bridger WA

Ammonium Sulfate 0.045

Ammonium Nitrate 0.038

Organic Carbon 0.178

Elemental Carbon 0.008

Soil 0.189

Coarse Mass 1.136

4.3.6.6 VISIBILITY POST-PROCESSING RESULTS

The results of the visibility modeling for both units, modeled together, for the baseline and control 

scenarios are shown in the tables below. For each scenario, the 2001 98th percentile Δdv results are 

reported along with the total number of days for which the predicted impacts exceeded 0.5 dv.

Table 15: CALPUFF Visibility Modeling Results - Baseline Conditions 1

Class I Area

2001 2002 2003

98th 

Percentile 

Value 

(Δdv)

Total

No. of 

Days > 

0.5 Δdv

98th

Percentile 

Value 

(Δdv)

Total

No. of 

Days > 

0.5 Δdv

98th

Percentile 

Value 

(Δdv)

Total

No. of 

Days > 

0.5 Δdv

Bridger WA 0.84 21 0.72 16 0.97 16

Fitzpatrick WA 0.50 8 0.47 7 0.59 10

1 Visibility results are for both units modeled together

Δdv = delta deciview

WA = wilderness area
General Chemical – Green River Works

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Table 16: CALPUFF Results for Baseline and Added Control Options 1

Class I Area

2001

98th Percentile Value (Δdv) Total No. of Days > 0.5 Δdv

Baseline

Bridger WA 0.84 21

Fitzpatrick WA 0.50 8

Control Scenario 1: Existing LNB with new SOFA

Bridger WA 0.62 11

Fitzpatrick WA 0.31 4

Control Scenario 2: SNCR

Bridger WA 0.68 13

Fitzpatrick WA 0.33 4

Control Scenario 3: SCR

Bridger WA 0.51 8

Fitzpatrick WA 0.26 4

1 Visibility results are for both units modeled together

LNB = low NOx burners

OFA = overfire air

SOFA = separated overfire air

A comparison of the 2001 98th percentile Δdv modeling results for both units for baseline, existing LNB

with new SOFA, SNCR, and SCR is shown in Figure 5 below. Modeled visibility improvement with the 

option of using existing LNB with new SOFA on both boilers, as compared to baseline, is 0.22 Δdv at 

Bridger WA and is 0.19 Δdv at Fitzpatrick WA. The addition of SCR to both boilers would provide a 

modeled improvement of an additional 0.11 Δdv at Bridger WA and 0.05 Δdv at Fitzpatrick WA.

Figure 5: CALPUFF Results for Baseline, Existing LNB with new SOFA, SNCR, and SCR

0.00

0.20

0.40

0.60

0.80

1.00

Baseline Existing LNB

with new SOFA

SNCR SCR

98th Percentile Values (2001) - Units Modeled Together

d

e

l

t

a

d

v

Bridger WA

Fitzpatrick WA
General Chemical – Green River Works

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4.3.7 BART CONCLUSION FOR NOx

After reviewing the original information submitted by General Chemical, information from the December 

15, 2008 response, and recent information from Alstom Power, and considering: (1) the costs of 

compliance, (2) the energy and non-air quality environmental impacts of compliance, (3) any pollution 

equipment in use or in existence at the source, (4) the remaining useful life of the source, and (5) the 

degree of improvement in visibility (all five statutory factors) from each proposed control technology, the 

Division determined BART for NOx emitted from the two boilers subject to BART at General Chemical‟s 

Green River Works.

The Division determined that the application of existing LNB with new SOFA and meeting a NOx

emission level of 0.28 lb/MMBtu, 30-day rolling average, was still a valid control option. Affording 

General Chemical the option to install an equivalent performing control technology does not change the 

basis of the BART determination as the BART determination is made based on currently available 

controls (e.g., existing LNB with new SOFA, SNCR, SCR), which were all deemed reasonable. 

Allowing the company to install an equivalent performing technology provides additional flexibility to 

control emissions to the specified BART levels, presumably in the most cost-effective manner.

After considering General Chemical‟s proposal and after considering all statutory factors in their entirety, 

the Division will revise its unit-specific NOx BART determination for Boilers C and D to the following:

Boiler C: Existing LNB with new SOFA or an equivalent performing technology and meeting NOx

emission limits of 0.28 lb/MMBtu (30-day rolling average), 149.5 lb/hr (30-day rolling 

average) and 654.9 tpy as BART for NOx.

Boiler D: Existing LNB with new SOFA or an equivalent performing technology and meeting NOx

emission limits of 0.28 lb/MMBtu (30-day rolling average), 246.4 lb/hr (30-day rolling 

average) and 1,079.2 tpy as BART for NOx.

LNB with SOFA is determined to be BART for Boilers C and D for NOx based, in part, on the following 

conclusions:

1. Installing only LNB with existing OFA to achieve a NOx emissions rate of 0.32 lb/MMBtu, 30-

day rolling average, is no longer technically feasible.

2. Existing LNB with new SOFA on Boiler C was cost effective with a capital cost of $5,837,180 

and a $1,480 per ton of NOx removed average cost effectiveness over a thirty year operational 

life. LNB with SOFA on Boiler D was cost effective with a capital cost of $7,487,600 and a 

$1,280 per ton of NOx removed average cost effectiveness over a thirty year operational life.

3. Combustion control using LNB with SOFA does not require non-air quality environmental 

mitigation for the use of chemical reagents (i.e., ammonia or urea) and there is a minimal energy 

impact.
General Chemical – Green River Works

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4. Modeled 2001 cumulative visibility improvement from the baseline summed across the two Class 

I areas achieved by using existing LNB with new SOFA on both Boilers C and D, is 0.41 Δdv

and the individual 98th percentile values for both Boilers C and D were below 0.5 Δdv.

5. Annual NOx emission reduction from installing LNB with SOFA on the boilers was 512 tons 

from Boiler C and 737 tons from Boiler D, as shown in Tables 5 and 7.

SNCR and SCR were not determined to be BART for Boilers C and D for NOx based, in part, on the 

following conclusions:

1. The cost of compliance for installing SNCR on each boiler is higher than LNB with SOFA. 

Capital costs for SNCR on Boiler C is $7,541,800 and $8,391,400 for Boiler D. Annual 

operating cost for SNCR is $825,850 for Boiler C and $810,234 for Boiler D.

2. As shown in the cost analysis results presented in Tables 5 and 7, applying SNCR to the boilers in 

place of using existing LNB with new SOFA further reduced NOx emissions by only 72 tons from 

Boiler C and 171 tons from Boiler D.

3. The cost of compliance for installing SCR on each boiler is higher than LNB with existing OFA. 

Capital costs for SCR on Boiler C is $14,097,600 and $19,194,500 for Boiler D. Annual 

operating cost for SCR is $1,298,542 for Boiler C and $1,852,189 for Boiler D.

4. Additional non-air quality environmental mitigation is required for the use of chemical reagents 

when either SNCR or SCR is used to reduced NOx emissions from the boilers.

5. Operation of SNCR requires an estimated 50 kW of additional power to operate. SCR on Boiler 

C requires 200 kW of additional power and Boiler D requires 300 kW.

6. The 2001 modeled visibility improvement in the Bridger WA achieved by using SCR in place of 

the existing LNB with new SOFA on both of the boilers is 0.11 Δdv and the improvement in the 

Fitzpatrick WA is 0.05 Δdv.

5.0 INTERIM NOx EMISSIONS REDUCTIONS

BART baseline NOx emissions for both boilers were taken from Operating Permit 3-1-123, which limits 

NOx emissions from each boiler to 0.7 lb/MMBtu on a 3-hour averaging period. Results from General 

Chemical‟s boiler performance tuning indicate that both Boilers C and D can operate below the current 

limit of 0.7 lb/MMBtu. General Chemical proposes to reduce NOx emissions by imposing limits of 0.53 

and 0.55 lb/MMBtu on Boilers C and D, respectively. Proposed NOx reductions from BART baseline 

emissions are show in Table 17 below.
General Chemical – Green River Works

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Table 17: Interim NOx Emissions Reductions

Baseline NOx Emissions 1,3 Proposed NOx Emissions 2,3

NOx Emissions 

Reductions 3

Unit lb/MMBtu lb/hr tpy lb/MMBtu lb/hr tpy lb/hr tpy

Boiler C 0.7 373.8 1,637.2 0.53 283.0 1,239.6 90.8 397.6

Boiler D 0.7 616.0 2,698.1 0.55 484.0 2,119.9 132.0 578.2

Total Reductions 222.8 975.8

1 Based on 3-hour averaging period for lb/MMBtu emissions

2 Based on 30-day rolling averaging period for lb/MMBtu emissions

3 Mass emissions (lb/hr and tpy) based on maximum firing rate of the unit and lb/MMBtu emission factor; annual emissions (tpy) 

based on 8,760 hours of operation

The Division will accept General Chemical‟s proposed interim NOx emissions limits, based on a 30-day 

rolling average, and establish a permit condition to make these limits federally enforceable.

6.0 CHAPTER 6, SECTION 4 – PREVENTION OF SIGNIFICANT DETERIORATION 

(PSD) APPLICABILITY

General Chemical‟s Green River Works is a “major stationary source” under Chapter 6, Section 4 of the 

Wyoming Air Quality Standards and Regulations (WAQSR) because emissions of a criteria pollutant are 

greater than 250 tpy. Installation of new SOFA or an equivalent performing technology is anticipated to 

reduce NOx emissions but may result in collateral emissions increase(s). Under Chapter 6, Section 4, 

General Chemical will be required to submit a permit application addressing collateral emissions 

increases and Prevention of Significant Deterioration (PSD) applicability. If required, a permit must be 

obtained prior to commencing construction to install new SOFA or an equivalent performing technology.

7.0 CHAPTER 5, SECTION 2 – NEW SOURCE PERFORMANCE STANDARDS (NSPS)

The installation of LNB with SOFA or an equivalent performing technology is not anticipated to change 

New Source Performance Standard applicability for the two (2) coal-fired boilers, C and D, at the Green 

River Works, as NOx emissions are not increasing.

8.0 CHAPTER 5, SECTION 3 – NATIONAL EMISSION STANDARDS FOR HAZARDOUS 

AIR POLLUTANTS (NESHAPs) AND CHAPTER 6, SECTION 6 – HAZARDOUS AIR 

POLLUTANT (HAP) EMISSIONS AND MAXIMUM AVAILABLE CONTROL 

TECHNOLOGY (MACT)

On Friday, June 4, 2010, EPA published a proposed rule (NESHAP) entitled National Emission 

Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional 

Boilers and Process Heaters (75 FR pages 32,006-32,073). EPA initially proposed to accept comments 

on the proposed rule (Subpart DDDDD) if they are received on or before July 19, 2010. Comments 

should be directed to the established docket, docket ID: EPA-HQ-OAR-2002-0058. On Wednesday, June 

9, 2010, EPA published a notice (75 FR pages 32,682-32,684) that extended the public comment period 

until August 3, 2010. General Chemical‟s two (2) coal-fired boilers may be subject to this NESHAP, as 

proposed, and General Chemical is expected to comply with all applicable requirements of Subpart 

DDDDD when it becomes effective.
General Chemical – Green River Works

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Page 28

The proposed installation of new SOFA or an equivalent performing technology is not anticipated to 

change 40 CFR part 63 applicability for the two (2) existing coal-fired boilers C and D at the Green River 

Works, as General Chemical is not proposing to increase HAPs emissions. A WAQSR Chapter 6, 

Section 6 (case-by-case MACT) review is not required since the boilers are existing units and are not 

being reconstructed.

9.0 CHAPTER 6, SECTION 3 – OPERATING PERMIT

General Chemical‟s Green River Works is a major source and subject to the requirements of Chapter 6, 

Section 3 of the Wyoming Air Quality Standards and Regulations (WAQSR). Operating Permit 3-1-123

was issued for the facility on June 10, 2008. General Chemical will need to modify their operating permit 

to include the changes authorized in this permitting action in accordance with Chapter 6, Section 3 of the 

WAQSR.

10.0 CONCLUSION

The Division is satisfied that General Chemical‟s Green River Works will comply with all applicable 

Wyoming Air Quality Standards and Regulations. The Division proposes to issue an Air Quality Permit 

incorporating the Division‟s revised BART determination for each boiler, existing LNB with new SOFA 

or an equivalent performing technology, and associated emission limits.

11.0 PROPOSED PERMIT CONDITIONS

The Division proposes to issue an Air Quality Permit to General Chemical (Soda Ash) Partners for the 

modification of the Green River Works with the following conditions:

1. Authorized representatives of the Division of Air Quality be given permission to enter and inspect 

any property, premise or place on or at which an air pollution source is located or is being 

constructed or installed for the purpose of investigating actual or potential sources of air 

pollution, and for determining compliance or non-compliance with any rules, standards, permits 

or orders.

2. All substantive commitments and descriptions set forth in the application for this permit, unless 

superseded by a specific condition of this permit, are incorporated herein by this reference and are 

enforceable as conditions of this permit.

3. That General Chemical (Soda Ash) Partners shall modify their Operating Permit in accordance 

with Chapter 6, Section 3 of the WAQSR.

4. All notifications, reports and correspondence associated with this permit shall be submitted to the 

Stationary Source Compliance Program Manager, Air Quality Division, 122 West 25th Street, 

Cheyenne, WY 82002 and a copy shall be submitted to the District Engineer, Air Quality 

Division, 510 Meadowview Drive, Lander, WY 82520.
General Chemical – Green River Works

AP-10837 Application Analysis

Page 29

5. Effective upon permit issuance, this condition shall supersede Condition 6 in Air Quality Permit 

MD-6046. Each time separated overfire air or an equivalent performing technology is installed, 

the owner or operator shall furnish the Administrator written notification of: (i) the anticipated 

date of initial startup not more than sixty (60) days or less than thirty (30) days prior to such date, 

and; (ii) the actual date of initial start-up within fifteen (15) days after such date in accordance 

with Chapter 6, Section 2(i) of the WAQSR.

6. Effective upon permit issuance, this condition shall supersede all portions of Condition 7 in Air 

Quality Permit MD-6046 that apply to NOx performance tests for Boilers C and D. NOx

performance tests shall be conducted on Boilers C and D within thirty (30) days of achieving 

maximum design rate after installation of separated overfire air or an equivalent performing 

technology, but not later than ninety (90) days following initial start-up in accordance with 

Chapter 6, Section 2(j) of the WAQSR. If maximum design production rate is not achieved 

within ninety (90) days of start-up, the Administrator may require testing at the rate achieved and 

again with maximum rate is achieved. For each test, a written report of the results shall be 

submitted and the operator shall provide fifteen (15) days prior notice of the test date.

7. Effective upon permit issuance, this condition shall supersede all portions of Condition 8 in Air 

Quality Permit MD-6046 that apply to NOx emission limits for Boilers C and D. Effective on and 

after the date on which an initial performance test is conducted, as required by Condition 6 of this 

permit, NOx emissions shall not exceed the levels below. The NOx emissions limits shall apply 

during all operating periods.

Unit

lb/MMBtu

(30-day rolling average)

lb/hr

(30-day rolling average) tpy

Boiler C 0.28 149.5 654.9

Boiler D 0.28 246.4 1,079.2

8. Effective upon permit issuance, NOx emissions from Boilers C and D shall not exceed the levels 

below. The NOx emissions limits shall apply during all operating periods.

Unit

lb/MMBtu

(30-day rolling average)

lb/hr

(30-day rolling average) tpy

Boiler C 0.53 283.0 1,239.6

Boiler D 0.55 484.0 2,119.9

NOx performance tests shall be conducted on Boilers C and D within ninety (90) days of permit 

issuance. Performance tests shall be conducted in accordance with Condition 9 of this permit.
General Chemical – Green River Works

AP-10837 Application Analysis

Page 30

9. Effective upon permit issuance, this condition shall supersede all portions of Condition 9 in Air 

Quality Permit MD-6046 that apply to NOx performance tests for Boilers C and D. NOx

performance tests, required by Condition 6 of this permit, shall consist of the following:

NOx Emissions – Compliance with the NOx 30-day rolling average shall be determined 

using a continuous emissions monitoring system (CEMS) certified in accordance with 40 

CFR part 60.

Testing required by the Chapter 6, Section 3, Operating Permit may be submitted to satisfy 

testing required by this condition.

10. Effective upon permit issuance, this condition shall supersede all portions of Condition 12 in Air 

Quality Permit MD-6046 that apply to NOx emissions from Boilers C and D. Effective on and

after the date on which the initial performance test is conducted in accordance with Condition 8

of this permit, compliance with the limits set forth in this permit for the coal-fired boilers C and D

shall be determined with data from the continuous monitoring systems as follows:

a. Exceedances of the limits shall be defined as follows:

i. Any 30-day rolling average of NOx emissions which exceeds the lb/MMBtu limit 

calculated in accordance with 40 CFR Part 60, Subpart D, 60.45.

ii. Any 30-day rolling average calculated using valid data (output concentration and 

average hourly volumetric flowrate) from the existing CEM equipment which 

exceeds the lb/hr NOx limit established in this permit. The 30-day average 

emission rate shall be calculated as the arithmetic average of hourly emissions 

with valid data during the previous 30-day period.

iii. Any annual ton per year NOx emissions calculated using valid data (output 

concentration and average hourly volumetric flowrate) from the required CEM 

equipment which exceeds the tpy limits established for NOx in Conditions 7 and 

8 of this permit.

iv. Valid data shall meet the requirements of WAQSR, Chapter 5, Section 2(j) and 

follow the compliance provisions and monitoring requirements of §60.48Da 

and §60.49Da.

v. Exclusion of startup, shutdown, and malfunction emissions applies to the NSPS 

or NESHAP standard(s) as authorized in the respective subpart(s) and as 

authorized in this permit.

b. General Chemical (Soda Ash) Partners shall comply with all reporting and record 

keeping requirements as specified in WAQSR Chapter 5, Section 2(g) and 40 CFR Part 

60, Subpart D. All excess emissions shall be reported using the procedures and reporting 

format specified in WAQSR Chapter 5, Section 2(g).
General Chemical – Green River Works

AP-10837 Application Analysis

Page 31

11. Records required by this permit shall be maintained for a period of at least five (5) years and shall 

be made available to the Division upon request.

12. Effective upon permit issuance, this condition shall supersede Condition 14 in Air Quality Permit 

MD-6046. General Chemical (Soda Ash) Partners shall install separated overfire air or an 

equivalent performing technology on Boilers C and D, and conduct the initial performance tests 

required in Condition 6 no later than December 31, 2014 for Boiler C and December 31, 2015 for 

Boiler D. The date of commencement of construction for each installation of separated overfire 

air or an equivalent performing technology shall be reported to the Administrator within thirty 

(30) days of commencement.

13. All conditions from Air Quality Permit MD-6046 shall remain in effect unless superseded by a 

specific condition of this permit.
Appendix A

Facility Location
¬«530

¬«372

§ ̈¦I 80

5 3 2

8

5

5

4 1

4

5 4

4

9

2

7

5 3

3

5

5

8

3 2

2

9

9

4

3

4

2

8

4

4

3

9

8

9

8

5

5

8

1

7

2 3

6

6

8

8

6

1

3

6

9

6

9

9

8

7

9

8

8

9

4

9

7

3

7

6

7

9

7 8 7 7

1

1

5 4 2

1

6 3 1 6 5 4 3 2 1 5 4

2

2

6

2

18

3

19

23

16 13

34

20

21

14

17

23

11

29

34

10

28

28

33

17

26

21

28

11

17

21

16

22

11

10

22

21

22

27

24

13 15

13

28

17

36

14

15

21

29

32

23

25

24

10

22

24

29

33

29

34

20

12

10

29

22

16

35

15

32

11

25

29

17

28

10

33

14

32

20

35

14

28 29

26

32

17

30

23

33

26

27

28

25

32

34

23

16

27

27 27

10

34

35

15

17

11

15

17

22

20

32

29

15

20

17

29

21

34

20

29

26

21

22

27

32

16

22

22

27

32

21

18

21

29

21

30

34

22

36

29

27

11

28

35

20

27

35

34

11

14

31

19

28

17

34

19

31

10

35

28

16

28

20

28

20

14

26

15

33

29

18

30

28

15

35

12

21

27

10

15

30

12

11

16

27

26

31

17

18

12

18

29

23

16

33

30

26

30

23

10

16

29

36

28

14

24

22

26

36

15

25

6

20

20

33

16

26

33

33

24

14

23

34

35

32

33

12

32

33

10

28

15

19

16

34

16

19

13

30

32 34

21

31

33

13

26

25

18

31

17

27

27 30

27

30

31

18

32

25

7

31

30

19

10

6

20

19

31

19 19

18 18

30

7

6

7 12

36

10

13

12

24

25

22

24

36

25

15

36

27

12

36

24

13

25

13

25

35

26

14

23

35

23

11

11

35

26

26

14

35

11

14

23

26

1

30

30

19

18

31

31

31

31

18

18

30

19

30

19

13

25

24

12

20 21 23 19 20 21 22 23 24 19 20 21 22 22 19 24 23

36 31 32 33 34 35 36 31 32 33 34 35 36 31 32 33 34

R109W R108W R107W

R110W R109W R108 R107W

T20N T20N

T19N T19N

T18N T18N

T17N T17N

T16N T16N

General Chemical Soda Ash Partners

General Chemical Green River Works

Sections 4-6, T18N and Sections 29-33, T19N, R109W

Sweetwater County, Wyoming

0 1.25 2.5 5 Miles

®

General Chemical

Green River