DEPARTMENT OF ENVIRONMENTAL QUALITY AIR QUALITY DIVISION

Application Analysis AP

- 10837

October 14 , 2 010

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) 87 5

- 3350

REVIEWING ENGINEER: Cole Anderson , Air Quality Engineer

1.0 PURPOSE OF APPLICATION

On June 7 , 20 10, General Chemical (Soda Ash) Partners (General Chemical) submitted a request to authorize the use of existing low NO x burners (LNB) with new separated overfire air (SOFA) or an equivalent performing technology in place of the BART

- determined control techno logy, 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 NO x 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 B est A vailable R etrofit T echnology (BART) for these two (2) units, Boilers C and D, based on a comprehensive BART an alysis 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 Work s ‟ locatio n is attached as Appendix A.

On June 22 , 20 10, General Chemical submitted additional documentation from Alstom Power addressing the feasibility of achieving the BART NO x emission s levels using LNB with existing overfire air.General Chemical

– Green River Works

AP

- 10837 Application Analysis Page 2

2.0 RELEVANT PERMIT HIS TORY

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 NO x 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 NO x 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 DESCRIPTION S

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 B oiler D was installed in 1975. Each boiler is currently equipped with a hot

- side electrostatic precipitator (ESP) to control particulate emissions. Existing low NO x burners, o verfire air and low excess air are currently used to reduce NO x 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) t he available retro fit control options ; (2) a ny pollution control equipment in use at the source ; (3) t he costs of compliance with control options ; (4) t he remaining useful life of the facility ; (5) t he energy and non

- air quality environmental impacts of control options ; and (6)
t he visibility impacts analysis. A BART determination must address air pollution control measures for each emissions unit or pollutant emitti ng activity subject to review.General Chemical

– Green River Works

AP

- 10837 Application Analysis Page 3

Each boiler w as addressed under BART using the methodology prescribed in 40 CFR part 51

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

Step 1: Identify all 1 available 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 re trofit 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 sa me 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

, Boiler s C and D, to determine pollutant

- specific BART control measure s for NO x and PM . All five steps were also applied to SO 2 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 SO 2 Milestone and Backstop Trading Program contain ed in Chapter 14, Sections 2 and 3, of the WAQSR

.

4. 2 EXISTING BART DETERMINATION FOR NO x The Division originally published a proposed BART determination for NO x , PM, and SO 2 on August 12, 2008, and accepted public comment on the proposal until October 2 0, 2008 (69 days). A public hearing was held on September 11, 20 0 8 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 NO x 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 NO x for each of the boilers

. C orresponding mass emission rate limits ( lb/hr and tpy ) w ere also established as part of the Divisio n‟s BART determination

. After the close of the public comment period

, General Chemical was requested by the Division to address lower NO x 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 NO x burners with existing OFA on each of the two boilers a nd 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 is sued a revised NO x BA RT analysis, dated August 7, 2009

, which add ress ed lower NO x emission rat es analyzed by General Chemical and after considering all statutory factors in their entirety, established a new BART determination for NO x 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.”General Chemical

– Green River Works

AP

- 10837 Application Analysis Page 4

Boiler C : N ew LNB with existing OFA and meeting NO x 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 NO x .

Boiler D : N ew LNB with existing OFA and meeting NO x 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 NO x .

New LNB with existing OFA wa s determined to be BART for Boilers C and D for NO x 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 NO
x 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 NO
x removed average cost effectiveness over a twenty year operational life.

2. Combustion control using n ew LNB with existing OFA does not require non

- air quality environmental mitigation for the use of chemic al 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. C umulative 3

- year averag ed 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 NO x emission reduction from installing new LNB with existing OFA on the boilers w as 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 NO x 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 c umulative 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

o perating cost for SNCR is $825,850 for Boiler C and $810,234 for Boiler D.General Chemical

– Green River Works

AP

- 10837 Application Analysis Page 5

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. Annua l 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 NO x 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 i nstallation and operation of the BART

- determined NO x controls, ne w LNB with existing OFA, on Boilers C and D to meet the corresponding emission limits on a continuous basis

, satisfy the statutory requi rements of BART. Under the Air Quality Permit MD

- 6046, BART controls are required to be installed on Boiler C by Decemb er 31, 2011 and on Boiler D by December 31, 2012.

4.3 REVISED BART DETERMINATION FOR NO x

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 NO x emissions limits. In February of 2010, Alstom Power performed an onsite investigation of the existing boilers‟ performan ce 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, NO x 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 e xisting LNB and install new SOFA by December 31, 2014 for Boiler C and December 31, 2015 for Boiler D. The associated NO x emissions control level of 0.28 lb/MMBtu, 30

- day rolling average, which was addressed in the revised NO x 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 NO x 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 NO x emi ssions by controlling the combustion process within the boiler. These two technologies effectively control NO x emissions by reducing the amount of oxygen directly accessible to the fuel during initial combustion and by enhancing air

- fuel mixing after init ial combustion to complete the combustion process. SNCR and SCR are add

- on controls that provide a chemical conversion mechanism for NO x to form molecular nitrogen (N 2 ) in the flue gas after combustion occurs. These four technologies are proven emissions controls commonly used on coal

- fired boilers.General Chemical

– Green River Works

AP

- 10837 Application Analysis Page 6

1. New Low NO x Burners with Existing Overfire Air

– LNB technologies rely on a combination of fuel staging and combustion air control to suppress the formation of thermal NO x . 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 c ombustion creating a fuel

- rich zone that reduces the nitrogen to molecular nitrogen (N 2 ) rather than using oxygen in the combustion air to oxidize the nitrogen to NO x .

2. Existing Low NO x Burners with New Separated Overfire Air

– SOFA can be used with existi ng LNB technology to further control the combustion process inside the boiler. The addition of separated overfire air provides additional NO x control by injecting air into the lower temperature combustion zone, above the LNB, where thermal NO x is less lik ely 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 c hemistry 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 NO x emissions reduction (up to fifty or sixty percent) and may emit ammonia out of the exhaust stack when too

mu ch ammonia is added to the system.

4. Selective Catalytic Reduction

– SCR is a post combustion control technology, similar to S N CR,

were vaporized ammonia or urea is injected into the flue gas upstream of a catalyst. NO x entrained in the flue gas is reduced to molecular nitrogen (N 2 ) 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
t he 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 am monia than a comparable SNCR control system.

In addition to applying these control technologies separately, they can be combined to increase overall NO x reduction. For example, the application of SCR on power plant boilers often includes installing LNB

w ith some form of advanced overfire air to reduce NO x emissions by 90% or more. General Chemical addressed the application of each control technolog y separately. Emission reductions were determined using baseline emissions and the applied control technolo gy.

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

.General Chemical

– Green River Works

AP

- 10837 Application Analysis Page 7

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 establis hing 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 N O x emissions control technology

. General Chemical‟s December 15, 2008 submittal, in response to the Division‟s request to address lower NO
x emission levels, proposed emissions rate of 0.32 lb/MMBtu and 0.28 lb/MMBtu for new LNB with existing OFA and new L NB with SOFA, respectively. As mentioned earlier, General Chemical has been working with Alstom Power to install the BART

determined 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 NO x emissions better than previously anticipated. Installing SOFA on each boiler, i n addition to the existing LNB and OFA system, is expected to significantly reduce NO x 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 exi sting LNB to control NO x , 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 cont

rol levels.

The proposed emission reductions for SCR and SNCR from Gene ral Chemical‟s original BART analysis are included in this analysis. Installing SNCR was determined to reduce NO x emissions by 50%. Based on the permitted baseline value of 0.70 lb/MMBtu, the resulting NO x emission rate is 0.35 lb/MMBtu for each boiler. Applying SCR to each of the boilers is anticipated to reduced NO x emissions by 80%. Based on the permitted baseline value of 0.70 lb/MMBtu, the resulting NO x emission rate is 0.14 lb/MMBtu. Revised achievable emission rates from the four proposed contro l technologies are shown in Table 3

.General Chemical

– Green River Works

AP

- 10837 Application Analysis Page 8

Table 3 : Controlled NO x Emission Rates Per Boiler

Control Technology Boiler C Resulting NO x Emission Rate (lb/MMBtu) / (lb/hr) Boiler D

Resulting NO x 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

. B aseline emission rate s for the cost ing 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. NO x e mission s r eductions 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 eco nomic, 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 NO x control options are presented below.

General Chemical n oted 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.General Chemical

– Green River Works

AP

- 10837 Application Analysis Page 9

General Chemical noted in their December 15, 2008, response that “[t]he level of bo iler 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 Rive r 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 em ission 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 co ntrols. 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 equip ment 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 unit s 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 aux iliary 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 SNC R 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 on e week ($658,000), while energy cost for the installation of LNB with SOFA was based on five weeks ($3,290,000). The Divisio n notes that five weeks downtime is notably higher than anticipated, especially when compared to the reported two

- week downtime req uired 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 a nnualize costs for e xisting LNB with new S OFA. The Division will use the same control life of 30 years to compare all three NO x 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 de terminations 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, Gene ral 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 andGeneral Chemical

– Green River Works

AP

- 10837 Application Analysis Page 10

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 NO x and SO 2 , EPA addressed cost effectivenes s 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 presump tive 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 improv ement 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 NO x emission control. Economic and env ironmental costs for additional NO x 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 $607,8 70 $1,136,267

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

Annual Cost of Control $0 $757,711 $1,433,7 20 $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 NO x Emission (tpy) 1,167 (a) 655 (b) 584 (c) 233 (c)

Percent Control from Baseline 0 44% 50% 80%

Annual NO x 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 $2,45 5 $2,60 7 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 NO x 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 e missions based on percent control times the 3

- year average of actual NO x emissions for calendar years 2001

- 2003General Chemical

– Green River Works

AP

- 10837 Application Analysis Page 11

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 NO x Emission ( tpy) 1,816 (a) 1,079 (b) 908 (c) 363 (c)

Percent Control from Baseline 0 41% 50% 80%

Annual NO x 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 NO x 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 e missions based on percent control times the 3

- year average of actual NO x emissions for calendar years 2001

- 2003

The Division considers the cost effectiveness and incremental cost effectiveness reasonable for all thre e proposed NO x BART technologies. The final step in the NO x 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., NO x , PM, and SO 2 ) . 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.General Chemical

– Green River Works

AP

- 10837 Application Analysis Page 12

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

w ere 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 BAR T 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 modeli ng 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 mod eling protocol, BART Air Modeling Protocol

- Individual Source Visibility Assessments for BART Control Analyses (WDEQ

- AQD, September 2006)

.General Chemical

– Green River Works

AP

- 10837 Application Analysis Page 13

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

AP

- 10837 Application Analysis Page 14

The CALPUFF modelin g 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 three

dimensional, gridded modeling domain. Met eorological 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 par ameters 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 three

dimensional wind fields developed b y 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 u sing 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 concentration s 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

- app roved 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 030709General Chemical

– Green River Works

AP

- 10837 Application Analysis Page 15

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 w as 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) 25General Chemical

– Green River Works

AP

- 10837 Application Analysis Page 16

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:

 Roc ky Mountain National Park (NP), Colorado

 Craters of the Moon National Monument, Idaho

 Highland, Utah

 Thunder Basin, Wyoming

 Yellowstone NP, Wyoming

 Centennial, Wyoming

 Pinedale, WyomingGeneral Chemical

– Green River Works

AP

- 10837 Application Analysis Page 17

For any hour that was missing ozone data from all stations, a defau lt value of 44 parts per billion (ppb) was used by the model as a substitute. For ammonia, a domain

- wide backg round 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 appr oximately 1.3 km in the east

- west direction and approximately 1.8 km in the north

- south direction.

Figure 3 : Receptors for Bridger WAGeneral Chemical

– Green River Works

AP

- 10837 Application Analysis Page 18

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 vari ous 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 NO x burners (LNB) and separated overfire air (SOFA): 6 0% reduction in NO x

 Selective catalytic reduction (SCR): 80% reduction in NO x

 Selective non

- catalytic reduction (SNCR): 50% reduction in NO xGeneral Chemical

– Green River Works

AP

- 10837 Application Analysis Page 19

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 NO x emissions. General Chemical submitted additional modeling that included evaluations of: 1) new LNB along with the existing OFA systems at a NO x emission rate based on 0.32 lb/MMBtu for each boiler, and 2) new LNB along with separated OFA with a NO x emissi on 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 1 1 presents the inputs that were used to model th e 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)

NO x Control

– overfire air, low excess air PM Control

– “hot

- side” ESP SO 2 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

SO 2 Emissions (lb/MMBtu) 1.2 1.2

SO 2 Emissions (lb/hr) 640.8 1056.0

H 2 SO 4 Emissions (lb/hr) 5.87 9.39

NO x Emissions (lb/MMBtu) 0.7 0.7

NO x 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 H 2 SO 4 = 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 NO x = nitrogen oxides PM = particulate matter SO 2 = sulfur dioxideGeneral Chemical

– Green River Works

AP

- 10837 Application Analysis Page 20

Table 1 1 : 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 SO 2 Emissions (lb/hr) 641.0 1056.0 641.0 1056.0 641.0 1056.0
H 2 SO 4 Emissions (lb/hr) 5.87 9.39 5.87 9.39 5.87 9.39 NO x 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 NO x levels achieved by LNB with new SOFA. H 2 SO 4 = sulfuric acid K = Kelvin lb/hr = pounds per hour LNB = low NO x burners
m = meters m/s = meters per second NO x = nitrogen oxides OFA = ov erfire air SOFA = separated overfire air PM = particulate matter SO 2 = sulfur dioxideGeneral Chemical

– Green River Works

AP

- 10837 Application Analysis Page 21



### 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 1 2 : Relative Humidity Factors for CALPOST

Month Br

idger 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, n atural background conditions as a reference for determination of the modeled Δdv change s hould 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 fo r each Class I area on an annual basis, but does not provide the individual species concentration data required for input to CALPOST

.

S pecies concentrations corresponding to the 20 percent best days were calculated for each Class I area by scaling back th e 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 mult iplied by the g uidance table annual concentrations, the 20 percent best days deciview value s 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
gu idance 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 (b ext 

### /10) or b ext 

### = 10 exp (dv/10)

where: b ext 

### = light extinction expressed in inverse megameters (Mm - 1 

### ).General Chemical

– Green River Works

AP

- 10837 Application Analysis Page 22



### Using this relationship with the known deciview value of 1.96, one obtains a n 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 individu al components of the light extinction is as follows:

b ext 

### = (3)f(RH)[ammonium sulfate] + (3)f(RH)[ammonium nitrate] + (0.6)[coarse mass] + (4)[organic carbon] + (1)[soil] + (10)[elemental carbon] + b ray



### where:

 bracketed quantities represent background concentrations in μg/m 3



###  values in parenthesis represent scattering efficiencies

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

 b ray 

### is light extinction due to Rayleigh scattering (10 Mm - 1 

### used 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 1 3 presents the annual avera ge natural background concentrations, the calculated scaling factor, and the calculated background concentrations for the 20 percent best days for Bridger WA.

Table 1 3 : Calculated Background Components for Bridger WA

Component Annual Average for

West Region 

### (μg/m 3 

### ) Calculated Scaling

Factor 20% Best Days for

Bridger WA 

### (μg/m 3 

### ) 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 T able 14

.General Chemical

– Green River Works

AP

- 10837 Application Analysis Page 23



### Table 14: Natural Background Aerosol Concentrations (μg/m 3 

### )
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 table s below. For each scenario, the 2001 98 th 

### percentile Δdv results are reported along with the total number of days for which the pred icted impacts exceeded 0.5 dv.

Table 1 5 : CALPUFF Visibility Modeling Results

- Baseline Conditions 1



### Class I Area 2001 2002 2003

98th Percentile Value (Δdv) Total

No. of Days > 0.5 Δdv 98 th



### Percentile Value (Δdv) Total

No. of Days > 0.5 Δdv 98 th



### 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 areaGeneral Chemical

– Green River Works

AP

- 10837 Application Analysis Page 24



### Table 1 6 : 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 0.5 0 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 1 3 Fitzpatrick WA 0. 3 3 4 Control Scenario 3 : SCR Bridger WA 0.5 1 8 Fitzpatrick WA 0. 26 4

1 Visibility results are for both units modeled together LNB = low NO x burners OFA = overfire air SOFA = separated overfire air



### A comparison of the 2001 98 th 

### percentile Δdv modeling results for both units for baseline, existing LNB with new S OFA, 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 0.2 2 Δdv at Bridger WA and is 0. 19 Δdv at Fitzpatrick WA. The addition of S CR to both boilers would provide a modeled improvement of an additional 0. 11 Δdv at Brid ger WA and 0.05 Δdv at Fitzpatrick WA

. Figure 5 : CALPUFF Results for Baseline, Existing LNB with new S OFA, 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 WAGeneral Chemical

– Green River Works

AP

- 10837 Application Analysis Page 25



### 4.3.7 BART CONC LUSION FOR NO
x 

### 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 qual ity 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 NO
x 

### 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 NO
x 

### emission level of 0.28 lb/M MB tu, 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 t o 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,
t he Division will revise its unit

- specific NO
x 

### BAR T determination for Boilers C and D to the following:

Boiler C : Existing LNB with new S OFA or an equivalent performing technology and meeting NO
x



### emission limits of 0. 28 lb/MMBtu (30

- day rolling average), 1 49.5 lb/hr (30

- day rolling average) and 654.9 tpy as BART for NO
x 

### .

Boiler D : Existing LNB with new S OFA or an equivalent performing technology and meeting NO
x



### 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 NO
x 

### .

LNB with S OFA is determined to be BART for Boilers C and D for NO
x 

### based, in part, on the following conclusions:

1. Installing only LNB with existing OFA to achieve a NO
x 

### 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 NO
x 

### removed average cost effectiveness over a thirty year operational life. LNB with SOFA on Boiler D was cost effective with a capital cos t of $7,487,600 and a $1, 280 per ton of NO
x 

### 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., am monia or urea) and there is a minimal energy impact.General Chemical

– Green River Works

AP

- 10837 Application Analysis Page 26



### 4. Modeled 2001 c umulative 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 98 th 

### percentile values for both B oilers C and D were below 0.5 Δdv

.

5. Annual NO
x 

### 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 NO
x 

### based, in part, on the following conclusions:

1. The cost of compliance for installing SNCR on each boiler is higher than LNB with S OFA. Capital costs for SNCR on Boiler C is $7,541,800 and $8,391,400 f or 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 , a pplying SNCR to the boilers in place of using existing LNB with new SOFA further reduced NO
x 

### 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 NO
x 

### emissions from the boilers.

5. Ope ration 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 e x i sting 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 NO
x 

### EMISSIONS REDUCTIONS

BART baseline NO
x 

### emissions for both boiler s were taken from Operating Permit 3

- 1

- 123, which limits NO
x 

### 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 NO
x 

### emissions by imposing limits of 0.53 and 0.55 lb/MMBtu on Boilers C and D, respectively. Proposed NO
x 

### reductions from BART baseline emissions are show in Table 1 7 below.General Chemical

– Green River Works

AP

- 10837 Application Analysis Page 27



### Table 1 7 : Interim NO
x 

### Emissions Reductions

Baseline NO
x 

### Emissions 1 ,3 

### Proposed NO
x 

### Emissions 2 ,3 

### NO
x 

### 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 NO
x 

### 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, Sect ion 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 NO
x 

### emissions but may result in collateral emission s 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 SOUR CE 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 NO
x 

### 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 AVAI LABLE 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 receive d on or before July 19, 2010 . Comments should be directed to the established docket, docket ID: EPA

- HQ

- OAR

- 2002

- 0058

. O n 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. G

eneral 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

AP

- 10837 Application Analysis Page 28



### T he 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 r equirements of Chapter 6, Section 3 of the Wyoming Air Quality Standards and Regulations (WAQSR) . Operating Permit 3

- 1

- 12 3 was issued for the facility on June 10 , 200 8

. General Chemical will need to modify their operating permit to include the changes au tho rized in this permitting action i n 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 perfor ming technology, and associated emission limits.

1 1

. 0 PROPOSED PERMIT CONDITIONS

The Division proposes to issue a n 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 actua l 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 sp ecific 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 WA QSR.

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 D istrict 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 Pe rmit MD

- 6046 that apply to NO
x 

### performance tests for Boilers C and D

. NO
x 

### p erformance 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 perfor ming technology, but not later th a n ninety ( 90 ) days following initial start

- up in accordance with Cha p ter 6, Section 2(j) of the WAQSR. If maximum design production rate is not achieved within ninety ( 90 ) d a ys of start

- up, the Administrator may require testing at the rate achieved and again with maximum rate is achieved. For each test, a written repo r t 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, thi s condition shall supersede all portions of Condition 8 in Air Quality Permit MD

- 6046 that apply to NO
x 

### 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 t his permit , NO
x 

### emissions shall not exceed the levels below. The NO
x 

### 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, NO
x 

### emissions from Boilers C and D shall not exceed the levels below. The NO
x 

### 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

NO
x 

### p erformance 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 NO
x 

### performance tests for Boilers C and D

. NO
x 

### p erformance tests, required by Condition 6 of this permit, shall consist of the following:

NO
x 

### Emissions

– Compliance with the NO
x 

### 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 th e Chapter 6, Section 3, Operating Permit may be submitted to satisfy testing required by this condition.

1 0

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

- 6046 that apply to NO
x 

### 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 NO
x 

### emissions which exceeds the lb/MMBtu limit calculated in accordance with 40 CFR Par t 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 NO
x 

### 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 NO
x 

### emissions calculated using valid dat a (output concentration and average hourly volumetric flowrate) from the required CEM equipment which exceeds the tpy limits established for NO
x 

### in Condition s 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 autho rized 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



### 1 1

. 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.

1 2

. Effecti

ve 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 B oiler s C and D

, and conduct the initia l performance test s 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 s hall be reported to the Administrator within thirty (30) days of commencement.

1 3

. 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

# ¬ « 5 3 0 

# ¬ « 3 7 2



# §  ̈ ¦ I 8 0

3 2 5 8

5 5

4 1 4 5 4

4

9 2

7 5 3

3 5

5

8 2 3 2

9 9 4 3

4 2

8 4 4

3

9 8

9

8 5 5

8 1

7 3 2

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

4 5 2 1

3 1 2 5 4 5 6 3 6 4 1 2

2

6 2

1 8

3 1 9

2 3

1 6 1 3 3 4 2 0

2 1 1 4 1 7

2 3 1 1 2 9

3 4 1 0

2 8 2 8

3 3

1 7

2 6 2 1

2 8 1 1

1 7 2 1 1 6

2 2

1 1 1 0

2 2 2 1

2 2 2 7

2 4 1 3 1 5

1 3 2 8

1 7 3 6 1 4 1 5

2 1

2 9 3 2

2 3 2 5

2 4 1 0

2 2

2 4

2 9 3 3 2 9

3 4

2 0 1 2

1 0

2 9 2 2

1 6 3 5

1 5 3 2

1 1 2 5 2 9 1 7

2 8

1 0 3 3

1 4 3 2

2 0 3 5 1 4 2 9 2 8

2 6 3 2

1 7

3 0 2 3 3 3

2 6 2 7

2 8 2 5 3 2 3 4

2 3 1 6 2 7

2 7 2 7 1 0

3 4 3 5

1 5

1 7

1 1 1 5 1 7 2 2

2 0

3 2 2 9 1 5

2 0 1 7

2 9 2 1 3 4

2 0 2 9

2 6

2 1

2 2 2 7 3 2

1 6

2 2 2 2

2 7 3 2

2 1 1 8 2 1

2 9

2 1 3 0

3 4 2 2 3 6

2 9

2 7 1 1 2 8

3 5 2 0 2 7

3 5

3 4 1 1

1 4

3 1 1 9 2 8

1 7 3 4

1 9 3 1

1 0 3 5

2 8 1 6

2 8 2 0

2 8 2 0

1 4 2 6

1 5 3 3

2 9 1 8

3 0 2 8

1 5 3 5

1 2 2 1

2 7 1 0

1 5

3 0 1 2 1 1

1 6

2 7 2 6 3 1 1 7

1 8

1 2 1 8

2 9

2 3 1 6 3 3 3 0 2 6

3 0 2 3 1 0

1 6 2 9

3 6

2 8 1 4

2 4

2 2

2 6 3 6 1 5 2 5

6 2 0

2 0 3 3

1 6 2 6

3 3 3 3

2 4 1 4 2 3 3 4

3 5 3 2

3 3

1 2 3 2 3 3

1 0

2 8 1 5 1 9

1 6 3 4

1 6 1 9

1 3 3 0

3 4 3 2 2 1 3 1

3 3 1 3 2 6

2 5 1 8 3 1

1 7 2 7 3 0 2 7

2 7 3 0

3 1

1 8 3 2

2 5 7

3 1

3 0 1 9 1 0 6

2 0 1 9 3 1

1 9 1 9 1 8 1 8

3 0 7 6

7 1 2 3 6

1 0 1 3 1 2

2 4

2 5

2 2 2 4 3 6

2 5

1 5 3 6

2 7 1 2 3 6

2 4

1 3 2 5 1 3 2 5

3 5 2 6

1 4

2 3 3 5

2 3 1 1

1 1

3 5 2 6 2 6

1 4 3 5

1 1

1 4

2 3

2 6

1 3 0

3 0 1 9 1 8

3 1

3 1 3 1

3 1 1 8

1 8 3 0 1 9

3 0 1 9

1 3

2 5 2 4 1 2 2 2 2 4 2 1 2 0 2 3 2 0 2 1 2 2 1 9 1 9 2 0 2 1 2 3 2 2 2 3 2 4 1 9

3 3 3 1 3 2 3 1 3 6 3 5 3 6 3 4 3 5 3 4 3 2 3 4 3 1 3 2 3 3 3 3 3 6 R 1 0 9 W R 1 0 7 W R 1 0 8 W

R 1 1 0 W R 1 0 9 W R 1 0 8 R 1 0 7 W T 2 0 N T 2 0 N

T 1 9 N T 1 9 N

T 1 8 N T 1 8 N

T 1 7 N T 1 7 N

T 1 6 N T 1 6 N



### G e n e r a l C h e m i c a l S o d a A s h P a r t n e r s G e n e r a l C h e m i c a l G r e e n R i v e r W o r k s S e c t i o n s 4

- 6
, T 1 8 N a n d S e c t i o n s 2 9

- 3 3
, T 1 9 N
, R 1 0 9 W S w e e t w a t e r C o u n t y , W y o m i n g 

# ®

0 2

. 5 5 1

. 2 5 M i l e s G e n e r a l C h e m i c a l

G r

e

e n R i v

e r