### IN THE MATTER OFA PERMIT APPLICATION (AP-6046) FROM GENERAL CHEMICAL SODA ASH PARTNERS FORA BEST AVAILABLE RETROFIT TECHNOLOGY (BART) PERMIT FORTHE GREEN RIVERWORKS
DECISION


### I. Introduction:
The Air Quality Division received a BART permit application from General Chemical Soda Ash Partners (General Chemical) for the two coal-fired boilers that operate at their Green River Works in Sweetwater County, Wyoming. Regulations governing the BART program have been established by the U.S. EPA in 40 CFR Part 51

- Appendix Y. As stated in the regulations, a source is eligible for BART ifit belongs within a particular group of stationary source categories, was not in operation prior to August 7, 1962, was in existence on August 7, 1977, and has the potential to emit 250 tons per year (tpy) or more ofany visibility impairing air pollutant. Fossil fuel boilers with more than 250 million Btu (MMBtu) per hour heat input are listed as an eligible source type. Boiler C, with a heat input of 534 million MMBtu, was installed at the Green River Works in 1973. Boiler D, with a heat input of880 MMBtu, was installed in 1975. Potential emissions from both boilers for two visibility impairing air pollutants, nitrogen oxides (NOx) and sulfur dioxide (S02), exceed 250 tpy andtherefore the units are eligible for BART.
The Division conducted an analysis ofthe BART permit application and on August 12, 2008, published in the Rock Springs Daily Rocket-Miner a public notice and notice ofpublic hearing ofthe proposed intentto issue BART determinations. Copies ofthe BART applications and the Division's analysis were placed in the Sweetwater County Clerk's office in Green River, Wyoming, in accordance with regulations. A 30-day public notice period ran from August 12, 2008, to September 11, 2008, and a public hearing was held on Thursday, September 11,2008, at 6 p.m. in Room 1302 at Western Wyoming Community College, located at 2500 College Drive in Rock Springs, Wyoming.
To allow adequate opportunity for comment as specified under the Regional Haze Rule 40 CFR 51.308(i)(2), the public commentperiod was extendedto October 20, 2008.
The Division received five (5) comment letters on the proposed permit during the public commentperiod: 1) a September 4,2008 letter from General Chemical; 2) a September 10,2008 letter from the Wyoming Outdoor Council; 3) a September 15,2008 letter co-signed by the U.S. Fish and Wildlife Service (FWS) and the National Park Service (NPS); 4) an October 17, 2008 letterwith supplemental comments from the Wyoming Outdoor Council; and 5) an October 17, 2008 letter from EPA Region 8. The Division received one (1) comment letter on the proposed permit after the public comment period on November 7, 2008 from the USDA Forest Service. The USDA Forest Service comments were received after the close ofthe 69-day public notice period that ran from August 12,2008 through October 20,2008. As such, the Division cannot consider or respond to the comments in the final BART determination on this application. The comments and the Division's responses are presented on the following pages.General Chemical SodaAshPartners Decision Document, BART PermitApplication, AP-6046 Page 2 of 15 

### ll. Analysis ofComments from General Chemical:
ILl Existing Overfire Air Can Achieve NOLLimits

- General Chemical commented that the**-----~installation-of_low-NGxbumers-EbNB)-and-the-operation-ofexisting-overfire-air-(GFA)-equipmentc------­** can achieve the proposed BART limit for NOx (0.49 lb/MMBtu). General Chemical states that the installation ofseparated overfire air (SOFA) would not clearly improve the operation ofeither boiler, and they request that the permit language be changed to read that a design "equivalent" to SOFA is available as an option. Response

- Afterthe close ofthe public commentperiod for General Chemical's BART application, the Division requestedthatthe company address NOx emission levels below the proposed emission rate of0.49Ib/MMBtu. On December 15,2008, General Chemical submitted a response to the Division's request. General Chemical analyzed emission levels of0.32 Ib/MMBtu fromthe application ofnew LNB with existing OFA and 0.28Ib/MMBtu from the application ofnew LNB with separated OFA. Updated cost information for the installation of eachtechnology and revised CALPUFF visibility modeling were also provided. The Division revised the August 4, 2008 BART analysis to specifically address the lowerNOx emission rates analyzed by General Chemical, andthe revised analysis is included as Appendix A to this document.
Based on the additional information provided by General Chemical on the capabilities ofLNB and the operation ofexisting OFA equipment, the Division will setthe BART emission limit for NOxfor both boilers at the facility to 0.32Ib/MMBtu (30-day rolling). The installation ofLNB and the use ofthe existing overfrre air systems will be required to achieve and maintain this emission level. The Division agrees that separated overfire air (SOFA) is not warranted as BART due to the minimal improvement in visibility that was modeled for LNB/OFA vs. LNB/SOFA. A comparison ofthe 3-year average 98th percentile modeling results shows that modeled visibility improvement with the option ofnew LNB with existing OFA, as compared to baseline, is 0.27**~dv** at BridgerWA. The addition ofSOFA would only provide a modeled improvement ofan additional 0.03**~dv** at BridgerWA.
The Division will require that General Chemical install low NOx burners to accompany the existing overfrre air on boilers C and D no later than December 31, 2011 for Boiler C and December 31, 2012 for Boiler D.
IL2 Responsible Official

- General Chemical requested that the responsible official be changed to Randy T. Pitts, PlantManager. Response

- The Division has changed the responsible official.
ID. Analysis ofComments from the Wyoming Outdoor Council:
IlL1 SCR Should Be Required as BART in Addition to LNB

- The Wyoming Outdoor Council commented that selective catalytic reduction (SCR) should be required as BART for the coalfired boilers to increase visibility improvement and because the Division did not impose specific emission limits for particulate matter (PM) and S02. Response

- The Division's BART limits for NOx emissions from the coal-fired boilers were based on several factors, including the modeled impact on visibility. The individual 98thGeneral Chemical SodaAshPartners Decision Document, BART PermitApplication, AP-6046 

### Page 3 of 15 percentile modeling result for each boiler with the proposed BART controls was less than a 0.5 delta deciview**(~dv)** 

### increase from background conditions for all three years ofmeteorology. Therefore, the proposed BART controls for both coal-fired boilers reduce visibility impacts**---~below-the-O~5-~dv-threshold-that-is-used-in-sereening-analyses-to-determine-if-sourees-eontribute~·~- ~~~**  

### to visibility impairment.
Control Option A (LNB and existing OFA) was chosen as BART rather than Control Option 3 (SCR) not only because ofthe added costs associated with Option 3, but also because LNB/OFA does not require non-air quality environmental mitigation for the use ofchemical reagents and because ofthe low level ofmodeled visibility improvement for Option 3. Option 3 provided a predicted improvement in visibility at Bridger WA ofonly 0.04 dv, as compared to LNB/OFA based onthe modeled 98th 

### percentile results.
BART limits for S02 will not be set because Wyoming is a §309 state participating in the Regional S02 Milestone and Backstop Trading Program. §308(e)(2) provides States with the option to implement or require participation in an emissions trading program or other alternative measure rather than to require sources subject to BART to install, operate, and maintain additional control technology to meet an established emission limit on a continuous basis. However, the alternate program must achieve greater reasonable progress than would be accomplished by installing BART. A demonstration that the alternate program can achieve greater reasonable progress is prescribed by §308(e)(2)(i). Since the pollutant ofconcern is S02, this demonstration has been performed under §309 as part of the state implementation plan. §309(d)(4)(i) requires that the S02 milestones established under the plan "

.. :must be shown to provide for greaterreasonable progress than would be achieved by application ofBART pursuant to §51.308(e)(2)."
Emissions ofPM will continue to be controlled with the existing electrostatic precipitators (ESPs) on each boiler, and PM emission limits will be set in the BART permit at a level of 0.09 Ib/MMBtu for eachboiler.
III.2 Impacts Analysis in the Proposed Permit is too Limited

- The Wyoming Outdoor Council commented that the Division's analysis ofthe BART options for the Green River Works did not fully consider all factors for a BART analysis, and that cost was the only driver in the BART determination for NOx• 

### Response

- The Division's BART determination for the Green River Works was not driven by a single factor. After considering: (1) the costs ofcompliance, (2) the energy and non-air quality environmental impacts ofcompliance, (3) any pollution equipment in use or in existence at the source, (4) the remaining useful life ofthe source, and (5) the degree ofimprovement in visibility (all five statutory factors) from each proposed control technology, the Division determinedBART for the Green River Works. The Division revised the August 4, 2008 BART analysis to address lower NOx 

### emission rates that were analyzed by General Chemical at the request ofthe Division (See response to General Chemical comment II. 1 and AppendixA).
Control Option A (LNB/existing OFA) was chosen as BART rather than Control Option 2 (selective non-catalytic reduction [SNCRJ) or Control Option 3 (SCR) not only because ofthe added costs associated with Options 2 and 3, but also because LNB/OFA does notrequire non-air quality environmental mitigation for the use ofchemical reagents and because ofthe low level of modeled visibility improvement for Options 2 or 3.General Chemical SodaAsh Partners Decision Document, BART PermitApplication, AP-6046 

### Page 4 of15 Based on the initial modeling submitted by the applicant and reviewed by the Division, Option 2 (SNCR) provided a predicted improvement in visibility at Bridger WA ofonly 0.08 dv for both units combined compared to the modeled impact for the scenario that was modeled as Option 1**~~~tbNB/-S8FA)~ -8ption-3-E-SGR)-provided-a-predieted-improvement-in-visibility-at-Bridger-WA-of~~~~~**  

### only 0.19 dv for both units combined as compared to LNB/SOFA. 

### The NOx 

### emission rate for LNB/SOF 

### A for that initial modeling was 0.49 lblMMBtu. After reviewing the comments received on the proposed BART limits for the Green River Works, the Division requested that General Chemical evaluate additional state-of-the-art control levels achievable through the application oflow NOx 

### burners with the existing OFA. 

### In a report submitted to the Division in December of2008, General Chemical stated that engineering reviews ofthe proposed LNB/OF 

### A system showed that NOx 

### emissions could be reduced to 0.32 lblMMBtu. This lower emission limit will be set as the BART limit for each ofthe two coal-fired boilers, as reflected in the [mal section ofthis document.
III.3 Receptors Are Not Adequately Identified

- The Wyoming Outdoor COlillcil commented that the Division's analysis did not adequately identify the receptors thatwere used to model visibility impacts at Class I areas. Response

- Latitude and longitude coordinates for Class I area receptors were taken from the NPS 

### Class I Receptors database and converted to the appropriate Lambert Conformal Conic coordinates for input to the CALPUFF model. The Class I receptors contained in the NPS database are recommended by the Federal Land Managers (FLM) for use in long-range transport (e.g., CALPUFF) modeling of Class I areas. Receptor spacing for the modeled areas is approximately 1.3 km 

### in the east-west direction and approximately 1.8 km 

### in the north-south direction. The receptor configurations that were used for Bridger Wilderness Area (W A) and FitzpatrickWA are shown inthe figures below.

.General Chemical SodaAshPartners Decision Document, BART PermitApplication, AP-6046 

### Page 5 of15 Figure 1 tors for Brid er W A

BridgerWilderness 684 Receptors USFS Boundary Source:

FS Nalional Coverage file: NRIS

-AlP group COlVallis,OR August 27.2003

Source: http://www.nature.nps.gov/air/Maps/Receptors**I~-----------~----**General Chemical SodaAsh Partners DecisionDocument, BART PermitApplication, AP-6046 Page 6 of 15 Figure 2 Receptors for FitzpatrickWA



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## • • •**~~_. ~---~-~~-**  FlzpalrickWiderness 316 Receptors USFS Boundary Source:

FS National Coverage file: NRIS· ALP group Corvallis. OR .August 27. 2003

Source: http://www.nature.nps.gov/air/Maps/Receptors/index.cfmGeneral Chemical SodaAsh Partners Decision Document, BART PermitApplication, AP-6046 Page 7 of 15
lIlA Impacts Less Than 0.5 dv Should Not Be Deemed A Per Se Does Not Contribute SituationThe Wyoming Outdoor Council commented that a modeled level of0.5 dv should not be used as a threshold below which visibility impacts are deemed to be insignificant. Response

- The Division is comfortable using 0.5 dv as the threshold level to exempt a source from BART or to deem modeled impacts as insignificant. EPA's 

### RegionalHaze Regulations and Guidelinesfor BestAvailable Retrofit Technology (BART) Determinations (Appendix Y to 40 CFR part 51), suggest that 0.5 dv can represent the level at which a source "contributes" to visibility impairment. This is also consistent with the rules which are being applied by most states in the WRAP region. Further, the Division believes that the 0.5 deciview threshold is a conservative value given that language in the Regional Haze Rule suggests that 1.0 dv is an appropriate perceptibility threshold and recent literature suggests that the perceptibility threshold is greaterthan 1.0 dv (from page 39120 ofAppendix Y to 40 CFRpart 51).
IlLS Scaling Factors Used for Background Aerosol Concentrations Should be Explained And Justified The Wyoming Outdoor Council commented that the process of determining background aerosol concentrations for the 20% best visibility days was not explained in adequate detail. Response

- Individual species concentrations corresponding to the 20% best days natural background were calculated for each Class I area by scaling back the annual average natural background concentrations given in Table 2-1 ofthe EPA**doCiiment~Guidance** 

### for Estimating Natural Visibility Conditions Under the Regional Haze Rule. The EPA guidance document provides annual average values ofnatural background for individual species, and total deciview values for the 20% best days for particular areas, but does not provide values for individual species for the 20% best days. Therefore, the Division developed separate scaling factors for each Class I area such that, when multiplied by the guidance table annual concentrations for each species, the 20% best days concentrations for each species for thatparticular Class I area could be calculated.
The scaling procedure is illustrated here for Bridger WA. From Appendix B in the EPA natural visibility guidance document, the total deCiview value for the 20% best days at Bridger WA is 1.96 dv. To obtain the speciated background concentrations representative ofthe 20% best days, the deciview value (1.96 dv) was first converted to light extinction. The relationship between deciviews and lightextinction is expressed as follows:
dv 

### = lOin (bex!10) orbext

### = 10 exp (dv/1 0) where: bext

### =light extinction expressed in inverse megameters (Mm-1). 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 atotal extinction value of 12.17 

### Mm-1. The relationship between total light extinction and the individual components ofthe light extinction is as follows:General Chemical SodaAsh Partners Decision Document, BART PermitApplication, AP-6046 Page 80f15
bexl 

### = (3)f(RH)[ammonium sulfate] 

### + (3)f(RH)[ammonium nitrate] 

### + (0.6)[coarse mass] 

### + (4)[organic carbon] 

### +(1)[soil] 

### + (1 0)[elemental carbon] 

### +bray

------ ---where:

• bracketed quantities representbackground concentrations in J.lg/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- I used for all Class I areas) Substituting the total light extinction for the 20% best days, 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 convertthe annual average natural background concentrations to values representative of the 20% best days natural background. Solving for X provides a value of0.376. Table 1 presents the annual average natural background concentrations, the calculated scaling factor, and the calculated background concentrations for the 20% best days natural background for BridgerWA.


### WA B"d dC 

### T hI 1 C I ltd 

### B k

a e : 

### a cu a e ac .!!roun omnonents or rI 

### l!!er Annual Average 20% BestDays Natural Natural Background for Calculated Background for the WestRegion Scaling BridgerWA Comnonent (11!!/m3) 

### Factor (l1IDm3) 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
Because ofthe geographical proximity and similar annual background visibility for the Bridger WA and Fitzpatrick WA, the scaled aerosol concentrations for the two areas were averaged. The 20% best days natural background aerosol concentrations that were used for the two Class I areas in question for this analysis are listed in Table 2 below.General Chemical SodaAsh Partners Decision Document, BART PermitApplication, AP-6046 Page 9 of 15
I C centrations (J.1g1m3) dA N t IB k ays aura ac (l!roun eroso on Fitzpatrick Aerosol WA& Component BrideerWA Ammonium Sulfate 0.045 Ammonium Nitrate 0.038 Organic Carbon 0.178 Elemental Carbon 0.008 Soil 0.189 Coarse Mass 1.136 Table 2: 20% BestD

III.6 Combined Impacts from Three Trona Plants in Southwestern Wyoming

- The Wyoming Outdoor Council commented that the modeled impacts from three trona plants in southwestern Wyoming should be considered in combination rather than individually. Modeled results for individual facilities were summed in a table in their October 17,2008 letter. Response

- Summing the 98th percentile modeled visibility impacts for separate facilities is not an accurate portrayal ofcombined impacts because the individual impacts may occur at different locations (receptors) and during different 24-hour time periods. Moreover, the visibility impacts from BART-eligible sources are to be determined separately. As stated in the EPA's Appendix Y to part 40 CFR 51

- 

### Guidelinesfor BARTDeterminations Under the RegionalHaze Rule, relative to the use ofthe CALPUFF model for BART determinations, 

### "We believe that CALPUFF is an appropriate applicationfor States to usefor theparticularpurposes of this rule, to determine 

## if
an individual source is reasonably anticipated to cause or contribute to impairment of visibility in Class I areas, and topredict the degree of visibility improvement which could reasonably be anticipated to resultfrom the use ofretrofit technology at an individual source. We encourage States to use it for thesepurposes. "
IV. Analysis ofComments from the FWS (and NPS):
IV.1 New Stackfor SNCR

- The FWS commented that General Chemical's cost estimate for SNCR includedthe cost for anew stack, and the FWS questioned the need for a new stack.

. Response

- As described in General Chemical's BART application, space for emissions control equipment is limited at the Green River Works. Flue gas exiting the boiler house passes through ESPs for each boiler and then is routed to the stacks. There is very limited vertical distance between the existing air heater and the intake to each electrostatic precipitator (ESP), prohibiting the construction of ductwork/equipment between the air heater and the ESP. fustallation of SNCRwould therefore require the construction ofnew stacks.
IV.2 SOl-Scrubber Costs

- The FWS commented that General Chemical inflated scrubber costs by underestimating the effectiveness ofthe S02 scrubbing options and by overestimating operating costs. Response

- Wyoming is a §309 state participating in the Regional S02 Milestone and Backstop Trading Program, and therefore visibility impacts from S02 emissions 

### will be reduced through an emissions trading program rather than through requirements that BART sources install, operate,General Chemical SodaAsh Partners Decision Document, BART PermitApplication, AP-6046 Page 10 of 15
and maintain additional control technology. The scrubber control effectiveness that was evaluated by the applicant was reasonable because it was based on an assumption ofcontinuous compliance when the control equipment is well maintained and operated in a manner consistent**~-- ~~~-~~---with~good~airpoHution~control~practices~for**  -minimizing-emissions-.**-In~order~to demonstrate~--** **~-- ~~**  continuous compliance with a 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 wet scrubbers, generally has inherent variability that must be considered. The Division is satisfied that the costs for S02 controls presented in the BART application are adequate for the purposes ofthis analysis.


### N.3 Combined Control Costs and Dollar per Deciview Metric

- The FWS commented that General Chemical combined the costs associated with controls for multiple pollutants when drawing cost effectiveness determinations. The FWS offered some conclusions on the costeffectiveness ofNOx and S02controls based on dollars per deciview ($/dv). Response

- The Division's cost effectiveness determinations were based on the costs associated with the control of each visibility-reducing pollutant separately. Cost effectiveness was not determined by the Division using a hybrid metric such as dollars per deciview. 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 ofthe economic costs to control emissions. The $/dv metric can illustrate the control cost and visibility improvement differences between control options, but it is not commonly used to assess the overall effectiveness of pollution control equipment. When performing the presumptive BART limits analyses for NOx and S02, EPA addressed cost effectiveness and incremental cost effectiveness separately from visibility improvement. EPA did not use the $/dv metric to compare control options. Visibility improvements from the application ofthe analyzed control measures used to establish presumptive levels were addressed in a separate visibility analysis.
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 emission control.


### NA Modeled Class I Areas

- The FWS commented that the Division modeled visibility impacts at the two closest Class I areas only (Bridger WA and Fitzpatrick WA). The FWS stated that the FLM typically ask for modeling at all Class I areas within 300 kilometers (km) ofa source. Response

- The distance for Class I area modeling is based largely on the size ofa given source and the source's potential to impact a given Class I area. While 300 km is generally recognized as the maximum effective distance for the CALPUFF model, this does not dictate that all CALPUFF analyses include each Class I area within 300 km. Only those Class I areas most likely to be impacted by the Green River facility sources were modeled, as determined 1JyGeneral Chemical SodaAsh Partners Decision Document, BART PermitApplication, AP-6046 

### Page 11 of 15 source/Class I area locations, distances to each Class I area, and professional judgment considering meteorological and terrain factors. The Division recognizes that more distant Class I areas may yield modeled impacts ofsome magnitude, but the Division is also satisfied that Class**~--~----- I-areas-at-a-greater-distance-and-in-directions-of-Iess-frequent-plume-transport-would-not--yield--~---­**  

### modeled impacts greater than those yielded by the two Class I areas chosen for BART modeling. The modeling results for the two chosen Class I areas allowed the Division to make an informed decision on the effect on visibility from the various control options.
IV.5 Control Strategies Should Not be Dismissed Because ofPerceptibility

- The FWS commented that athreshold ofperceptibility should notbe used to interpretvisibility modeling orto exclude a given control strategy from consideration as BART. The FWS stated that the Division's misinterpretation ofthe 0.5 dv threshold led to the Division proposing only combustion controls ratherthan SNCR. Response

- The Division does recognize that the chosen control option for BART (LNB/overfrreair) brought the modeled impacts for each boiler to less than the 0.5 dv threshold at which a source is consideredto "contribute" to visibility impairment, but incremental differences between control options were also considered (see response to Wyoming Outdoor Council comment III.2)
IV.6 S02 Controls

- The FWS commented that the Bridger WA is not one ofthe Class I areas under the Western Backstop Trading Program, and therefore "S02 controls of Section 309 sources should be evaluated and documented as to the effects on the Section 308 areas." Response

- Wyoming, along with other 309 States in the WRAP region, evaluated the impact of the 309 program on all Class I areas in the west, even though the requirement by rule was to demonstrate improvement in Class I areas on the Colorado Plateau. The following table summarizes WRAP modeling for sulfates, and shows that all Class I areas in and around Wyoming sources are benefiting from the sulfur dioxide emission reductions instituted in the 309 program. Sulfate extinction levels show improvement on the 20% worst days and improvement or at least no degradation on the 20% best days. Furthermore, the Regional Haze rule allows the state to take full credit for strategies implemented under 309 when addressing Class IAreas away from the Colorado Plateau (51.309(g)(4)(i».General Chemical SodaAsh Partners Decision Document, BARTPermit Application, AP-6046 Page 12 of15
T bl 3 WRAP M d 

## r f, S If E·

Represents 2018 Base Case WIthout S02 control strategIes 2Represents 2018 Preliminary Reasonable Progress with Regional S02 Strategies 

### a e : o e m2 or u ate xtmctlOn Visibility
- Sulfate Extinction Onh (Mm-1) 20% Worst Visibility Days 20% BestVisibility Days (Monthly Avera2e)

. (Monthly Avera2e)

20181 20182 20182 Base Preliminary Preliminary Case Reasonable 20181 Reasonable (Base Progress Case Base Case Progress Case Class 

### I Area 18b) (PRP18) (Base 18b) (PRP18) Bridger, WY 5.2 4.3 1.6 1.3 (BridgerW. and FitzpatrickW.) North Absaroka, WY (NorthAbsaroka W. and 4.8 4.5 1.1 1.1 Washakie W.) Yellowstone, WY (Yellowstone NP, GrandTeton 4.3 3.9 1.6 1.4 NP, and Teton W.) Badlands, SD 17.8 16.0 3.5 3.1 Wind Cave, SD 13.0 12.1 2.7 2.5 Mount Zirkel, CO 4.6 4.1 1.4 1.3 (Mt. Zirkel W. andRawahW.) Rocky Mountain, CO 6.8 6.2 1.3 1.1 Gates ofthe Mountains, MT 5.3 5.1 1.0 1.0 ULBend,MT 9.7 9.6 1.8 1.7 Craters ofthe Moon, ill 5.8 5.5 1.5 1.5 Sawtooth, ill 3.0 2.8 1.2 1.1 Canyonlands, UT (Canyonlands NP andArches 5.4 4.8 2.1 1.9 NP) Capitol Reef, UT 5.7 5.4 1.9 1.8 IGeneral Chemical SodaAsh Partners Decision Document, BART PermitApplication, AP-6046 Page 13 of 15 

### N.? SNCR as BART in Addition to LNB/overfire air

- The FWS commented that SNCR and Dry FGD shouldbe considered as BART because costs are reasonable.

--**-----~----~Response~See-responseto-WyomingOutdoor·-Council-comments-IU:-l-and-ill-;-2.** V. Analysis ofComments from EPA Region 

### 8:
V.1 NO!..BART Control Option Selection

- EPA Region 8 objected to the Division's use ofthe 0.5 dv threshold to deem a given control strategy as acceptable, and commented that regional haze impacts shouldbe considered cumulatively and not per individual source. Response

- See response to Wyoming Outdoor Council comments lIlA and 1II.6.
V.2 SOLControl

- EPA Region 8 commented that the Division's Regional Haze SIP under the Western Backstop SulfurDioxide Trading Program must demonstrate greater reasonable progress than**source~specific** BART at all Class I areas, including Bridger WA and Fitzpatrick WA. Suggestions for S02control atthe Green River Works in the event reasonable progress cannot be demonstrated were provided. Response

- See response to FWS Comment

### N.6.
V.3 PM Analysis

- EPA Region 8 commented that costs and impacts associated with PM controls should be evaluated separately. Response

- The Division is satisfied that the existing PM controls (ESPs) at the Green River Works representBART, and PM emission limits will be set in the BART permit at a level of0.09 IblMMBtu for each boiler. It is the experience ofthe Division that a potential upgrade from ESPs would not be cost effective, and that modeled visibility impacts would not be affected to a significant degree by reductions in PM emissions thatwouldresultfrom an upgrade from ESPs.General Chemical SodaAsh Partners Decision Document, BART PermitApplication, AP-6046 

### Page 14 of15
VI. Decision:
On the basis ofcomments received during the public commentperiod, an analysis ofthose comments, and

._.
__**.~** 

### Tepresentations-madeby6eneral-8hemical;-theBepartment-of-Environmental**~uality-has-determined-that-~---** 

### ._- the permit application filed by General Chemical complies with all applicable Wyoming Air Quality Standards and Regulations and that a BART permit will be issued for the General Chemical Green River Works. All ofthe conditions proposed in the Division's analysis will be included in the permit with the following changes and additions (in bold):
6. Each time low NOx 

### burners with seflamted overfire air is installed, the owner or operator shall furnish the Administratorwritten notification of: (i) the anticipated date ofinitial startup notmore than 60 days or less than 30 days prior to such date, and; (ii) the actual date ofinitial start-up within 15 days after such date in accordance with Chapter 6, Section 2(i) ofthe WAQSR.
7. [replace previous] PMlPMlO

### performance tests shall be conducted on boilers C and D no later than 90 days after permit issuance. NOx 

### performance tests shall be conducted on boilers C and D within 30 

### days ofachieving maximum design rate after installation ofthe low NOx 

### burners to accompany existing overfire air, but not later than 90 days following initial startup in accordance with Chapter 6, Section 2(j) of the WAQSR. If 

### maximum design production rate is not achieved within 90 days ofstart-up, the Administrator may require testing at the rate achieved and again when maximum rate is achieved. For each test, a written report ofthe results shall be submitted and the operator shall provide 15 

### days prior notice ofthe test date.
8. 

### [replace previous] Effective upon startup ofthe unit with low NOx 

### burners with overfire air and completion ofthe initial performance tests required by Condition 7 ofthis permit, NOx 

### emissions shall not exceed the levels below. The PMlPMlO 

### levels shall apply upon permit issuance. The NOx 

### and PMlPMlO

### limits shall apply during all operating periods.
Boiler C:

Filterable portIOn only 

### Pollutant IblMMBtu lb/hr tpy NOx 0.32 (30-day rolling) 170.9 (30-day rolling) 748.5 

### PMlPM1O(1) 0.09 50 219.0 (I) • 

### BoilerD:

Filterable portIOn only 

### Pollutant IblMMBtu lb/hr tpy NOx 0.32 (30-day rolling) 281.6 (30-day rolling) 1233.4 

### PMlPM1O(1) 0.09 80 350.4 (I) • 

### 9. Performance tests, required by Condition 7 ofthis permit, shall consist ofthe following:
Boilers C and D:
Emissions

- Compliance with the NOx 

### 30-day rolling average shall be determined using a continuous emissions monitoring system (CEMS) certified in accordance with 40General Chemical SodaAsh Partners Decision Document, BART PermitApplication, AP-6046 Page 15 of 15 CFRpart 60. Testing is required for boilers C and D after installation oflow NOx burners with separated overfire air.**-~~--~~. ~_·_--·--PMJPMfOEmissions-~-Testing-shall-follow-40-€FR-60046-and-EPA-Reference-'I'est~** **._~-** ._- Methods 1-4 and 5. Testing required by the Chapter 6, Section 3, Operating Permit may be submitted to satisfy the testing required by this condition.
10. Priorto any pel'formanee testing required by this permit, a testprotocol shall be submittedto the Division for approval, at least 30 days prior to testing. Notification should be provided to the Division at least 15 days prior to any testing. Results ofthe tests shall be submitted to this office within 45 days ofcompletingthe tests.
11. [replace previous] General Chemical shall comply with all requirements ofthe Regional S02 Milestone and Backstop Trading Program in accordance with Chapter 14, Sections 2 and 3, ofthe WAQSR.
12. [add to previous] Testing for PM shall be conducted annually, or more frequently as specified by the Administrator, following 40 CFR 60.46 and EPA Reference Test Methods 1-4 and 5. Testing required by the Chapter 6, Section 3, Operating Permit may be submitted to satisfy the testing required by this condition.
14. General Chemical shall install low NOx burners with separated overfire air on boilers C and D, in accordance with the Division's BART determination, and conductthe initial performance tests required in Condition 9 no later than December 31, 2011 for Boiler C and December 31, 2012 for BoilerD.

Datedthis 

### i h day ofAugust, 2009. 

# r//**v?~/;;V** JohnV. Corra Director Wyoming Department ofEnvironmental Quality

## APPENDIXA
Revised NOx

## BART Analysis**DEPARTMffiNTOFE~ONMENTALQUALITY** AIR QUALITY DIVISION
Revised NOx BART Analysis AP-6046 August 7, 2009

- --**--~-PURPOSE-OF~VISION-: ~_._-**  .
__.. ..- -- _.- ---
Afterthe close ofthe public commentperiod for General Chemical (SodaAsh) Partners' BART application, AP-6046, the company was requested by the Division to address NOx emission levels belowthe company-proposed emission rate of0.49 Ib/MMBtu from bothboilers. On December 15,2008, General Chemical submitted 

### aresponse to the Air Quality Division's request. General Chemical analyzed emission levels of0.32 Ib/MMBtu from the application ofnew low NOx burners (LNB) with existing overfire air (OFA) on the two boilers and 0.28 Ib/MMBtu from the application ofnew LNB with separated OFA (SOFA) on the same units. Updated cost information for the installation ofeach technology and revised CALPUFF visibility modeling were also provided. The Division is revising the August4,2008 BART analysis to specifically address lowerNOx emission rates analyzed by General Chemical.
DESCRIPTION OF BART ELIGffiLE SOURCES:
General Chemical Green River Works' two existing coal-fired boilers, Boilers C and D, are colocated atthe facility powerplantbuilding. Burning low-sulfur bituminous coal, they supply power and process steamto the mining and ore-processing operations. Both boilers are tangentially fired using in-line coal pulverizers. Boiler C was installed in 1973 and BoilerD was installed in 1975. Each boiler is currently equipped with a hot-side electrostatic precipitator (ESP) to control particulate emissions. Overfire air and low excess air are currently used to reduce NOx emissions from the boilers. S02 emissions are controlled withoutthe use ofadd-on controls by burning low-sulfur coal.
(a) f T bl 1 C I fi d B 'I C d D B 

## r 0

Same baseline operatIOns as presented In the DlVlslOn Songmal BART analySIS a e : oa
- Ire OJ ers an ase me 'pera Ions Operating Permit 3-1-123 Emission Limits Firing Rate Existing NOx S02 PMlPMlO Source (MMBtu/hour) Controls (lb/MMBtu) (lb/MMBtu) (lb/hr) Boiler C 534 Overfire air, dry 0.7 1.2 50.0 ESP (3-hourrolling) (2-hour fixed) Boiler D 880 Overfire air, dry 0.7 1.2 80.0 ESP (3-hour rolling) (2-hour fixed) (aJ 

### . . . , 

### ..
CHAPTER 6, SECTION 9 - BEST AVAILABLE RETROFIT TECHNOLOGY (BART)
A BART determination is an emission limitbased onthe application ofa continuous emission reduction technology for a visibility impairing pollutant emitted by a source. It is "

...established, on a case-by-case basis, taking into consideration the technology available, [1] the costs of compliance, [2] the energy and non-air quality environmental impacts ofcompliance, [3] any pollution equipmentin use or in existence atthe source, [4] the remaining useful life ofthe source, and [5] the degree ofimprovement in visibility which may reasonably be anticipatedtoGeneral Chemical Green RiverWorks AP-6046 Revised NOx BARTAnalysis Page 2
resultfrom the use ofsuch technology."! A BART analysis is a comprehensive evaluation of potential retrofittechnologies with respectto the five criteria above. Atthe conclusion ofthe BART analysis, atechnology and corresponding emission limit is chosen for each pollutantfor**-~~~-----each-unitsubject-t0-BAR-I'. ----~----**  ----- - Visibility control options presented in the application for each source were reviewed using the methodology prescribed in 40 CFR 51 Appendix Y, as required in WAQSR Chapter 6 Section 9(c)(i). This methodology is comprised offive basic steps: Step 1: Identify ale available retrofit control technologies Step 2: Eliminate technically infeasible options Step 3: Evaluate control effectiveness ofremaining control technologies Step 4: Evaluate impacts and documentthe results Step 5: Evaluate visibility impacts
The Division acknowledges that BART is intended to identify retrofittechnology for existing sources and is notthe same as atop down analysis required for new sources underthe Prevention ofSignificantDeterioration (PSD) rules known as BestAvailable Control Technology (BACT). Although BART is notthe same as BACT, it is possible that BART may be equivalentto BACT on a case-by-case basis.
In the original BART analysis for Boilers C and D at General Chemical's Green River Works, the Division applied all five steps to each ofthe three identified visibility impairing pollutants emitted from each coal-fired boilerthereby conducting a comprehensive BART analysis for NOx, S02 and PM/PMIO• Based on the additional information submitted by General Chemical, a revised comprehensive NOx BART analysis is provided.
NO!: IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES
General Chemical identified four control technologies to control NOx emissions: (1) LNB with existing OFA, (2) LNB with SOFA, (3) selective non-catalytic reduction (SNCR), and (4) selective catalytic reduction (SCR). LNB with existing OFA and LNB with SOFA are two combustion control technologies thatreduce NOx emissions by controlling the combustion process within the boiler. These two technologies effectively control NOx emissions by reducing the amount ofoxygen directly accessible to the fuel during combustion and by enhancing air-fuel mixing above the main combustion zone located nearthe burners. SNCR and SCR are add-on controls thatprovide a chemical conversion mechanism for NOx to form molecularnitrogen (N2) in the flue gas after combustion occurs. These four technologies are proven emissions controls commonly used on coal-fired boilers.

1 40 CFR Part51 Appendix Y: Guidelines for BART Detenninations underthe Regional Haze Rule (70 Federal Register 39163). 2 Footnote 12 of40 CFR 51 Appendix Y defines the intended use of'all' by stating "

...you must identify the most

stringent option and a reasonable set ofoptions for analysis thatreflects a comprehensive list ofavailable technologies."General Chemical Green River Works AP-6046 Revised NOx BART Analysis Page 3
1. Low NOx Burners with Existing Overfire Air

- LNB technologies rely on a combination offuel staging and combustion air control to suppress the formation ofthermal NOx' Fuel staging occurs in the very beginning ofcombustion, where the pulverized coal is**~--~~----~-~injected-through** the-burner-into-thefurnace.-CarefuLcontroLof-the-fuel

..air-mixture-

-**--~~- --~**  leaving the burner can limitthe amount ofoxygen available to the fuel during combustion creating a fuel-rich zone that reduces the nitrogen to molecularnitrogen (N2) ratherthan using oxygen in the combustion airto oxidize the nitrogen to NOx'
2. Low NOx Burners with Separated Overfire Air

- SOFA canbe used with LNB technology to further control the combustion process inside the boiler. The addition of separated overfire airprovides 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 ofthe fuel, orburnout, under more controlled conditions.
3. Selective Non-Catalytic Reduction

- SNCR is similarto SCRinthat it involves the injection ofareducing agent such as ammonia or urea into the flue gas stream. The reduction chemistry, however, takes place withoutthe aid ofa catalyst. SNCR systems rely on appropriate injection temperatures, proper mixing ofthe reagent and flue gas, and prolonged retention time in place ofthe catalyst. SNCR operates at highertemperatures 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 lowerNOx emissions reduction (up to fifty or sixty percent) and may emit ammonia out ofthe exhaust stackwhentoo much ammonia is added to the system.
4. Selective Catalytic Reduction

- SCR is a post combustion control technique in which vaporized ammonia orurea is injected into the flue gas upstream ofa catalyst. NOx entrained in the flue gas is reducedto molecularnitrogen (N2) and water. The use ofa catalyst facilitates the reaction at an exhausttemperature range of300 to 1,1OO°F, depending on the application and type ofcatalystused. When catalysttemperatures 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 ammoniathan a comparable SNCRcontrol system. In additionto applying these control technologies separately, they canbe combinedto increase overallNOx reduction. For example, the application ofSCR on power plantboilers often includes installing LNB with some form ofadvanced overfire airto reduce NOxemissions by 90% ormore. General Chemical addressed the application ofeach control technology separately. Proposed control efficiencies are based on feasible reductions reported in literature for each technology.


### NO!: ELIMINATE TECHNICALLY INFEASIBLE OPTIONS
General Chemical did not eliminate any ofthe four individual control technologies as technically infeasible. All four technologies are proven emissionreductiontechnologies with several examples ofeach in operation.General Chemical Green River Works AP-6046 Revised NOx BART Analysis Page 4


### NO!: EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES
The Division considers the controleffectiveness ofa proposed control technology to be

-- --- --equivalent-to-the BAR'I'-determined-permitlimit.--The-limit-is--based-on-continuous-compliance-

-- - - whenthe control equipment is well maintained and operated in a manner consistentwith good air pollution control practices for minimizing emissions. In orderto demonstrate continuous compliance with the permit limit it is importantto considerthat even well maintained and operated equipmentwill have some emissions variability. Complex emission control equipment, such as LNB with existing OFA, generally have inherentvariabilitythat mustbe considered when establishingthe limit. Otherwise, the source will be out ofcompliance even though the equipment is operated and maintained as well as possible.
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 ofthe control, any ancillary equipment, and a new stack. Equipment costing for these options include demolition costs and installing a new stack.
General Chemical noted in theirDecember 15,2008, response that "[t]he level ofboilerwork required to install each ofthese systems varies significantly [LNB with existing OFA vs. LNB with SOFA]. Installation ofLNB is a matter ofchangingthe existing burners and replacing them with burners with a different configuration in the same space. Installation ofLNB+SOFA requires extensive modification ofthe boilerwindbox where new airports are installed, air supply provided, and operator interface control provided." (Response to Commentfor the BART Analysis-General Chemical Green River Works, pg. 3-1). Boiler modifications significantly increase the time necessary to install LNB with SOFA and increase the amount oftime the unit is shutdown.
General Chemical reviewed literature for each ofthe four emission control technologies and determined achievable emissionrates for each. General Chemical's December 15,2008 submittal included revised emission reductions for LNB with existing OFA and LNB with SOFA. General Chemical anticipates LNB with existing OFA can achieve a new emission rate of0.32lblMMBtu on each boiler and the installation ofLNB with SOFA is anticipated to achieve a new emission rate of0.28 IblMMBtu. General Chemical was notrequested to provide additional information regarding the application ofSNCR or SCR. The proposed emissionreductions from the original BART analysis are included in this analysis. Installing SNCRwas determinedto reduce NOx emissions by 50%. Based on the permitted baseline value of0.70 Ib/MMBtu, the resulting NOx emissionrate is 0.35 Ib/MMBtu for each boiler. Applying SCRto each ofthe boilers is anticipated to reducedNOx emissions by 80%. Based onthe permitted baseline value of0.70 IblMMBtu, the resulting NOx emissionrate is 0.14 IblMMBtu. Revised achievable emissionrates from the four proposed control technologies are shown in Table 2.General Chemical Green River Works AP-6046 Revised NOxBART Analysis PageS
Table 2: Revised NOx Emission Rates Per Boiler

40 CFRpart 60, subpartD lImit (b) Calculated by dividing the proposed lb/hr emission rate by the boiler's maximumheat input Boiler C Boiler D Resulting NOx Resulting NOx

-----_

.._-------- ---**-Emission-Rate--~** -Emission-Rate---

-

Control Technology (lblMMBtu) / (lb/hr) (lblMMBtu) / (lb/hr) Good Combustion Practices 0.70 (a) / 374.0 0.70 (a) / 616.0
LNB with existing OFA 0.32 (b) / 170.9 0.32 (b) / 281.6
LNB with SOFA 0.28 (b) / 149.5 0.28 (b) / 246.4
SNCR 0.35 (b) / 188.0 0.35 (b) / 308.0 SCR 0.14 (b) / 75.0 0.14 (b) /123.0

(a) 

### ..

The above emission rates were used inthe comprehensive visibility analysis, butnot in the cost analysis. Instead, a 3-year average ofactual emissions from the BART baseline period, 2001- 2003, was used as the baseline emission rate. Reduction efficiencies for SNCR and SCRwere applied to the 3-year averaged baseline emission rate to calculate emission reductions. Emission reductions for LNB with existing OFA and LNB with SOFA were calculated based on the difference between the baseline emission rate andthe achievable emission rate ofeither 0.32 lb/MMBtu or 0.28lblMMBtu, respectively.
NO!: EVALUATE IMPACTS AND DOCUMENT RESULTS
General Chemical evaluatedthe economic, environmental, and energy impacts associated with the four proposed control options for Boilers C and D. General Chemical contacted vendors for information, but did notprovide vendor quotes in the original application for equipment costs associated with each proposed control option. A vendor quote was provided in the December 15, 2008 response for the capital costs ofinstalling LNB with existing OFA. Costs associated with proposedNOx control options are presented below.
In additionto 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 steamto supplement lost steam production when each ofthe existing boilers is shutdown to install the emission controls. Site preparation costs are included in the capital costs for each control option and accountfor additional structural modification and demolition workrequired to retrofitthe existing boilers, since the installation of the emission control equipmentwas not accounted for in the original plant design. Auxiliary energy costs were included in the revised application, as well as inthe original application for the installation ofSNCR and SCR, to accountfor lost steam production as each ofthe units is shutdown for modification. Makeup steam can be generatedby BoilerE, a 490 MMBtu/hr natural-gas fired boiler. However due to the size ofthe boiler, the plantwill operate on reduced steam demand when firing BoilerE. General Chemical included auxiliary energy costs, reported as lostrevenue in the costing analysis, for installing LNB with existing OFA and LNB with SOFA in their December 15,2008 response. The same differential energy costbasis thatwasGeneral Chemical Green River Works AP-6046 Revised NOx BART Analysis Page 6 originally proposed for installation ofSNCR and SCR, $8/MMBtu, was used to calculate energy costs associated withthe revised LNB options. However, the replacement energy cost included in the economic costs for installing LNB with existing OFA was based on firing BoilerE for one**week($658,OOO~,~while-energy-cosLfoLthe installation-ofLNB~withSOEA-was-based-on_fI"V'e_** **~~ ~~**  --- weeks ($3,290,000). The Division notes thatfive weeks appears somewhat excessive when compared to the reported two-week downtime and necessary firing ofBoiler E required for installing SCR.
General Chemical based the capital recovery factor (CRF) and annual cost ofcontrol ofSNCR and SCR on a 7% interestrate and a control life of30years. LNB with existing OFA and LNB with SOFA costs were annualized using a 7% interestrate and a control life of20 years. Labor and service costs associated with SNCR and SCR were estimated at $37 per hour, while only $30 per hour was used to calculate them for the options including LNB.
Several different metrics can be considered when evaluating the cost-benefitrelationships of different emission control technologies. In 40 CFRpart 51 Appendix Y two metrics are specifically mentioned: cost effectiveness and incremental cost effectiveness. Through the application ofBACT, the Division has extensive experience using cost effectiveness (i.e., dollars perton ofpollutantremoved) 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 eitherprocess are based on cost effectiveness and incremental cost effectiveness and are indicative ofthe economic costs to control emissions. In additionto providing cost effectiveness and incremental cost effectiveness results, General Chemical provided cost information in terms ofcost ofapplying emission controls and the level ofvisibility improvement achieved (i.e., dollars per deciviews). While this metric can illustrate the control cost and visibility improvement differences between control options, it is not commonly used to assess the overall effectiveness ofpollution control equipment. When performing the presumptive BART limits analyses for NOx and S02, 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 ofanticipated visibility improvement gained bythe application ofadditional emission control technology. The Division considered capital cost, annual cost, cost effectiveness, and incremental cost effectiveness in the evaluation ofeach proposed NOx emission control. Economic and environmental costs for additional NOx controls on Boilers C and D are summarized in Tables 3- 6.General Chemical Green RiverWorks AP-6046 Revised NOxBART Analysis Page 7 

### Table 3· Boiler C Economic Costs

CRF IS based on 7Yo mterest over 20 years (b) CRF is based on 7% interest over 30 years (e) Labor rate of$30/hour was used for LNB options instead of$37/hour which was used for SCR and SNCR 

# . Option 1: Option 2: Option 3: Option 4: Cost Baseline LNBw/OFA LNBw/SOFA SNCR SCR**eontrol~Equipment-~ -~-**  ---**~----_.~~--** --------**~--_._--~-** ----------- Capital Cost $0 $1,121,750 $5,837,180 $7,541,800 $14,097,600 Capital Recovery Factor N/A 0.0944 (a) 0.0944 (a) 0.0806 (b) 0.0806 (b) Annual Capital Recovery Costs $0 $105,893 $551,030 $607,870 $1,136,267 Annual O&M Costs $0 $96,341 (0) $287,234 (0) $825,850 $1,298,542 Annual Cost ofControl $0 $202,234 $838,264 $1,433,720 $2,434,809 ta) o .



### Table 4· Boiler C Environmental Costs

Annual baselme emiSSIOns based on 3 year average ofactual NOx emiSSIOns from the boiler for calendaryears 2001 2003 Option 1: Option 2: Option 3: Option 4: Baseline LNBw/OFA LNBw/SOFA SNCR SCR Annual NOxEmission (tpy) 1 167 (a) 748 655 584 233 

### , Percent Control from Baseline 0 36% 44% 50% 80% Annual NOx Reduction from Baseline (tpy) 0 419 512 584 934 Annual Cost ofControl $0 $202,234 $838,264 $1,433,720 $2,434,809 Costperton ofReduction N/A $483 $1,637 $2,457 $2,608 Incremental Costperton ofReduction N/A $483 $6,839 $8,270 $2,860 ta) . . 

### ..



## - - Table 5· BoilerD Economic Costs

CRF IS based on 7Yo mterest over 20 years (h) CRF is based on 7% interest over 30 years (e) Laborrate of$30/hour was used for LNB options instead of$37/hour which was used for SCR and SNCR 

# . Option 1: Option 2: Option 3: Option 4: Cost Baseline LNBw/OFA LNBw/SOFA SNCR SCR Control Equipment Capital Cost $0 $1,188,000 $7,487,600 $8,391,400 $19,194,500 Capital Recovery Factor N/A 0.0944 (a) 0.0944 (a) 0.0806 (b) 0.0806 (b) Annual Capital Recovery Costs $0 $112,147 $706,829 $676,347 $1,547,077 Annual O&M Costs $0 $98,461 (0) $340,048 (0) $810,234 $1,852,189 Annual CostofControl $0 $210,608 $1,046,877 $1,486,581 $3,399,266 (al o .General Chemical Green RiverWorks AP-6046 Revised NO. BART Analysis Page 8 

### Table 6· BoilerD Environmental Costs

Annual baselme emlSSlOns based on 3 year average ofactual NOx emlSSlOns fromthe bOilerfor calendaryears 2001 2003 

# . Option 1: Option 2: Option 3: Option 4: Baseline LNBw/OFA LNBw/SOFA SNCR SCR**~--- ~~** **-~----** ---- --- -- ---**----~._--** Annual NOx Emission (tpy) 1 816 (a) 1,234 1,079 908 363 

### , Percent Control from Baseline 0 32% 41% 50% 80% Annual NOx Reduction from Baseline (tpy) 0 582 737 908 1,453 Annual Cost ofControl $0 $210,608 $1,046,877 $1,486,581 $3,399,266 Cost perton ofReduction N/A $362 $1,420 $1,637 $2,340 Incremental Costperton ofReduction N/A $362 $5,395 $2,571 $3,510 ta) 

### .. . .


## - The Division considers the cost effectiveness and incremental cost effectiveness ofall four proposed NOx BART technologies are reasonable.
The final step in the NOxBART 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. The visibility analysis follows below. Tables on pages 9 and 10 listthe modeled control scenarios and associated emissionrates. 

### VISIBILITYIMPROVEMENT DETERMINATION:
The fifth offive factors that mustbe considered for a BART determination analysis, as required by 40 CFRpart 51

- Appendix Y, is the degree ofClass I area visibility improvementthatresults 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 predictthe change in Class I areavisibility. A detailed description ofthe modeling setup and results for the initial BART submittal from General Chemical can be found in the Division's August 4, 2008 BART analysis.
In response to comments received onthe initial BART determinations forthe facility, the Divisionrequestedthat General Chemical evaluate additional state-of-the-art control levels that could be achieved for NOxemissions. General Chemical submitted additional modeling that included evaluations of: 1) new LNB along with the existing OFA systems at a NOx emissionrate based on 0.32 Ib/MMBtu for each boiler, and 2) new LNB along with separated OFA with aNOx emissionrate based on 0.28 Ib/MMBtu for each boiler. The Divisionreviewedthe modeling, which consisted ofyear 2001 modeling for each ofthe two control options, and expandedthe modeling to include all three years ofavailable meteorological data.
Table 7 presents the model inputs thatwere used to representthe baseline scenario for Boilers C and D, and Table 8 presents the inputs thatwere usedto model the additional control scenarios.General Chemical Green River Works AP-6046 Revised NOx BART Analysis Page 9
Table 7: Source Parameters and Emissions for the Baseline Scenario Baseline Coal-Fired Boiler C Coal-Fired BoilerD**~~-----------~- ~(GR;;2;;-L)** **(GR;;-3;;-W)~--**

NOxControl- overfire air, low excess air Parameter PM Control- "hot-side" ESP S02 Control- no add-on controls Heat Input (MMBtu/hr) 534 880 Base Elevation (m) 1928 1928 StackHeight (m) 47.55 47.55 StackDiameter (m) 3.05 3.05 StackTemperature (K) 452.6 460.9 ExitVelocity (m/s) 15.98 25.12 S02Emissions (lb/MMBtu) 1.2 1.2 S02Emissions (lb/hr) 640.8 1056.0 H2 S04Emissions (lb/hr) 5.87 9.39 NOxEmissions (lb/MMBtu) 0.7 0.7 NOxEmissions (lb/hr) 374.0 616.0 PM Coarse Emissions (lb/hr) 27.77 44.44 PMFine Emissions (lb/hr) 21.39 34.24 Elemental Carbon Emissions 0.82 1.32 (lb/hr) Organic Carbon Emissions (lb/hr) 1.47 2.35 ESP = electrostatIc precipitator H2S04= sulfuric acid K=Kelvin lb/hr = pounds perhour lb/MMBtu = pounds permillion Britishthermal units m/s = meters per second MMBtu/hr = million Britishthermal units perhour NOx= nitrogen oxides PM = particulate matter S02= sulfur dioxideGeneral Chemical Green River Works AP-6046 Revised NOx BART Analysis Page 10


### I M drS narios 

### Add"f dE

.. t p : ource arame ers an mISSIons or I JOna o e mg ce**---~** ----**-~- -~**  --**~_** ..._----_

..-

- Control Scenario A: Control Scenario B: LNB wIExisting OFA LNBw/SOFA

Coal- Coal- Coal- CoalFired Fired Fired Fired Boiler C Boiler D Boiler C Boiler D Parameter (GR-2-L) (GR-3-W) (GR-2-L) (GR-3-W) Base Elevation (m) 1928 1928 1928 1928 StackHeight (m) 47.55 47.55 47.55 47.55 StackDiameter (m) 3.05 3.05 3.05 3.05 StackTemperature (K) 452.6 460.9 452.6 460.9 Exit Velocity (mls) 15.98 25.12 15.98 25.12 S02Emissions (Ib/hr) 641.0 1056.0 641.0 1056.0 H2 S04Emissions (lb/hr) 5.87 9.39 5.87 9.39 NOxEmissions (lb/hr) 171.0 282.0 149.5 246.4 PMCoarse Emissions (lb/hr) 27.77 44.44 27.77 44.44 PMFine Emissions (lb/hr) 21.39 34.24 21.39 34.24 Elemental Carbon (lb/hr) 0.82 1.32 0.82 1.32 I Organic Emissions (lb/hr) 1.47 2.35 1.47 2.35 Table 

### 8 S

H2S04= sulfuric acid K=Kelvin lb/hr = pounds per hour LNB 

### =low NOxburners m=meters mls = meters per second NOx= nitrogen oxides OFA = overfire air SOFA= separated overfire air PM = particulate matter S02

### =sulfur dioxide Visibility Post-Processing Results
The results ofthe baseline visibility modeling for both units combined are shown in the table below. For each year modeled, the 98th percentile result is greaterthan 0.5**~dv** at BridgerWA. ForFitzpatrickWA, the 98th percentile results equals or exceeds 0.5**~dv** for two ofthe three years ofmeteorology.
Particulate (PM) emissions contributedvery little to the modeled results. For example, the percentage contribution from PM on days above 0.5**~dv** at BridgerWA was at most 3.5% and on average 1.6% (2001 meteorology). Therefore, subsequentmodeling ofthe various control options did not consider any additional PM controls.
Table 10 presents a summary ofthe modeling results for the additional control scenarios.General Chemical Green RiverWorks AP-6046 Revised NOxBART Analysis Page 11

Adv = delta declVlew WA = wilderness area 

### Table 9: CALPUFF Visibility Modeline Results

- Baseline Conditions 2001 2002 2003**-~~~~-~-** 98th Total 98th Total 98th Total**---------~ ----~** **~-~~~- -~--~--** **~--_.--~-_._-** -_

.. .. Percentile No. of Percentile No. of Percentile No. of

Value Days> Value Days> Value Days> Class I Area (Adv) 0.5 Adv (Adv) 0.5 Adv (Adv) 0.5 Adv BridgerWA 0.84 21 0.72 16 0.97 16 FitzpatrickWA 0.50 8 0.47 7 0.59 10

..



### Table 10: CALPUFF Results for Baseline and Added Control Options

3-Year Averal!e
98th Total Percentile No. of

Value Days> Class I Area (Adv) 0.5 Adv Baseline BridgerWA 0.84 18 FitzpatrickWA 0.52 8 Control Scenario A: New LNB andExisting OFA BridgerWA 0.57 10 FitzpatrickWA 0.32 3 Control Scenario B: New LNB/SOFA BridgerWA 0.54 8 FitzpatrickWA 0.31 3

LNB = low NOxburners OFA = overfire air SOFA

### =separated overfire air
A comparison ofthe3-year average 98th percentile modeling results for baseline, LNB/OFA, and LNB/SOFA is shown in Figure 1 below. Modeled visibility improvement with the option ofnew LNB with existing OFA, as compared to baseline, is 0.27**~dv** atBridgerWA. The addition of SOFA would only provide a modeled improvement ofan additional 0.03**~dv** at BridgerWA.General Chemical Green RiverWorks AP-6046 Revised NOx BART Analysis Page 12 Figure 1 CALPUFF Results for Baseline, LNB/OFA, and LNB/SOFA

• BridgerWA

• FitzpatrickWA

lNB/SOFA lNB/OFA Baseline 0.000 0.200 

### v t

a 0.400 d __**1_.00~l--___ I~_~_~~** **~~** __ 

# I d 0.800 

# +-

e 0.600 1

3-YearAverage 98th Percentile

BART CONCLUSION FORNOx: Afterreviewing the original information submittedby General Chemical and the December 15, 2008 response, and considering: (1) the costs ofcompliance, (2) the energy and non-air quality environmental impacts ofcompliance, (3) any pollution equipment in use or in existence atthe source, (4) the remaining useful life ofthe source, and (5) the degree ofimprovement in visibility (all five statutory factors) from each proposed control technology, the Division determined BART for NOx emitted from the two boilers subjectto BART at General Chemical's Green River Works.

LNB with existing OFA is determined to be BART for Boilers C and D forNOxbased, in part, on the following conclusions:
1. LNB with existing OFA on Boiler C was cost effective with a capital cost of$I,121,750 and a $483 perton ofNOx removed average costeffectiveness over a twenty year operational life. LNB with existing OFA on BoilerD was cost effective with a capital cost of$I,188,000 and a $362 perton ofNOx removed average cost effectiveness over a twenty year operational life.
2. Combustion control using LNB with existing OFA does notrequire non-air quality environmental mitigation for the use ofchemical reagents (i.e., ammonia orurea) and there is a minimal energy impact.General Chemical Green River Works AP-6046 Revised NOx BART Analysis Page 13
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-LNB-with-existing-OFA-on-both-Boilers-C-and-D,-is-O.41-~d:v.~-**  ---**~~** --- 4. Annual NOx emission reduction from installing LNB with existing OFA on the boilers was 419 tons from Boiler C and 582 tons from BoilerD. Applying LNB with SOFAto 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.
LNB with separated OFA, SNCR, and SCRwere not determined to be BART for Boilers C and D for NOx based, in part, on the following conclusions:
I. The cost ofcompliance for installing LNB with SOFA on Boilers C and D is significantly higherthan LNB with existing OFA. Capital costs for installing LNB with SOFA on Boiler C is $5,837,180 and $7,487,600 on BoilerD. Annual operating costs associated with operating LNB with SOFA on Boiler C are $190,893 higherthan the operating costs for LNB with existing OFA. Annual operating costs for LNB with SOFA on BoilerD are $241,587 higherthan 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 LNB with SOFA instead ofLNB with existing OFA on both Boilers C and D isjust0.04**~dv.** 3. The cost ofcompliance for installing SNCR on each boiler is higherthan LNB with existing OFA. Capital costs for SNCR on Boiler Cis $7,541,800 and $8,391,400 for BoilerD. Annual operating cost for SNCR is $825,850 for Boiler C and $810,234 for BoilerD.
4. The cost ofcompliance for installing SCRon eachboiler is higherthan LNB with existing OFA. Capital costs for SCR on Boiler C is $14,097,600 and $19,194,500 for BoilerD. Annual operating costfor SCRis $1,298,542 for Boiler C and $1,852,189 for BoilerD.
5. Additional non-air quality environmental mitigation is required for the use ofchemical reagents when either SNCRor SCRis used to reducedNOx emissions from the boilers.
6. Operation ofSNCRrequires an estimated 50 kW ofadditional powerto operate. SCR on Boiler C requires 200 kW ofadditional power and BoilerD requires 300 kW.General Chemical Green River Works AP-6046 Revised NOx BART Analysis Page 14
7. Visibility impacts from General Chemical's additional scenarios for LNB with existing OFA and LNB with SOFA, which were proposed in the December 15, 2008 response, were determined using the average ofthree modeledyears, 2001-2003. Visibility impactsforSNCR-and-SCR-weredeterminedusingthe.2001modeled-year,-which yielded the highest modeled impacts. Result indicate the application ofLNB with existing OFA and LNB with SOFA yield lowervisibility impacts than applying SNCRto each ofthe boilers. Installing SCR on each ofthe boilers reduces visibility impacts belowthe visibility impacts ofLNB with existing OFA in the BridgerWilderness Area by 0.04**~dv.** The Division considers the installation and operation ofthe BART-determinedNOx controls, LNB with existing OFA, on Boilers C and D to meetthe corresponding emission limits on a continuous basis, to meetthe statutory requirements ofBART. BART controls will be installed on Boiler C by December 31,2011 and on BoilerD by December 31,2012. Unit-by-unitNOx BART determinations:
Boiler C:

BoilerD: LNB with existing OFA and meeting NOxemission limits of0.32 Ib/MMBtu (30-day rolling average), 170.9 lb/hr (30-day rolling average) and 748.5 tpyas BART for NOx' LNB with existing OFA and meeting NOx emission limits of0.32 Ib/MMBtu (30-day rolling average), 281.6Ib/hr (30-day rolling average) and 1,233.4tpy as BART for NOx'