$ 62,627,093 Flowrates fron

SCR Cost, $h Flow, scfh, @ 

### $430,000,000 SCR Capital ( Based on vert 

### .,..e,)CfrS SCR • WA Parish Units 5 _8

# r WAP5 WAP6 WAP7 WAP8 Dry Bottom Dry Bottom Tangential Tangential B&W B&W CE CE 690 690 590 650 2,620 10,500 10,500 10,500 10,500 $ 1.50 $ 1.50 $ 1.50 $ 1.50

0.17 0.17 0.17 0.17 0.03 0.03 0.03 0.03 82% 82% 82% 82% 0 0 0 0 164 164 164 164 164 164 164 164 164 $ 100,000 $ 100,000 $ 100,000 $ 100,000 1,035 1,035 885 975 3 3 3 3 24,000 24,000 24,000 24,000 10,000 10,000 10,000 10,000 no no no no $ 1,000 1,000 1,000 1,000 113,244,275 113,244,275 96,832,061 106,679,389 $ 250 $ 250 $ 250 $ 250 0.50% 0.50% 0.50% 0.50%

0.95 0.94 0.90 0.82 12.00 12.00 12.00 12.00 15.00 15.00 15.00 15.00 9735% 9735"0/0**~5%** 9735"0/6 0.127 0.127 0.127 0.127 $ 388,296 $ 385,012 $ 314,823 $ 316,679 $1,191,251 $1,181,177 $ 965,845 $ 971,539

$119,125 $118,118 $96,584 $ 97,154 $ 450,293 $ 446,485 $ 365,089 $ 367,242 $ 2,148,964 $ 2,130,791 $1,742,342 $1,752,614

$100,000 $100,000 $100,000 $100,000 $ 14,340,513 $14,340,513 $ 12,262,178 $13,509,179 $ 16,589,477 $ 16,571,304 $14,104,520 $ 15,361,792 4,203 4,167 3,408 342

2.90 2.92 3.04 3.29 >

Economic Analysis UNIT TYPE Manufacturer MW Heat Rate Fuel Cost, MMBTU Uncontrolled NOx Controlled NOx Percent SCR Reduction Burner Capital Cost ($/KW) SCR Capital Cost ($/KW) Total Capital Cost ($/KW) Fixed O&M ($/yr) Catalyst volume, m3 # layers Hrs between cat addition Catalyst price $/m3 100% bypass? yes/no Catalyst Disposal $/m3 Total Capital $ Reagent Price, $/ton Loss in heat rate Capacity factor Months deNOx in service Book Life of Project**~~~~~-~ ~-I;RH:>eal""Ca.~1"8t6T"%**  Cap. Rec. Factor Annual Ammonia Ann. Catalyst Catalyst Disposal Ann. Heat Rate Pen. Variable O&M, $/yr Fixed O&M ($/yr) Fixed Chrg Capital Annual Cost Ann. NOx Red'n, tons $/Mwhr

# D::n~JIWJ&**~T-\))U- e-MtUL~~** **\?ClYlcl~~lli1~cb T~A0~**  

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# \':.;1J\.:r l 

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# 1-F Y\

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# -eole-e0**~ost** based on Reliant's Post-installation Cost Recovery Data )al statements from Ben Carmine, Reliant/NRG, TCEQ plant trips Fall '04 and Fall'05

n NRG Flex Permit Application 79255, Table 1(a), dated 1/11/07 Unit 5 Unit 6 Unit 7 Unit 8**~3%02** sefh 85,000,000 $ 1.26

## IPollutant Information 

## IRACT/BACT/LAER Clearinghouse 

## IClean Air Technology Cent... Page 1 of 1

http://cfpu tll. epa.qov/rl)lc/1I1dex.<:fm**?action~** PermitDetail. PolIutantlnfo&FaCility

....l D 0025368&ProcessJ D 1001 02&PoliutanCI D**~@t** . Last updated on Wednesday, March 31, 2 0 Technology Transfer Network 

# cClean Air Technology Center
- RACTjBACTjLAER Clearinghouse

You are Ilere: EPA Home Air & Radiation TTNWeb
- Technology Transfer Network Clean Air Technology Center RACT/BACT/LAER Clearinghouse RBLC Basic Search RBLC Search Results Pollutant Information 

### Pollutant Information Click on the Process Information button to see more information about the process associated with this pollutant. Or click on the Process List button to return to the list of processes.

Help 

### I FINAL
RBLC ID: WY-0057 Corporate/Company: BLACK HILLS CORPORATION Facility Name: WYGEN 2 Process: BOILER, 500 MW PC
Pollutant: Nitrogen Oxides (NOx) Pollutant Group (s) : CAS Number: 10102 Substance Registry System: Nitrogen Oxides (NOx)

Pollution Prevention/Add-on Control Equipment/Both/No Controls Feasible: B**------~P·2-/-Add--<>n-D&SG·r-i]i)a-Gn-:-lBw_N0~_B1jRNERSf_SE:RRc------·-------------------** Test Method: Unspecified EPA/OAR Method. 

## I All Other Method.
Percent Efficiency: 0 Compliance Verified: EMISSION LIMITS:

Case-by-Case Basis: BACT-PSD Other Applicable Requirements: Other Factors Influence Decisio.n. : --..**.,~** .. -.'-."

- 

# -.ri?ZT. Emission Limit 1:**''';;'';ji~lillljI1J!'IZ>I\'I~l'g_i(l~~.** Emission Limit 2: 0 Standard Emission Limit: 0.0700 LB/MMBTU COST DATA:

Cost Verified? Yes Dollar Year Used in Cost Estimates: Cost Effectiveness: Incremental Cost .Effectiveness,· Pollutant Notes:



### http://cfpubl.epa.gov/rblc/index.cfm?action=PermitDetail.PollutantInfo&Facility

_ID=253... 3/31/2010

## IPollutant Infonnation 

## IRACT/BACT/LAER Clearinghouse 

## I Clean Air Technology Cent... Page 1 of 1

htlp I/cfpubl epa qov/rblc/lOdex cfm 7ac110n=PerrnltDelall.PoliutantInfo&Facdlty

_ID= 25368&Process ,lD= 100l02&Poliulanl, lD=§92 Last updated on Wednesday.**~1arch** 31. 201 Technology Transfer Network Clean Air Technology Center
- RACT/BACT/LAER Cleannghouse

You dr(' hele EPA Home Air & Radiation lTNWeb, Technoloov Transfer Network Clean Air Technology Center RACT/BACT/LAER Clearinghouse RBLC Basic Search RBLC Search Results Pollutant JIlfor,."",lol1 

### Pollutant Information Click on the Process Information button to see more information about the process associated with this pollutant. Or click on the Process List button to return to the list of processes.

Help 

## I FINAL
RBLC 10: WY-0057 Corporate/Company: BLACK HILLS CORPORATION Facility Name: WYGEN 2 Process: BOILER, 500 MW PC pollutant: Sulfur Oxides (SOx) pollutant Group (s) : CAS Number: 7446 Substance Registry System: Sulfur Oxides (SOx)

Pollution Prevention/Add-on Control Equipment/Both/No Controls Feasible: A**-~~---1'2jA&i~on-DesG~ip&-:i.on-:,---SEMl-&R:V--HME-5.pRA-Y-I3RY-ER-A:BSeRBi:R--------'-----'-------.-----'.-'----'-----'--'-~-**
Test Method: Unspecified EPA/OAR Method. 

## I All Other Method.
Percent Efficiency: 0 Compliance Verified: EMISSION LIMITS:**Case-~-Case** Basis: BACT-PSD

Other Applicable Requirements: Other Factors Influence Decision: Emission Limit 1: Emission Limit 2: Standard Emission Limit: COST DATA:

Cost Verified? Yes Dollar Year Used in Cost Estimates: Cost Effectiveness:**IO~~~f;t~'~A~ll** Incremental Cost Effectiveness:' n pollutant Notes:



### http://cfpubl.epa.gov/rblc/index.cfm?action=PennitDetail.PollutantInfo&Facility_ID=253... 3/31/2010

### DEPARTMENT OFENVIRONMENTAL QUALITY DIVISION OF AIR QUALITY PermitApplication Analysis, NSR-AP-C92 April 24, 2002


### COMPANY: FACILITY: FACILITY LOCATION:

TYPE OF FACILITY: RESPONSIBLE OFFICIAL:

COMPANY REPRESENTATIVE:

MAILING ADDRESS:

REVIEWED BY:
]>URPOSE OF APPLICATION: BlackHills Corporation WYGEN2 13151 Highway 51

.**Gillette~** WY

Section 27, T50N, R71W Campbell County, Wyoming Coal Fired Steam Electric Generating Plant Tom Ohlmacher Senior V.P. Power Supply and Operations Fred Carl Environmental Coordinator P.O. Box 1400 Rapid City, SD 57709-1400 Stewart Griner, Air Quality Engineer Ken Rairigh, Air Quality Engineer/Modeler

Black Hills Corporation submitted an application to construct a 500 megawatt (MW) pulverized coal (PC) fired electric generating facility to be known as WYGEN 2. The proposed facility consists ofone PC boiler burning coal from the nearby Wyodakcoal mine with associated coal and lime handling and flue gas desulfurization (FGD) waste product handling. Parameters used for design values, based on coal from the Wyodak mIne, include 

## adesign heat content of7,950 Btu/lb and a maximum sulfur content of 1.2%. The maximum design heat input to the facility will be 5,145.7 MMBtu/hr. The applicant identified the following emission sources in the permit application:Black Hills Corporation (WYGEN 2) Permit Application Analysis, NSR·AP·C92 Page 6

Annual Emissions Emissions Reduction Total Annualized Cost

Incremental Reduction* Incremental Annualized Cost Baseline I 

### 0.25 IblMMBtu 5,635 tpy Baseline Baseline Baseline

### L~/SCR O.09lblMMBtu 

### 2,028 tpy 3,606 tpy. $12,563,000

$3,484Iton Baseline. Baseline
Baseline $3,019,000 I 676 tpy $5,235,000

* The Division calculated incremental costs based on a 0.09 IblMMBtu baseline for both 0.08 and 0.06 IblMMBtu because an economizerbypass is required to achieve either 0.08 or 0.06 IbIMMBtu. Black Hills Corporation chose 0,09 IblMMBtu as BACT because they considered the incremental cost effectiveness to be unreasonable for the lower emission levels and because they were unable to find an**-~---~~"isst!ecl** pennlt"witi1"a ITmit less than 0:l2 IbfMMBttl tor

## i-pC

## bolTer." (Note-that the Hawthorne Stali()rl boiler in Missouri has a limit ofO.12lblMMBtu for 

### 3 years and then a limit ofO.08lblMMBtu unless the permittee can demonstrate that 0.08 IblMMBtu is not feasible.) According to Missouri DNR, Hawthorne Station is meeting the 0.08 Ib/MMBtu limit. Missouri DNR is also working on a permit for Great Plains Power with a proposed limit of0.08 IbIMMBtu. Although Great Plains Power requested 

### 3 years to
. determine ifthey can comply with the limit as allowed in theHawthorne Station permit, Missouri DNR indicated that they do notplan to issue the permit with any exceptions to the 0.08 Ib/MMBtu limit. The Division evaluated the control efficiency required to meet limits of0.09, 0.08, and 0.06Ib/MMBtLi using a baseline of0.25 Ib/MMBtu as shown in the following table:
Emission Level

(lb/MMBtu) 0.09 0.08 0.06 Control Efficiency 

### (%) 64 68 76

. These efficiencies seem low based on information that vendors are designing and providing guarantees

for SCR systems with at least 90% control efficiencies. For example, Montour Steam Electric Station in Allentown, PA retrofitted two 750 MW coal fired boilers with SCR systems designed for 90% control efficiency and 0.04 Ib/MMBtu using eastern bituminous coal. It should be noted that these are design levels to meet acid rain requirements and there are no permit limits requiring this level ofreduction.Black Hills Corporation (WYGEN 2) Permit Application Analysis, NSR-AP-C92 Page 7 

### The BACT analysis indicates that 0.06 Ib/MMBtu is technically feasible andthe Division considers the total and incremental cost effectiveness to be reasonable. Note that the incremental cost effectiveness is much lower when considering emission limits less than 0.08 lb/MMBtu because an economizerbypass is required to achieve emission limits of0.08 lb/MMBtu or less. Although the BACT analysis indicates an emission level of0.06 Ib/MMBtu, BlackHills Corporation has expressed uncertainty about meeting 0'.06 Ib/MMBtu on a continuous basis. The Division and BlackHills Corporation discussed various options for dealing with this uncertainty while setting an appropriate BACT level. One option discussed was 0.06 Ib/MMBtu annual average and 0.08 Ib/MMBtu 30 day average. This option still left Black Hills Corporation with a measure ofuncertainty in regards to meeting the annual limit and they requested that the 0.06 Ib/MMBtu limit not become effective until issuance ofthe Title V operating pennit in order to allow additional time to demonstrate compliance. Even with the additional time for compliance, Black Hills Corporation expressed concern about meeting a 0.061b/MMBtu limit and discussed options ifthey could not meet the limit. Upon further discussion, the Division and Black Hills Corporationagreed that a 30 day limit of0.07 Ib/MMBtu would be more stringent than any existing limit for ano eratingPC boiler and could be met without additional time to demonstrate com liance.



### II. 500 MW PC 

### Boiler

- S02 

### Control**~·~~~-···~~Hl-ack-H1+I-g-t-ef'l"mra:tii)ni'lr-ep0s-e6·a~-em.j-dry-4iTl'le~r-aY~FY%r~abS{)FI:)(~r~wi~mi.ssionJ~mit~.O.J~~_** 

### ..**~.~** 

### ..... Ib/MMBtu (30 day average) and 0.17 Ib/MMBtu (2 hour block). The Division reviewed the RACT/BACT/LAER Clearinghouse (RBLC) and infonnation from EPA Regional offices to find pennitted or proposed PC utility boilers with S02 emissions lower than 0.15 lb/MMBtu as shown in the following table:

# Lx,x:QmQJd- 

# -0Thn

# ~\'{Q. D'IN£I'\S 

# @

Commonwealth ofPennsylvania Department ofEnvironmentalProtection May 2, 2005 

### Subject: PlanApproval ApplicationReview Memo (PSD, NSR, NSPS, MACT) RiverHill Power Company, LLC Karthaus Township, Clearfield County PlanApproval Application#17-00055A 

### To: DavidW. Aldenderfer Environmental ProgramManager Air QualityProgram 

### From: Cortney

### A. Danneker New SourceReview Section Air QualityProgram SeanWenrich Facilities Permitting Section Air QualityProgram 

### Through: Muhammad Q. Zaman Chief, Facilities Permitting Section 

### Background RiverHill Power Company, LLC has submitted a plan approval application for the construction ofa 290 megawattwaste coal fired electric generating facility to be located in Karthaus Township, ClearfieldCounty. The electric generating facility will consist ofa 2,871 MMBtuIhrbituminous waste"coal fired circulating fluidized bed (CFB) boiler, a steam turbine generator, a#2 fuel oil fired auxiliaryboilerfor CFB boiler start-up, a mechanical draftwet cooling tower, a diesel fired generator, a diesel fired fire pump, a 50,000 gallon#2 fuel oil aboveground storage tank, as well as 

### dry materials handling, preparation, and storage systems for coal, limestone and ash. The air contaminantemissions from these sources will be controlledwith source specific control devices, limited operating hours and limited material throughputs which will be discussed in further detail laterinthe review memo. The facility is expected to have significantenvironmental and economic benefits byutilizing up to two million tons ofwaste coalperyearandby generating overtwo million megawatt-hours ofelectricity on an annualbasis. Economicbenefits associated with the facility include stabilization ofelectricrates causedbythe lowercost of electricitygenerated by coalpowered electric plants, thereducedneed infuel oil consumption, the creation of 1,000 ormorejobs overthe three year constructionperiod as well as up to 60 full timejobs during the plant's operational life span and the influx ofmillions ofdollars into the area to supportwages, subcontracted services, and thepurchasing ofmaterials and supplies from local merchants. Additionally, the utilization ofwaste coal piles will also reduce the huge waste coal piles inPennsylvania, and overone million tons peryearofash and combustion byproducts from the facility will bereused to mitigate the affects ofabandonedmine drainage. The companyplans to start construction ofthe facility soon afterthe plan approval is issued with an anticipated first fire ofthe CFB boiler scheduled for September2007. Thecompleted construction ofthe entirefacility is scheduled for May2008 with thebeginning ofcommercial operation scheduled for June 2008.**c;RA;CT~A'J;R:~yi~** 

## "TheS": 10

>"

.**V':'~**

. " 

### "

.

### na3 

### t, control equipment «e. 

### ill additi ichcorr ny's

,t 

### is in companythe eeatinput, which s to a 98.2% S02 control efficiency and 

### i ent 's BACT andBA'r**~QtQ,.22**

### ..**p.oJJn.ds~.:p~liQnJ3tJ.l** 

### oillelltinpJJiwlri,cll,QQ'**S'MLcQntrJ)leifki.eJlc~** 

### ..**-B~,** 

### ,,_ g an emissi e CEM will be able to provide quick the operator and willallowbetter control overtbe CFB tern. On February 28. 2005, th :ralRegisterpublished for commeptthe proposedamendments ubpartDaofthe Standew Stationary Sources, 40 

### CFR 60. According to the proposed amenuldbe subjectto an 

### S02 emission limit of2. unds permegawatthour ofgross energy output (equivalenHo 0.2 pounds permillionBtu ofheat input at the maximum design heatrate) on a 30-dayrolling average basis. The RiverHillPowerproposed

### S02 emission limit of0.2 pounds permillion Btu ofheat input on a 30-dayrolling average satisfies proposed SUbpart Daamendments as well as BACT and BAT requirements. Therefore, Irecommend that an S02 emission limit of0.2 pounds permillion Btu ofheatinput on a 3D-dayroIling average basisshall be established since,it satisfies the technical and economic analysis for BACT as well as BAT. I also recommend that eitherthe spray dryer absorber orthe fla$h dryer absorber shall be installed for postustion S02 control in combinationwith the CFB boilerlimestone injection in orderto achieve an overall rate of0.2 pounds permillion Btu ofheatinputbased on a 30-dayrolling average to satisfyBACT and requirements. Thereason for the installation ofeitherthe spraydryer absorberorthe flash dryerabsother is because the company was not able to specifywhich ofthese two dry flue gas desulfurization systems would be installed since the manufacturerofthe boilerdetermines which control device is used andthe boiler· manufacturerwould notbe determined until the project is sent out forbid. 

### ill ,addition,the outlet of eitherthe spray dryerabsorberorthe flash dryerabsorber shall be equipped with instrumentation in monitor and' recordthe outlettemperature ofthe flue gas entering thefabric collector: The outlettemper onitoring and recording will provide verification that the temperature ofthe flue gas entering the downstreamfabric collector " is not exceeding the maximum temperature to destroy the fabric filters. The maximum temperature willbe submitted to the Departmentonce the manufacturerofthe fabric collectorhas been selected.Pennit Analysis Rocky Mountain Power, Inc. Pennit#3185-02 

### 1. IntroductionlProcess Description A. Pennitted Equipment Rocky Mountain Power, Inc. (RMP) was pennitted under Permit #3185 to construct a nominal I 16-gross megawatt (MW) electrical power generation facility approximately 1.2 miles northeast ofHardin, Montana. The facility consists ofa pulverized coal-fired (pC-fired) boiler and a steam turbine, which will drive a 135 MVA class nameplate electric generator to produce anominal 116-gross MW ofelectri

# cpower (11**~MW** ofthe powerproduced will be used on average by RMP for plant auxiliary power). The legal description ofthe site location is the Northwest Y4 ofSection 12, Township 1 South, Range 33 East, in Big Horn County, Montana. The following equipment is permitted for this facility: 1. 1,304 million British thermal units per hour (MMBtulhr) PC-fired Boiler (with associated steam turbine and electric generator) with a 250-foot stack 2. Cooling tower 3. Coal, lime, and ash handling systems a. Coal unloadingbaghollse (RCF-BH-001)

- 50,000 dry standard cubic feet per minute (dscfm) b. Coal silo baghouse (RCF-BH-002)

- 7,500 dscfm c. Coal storage bunkers baghouse (RCF-BH-003)-- 5,000 dscfm d.**~pray** dry atsorber (5DA) 

## lime Silo bm vent 

### (Fel-S V-00 1)

- 1,000 ds-cfm e. Flue gas desulfurization (FGD) ash silo bin vent (WMH-BV-002)

- 2,000 dscfm f. Recycle ash silo bin vent (FGT-BV-002) -' 2,00b dscfm g. Water treatment lime silobaghollse (RWS-BH-001)

- 1,000 dscfm h. Soda ash silo baghouse (RWS-BH-002)

- 1,000 dscfm B. Source Description 1. Boiler and Associated Emission Control The permitted boiler is a 1968 wet-bottom, wall-fired boiler manufactured by Mitchell of the United Kingdom. The boiler is configured with 3 pulverizers and 12burners with opposed firing. The maximum nominal heat inputrate to the boiler will be 1,304 MMBtu/hr, which will be used to produce up to approximately 900,000 pounds ofsteam perhour. Natural gas will be used to fire the boiler during periods ofstart-up. During normal operations, the boiler will be fueled with pulverized coal. At this time, RMP anticipates the boilerwill combustcoal owned by the Tribe ofCrow Indians from the Absaloka Mine. The mine, which is owned by Westmoreland Resources, Inc., is located approximately 30 miles east ofHardin. Using the heat content of8,700 Btu perpound (Ib) ofAbsaloka Mine coal,

# as provided byWestmoreland Resources, Inc., the coal-firing rate will be approximately 75 tons per hour (tonlhr) and 656,500 tons per year (tpy). Boiler combustion gases (flue gases) would be routed to a Selective Catalytic Reduction (SCR) unit for control ofnitrogen oxides (NOx). From the SCR unit, the flue gas would then be routed to a dry flue gas desulfurization (FGD) system (specifically characterized as a Spray DryAbsorber (SDA» that uses a lime reagent for control ofsulfur dioxide (S02)' Other acid gases including sulfuric acid**(H2S0~),** hydrochloric acid (HC!) and
3185-02 Final: 05116/05b. Eliminate TechnicallyInfeasible Options All ofthe above technologies are technically**feasib~e** for a PC-fired Boiler.

c. Ranking ofControlTechnologies Based on Control Efficiencies

Control Technology Control Efficiency Wet FGD options (including lime, Up to 96% limestone and dual alkali) DryFGD- SDA Up to 94% Dry FGD

- Dry Sorbent Iniection Up

# to 50% Fuel Switching Up to 50% Fuel Blending Up to 50% Coal Cleaning Up to 20% d. Evaluation ofMost Effective Controls The two most effective controls, wet FGD and dry FGD-SDA, both very similar control efficiencies will be compared to determine which method would be most appropriate for the RMP Boiler. the fuel switching, fuel blending, and coal cleaning options will not be considered in conjunction with the FGD options as.the coal sulfur content may only be decreased slightly (ifat all) based on those methods because of the current proposed use oflow sulfur coal. In addition, on very low sulfur coals, the**--~~~-"-"'~"'~-""-'~"-"""""effectiverreSS"'"ofF6B'systemsflattens~t1iue~to·th~inereasedefii·ffi-eulty'i'}f~omr-oHing·-~··· ~";_.~**  very small amounts of

### 802• For this BACT analysis, it was assumed that the wefF0l)sySfem would consist of wet limestone scrubbing with forced oxidation. Wet lime and wet limestone scrubbing systems achieve about the same 

### S02 control efficiency; however, the higher cost oflime makes wetlimestone scrubbing themoreeconomically reasonable option ofthetwo.**g§il;1~74;IlJ~#1illiltMC~ti~()11~d,$:Qi(lrrrisstQn.tate);Qfl.k61** 

### .'

...",

.

# J!i:;tm\i!~,;;ile~~r,~~ip~4!'~~~~~b

BACT analyses must include energy and environmental impacts ofpotential control technologies. Both wet and dry FGD systems require electricity to operate. Electricity is included in the cost estimates for the two systems. Energy demand for awet FGD system is approximately 40% higher than for a dry system. Potentia! collat.eral environmental impacts can be categorized in the areas ofwater consumptiori:**w~~e** water handling, solid waste handling, and toxic emissions.

. . .

3185-02 15 Final: 05116/05Although coal cleaning, fuel switching, and fuel blending would not be evaluated by themselves due to other options with much higher control efficiency, these options could be combined with FGD methods. As previously mentioned, coal cleaning has mostly been utilized for high-sulfur eastern coals with high pyrite contents. Little research was found for low-sulfur western subbituminous coals. In addition, cost

.effectiveness information was based on high-sulfur eastern coals being combusted in power plants without FGD technology (in fact, coal cleaning was used to avoid installation ofwhat was considered expensive FGD for moderate S02 reduction). No cost information was found regarding coal cleaning in combination with FGD. With respect to fuel switching or fuel blending, RMP cannot predict or control future availability oflower sulfur fuels or the price ofthose fuels. Other sources required to bum low sulfur coals are generally limited to coal with less than 1% sulfur content

. (also a requirement in Pennit #3185-02 and representative ofAbsaloka Coal). There.

is nojustification, either economically or environmentally, to require RMP to use a coal with lower sulfur content. However, RMP is not prohibited from coal switching or coal blending, as long as established emission limits can be achieved. Therefore, coal cleaning, fuel SWitching, and fuel blending, on their own and in combination with other control technologies are eliminated from consideration as a requirement under BACT for S02 on the Boiler.

e. Select BACT 111C Department deternlincd that wet FGD systems do not constitute BACT for the they ure more costly and can result in collateral environmental inlpacts. For example, wet FGD systems can result in the formation ofcondensable particulate matter and acid gases, neither ofwhich would be controlled with the proposed particulate control (baghouse). Creation ofhazardous air pollutants is ofgreat concern to the community ofHardin and the Department. In addition, the wet FGD systems would require additional water and energy. Also, the solid waste by-product from the scrubbing process would need to be managed in dewatering ponds andlor a landfill. Conversely, the Department determined that the control provided by a dry FGD system is consistent with other recently pennitted similar sources and that the collateral environmental effects, in this case, from using a wet FGD system compared with a dry FGD system are too great tojustify designating that a wet FGD (with or without WESP, as further described in the PM 10 and H2S04 sections) system constitutes BACT. Therefore, a dry FGD system (in this case, an SDA) constitutes BACT. The Department investigated the sulfur percentage ofthe Absaloka Mine coal ("'" 0.61 %) in comparison with the sulfur percentage ofthe coal for otherrecently pennitted similar sources and their associated limits (see table below, note: this table does not represent the only information reviewed for this BACT determination, it is only a representation ofsome material reviewed) and for recently permitted sources with similar control equipment that have operated effectively for some period oftime (information from EPA's Acid Rain database). Control ofS02becomes progressively more difficult and less effective on lower sulfur coals. Based upon this information,

The limit is expressed as a lblhr limit to allow or flexibility (to decrease load to minimize S02 emissions) during periods ofatomizer changeout on the SDA system.
3185-02 17 Final: 05/16/05

# STATE OF 

# NEBRASKA

PREVENTION OF SIGNIFICANT DETERIORATION (PSD) PERMIT TO MODIFY AN AIR CONTAMINANT SOURCE IS HEREBY ISSUED TO: Mike Johanns Governor 

### CONSTRUCTION PERMIT DEPARTMENT OF ENVIRONMENTAL QUALITY Michael J. Linder Director Suite 400, The Atrium 1200 'N' Street P.O. Box 98922 Lincoln, Nebraska 68509-8922 Phone (402) 471-2186

FAX (402) 471-2909

Omaha Public Power District 444 South 16th Street Omaha, Nebraska 68102-2247 

### FOR THE SPECIFIC CONSTRUCTION OF: A nominal 660-megawatt coal-fired electric generating unit with supporting equipment (Nebraska City Unit 2) 

### TO BE LOCATED AT: OPPD

- Nebraska City Station 7264 L Road

Pursuant to Chapter 14 ofthe Nebraska Air Quality Regulations, the public has been notified by prominent advertisement ofthis proposed modification ofan air contaminant source and the thirty (30) day period allowed for comments has elapsed. This Construction Permit approves the proposed construction ofa new nominal 660-megawatt coal-fired electric generating unit with supporting infrastructure, and places new emission limits on existing equipment at the existing Nebraska City Station located approximately 5 miles southeast ofNebraska City. Compliance with this permit shall not be a defense to any enforcement action for violation ofan ambient air quality standard. This permit is issued with the following conditions: General Conditions 

### 1. This permit is not transferable to another source or location. (Title 129, Chapter 17) 

## n. Holding ofthis permit does not relieve the owner/operator ofthe source from the responsibility to comply with all applicable portions ofthe Nebraska Air Quality Regulations and any other requirements under local, State, or Federal law. (Title 129, Chapter 41) 1lI. Any applicant who fails to submit any relevant facts or who has submitted incorrect information in a permit application shall, upon becoming aware ofsuch failure or incorrect submittal, promptly submit such supplementary facts or corrected information. Ifthe source wishes to

OPPD Nebraska City Station-S8343cOI.doc PSD Construction Permit-Page Iengineering estimating practices presented in the EPA Air Pollution Control Cost Manual, Sixth Edition, January 2002. The total annual cost to maintain a 0.095 

### Ib/MMBtu S02 emission level for Unit 2 using a Dry FODlFabric Filter control system is estimated to be $14,685,700. This annual cost results in a cost effectiveness for S02 removed of

### $468/ton when combusting subbituminous coal (See Table 5). 

### Table 5 - Summary ofEmission Rates & 

### Top-Down S02 BACT Analysis Costs Emission Unit Emission Emissions Total Total Cost Control Rate Emissions Reduction Annualized Effectiveness Alternative (LbIMMBtu) (Iblhr) tpy tpy Cost $/yr $/ton Unit 2 Unit 2 Uncontrolled WetFOD (7,774) 1.2 34,048 0.095 (615) 2,695 31,353 18,925,300 604

### =;-i~lSl_~1r;~.4¥~f 

## :: 1.14 Proposed S06 & 

### H6 S04 

### BACT Selection Because the Wet FOD and Dry FOD can produce an equivalent level ofS02 control for this application, and because Dry FOD has a lower annualized cost than Wet FDO, OPPD proposes to use Dry FOD as BACT for S02 emissions from the Unit 2 boiler. Also, Dry FOD has an environmental advantage over Wet FOD in that Dry FOD does not consume as much water and does not produce a wet waste product/slurry. OPPD also proposes the SDAsystem and fabric filter as BACT for control ofH2 S04 emissions, which is considered to be the most effective control and emissions are expected to be reduced

__o_o

__**~~o.o** ..**o_.h¥_apPtoximatel~i)S%nsin.glhe~roposed_contf-Ol~y-stem,_oTh4mposedJlAC'Lemission_limitJok~~~.~o** ..**~.o_.o** ..**~.oooo.~** __**~o~** H2 S04 emissions is 

### 0.0042Ib/MMBtu, which is the same as that permitted for the Council Bluffs Energy Center Unit 4 boiler. Table 3 lists the S02 and H2 S04 emission limitations proposed as BACT under typical operating ranges for the Unit 2 Boiler. For short-termperiods ofspray dryer absorber (SDA) maintenance, higher S02 emissions limits are needed to allow for changeout ofthe SDA atomizer every 3-4 months. The atomizer changeout can be done in a matter ofhours, and in normal cirCl,lmstances, is not expected to affect the ability ofthe unit to meet the above BACT limit on a 30-day rolling average basis. However, to allow for the higher S02 emissions during atomizer changeout, the dispersion modeling for short term (3-hour and 24-hour) averaging periods has been done using higher S02 emission rates to account for only partial control during atomizer changeout. Because the system will have two separate SDA modules, only one ofthese will normally be out ofservice during atomizer changeout, which is expected to take 4 hours or less. The in-service SDA module will be designed to remove 60% ofall S02 when the other module is off-line. Thus, the proposed 3-hour maximum emission rates are based on 60% control, and 24-hour maximum emissions are based on 60% control for 4 hours and full control for the other 20 hours. Therefore, OPPD requests 3-hour and 24-hour average, modeling-based S02limits of0.48 

### Ib/MMBtu (60% control from 

### 1.21b/MMBtu), and 

### 0.1631b/MMBtu, respectively.



### 1.15 BACT Selection Review For S06 & H6 S04 Information concerning recently proposed or permitted coal-fired power projects was obtained from EPA's Clean Air Technology Center (CATC) website, where a list ofnationwide coal-fired power projects has been compiled and is available for downloading at

OPPD Nebraska City Unit 2-58343tDl.doc Fact Sheet-Page 10

## IPollutant Information 

## IRACT/BACT/LAER Clearinghouse 

## IClean AirTechnology Cent... Page 1 of 1

http://cfpub1.epa.qov/rblc/ll1dex.cfm 7action=PerrrlltDetail.PoliutantInfo&.FaCility_ID=26667&Process

...ID= 106121&PoliutanCI D= 1 Last updated on Wednesday, March 31,

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### Pollutant Information Click on the Process Information button to see more information about the process associated with this pollutant. Or click on the Process List button to return to the list of processes.

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## I FINAL
RBLC ID: WY-0063 Corporate/Company: BLACK HILLS CORPORATION Facility Name: WYGEN 3 Process: PC BOILER
Pollutant: Nitrogen Oxides (NOx) CAS Number: 10102
Pollutant Group (s) : Substance Registry System: Nitrogen Oxides (NOx)

Pollution Prevention/Add-on Control Equipment/Both/No Controls Feasible: A

.._-..**-.~ 'P2,lAdd-on~Descriptiom'--SCRltN131()\1ERFlRE1\'IR:---"-'---"'-'----'-'-.-.--**  .. --.-- .-..------..**-.~.-.-.-.-.----** ..-.-..- ......._-.-- ...- .....-

Test Method: Unspecified EPAiOAR Methods 

### I All Olher Melhods

a a

BACT·PSD NSPS**~~€lw~l** 65.0000 LB/R 30 DAY ROLLING a Percent Efficiency: Compliance Verified: EMISSION LIMITS:

Case-by-Case Basis: Other Applicable Requirements: Other Factors Influence Decision: Emission Limit 1: Emission Limit 2: Standard Emission Limit: COST DATA:

Cost Verified? No Dollar Year Used in Cost Estimates: Cost Effectiveness: Incremental Cost Effectiveness: Pollutant Notes:



### http://cfpubl.epa.gov/rblc/index.cfm?action=PermitDetail.PollutantInfo&Facility _ID=266... 3/31/2010

### DEPARTMENT OF ENVIRONMENTAL QUALITY DIVISION OF AIR QUALITY PermitApplication Analysis, NSR-AP-3934 October 9, 2006 

### COMPANY: RESPONsmLE OFFICIAL:
COMl>ANY REPRESENTATIVE:
MAILING ADDRESS:
FACILITY NAME: FACILITY LOCATION:

TYPE OF FACILITY: REVIEVIED 

### B¥:

PURPOSE OF APPLICATION: BlackHills Corporation Mark Lux Vice PI'esidentlGeneral Manager Power Delivery Fred Carl Director Environment and Safety P.O. Box 1400 Rapid City, 

### SD 57709 WYGEN3· 13151 Highway 51 Gillette, Campbell County, WY Coal Fired Electric Power Generating Station 

### Stewart Griller, P.E.· A'iT**~(]afitflSllgitleel** Ken Rairigh, P.E.

- Air Quality Engineer Cole Anderson

- Air Quality Engineer Don Watzel- Air Quality Specialist

Black Hills'Corporation submitted an application to construct a nominal 100 megawatt (MW) coal fired electric power generating station, to be known as WYGEN 3, located at 1315 I Hwy 51, approximately five (5) miles east ofGillette in Campbell County, Wyoming. The proposed facility consists ofone 1,300 MMBtu/hr pulvel'ized coal (PC) boiler with associated coal, lime, and ash handling and will burn subbitum.inous coal from the nearby Wyodak coal mine. The proposed facility will obtain coal through the existing coal handling system and storage silos available atthe WYGEN 2 facility. New coal conveyors to transfer coal from the existing'equipment to the proposed facility will be controlled with dustless fogging systems that resultin .1)0 airemissions. New coal storage silos will be controlled with bin vent filters connected to the lh1it 3 Boilerbaghouse. Lime and ash will be pneumatically transferred to silos also controlled with bin vent filters connectedto'the Unit 3 Boiler baghouse. Therefore, the Unit 3 Boiler baghouse will be the only emission pointassociated with material handling.

. A map ofthe proposed site location for WYGEN 3 is located in Appendix A.Black Hills Corporation, WYGEN 3 Permit Application Analysis, AP·3934 Page 10 

### PC Boiler

- 

### PMIPM IO 

### Black Hills evaluated fabric filters with emission**Iirnjt~fi**

tion is the difference between an estimated uncontrolled emission rate of3.64

### ·'I.a~~i,~rQ'$t~~:t~\1lj.~~i~.~~1:,~~~!~ 

### ..'costeffectiveness is the total

..... ' ., d maintenance costs, divided eness to be reasonable for all

In addition to average cost effectiveness, the draft 1990 New Source Review Workshop Manual provides amethod to evaluate incremental cost effectiveness between dominant options known as the lea!)t cost envelope. Forthis method, a plot ofannual emissions reduction vs. total annualized cost is produced and the dominant control options are indicated by fitting a curve or line through the lower and right most points. Points above and to the left ofthe line are considered inferior controls because points on the line provide more emissions reduction for less money.Black Hills Corporation, WYGEN 3 Permit Application Analysis, AP-3934 Page II Least Cost Envelope for PMIPM IO 

### Least Cost Envelope
4.0 -------. -------



### ..... rn o <...> "C 3.0**+-------------------------:::::;:::..-~7aB_e..;;;f___{** Q,) N

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### 20,6&2 20

..6'94 20.696

. 

### Annual emIssions Re.duction (tpy)



### AIhhree'options**aredomin~ntandthe** 

### following table; The 

### in

_ -

_ . the diffel'encein 

### these values 

### for each is the incremental emissions reduction

-- 

### between options is calculated 

### in the hlcl'easein total annualized cost is TheincrementalcQst effectiveness ental increase in total annuaHzed cost.

## IPollutant Information 

## IRACT/BACT/LAER Clearinghouse 

## IClean AirTechnology Cent... Page 1 of1

http://cfpubl.epa.qov/rblc/lndex.cfrn 7actiol1=PermltDetail.Poliutantlnfo&Facilil:Y.ID =26667&Process

_ID= 1 D6121&Pollutant_.ID= 189 Last updated on Wednesday, Marcil 31, 2010

# @ Technology Transfer Network Clean Air Technology Center
- RACTjBACTjLAER Clearinghouse

You are here: EPA Home Air & Radiation TINWeb
- Technology Transfer Network Clean Air Technology Center RACT/BACT/LAER Clearinghouse RBLC Basic Search RBLC Search Results Pollutant Informat;'''·, 

### Pollutant Information Click on the Process Information button to see more information about the process associated with this pollutant. Or click on the Process List button to return to the list of processes.

Help 

## I FINAL
RBLC 10: WY-0063 Corporate/Company: BLACK HILLS CORPORATION Facility Name: WYGEN 3 Process: PC BOILER

Pollutant: Sulfur Dioxide (S02) CAS Number: 7446-09-5
Pollutant Group (s) : Substance Registry System: Sulfur Dioxide (S02)

Pollution Prevention/Add-on Control Equipment/Both/No Controls Feasible: A

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Test Method: Unspecified EPA/OAR Methods 

## I All Other Methods

o

BACT-PSD NSPS

o $/ton 644 $/ton 0.0900 LB/MMBTU 12 MONTH ROLLING 117.0000 LB/H 30 DAY ROLLING o Percent Efficiency: Compliance Verified: EMISSION LIMITS:

Case-by-Case Basis: Other APplicable Requirements: Other Factors Influence Decision: Emission Limit 1: Emission Limit 2: Standard Emission Limit: COST DATA:

Cost Verified? No Dollar Year Used in Cost Estimates: Cost Effectiveness: Incremental Cost Effectiveness: Pollutant Notes:



### http://cfpubl.epa.gov/rblclindex.cfm?action=PermitDetai1.Pollutantlnfo&Facility_ID=266... 3/31/2010

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Prevention ofSignificant Air Quality Deterioration Review Ofthe LongleafEnergy Associates, LLC LongleafEnergy Station To be located in Early County, Georgia

PRELIMINARY DETERMINATION

SIP Permit Application No. 15846 July 2006

DepartmentofNatural Resources Environmental Protection Division Air Protection Branch

Stationary Source Permitting Program Planning & 

### Support Program (SSPP) Prepared by Anna C. Aponte

- NOx Unit Peter Courtney

- Data & 

### Modeling Unit Reviewed and Approved by: Michelle Keith

- NOx Unit Coordinator James Boylan

- Unit Coordinator, Data James Capp

- SSPP Manager & 

### Modeling Unit Heather Abrams

- Chief. Air Protection BranchPSD Preliminary Determination Page 62 of205



### Sulfuric acid mist emissions are better controlled by a dry scmbber system as compared to awet scrubber. Economic Impacts: 

### The following table illustrates the economic analysis for the wet and dry scrubber systems for CAPP coal.

Baseline is 1% by weight sulfur coal Costs determined fora 600 MW (net) facility with an 85% capacity factor. Wet scrubber assumes 95% removal Dry scrubber assumes 92.7% removal. 

### Incremental Cost Effectiveness ($/ton) . Cost Effectiveness over Baseline ($/ton) Emissions 

### (tpy)

9,228 34,356 Emissions

(lblbr) Table XIV.


### Control Option

-**_--~c** 

### ..**~.~~~~~._--~-~** 

### ..**~c·~::r-nec-feUewiflgc~ctable-c~1Iustr-ates-ccw-ater-.~Qflsumptiml~~fro~J~twQ~Qntt:QLc~~.~c.c~~~c.~_.c~_cc,j.~** 

### technologies. Table XV Summary ofEstimated Water Consumption ofScrubbers for I200 MW Facility , 

### Water Incremental Incremental Control Options Consumption Consumption Consumption % (m**illionl~al/year)** 

### (mUlion gal/year) 

### Wet Scrubber 355 228 161% 

### Drv Scrubber 127 

# ---- ----

# ~~\~~¥~~~~~;t;~~,~:!~;t~iJ]~SiS::: 

# .**bec~&~~;:'~'~~1!~:!~~' waterconsumption,ce~ssiv(feooltomic**  

### impacts and lower ability·to control HAP and sulfuric acid emissions.'

.**'\~~\'** 

### ....**~~~;**FACT SHEET Cargill, Incorporated

650 Industrial Rd Blair, Nebraska September 8, 2006 DESCRIPTION OF THE FACILITYORACTIVITY: Cargill, Inc. (Cargill) operates a com wet milling facility in Washington County nearBlair, Nebraska. The facility produces fructose, ethanol, and com oil as primary products; com germ gluten meal, and fiber

. feed materials as secondary products. In addition tothe com wetmilling facility, the Cargill Blair Complex also includes the following facilities:

• PGLA-I, which is a Cargilljointventure
• NatureWorks, which was originally a Cargilljoint venture (Cargill Dow, LLC) butis now wholly owned by Cargill

• Cargill Polyols, which was originally a Cargilljointventure (M & C Sweeteners) but is now wholly owned by Cargill

• Degussa, which was originally a Cargilljointventure (MidwestLysine) but is now "wholly owned byDegussa

• Purac Cargill is proposing to construct an expansion to theirexisting com wet milling facHity, for which·a PSD**~_~~~_.~~~~~~~permit..wasjssued~on.DecemberS,~2002.~Cat:gillooSubmitted~n~application~for.~e...expamionprojectJn~~~.~~~~~~~~~~-**
, January 2006. Due to design changes in the proposed expansion, Cargill submitted an application revisionon June 16,2006. The proposed project will increase the comprocessing rate for the facility from 200,000 bushels ofcom per dayto 340,000 bushels perday to allow an increase in ethanol production from the current 100 million gallons peryear to 240 million gallons peryear. The project will also include the addition ofa solid fuel-fired steam generating boilerfor the production ofprocess steam. The expansion ofthe corn plant and ethanol production will be primarily accomplished through the addition ofnew emission units/points which, in mostcases, are replicates ofexisting emission points sizedto process the increased cornthroughput of140,000bushels perday. The project will also include a permitted increase to the existing comtruckunloadingbay and several new emission units/points for the conveying and storageofgluten and germ. In addition, capacity for the existing comunloading conveyors (EP 1) will be increased, tanks inthe existingmillhouse (EP 7) will be modified slightly, air flow in the existing fiber flash dryer (EP 12) will be modified to a semi-closedloop recirculating system, and the airflow for the fabric filter for the existing fiber bin filter rece,iver (EP 59) willbe increased. The proposed expansion does not include any changes to the refinery (com syrup production) or germ plant (vegetable oil production), and does not include the addition ofnewtypes ofprocesses orproducts. The addition ofa solidfuel-fired steamgenerating boilerwill consistofa circulating fluidized bed (CFB) boilercapable ofcombusting a variety offuels. Coal from the Powder River Basin (subbituminous) will be the primary fuel for the CFB boiler. The existing natural gas-firedboilers will be retained on site for use primarily during periods ofstartup, shutdown, and malfunction ofthe CFB boiler. The existing permitted limits ofthe natural gas boilers, including operating hours, will be retained by this project.

TYPE AND QUANTITY OF AIR CONTAMINANTEMISSIONS ANTICIPATED: Cargill, Inc.-S7902fll.doc FactSheet-Page I**B~(1;g;iQ'ft'tp~t0'nsafVia~1\i~:t1~¢lfin.'-e',;of2+7\l.b;;~:Q~~tll!** in conjunction with 

### 95 percentcontrol provided**bY;~~** ,".. '.,

.. . ',"

.. . 'J1JInit forthe CFB boilerwas proposed in the draft p '. received during the public noticeperiod, the**V~r;t~use** the te to aleS02 O2 limit

daily tain

tlJ.e permit

.Ox control g the t ,ess analysis was not reviewed for the addition ofthe dry etberadditional control would be cost-effective. With respect 

### '" '. '1;&"

".

. .'

# .$~r~~te catalytic reduction (SCR) systems are an add-on flue gas**trell.tm¢~t·~f¢tGHbgy** to control NO. emissions. The SCRprocess involves the injection ofa nitrogenbas¢d.t¢dmn,l1,gf,igent, such as ammonia, to reduce the NO. in the flue gas to N2and H2 0. The reagent is**.~.** '*;. 

## pel' unstated**reasons,.As;ii::t~'i:lit;** FGDsystem. The permitapplication for

### the<La~ar Utilities Board facility did not propose the use ofa dry FGD system in conjunction with limestone injection. During the permitreview process the EPA commented on the potential for apolishing scrubber(dry FGD) and information was supplied by the permittee to address the site-specific application ofsuch.·The final permit indicated that apolishing scrubberwas costprohibitive**~~~~~** ...**~~** ..**~....** ..**and.had.additionaLde.trimentaLenyjronmeolaL~Q.QQ..l<J1l~Jmc!:las** additj.QJill.l**\Vl!!~LfonsulUption** and waste
.. .. . 

## . ,.**,~._.. ;,~gill)**  

## _._..**_._~~.~**

Cargill, Inc,-57902f11 ,doc FactSheet-Page 12FACT SHEET 

### ArcherDaniels Midland Company 3000 East 8th 

### Street Columbus, Nebraska 68601-9073 August4, 2006 

### DESCRIPTION OF THE FACILITYORACTIVITY: ArcherDaniels Midland Company (ADM) owns and operates a wetcom milling and ethanol production plantlocated at 3000 East 8th 

### Street in Columbus, Nebraska. This plant, owned by MinnesotaCom Processors, LLC until 2002, was constructed in 1991. The plantoperates under primary Standard Industrial Classification (SIC) Code 2046 (WetCom milling) and secondary SIC 2869 (Industrial Organic Chemicals). The facility consists ofthe following majorproduction steps/areas:

• grainreceiving, storing, and wetcom milling;
• germ, gluten, starch separation;
• germ, gluten, and starch drying;
• fermentation and distillation;
• ethanol and denaturant storage and loadout;
• sweeteners production;
• steam generation;

• emergency powergeneration. This permit is intendedto address several outstanding regulatory requirements, as well as to permit expansion ofthe existing ethanol plant. First, this permit addresses requirements contained in aConsent Decree negotiated underUnitedStates v. ADM (C.D. IL, NO. 03-CV-2066), which was filed with the U.S. DistrictCourt

- Central DistrictofIllinois on August 21, 2003. In addition, the facility is planning an expansion oftheir operations, which will increase the capacity ofthis facility from 100 million gallons ofethanol peryearto 120 million gallons ofethanol peryear. Finally, this permit addresses the requirements and associated injunctive reliefrelated to compliance withTitle 129, Chapter27, Section 002 (BestAvailable Control Technology requirements for sources ofhazardous airpollutants) ofthe NebraskaAdministrative Code. The majorregulatory actions required by the Consent Decree which are addressed in this permit include:

• submittal ofaPSD permit application to identify and correct any non-compliance with the National AmbientAirQuality Standards (NAAQS);
• 95%VOC control (orcontrol to 20 ppmvd) on the Germ Dryers, the Millhouse Vent, the Distillation Scrubber Vent, the FermentationVent, and the Stillage MR Vents;
• identification and inclusion/revision ofCO and VOC emission limits forexisting sources; and

., modification and optimization ofexisting control devices and emission units to reduce emissions. Concerning the plantexpansion, this permit authorizes the construction and modification ofthe following emissionunits:

ArcherDaniels MidlandCompany-39285F06.DOC FactSheet·Page I90% \\lith no increase in NO.

_ orCOemissions.

### thet;e'adcled~nvlt&ifnientiI'H~rt€fi~~nlak¢:thelfi'StaHatibn'<Yr:~;~'6f;;

# '~~~;~:~1~~~~~f;j~~~;;~~~{:s,t:l:=I~~~~~:~riZ~:~~~:~~ri~;{f~ti;~J:ttoposes'tba~~~:~~.~~f: As table 1-9 also shows, useofawet scrubberwiH also resultreduction in HAP emissions of1.7 tons peryear. Sincethe wet scrubber has been determinedto be BACTfor VOC, ADM concludes thatBACTfor HAP emissions shouldbe compliance with the VOC BACT limitof1.5 Iblhr.
Table 1-9. Economic, Energy and Environmelltallmpacts of Applying Wet Scrubbing and Thermal Oxidation to tbe Columbus FBGD

BaselineVOC Emissions (tnv) Reduction efticiencv VOCEmis.sions Reduction (tov)**Annuafjz~d** Cost($10") CostEff'e-ctiveness ($Iton) Environmental Impacts

Energy Impacts Thermal**Q~dati()n** -, 32.9 95% 31.2 $2.12 IncreasedNO. Emissions of 9.1 tpy Reduced HAP Emissions of3.1 tPY Net Reduction in CO Emissions of 10.8 tov 1,880 MWH/yrofelectricity consumed 365 -" lamraI l!as consumed 32.9 80% 26.3 $0.14 Reduced S02 emissions of18 tpy. Redl,lced HAP emissions of 1.7 -tPy No impact on NO. orCO emissions 308 MWH/yrof electricity consumed No natural gas Secondary sources ororganic HAP emissions from germ processing are the Germ Cooling baghouses (SV-9 and SV-12). ADMhas conservatively estimated that HAP emissions from these sources are atmost 1.2 Ib/hr in aflow streamof108,000 scfm. These emissions represent organic HAP that may remain in the product afterdrying and then be stripped from the germ by the air used to convey and cool the germ. Because the HAP concentration in this streamis much more dilute than the concentration in the dryerexhaust, the cost ofcontrol will be much higher than thecost ofcontrol for the germ dryers. ADM estimates thatthe HAP control cost-effectiveness ofthermal oxidation forthis combined stream exceeds $750,000 per ton. The added HAP reductions that would be provided by this technology cannotbejustified by ihe high cost ofinstalling and operating additional control equipment on these sources. 1.7.2 CO Control Technology Review Emissions ofCO from the FBGD at the Columbus plantresult from incomplete combustion ofthe natural gas in the dryer's burner. To identifY the types ofCO controls used in similardryers, the RBLC database was searched for germ dryerBACT determinations, from 1994 to present. This review was used to identifY the control technologies that in the past havebeen used in the industry, as well as the accompanying control efficiencies and BACTemission limits ofeach controls listed. The resultS ofthis search as itrelates to CO emissions are summarized inTable 1-10. As shown, for CO, the only control technology identified for germ dryers is the use ofcombustion control. Another CO control technology known to be used on corn mill dryers is thermal oxidation. However, as described earlier, the use ofthermal oxidation will produce additional CO emissions from the combustion ofauxiliary fuel. Assuming aCO emissions factor of84 IbIMMSCF(AP-42, Table 1.4-1, 7/98 edition), athermal oxidizer is projected to produce about 2.8lb/hr ofCO emissions from the gas combusted in the oxidizerburner. The current baseline CO emissions limit for this dryer is 5.9 Iblhr and the increase in capacity is projected to result in aCO emissions limitof

Archer Daniels Midland Company-39285F06,DOC Fact Sheet-Appendix B-Page 14

### Table 1-4. Economic, Energy, and Environmental Impacts ofSNCR Technology

SNCR CONTROL LEVEL, Ib/MMBtu 7 0.05* 

## .". 0.15 ECONOMIC IMPACTS Total Capital Requirement: $1,227,951 $1,203,169 $1,190,778 Annual Fixed O&M Costs: $82,426 $82,42 $82,426 Annual in Variable O&M Costs: $1,101,156 $566,054 $283,939 Capital Recovery Costs: $143,670 $140,771 $139,321 Total Annual Costs: $1,327,252 $789,251 $505,687 4 

# _., $2,694 $3,077 '

.. :**~,.~"** Incremental NO, Reduction Cost Effectiveness: $5,555 $2,174 ENERGY IMPACTS NH3 /NO, ratio: 4 2 I MMBtu/hr Boiler Efficiency Penalty: 37 19 10 ENVIRONMENTAL IMPACTS Tons per Year NO, Emissions: 159 122 476 Tons per Year NO, Reduction: 493 427 164 NH3 PPM: 20 <10 <5 Tons per Year ofNH3Slip: 43 22 II TonsJler Year ofIncreased Particulate:

__ 168 42 21
.- - Annual Emissions Reduction (NO,-NH3-PM IO): 282 363 132 *Not considered to be technically feasible due to increased opacity and fabric filter plugging from high levels of ammonium salt formation. Cost impacts do not include increase in system pressure drop due to fabric filter plugging and more frequent bag filter replacement. Note: All calculations are on a per boiler basis. 1.1.6.1 Economic Impacts ofSNCR To assess the economic costs ofSNCR, the U.S. EPA Coal Utility Environmental Cost (CUECost) model was used. Energy costs include power cost for the increased baghouse pressure drop, steam to assist with the injection of ammonia, and electrical costs for operation ofthe ammonia injection system. The capital cost ofthe three SNCR systems varies only slightly as a function ofthe ammonia injection rates required for the three levels ofcontrol. The assumed molar ratios for the three levels ofcontrol are; 1.0 for the 0.15 Ib/MMBtu case, 2.0 for the 0.07Ib/MMBtu case, and 4.0 for the 0.05 Ib/MMBtu case. The primary difference in annual cost between the three cases is due to the injection steam requirement, which is assumed to vary proportionately with ammonia flow. 1.1.6.2 Energy and Environmental Impacts ofSNCR The energy impact component for each case comprises injection steam usage, fan power requirements (for increased pressure drop due to ammonium sulfate buildup on the baghouse fabric filter), and the electrical energy requirement for the ammonia system. The injection steam requirement accounts for approximately 80 percent ofthe energy requirement. The environmental impact for each case identifies the NO, emissions decreases along with the corresponding increases in ammonia slip, particulate emissions and opacity. The increase in ammonia slip results from the higher ammonia to NOx ratio required to achieve the higher reduction levels. The increased particulate emissions result
Archer Daniels Midland Company-39285F06.DOC Fact Sheet-Appendix D-Page 8from the reaction ofslip ammonia with S03 to form ammonium salts. The increased presence ofthe ammonium salts is the cause ofthe increase in stack opacity. In an effort to quantify the overall impact ofNOx emission reductions with increase in ammonia slip and fine particulates, the change in total annual emissions ofthese three pollutants (NO" NH3 , PM IO) is calculated by subtracting the estimated emissions ofammonia and ammonium sulfate (fine particulate matter) from the decrease in NOx emissions. This calculation shows that the overall emissions impact ofreducing NO, emissions from 0.07Ib/MMBtu to 0.05 Ib/MMBtu is negative. In other words, the decrease in tons ofNO, emissions is more than offset by an increase in the tons ofNH3and particulate matter emissions. 1.1.7 Proposed BACT Limit for NOx Emissions

### ~~Jj:g~liIDJj);Ml~J1'1f11jJm~lfa1tfl~@1r~41iia The BACT selection rationale follows: SCR is considered technically infeasible for the proposed CFB at the Columbus facility because the catalyst will be rapidly deactivated due to:

• The poisoning effect ofcalcium oxide, a strong alkali, on the catalyst acidic reactive sites; and

• The fouling effect ofthe high particulate loading in the flue gas path where the SCR must be located to be in the proper operating temperature range. SNCR control levels less than 0.07 Ib/MMBtu are rejected as BACT based on the following environmental impacts:

• Stack opacity increases by 10 percentage points «10% to 20% opacity) or more;
• Ammonia slip level increases above 10 ppm increase condensable PM emissions downstream; 

## • lpressure drop due to fabric filter plugging and the costs ofmore frequent replacement ofplugged filter

• The increases in fine particulate matter and ammonia emissions make the proposed BACT limit for particulate matter unattainable. The proposed NO, BACT limit below is based on an emission rate of0.07 Ib/MMBtu: Pollutant Emission Limit Compliance Demonstration NO,**Bllbilm~** per boiler; 30-day rolling average using continuous monitor; excluding**'1':-)};,;;~:~** periods of"cold startup"l NH3 10ppm appropriate stack test methods

1.2 Sulfur Dioxide, Sulfuric Acid Mist (H2S04), and Fluoride (F) Control Technology Review Emissions ofS02 result from the oxidation offuel sulfur. During combustion, the majority ofthe fuel sulfur is emitted as S02. A portion ofthe fuel sulfur is further oxidized to S03. At temperatures below about 600°F, sulfur trioxide readily combines with moisture in the flue gas or in the atmosphere to form H2 S04. Emissions ofF result from the volatilization offluorides contained in solid fuels and limestone. During combustion, the majority ofthe

1 A cold startup period is defined as that period oftime when a CFB boiler is proceeding to increase the

temperature in the lower combustor from less than 400°F to at least l500°F. This period shall last no more than 48 hours and NOx emissions data from this period shall be excluded when determining compliance with the proposed BACT limits. Ammonia injection shall begin as soon as the lower combustor temperature reaches 1500°F and the cold startup period will end at this time. All data from cold startup periods after the first 48 hours, or while ammonia is injected in the boiler, will be included in determining compliance with the BACT limit. Archer Daniels Midland Company-39285F06.DOC Fact Sheet-Appendix D-Page 9

### Table 1-7. Economic, Energy, and Environmental Impacts ofFGD Technology plus LI
CONTROL @ Ib S02/MMBtu WFGD@ SDFGD@ DIFGD@ ALI @ 0.20 0.025 0.063 0.125 ECONOMIC IMPACTS Total Capital Requirement: $45,855,419 $30,070,051 $21,061,726 $0* Annual Fixed O&M Costs: $3,061,294 $2,121,594 $1,629,351 $346,900* Annual Variable O&M Costs: $405,830 $193,234 $247,951 $755,225* Capital Recovery Annual Costs: $5,794,821 $3,518,196 $2,464,222 0* Total Annual Costs: $9,261,946 $5,833,024 $4,341,524 $1,102,125* Cost Effectiveness over L1: $12,691 $9,591 $10,708 $6,710 ENERGY IMPACTS MMBtu/hr ofElectricity: 19.4 5.3 5.3 0* ENVIRONMENTAL IMPACTS

Annual S02 Reduction over L1. tons: 730 608 405 164 Annual Increase Solid Waste over L1. 2,514 1,971 2,606 16,848 tons: *Incremental costs over LI @ 0.25 Ib/MMBtu Note: All calculations are on a per boiler basis. 1.2.7.1 To assess the economic costs ofa WFGD system, the U.S. EPA CUECost model was used. The economics ofthe WFGD S02 control system are based on the CUECost Limestone Forced Oxidation system. A 90 percent reduction for WFGO (instead of95%) was assumed due to the low inlet S02 concentration. Additionally because particulate emissions from a wet FGD system can not achieve aparticulate matter emission limit of0.0 15, the costs ofa wet ESP to reduce WFGO particulate matter emissions to 0.015 Ib/MMBtu are estimated using the CUECost dry ESP model. Although CUECost does not have a wet ESP control option, the cost ofa conventional ESP was developed based on an inlet particulate matter loading of0.03 Ib/MMBtu. To assess the economic costs ofa SDFGD system, the U.S. EPA CUECost model was used. The economics ofthe SDFGD S02 control system are based on the CUECost Lime Spray Dryer system. A 75 percent reduction for SDFGD (instead of90%) was assumed due to the low inlet S02 concentration. The fabric filter baghouse costs to reduce SDFGD particulate matter emissions to 0.015 Ib/MMBtu are not included because a fabric filter baghouse system is considered as part ofthe base cost ofthe project for particulate matter control and for a new application, the spray dryer absorbers can be located before the baghouse. The baghouse solids handling equipment (e.g., hoppers) would need to be upsized somewhat to handle the increased solids loading, but this cost isjudged to be minor. To assess the economic costs ofa DIFGO system, the U.S. EPA CUECost model was used. The economics ofthe DIFGD S02 control system are based on the CUECost Lime Spray Dryer system excluding the cost ofthe spray dryer absorber. A 50 percent reduction for DIFGD was assumed due to the low inlet S02 concentration. The fabric filter baghouse costs to reduce DIFGD particulate matter emissions to 0.015 Ib/MMBtu are not included because a fabric filter baghouse system is considered as part ofthe base cost ofthe project for particulate matter control and for a new application, the duct injection can be located before the baghouse. Again, the baghouse solids handling equipment would need to be upsized to accommodate the increased solids loading.

Archer Daniels Midland Company-39285F06.DOC Fact Sheet-Appendix D-Page 18To account for 90.0 percent reduction ofS02 in the CFB boilerusing LI, the CUECost "user specified coal" option was used by inputting coal parameters for western and Midwestern bituminous coals and TDF adjusted to reduce the coal sulfur content by 90.0 percent. The cost for additional limestone injection was estimated based on the increased cost oflimestone for the increased calcium to sulfur ratio necessary for the increased S02 reduction and the increased waste generated by the increased limestone usage and S02 removal. 1.2.7.2 S02/H2S04/HF Energy and Environmental Impacts Energy impacts for the FGD technologies are due to increased the pressure drop across the flue gas contactor (scrubber, absorber, or ductwork), lime/limestone handling/preparation, waste handling, and the operation ofthe wet ESP, The WFGD system combined with a wet ESP results in the greatest increase in energy requirements due to the higher increased pressure drop relative to the other control options and due to the much higher energy requirements for processing limestone versus lime. The environmental impacts for the FGD technologies and ALI are dominated by the increase in solid waste. This increase is the highest with the ALI and DIFGD because the calcium utilization ofthese processes is much lower than for WFGD and SDFGD. Note, the WFGD produces a wet scrubber sludge, which could require special handling and disposal ifthe moisture content ofthe waste exceeds 10-15 percent due to operational problems, Assuming no flue gas reheat, the WFGD will produce a saturated stack plume which would have a negative aesthetic impact and could produce fogging and icing conditions under certain meteorological conditions. This is not an issue with the other control options, One advantage to the combination ofwet FGD and wet ESP might be a slight decrease in emissions ofF and H2 S04 over the other S02 control options, However, quantification ofthis benefit is not feasible considering the low expected emissions ofthese pollutants under any ofthe S02 scenarios evaluated. 1.2.8 Proposed BACT Limit for S02, H2 S04 , and F Emissions Based on the above analysis, ADM proposes LI at 90 percent overall S02, H2 S04, and F emission control as BACT. The BACT selection rationale follows: LI plus Wet FGD is rejected as BACT because ofthe:

• High incremental cost effectiveness ofapproximately $28,000 per ton over LI+SDFGD, ofapproximately $15,000 per ton over LI+DIFGD, and ofapproximately $13,000 per ton over LI;

• Increased energy requirements over LI+SDFGD, LI+DIFGD, ALI, and LI; and

• Increased waste disposal requirements over LI+LSFGD, LI+DIFGD, and LI, LI plus SDFGD is rejected as BACT because ofthe:



## •

• Increased energy requirements over LI; and

• Increased waste disposal over LI. LI plus DIFGD is rejected as BACT because ofthe:



## •

• Increased energy requirements over LI; and

• Increased waste disposal over LI. ALI is rejected as BACT because ofthe:
Archer Daniels Midland Company-39285F06.DOC Fact Sheet-Appendix D-Page 19

## •**~,.,IDftr~'~fl~~~gR,t~!lm'~1~~~it9~;** • Increased waste disposal over LI. Thus, ADM proposes BACT limits for SOz, Hz S04, and F of:

F 7,2 Ib/hour; use of limestone injection and

ba house as control 0.9 Ib/hour; use of limestone injection and

ba house as control Com Hance Demonstration per boiler 30-day rolling average using continuous monitoring as required by NSPS Subpart Db;
perboiler

- compliance determined using USEPA reference Method 8; and
per boiler.,- compliance determined using USEPA reference Method 13,

The emission rate for Hz S04 and F are difficult to determine because the available information on Hz S04 and F removals for different types ofSOz control devices are highly variable, As such, Table 1-8 summarizing the HzS04 and F BACT limits identified for CFB boilers since 1992 is used as the basis for selecting the BACT emission limits for Hz S04 and F, ADM proposes limestone injection with baghouse control as BACT for HzS04 emissions. A review ofTable 1-8, which presents the results ofthe RBLC review and review ofother permits, shows that Hz S04 permit limits range from 0,0I0 Ib/MMBtu to 0.015 Ib/MMBtu. ADM proposes aper boiler BACT limitation of7.5 pounds per hour, This limit is equal to a HzS04 emission rate of0.010 Ib/MMBtu.**-~~-'-"~~"-~"'~Ai')Jvt~prop~o~eB""time"St(Jrre~trrje'ctiun'with"baghous-e-c;(Jntrul~a:S"·BA.e'f·forFemtsstol1S:·~A-revtew\Jf'fattei~.:8';·whtch···~--·~-·--···** presents the results ofthe RBLC review and review ofother permits, shows that F permit limits range from 0.0004 Ib/MMBtu to 0.0053 IbIMMBtu. ADM proposes a per boiler BACT limitation of0.9 pounds per hour. This limit is equal to a F emission rate of0.0012 Ib/MMBtu. This limit is consistent with a recent BACT emissions limit found in Table 1-8. Table 1-8. Summary ofEmission Limits Identified in Recent BACT Determinations for CFB Boilers RBLC Permit Company/Facility ID Date SOz Limit H2S04 Limit HF Limit Enviropower Benton,IL· 07/03/01 0,25 Ib/MMBtu No limit 9.6 tons/yr (0.0004 Ib/MMBtu)* Kentucky Mountain Power, LLC Ary, KY· 05/04/01 0,13 Ib/MMBtu O.OIOlb/MMBtu 0,0053 Ib/MMBtu
lEA NORTHSIDE GENERATING STATION FL-0178 7/14/1999 0,2 Ib/MMBtu No limit No limit
ARCHER DANIELS MIDLAND COMPANY lL-0060 12/2411998 0,71b/MMBtu No limit No limit Decatur Units 9 & 10 ARCHER DANIELS MIDLAND COMPANY IA-0051 6/3011998 0,36 Ib/MMBtu No limit 0,00121b/MMBtu Cedar Rapids Unit 5 ARCHER DANIELS MIDLAND COMPANY IA-0046 6/30/1998 0.36 Ib/MMBtu No limit 0,00121b/MMBtu Cedar Rapids Unit 6 TOLEDO EDISON CO.

- BAYSHORE PLANT OH-023I 6/20/1997 0,73 Ib/MMBtu No limit No limit

Archer Daniels Midland Company-39285F06,DOC Fact Sheet-Appendix D-Page 20- .. '

0< 

### DEPARTMENT OF :ENVIRONMENTAL QUALITY DIVISION OFAIR QUALITY 

### Permit Application Analysis, NSR-AP-3546 

### February 5, 2007 COMPANY: MAILING ADDRESS:

RESPONSIBLE OFFICIAL:

FACILITY NAME: FACILITY LOCATION:

TYPE OFFACILITY: 

### Basin Electric Power Cooperative 1717 East Lnterstate Avenue Bismarck, ND 58503 Jerry Menge ._ Ail: Quality Program Coordinator (701) 355-5655 Dry Fork Station Highway 59, Approximately 7 Miles North Northeast ofGiBette, Campbell County, WY

. Coal Fired Electric Power Generating Station REVIEWED BY: 

### Stewart Griner-Air Quality Engineer**-~-~~~--~-~~~---~~-~~~~~~~~----~-~-------~------~~------------~--~ce:1c7'i:AEteFso~ Kit~HaJit~!-ER-g:Hroor**  

### Don Watzel- Air Quality Specialist PURPOSE OF APPLICATION: 

### Basin Electric submitted an application to construct acoal fired electric-power generating station adjacent to the Dry Fork Mine on Highway 59, approximately 7 miles north nOltheast

# ofGillette, Campbell County, Wyoming. Amap ofthe proposed site location is included in Appendix A. °The proposedfacility includes one pulverized coal (PC) boilerrated at422 MW (gross) and 385 MW (net) with associated material handling and auxiliary equipment. The maximum design heat input for the PC boiler is 3,80I MMBtu/hr. The design values used for coal fi'om Dry Fork Mine include aheatvalue of8,045 Btu/lb (7,800 Btu/lb minimum to 8,300 Btu/lb 

### maximum) and a sulfurcontent of0.33% (0.25% minimum to 0.47% maximum). Material handling will include coal, lime, flyash, bottom ash, and waste pmduct from the flue gas desulfurization (FGD) system. Auxiliary equipmentwill inciudean 8.36 ' MMBtu/hr Inlet Gas Heater, a 360 hp Fire Pump, and a 2377 hpEmergency Generator. The application identifiedthe following emission units:'.,

Basin Electric, Dry Fork Station PennitApplication Analysis, AP-3546 Page 6

,rating

that 0.056 Ib/MMBtu is the lowestfeasible emission limit.

., . itting approximately 0.030 to 0.045 'at this point in the review, what a 

### " evel and an emission limit. The**'~llrget** emission levels. An analysis ofcost effectiveness for the design target emission levels in the previous table was performed**_~** .. ....,_ .._

.._**.~~** ..**~.aJ1!Lth~Lr~~l,lltL!!re shoV(nJ1~JQ.\I,I.,.** **Th~** ellljssions**!:.~.!!p!!onj~ tl!.~.differenc~~** **betY"e~n a.Eas~lin~~IlJ~~l~~l~**  ..**~;** .. .._..... ... .._.. ra .**w.~,q~¥fire** air and the controlled emission rate using S . "

. ',' ,'. rthe option, including capital cost and 

# ·=:i:i::Z;IS

7.5 

### 8.7

ew Source Review Workshop Manual provides en dominant options known as the least cost uction ys. total annualized cost is produced and

, ed by fitting a curve or line through the lower and right most point<;, Poi

..

### .!'**'~** 

### ". eline are considered inferior controls because points onthe line provide more emissions reduction for less money, The least cost envelope is shown below:Basin Electi'ic, Dry 

### Fork Station Permit Application Analysis,**AP~3546** Page 8 

### At this point in the review, it was necessary to determine a reasonable margin between the design target emission level and an emission limit. Further discussions with Basin Electric and catalystvendors indicated thlit are several issues that necessitate a margin ofsafety as discussed below: I. 

### Emission guarantees below 0.05 

### Ib/MMBtu are associated with high ammonia (NH) 

### slip values that cause problems elsewhere in the plant. Excess NH

### 3slip reacts with S03 in the flue gas to generate ammonium sulfate and ammonium.bisulfate which deactivate the SCR 

### catalyst, contribute tQ pluggage ofthe downstream air heater, and may result in an increase in particulate matter emissions. A portion ofthe excess NH3 

### slip will be captured with the fly ash anQ may result in ammonia offgassing during handling and in the landfill. 2. Increasing the catalyst activity to increase NOx reduction or reduce NH3 

### slip may result in additional conversion ofS02 to SO) and react with water in the flue gas to form sulfuric acid mist. The ·additional S03 may also increase gelieration ofammonium sulfate and ammonium bisulfate with the associated problems described above.

. . . 

### 3. Emission levels will increase somewhat during catalystchange outs. Catalysts are typically**~hanged** 

### by moving the second layer ofcatalyst (second to come in contact with the flue gas) into the first**laye~** 

### position and putting fi'eshcatalyst in the second layerposition. This is done one section at a time while the plant is on line and**~esults** 

### in somewhat higheremissions during the change out. jJ;reed to an annual average emission limit of0.05



### ......**ase,t()n~** 

### .**.s(lLMMB.tuLhu.nd.O~.05~~** 

### _.. .. .. (i.e. design target) will be in the range of 1.5% S02 to S03 oxidation (maximum). t-!rget due to the nature ofthe limits and the inimizes the effects ofemission spikes. The

..... exibility than a Ib/MMBtu limit and allows the 

## .b.'¥**;~~~** 

### power output. Emissions in Ib/MMBtl1.do not

PC Hoiler

- 

### S02 Basin Electric evaluated the fol.lowing emission control technologies: I. Wet Flue Gas DesuIfurization (FGD)

- For wet FOD, S02 is reacted with a limestone or lime slurry to produce calcium sulfite or**cal~.i"** 

### urn). Forced ox.idation is commonly used to assure thatonly calcium sulfate is p '.' 

### 'Wr;':":,"**":"~ciency** 

### but uses more water than dry FGD and has**~",** 

### .**".~Jt;:** 

## . "kS';mff.j!itieremissions of'

. particulate matter compared**tQ.~~~~~** 

### the palticulate removal device must be upstream of the wet FGD. Wet FGD also has lower removai efficiencies for acid gases and may result in hi'gher mercury emissions.

.

# .. Basin Electric, Dry Fork Station Pennit Application Analysis, AP-3546 Page 10

Case Design Target Emission Levell Averaae CostEffectiveness for 

### 80 2 Emissions Total Reduction ' Annualized Cost

. t 

### Million $ 12303 14.3 12436 15.5 12503 17.7 12619 19.0 12753 20.3 posed emission limits by 123%[01' SDA and

# r FGD. In addition to**averag~cost** effectiveness, the draft 1990 New Source Review Workshop Manual provides a method to. evaluate incremental costeffectiveness between dominant options known as the least cost envelope. For this method, a plotofannual emissions reduction vs. total annualized cost is produced and the dominant control options are indicated by fitting a curve or line through the lower and right most points as shciwn below. Points above and to the left ofthe line are considered inferior controls because points on the,line provide more emissions reduction for less money.
Least Cost Envelope for S02
22. 0**~"':;r""""""""""""-----~------------------'------'---''''''''''----'--'''-"-o** .f**21.0;)'~.i!.,~~,::,::,;;;""',''''''''.''** ",",.,";-"",-,**----;,;;.:~,~:".:,..-, ~----------------~"""'-"""""'~~~""'-!** **:';...#;;Q~~~6** 

# § 200" 

# /j
19.0 ':'[1' 

# 7 ---:'\

,; 18.0 

# -I----'-.,'------------------+--------..ol.l +case3/ 

# i 17.0 

### +-

_____'___'

__**~--~L----'----~------.::,** 

# j 160

# -I-----------~----a-s.."e,.L.2:..,----------------r 15 0**+------~----=-..::::..-----------------------<1**

### ~o· :J ase 1 j

.... 14.0 

### +---'----..;;..;..--:.----------,--------------11 

# 1 13.0 

# -1------------------'--------------'

12800 12700 12400 12500 12600 Annual Emissions Reduction (tpy) 12300 12.0 

### +-----r------.r-------,---'----,------.------: 12200

### Basin Electric, Dry Fork Station Pennil Application Analysis, AP-3546 Page 11 The dominant options are Cases I (SDA @ 0.081 [b/MMBtu), 

### 2 (SDA @ 0.073 Ib/MMBtu), and 5 (Wet FGD 

### @**0.054'lh~~JJ.f ,r1le.t~e.'t3\~loost**  

### effectiveness for the dominant options is calculated in the following"

.... ,. ..'." .'**'~m~~l1:s** 

### reduction and incremental increase in total annualized cost is the d'

. . ..**,":~;~ption** 

### from the previous table. The incremental cost
.

### effectivenes~i~>i~'~_1 annualized costdivided by the incremental emissions reduction.

. j '.""

.


### Incremental Cost Effectiveness s for 

### S02 Options Compared

five (;)n 

# :r usage, visible moisture plume, hi T.

.. Y

### for acid gases, and possibly higher mercury emissions).**Th~;itW:l~~$if~'** 

### is considered reasonable for SDA 

### with adesign target emission level of0.073 Ib/MMBtu.**-~,-~~~~~~~~A£~wiLJilinx.jLYia£,AecessaJ:y~to~determioe~,re,as,onahle~mJl.rgiDj2~t~ILtb~~J:!e§lg!11~[g~j:,,~rnj§§l9lU~Y£L~,~,,~~~,~~~,~**


### , ana an emISSion limit at thispotnt l.n the revIew. FUliherdiSCUSSions with BaSin Electnc IOcltcated that are several issues that necessitate amargin ofsafety as discussed below: I) Basin Electric stpted that the lowest emission guarantee available for SDA 

### is 94% removal with a floor of0.08 IblMMBtu (regardless ofS02 loading). With an S02 loading of1.33 Ib/MMBtu,94% removal results in an emission level of0.08 Ib/MMBtu. Basin stated that vendors will guarantee 94% removal with S02 loadings above 1.33 IblMMBtu 

### butwill not guarantee less than 0.08 Ib/MMBtu**(~quivalcnt** 

### to an S02 concentration ofapproximately 40 PPITIv @ 

### 3% 02) 

### with lower S02 loadings. Basin Electric originally established a performance target(Le. design target) of0.073 Ib/lYlMBtu based ol1'an SO,- loading of 1.21 

### Ib/MMBtu and 94% removal but subseq!Jently learned that 0.073 Ib/MMBtu is below the tloor of0.08 

### Ib/MMBtu for an emission guarantee. 2) 

### Injecting additional lime slurry and/or operating the system at an outlet temperature approaching saturation may increase S02 removal but the slurry feed rate is limited by the requirement to operate the SIJA 

### above saturation temperature and produce adry by-product. Operating the SDA at or below 

### the design limit increases the potential for operating issues including wall wetting, scaling, plugging, and operational problems with the downstream fabric filter.

. As a result oft,hese discussions, Basin Electric agreed to al

....

### ~mission limitof0.08 lb/MM

### Btu with a 30 day rolling average limit of304.1**Ib/h'f(b~~(fu'** 

### 3;30'1' MMBtu/hr and 0.08 Ib/MMBtu). As with**NOx~** 

## a I.b/hrlimit for the 30 day averaging period provides more flexibility and allows the facility t' '.

. ., quickly by lowering power output. Emissions in Ib/MMBtu do not n r output.**http://dp~Jr).epa** .qov/rblc/cfm/facdetl.cfrn**"lfaCJ'IUrn-~:** 26790 Last updated on Monday, November 16th, 2.009. 

## i Facility Information 

## IRACT/BACT/LAER Clearinghouse 

## IClean Air Technology Cente... Page 1 of2

Technology Transfer Network Clean Air Technology Center
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You are here: EPA**HOlIl~** Air & Radiation TTNWeb
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RACT/BACT/LAER Clearinghouse RBLC Basic Search. RBLC Search Results Facility Information 

## Facilit Information To learn more about the processes associated with this facility, click the Process list button. You can then view pollutant information for each process.

Date Entered: 02/19/2008

RBLC 10: WY-0064 Corporate/Company: BASIN ELECTRIC POWER COOPERATIVE Facility Name: DRY FORK STATION Facility Description: ONE PC BOILER RATED A 385 MW (NET)
State: WY County: CAMPBELL EPA Region: 8 Facility Contact Information:

Name: JERRY MENGE Phone: 7013555655

Agency Contact Information:

Agency: WY001

- WYOMING AIR QUAL DIV, DEPT OF ENV QUAI, Contact: MR. ANDREW KEYFAUVER Address:WY DEQ AIR QUALITY DIVISION 122 WEST 25TH STREET CHEYENNE, WY 82002 Phone: (307) 777-7340 Other AgencYCHAD SCHLICTEMEIER, NSR PROGRAM MANAGER Contact Info: Help 

## I Date Last Modified: 04/20/2009 DRAFT

Zip Code: 82716

Country: USA

E-Mail:

Permit Number: CT-4631

Permit Type: A: NEW/GREENFIELD FACILITY

Affected Class 1/ U.S. Border Area:

Distance to Area
180 kIn 220 kIn EST/ACT DATE Application Accepted Date: ACT 08/18/2006 Permit Date: ACT 10/15/2007

FRS Number: 110024429714 SIC: 4911 NAICS: 237130

Area Name
Wind Cave NP, SD Badlands, SD



### http://cfpub.epa.gov/rblc/cfm/facdetl.cfm?facnum=26790 11/16/2009

## IFacility Information 

## IRACT/BACT/LAER Clearinghouse 

## IClean Air Technology Cente... Page 2 of2

Facility-Wide Emission Increase/Decrease: (After prevention/control measures)

Pollutant Particulate Matter (PM) Sulfur Oxides (SOx) Volatile Organic Compounds (VOe) Carbon Monoxide Nitrogen Oxides (NOx)

Other Permitting Information: Increase (+)/Decrease (-), Tons/Year
225.9000 1165.4000 61.6000 2508.5000 837.8000



### http://cfpub.epa.gov/rblc/cfm/facdetl.cfm?facnum=26790 11/16/2009

## IPollutant Infonnation 

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## IClean Air Technology Cent.

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http://efpu!) .epa .qov/rblc/cfm/PoltDetl.cfll1**?facnunl~"** 26790&Procnum**~·1** 06469&poltnum o, 146305 Last updated on Monday, November 16th, 2009. Technology Transfer Network Clean Air Technology Center
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## Pollutant Information Click on the Process Information button to see more information about the process associated with this pollutant. Or click on the Process List button to return to the list of processes.

Help 

## I DRAFT
RBLC 10: WY-0064 Corporate/Company: BASIN ELECTRIC POWER COOPERATIVE Facility Name: DRY FORK STATION Process: PC BOILER (ES1-Ol)
Pollutant: Nitrogen Oxides (NOx) CAS Number: 10102 Pollution Prevention/Add-on Control Equipment/Both/No Controls Feasible: A P2/Add-on Description: LOW NOX BURNERS AND SCR

Test Method: Unspecified EPA/OAR Methods 

## I All other Methods
Estimated % Efficiency: Compliance Verified: EMISSION LIMITS: Basis: Other Applicable Requirements: Other Factors Influence Decision: Emission Limit 1: Emission Limit 2: Standardized: UNKNOWN BACT-PSD NSPS, MACT Unknown 0.0500 LB/MMBTU 12 MONTH ROLLING 190,1000 LB/H 30-DAY ROLLING 832,4000 T/YR ANNUAL COST DATA: Verified by Agency?Yes Year Used in Cost Estimates: 2006 Cost Effectiveness: 1,200,700 $/ton Incremental Cost Effectiveness: 10,303 $/ton
Pollutant Notes:



### http://cfpub.epa.gov/rblc/cfmJPoltDetl.cfm?facnum=26790&Procnum=106469&poltnum...11/1612009

# I

# li~~GS**A-\(~ od~**  \N'NIN

.

# c\.e~ <; 

# -tCl:\-e.., 'M-t \}<;,

# I'A,

..Ii!\AO.l.

# \-Dj I Mill

# per

# ";<Is~ MONTANA AIR QUALITY PERMIT 

# 34-23-00

.

# pdfIssued To: Southern Montana Electric Pennit: #3423-00 Generation and Transmission Cooperative

- Application Complete: 5/16/06 Highwood Generating Station Preliminary Determination Issued: 3/30/06 3521 Gabel Road, Suite 5 Supplemental Preliminary Determination Billings, MT 59102 Issued: 6/22/06 Department's Decision Issued: 05/11107 PennitFinal: AFS #013-0038 An air quality permit, with conditions, is hereby granted to SouthernMontanaElectric Generation and Transmission Cooperative

- Highwood Generating Station (SME-HGS), pursuantto Sections 75-2-204 and 211 ofthe Montana Code Annotated (MCA), as amended, and Administrative Rules ofMontana (ARM) 17.8.740, 

### etseq., as amended, for the following: SECTION I: Permitted Facilities 

### A. Permitted Equipment SME-HGS operates a gross 270-megawatt (MW) electrical power generating plant. The SME-HGS facility is a coal-fired stearn/electric generating station incorporating a circulating fluidized bedboiler (CFB Boiler). Auxiliary powerto operate the facility is estimated to be approximately 20 MW resulting in an approximate netpowerproduction· capacity of250 MW. Emissions from the CFB-Boiler are controlledby CFB limestone injection technology, a fabric filterbaghouse (FFB), a hydrated ash re-injection system



### .. ..**~...** 

### (HAR),.Jnl(:La

..**s.e.le.c.tiY.e~no.n:.ca.talyj:ic.:tedus;Jion~unit(Sl:~ICR).JhsLtQlaLCEll:ItQileL** ..**~~ ~.**  emission control strategy is characterized as an integrated emission control system (lECS). A complete list ofpennitted equipment/emission sources is contained in Section LA ofthe pennit analysis to this permit. B. Plant Location The SME-HGS plant encompasses approximately720 acres ofproperty and is located approximately 8 miles east ofGreat Falls, Montatla, and approximately 1.5 miles southeast ofthe Morony Dam on the Missouri River. The legal description ofthe site is in Section 24 and 25, Township 21 North, Range 5 East, M.P.M., in Cascade County, Montana. The approximate universal transverse mercator (UTM) coordinates are Zone 12, Easting 497 kilometers (km), and Northing 5,268 km. The site elevation is approximately 3,290 feet above sea level. C. CurrentPermitAction The Department ofEnvironmental Quality (Department) issued its preliminary determination on air quality Permit#3423-00 on March 30, 2006, and accepted comments on the preliminary determination through May 1, 2006. Further, on April 25, 2006, Bison Engineering, Inc., on behalfofSME-HGS, verbally notified the Department ofadditional emitting units that were notpreviously analyzed andpermittedunderthe preliminary determination and were deemed necessary for the construction and operation ofthe CFB Boiler. Specifically, SME-HGS detennined that during the CFB Boilerconstruction phase andperiodically thereafter, as necessary, SME-HGS would need to operate portable/ temporary propane-firedheaters for the purpose ofcuring the CFB Boilerrefractory brick. SME-HGS submitted an application for the proposed additional emitting units on May 16, 2006, and the Department issued a supplemental preliminary determination on Pennit 3423-00 1 DO: 05/11/07atmosphere. Anothernegative environmental impact associated with awet FGD system is related to waterusage. A wet FGD system uses approximately 20% more water than a dry FGD. Both wet and dry systems produce solid waste streams containing fly ash and spent lime orlimestone and these wastes are generally disposed ofin a landfill area or stored in surface impoundments. The wet dual-alkali system uses sodium-based chemicals, which generates a less stable sludge than wet lime/limestone scrubber sludge. This can create material handling and disposal issues ofconcern. Even though wetFGD systems use more water and generate a wastewater sludge, wetFGD systems cannotbe eliminatedfrom further investigation underthe BACT analysis and are therefore evaluated further for economic and energy impacts. The dual-alkali wet scrubberwill be eliminatedfrom further investigation due to the material handling and disposal issues (e.g., leachate polluting the ground watercausing long-term storage issues) associated with the sludge byproducts. ii. Economic Impacts Department verified economic impacts associated with CFB Boilers for each ofthe above FGD systems were comparedin the SME-HGS application using estimated annualized capital, operating, and maintenance costs. Cost estimates were provided from commercial suppliers ofthis type ofequipment. Where appropriate, constant operation and**maintenanQ~g"1QIs-w.erejdentified~d~~~~" """~~~""~~~"~"""~"­** **""~"~""~~~"""~" "~""""""""~"""""-apptietrc::l)nsistent1ytO~coritrol**  

### optionS:

iii. Energy Impacts

.Both wet and dryFGD systems require electricity to operate. The wet FGD system uses electricitJprimarily for the 

### ill fan, re-circulation pumps, reagent handling, and for wet waste dewatering. The dryFGD uses electricity primarily for the ID fan, limellimestone handling equipment and FFB lJlowers. Wet FGD systempowerconsumptionis approximately 40% greaterthan that ofthe dry FGD system. With a HAR system, there is no recirculation pump, wet waste dewatering and reduced powerconsumption for the reagent (lime/limestone) handling system. None ofthe control options are eliminated based on energy impacts.

3423-00 23 DD: 05/1 1/07E. SOz BACT Detennination SME-HGS proposed the use ofCFB Boiler technology with limestone injection, low sulfur coal, and HAR to maintain compliance with aproposed SOz BACT emission limit of0.038 Ib/MMBtu (30-day average). Based on Department verified infonnation contained in the SME-HGS application for Pennit #3423-00 and taking into consideration technical, environmental, and economic factors, the Department detennined that the proposed SOz emission control strategy and emission limit constitute BACT in this case. This BACT detennined control option constitutes an approximate 97% SOz reduction efficiency. Other recent SOz BACT detenninations for coal-fired powerplants were researched in the RACT/BACT/LAER Clearinghouse (RBLC) and Western US agency websites. The Department verified data from these websites is summarized in the application. The SME-HGS BACT detennined SOz emission limit is at the low end ofall other recently pennitted similar source SOz BACT detenninations, worldwide. The only facilities with pennitted and BACT detennined SOz emission limits lower than SME-HGS are the AES facility in Puerto Rico and the proposed NEVCO facility in Utah. The applicable SOz BACT emission limit for both of these facilities is 0.022 Ib/MMBtu. To the best ofthe Department's knowledge, as ofthe date ofpennit issuance, compliance with the applicable SOz BACT emission limit had not been demonstrated at the AES facility orthe NEVCO facility. The Department detennined that the CFB Boiler operating under the BACT detennined control requirements is capable ofmeeting the established SOz BACT emission limit of0.038 lb SOz/MMBtu (30-day average). Further, the Department detennined that the periodic SOz source testing, the applicable continuous emission**~~** ...**,.,.,.~.,~,-,~"**,',.,',

.., .......**".".,.,.~** ..". ·······..······..**··~m0nitoring** ..**reqtlirementS',·and-the-applieable'ree0rdk-eeping-and"rep0rting'~""~""""'"** ..., ........, ....,',

... requirements will adequately monitor compliance with the pennitted SOz BACT limit(s). 2. Filterable PM Emissions Particulate matter emissions consist offilterable and condensable particulate. Filterable PM resulting from the proposed SME-HGS project is comprised ofash from the combustion offuel, noncombustible metals present in the fuel, and unburned carbon resulting from incomplete combustion. Filterable PM is material that is in particulate form within the boiler stack and thus collects on the filter ofa particulate sampling train. Condensable particulates include condensable organic compounds and minerals (in vapor fonn) that pass through the filter on a sampling train and are collected in glass impingers that contain a chilled wet solution to condense the vapors from the exhaust stream. This BACT analysis focuses on control technologies for filterable PM. PM\o (filterable and condensable) is addressed later in the BACT analysis for the proposed project (see PM IO (filterable and condensable) BACT Analysis and Detennination). A. Identification ofAvailable Filterable PM Control Strategies/Technologies Several techniques can be used to reduce filterable PM emissions from fossil fuel combustion. Three ofthe most commonly available and effective methods for control offilterable PM emissions are listed below: i. Wet scrubbers, 11. Electrostatic precipitators (ESP), and iii. Fabric filter baghouses (FFB)
3423-00 24 Final: 05/30107C. Ranking ofAvailable and Technically Feasible NOxControl Options by Efficiency Various information sources evaluatedby the Departmentthrough the NOxBACT analysis process assigned varying NOxcontrol efficiencies for each ofthe identified available NOxcontrol technologies/strategies. The following analysis uses the average ofexpected control efficiencies reported for each strategy: NOxControl Option NOxEmission Rate Estimated NOx (lb/MMBtu) Control Efficiency CFB Boilerwith SCR 0.014 90.00% CFB Boilerwith SNCR 0.07 50.00% CFB Boilerwithout Controls 0.14 0.00% D. Evaluation ofControl Technologies Including Environmental, Economic, and Energy Impacts The following text evaluates the environmental, economic, and energy impacts associated with the NOxcontrol options on a CFB Boiler.
1. Environmental Impacts The environmentalimpacts from both SCR and SNCRresult from the handling ofthe anhydrous ammonia. Spent catalyst from an SCR willhave to be properly disposed ofas apossible hazardous waste. 

### An SCR unit would have to be installed downstream ofthe baghouse to reduce fouling ofthe

. catalyst. Therefore, as an example, natural gas would have to be used to reheat

the exhaust gas to optimal temperature for the SCR·unit. The combustion of the natural gas \¥ould cause additi()nall\lOx, CO, VQf,**anqJ:lMHL~!!l~~ig1!~~~~~**

## .. ...**~.~.~** 

## .. ..**~~~~** 

## ... ...-**~~~** ...**~~** ...**~~~--~~** ... ...**~~.~** ....**~.~~** .. .... ...**~~** ..**~.~lnfO~ffie~atmospliere.** Eventhoughthere- areenviroiimental concerns associated with SCR and SNCR, these NOxcontrol options cannotbe eliminated based on these concerns. 

### ji. Energy Impacts SCR would cause significant backpressure in the CFB Boilerleading to lost boiler efficiency and, thus, a loss ofpowerproduction. Along with the power loss, SME-HGS would be subject to the additional cost ofreheating the exhaust gas, which would be expensive at the currentprice ofnatural gas. The energy impacts from an SNCR are.minimal and an SNCR does not cause a loss ofpower output from the facility. Even though there are energy impact concerns with SCR, the control options cannot be eliminatedbased on these concerns. The impacts ofadditional cost due to reheating the exhaust gas are includedin the annual cost ofoperating an SCRunit, which is presented in the economic impact analysis

.



### . iii. Economic Impacts Department verified economic impacts associated with NOxcontrol options were compared in the SME-HGS application using estimated annualized capital, operating, and maintenance costs. Costestimates for SCR and SNCR were derived from Chapter4 in the OAQPS COSTControlManual (EPA 452/B-02-001). Where appropriate, assumptions were made from suggested/typical data that were supplied in the manual, and ifdata was not

### ~vailable**~o~** the manual, best

### ~ngineering**judgmen~** was

### use~. J

### £iflI~

3423-00 32 DD: 05111/07"d

### ~~~~iiU~~fti~~ibl~f~tilli~_91e.q';'@!tiimmIS{51:{~ 

# A**d~tail~d** cost

### ~alysis is included in the application

### f~~ 

# 'thr;**~k~q~~litY** . permit. E. NOxBA(:T Determination SME-HGS proposed the use ofSNCR to maintain compliance with aproposed NOx Based on Department ven Ie 10 ormation contame in the SME-HGS application for this air quality permit and taking into consideration technical, environmental, and economic factors, the Departmentdetermined that the proposed NOxemission control strategy and emission limit constitute BACT in this case. This BACT determined control option will provide an approximate 50% NOxreduction efficiency.

. SCR was eliminated based on the high costperton ofNOxremoved. Further, since the SCR unit would have to be installed downstream from the permitted and BACT determined FFB to eliminate fouling and excessive loading ofthe catalyst, the CFB exhaust gas would need to be reheated. Reheating the exhaust gas is a significant factor in the high annual cost ofSCR and leads to a substantial increase in emissions from the reheat process summarized. Finally, the Departmentis unaware ofany CFB Boilerpermitted orin operation in the United States, which has an SCR unit installed for NOxemission control. The BACT determined NOxemission limit is equalto the lowestNOxBACT emission rates contained in the RBLC. Further, two ofthe boilers permitted with**_.~._.,** _**~Q~AkLemissionJimits..(}f·O..()'7-lbtMMBtu;Tespectivety, are'CFBllo1Iers-fIiaf~**  employ SNCR. The data from the RBLC website is summarized in the application. The Department determined that the CFB Boileroperating under the BACTdetermined control requirements is capable ofmeeting the established NOxBACT emission limit ofO.07lb NOxlMMBtu (30-day rolling average). Further, the Department determined that the periodic NOxsource testing, continuous NOx emission monitoring, and the applicable recordkeeping and reporting requirements will adequately monitor compliance with the permitted NOxBACT limit(s). 4. CO Emissions CO emissions from a CFB coal-fired boiler are typically controlled using proper design and combustion techniques. Typical CO control technologies (e.g., catalytic and thermal oxidizers) are available; however, they are not typically considered appropriate for coalfired boilers because ofhigh particulate loading, catalyst fouling, and/orhigh costto reheat the exhaust gas. A. Identification ofAvailable CO Control Strategies/Technologies The following control options are evaluated as available CO control options for the proposed SME-HGS project: i. CFB Boilers with ProperDesign and Combustion (no add-on control); and ii. CFB Boilers with Catalytic orThermal Oxidizers.

3423-00 33 DD: 05/11107

# ~~CI)**Ptv~** 

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# ®

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## 'NoN• 

## .e{'<A

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# I q"y 

# I**~-f** / 

# e, V\

# <JS-IRUVjeY\Wt 

# i(?,a.s\<; ,pd-f'-

III. Conditional Permit to Construct A. 

### General Infonnation Pennitnumber: AFSnumber: SIC Code and SIC Description: Site Location BonanzaPowerPlant 12500 East 25500 South Vernal, Utah 84078 PSD-OU-0002-04.00 049-047-00001 4911

- Electric services Corporate Office Location DeseretPowerElectric Cooperative 10714 SouthJordan Gateway SouthJordan, Utah 84095 The equipmentlisted inthis pennit shall be constructed byDeseretPower atthe following location: BonanzaPowerPlant Latitude 400 

### OS' 

### 11" N, Longitude 1090 

### 16' 48" W**~5** 

### miles southeastofVernal, Utah ' B. 

### Process Description: The Waste Coal FiredUnit (WCFU)will consistofacirculating**~c.~~.~~ -~~~~**  0**_c_~** 

### c--fluiClizeaoeo1CFBro6i1erana**assoCiatea~eqtiTpmenl** 

### at tlie

## eXIsfingBonanzapowerpraiif.

0**··_~~c~~.~~~~._~~~~** 

### The WCFU will have anominal capacity ofup to 119 megawatts gross electrical'output. The CFB boilerwill supply superheated steamto the extracting/condensing turbine, to drive an electrical generatorand supply cycle andplant auxiliary stc::amthrough uncontrolled extraction from the turbine. The CFB boilerwillbe fired onwesternbituminous coal from the Deserado mine. DeseretPowerha.s designedtheprojectto befired on waste coal alone, buthas also requested operational flexibility in the permitto Use ablend ofwaste coal andrun-ofmine coal at any time, as needed, atup to a 50150

### ratio by weight (equivalentto coal with heat contentofapproximately 6,500 Btu/lb). Run-of-mine coal is raw coal from the mine thathas notbeen washed inthe coal washingplant atthe mine. During emergencies that wouldpreventthe waste coal from being delivered andplaced into the WCFU, Deseret Powerhas requestedpennitflexibility to useeitherrun-of-mine coal orwashed coal from the Deserado mine. The waste coal is pr.oduced as anunavoidable byproductofthe coal washing process at the Deserado mine. The waste coal has anominal heating value range ofapproximately 3,000to 5,400 Btu/lb, with anaverage heating value ofapproximately 4,000 Btu/lb. The waste coal will**b~** 

### deliveredviaan existing electric train line from the Deserado mine, approximately 35 miles eastofthe Bonanzapowerplant. The run-of-mine coal has a heating valueranging from 8,500 to 10,000Btu/lb. 

### 4

### IbIMMBtu which can be achieved with a dry scrubber to 0.045 IbIMMBtu. Economic Evaluation Summarized in the table below are the expected controlled S02emission rates, and maximum annual S02emissions, associated with wet and dry FGD systems based on the design sulfurcoal. Also shown are the capital costs and annual costs associated with building and operating each control system. The table also presents the average annual control efficiency for each S02control system. A detailed summary ofthe cost estimates used in this BACT determination is attached. A CFB boiler with limestone injection is an inherently low S02emitting technology, and can be designed to remove approximately 85% ofthe potential S02 with limestone injection. The incremental cost of$10,540 per ton ofremoved S02 to install a wet scrubber rather than a dry scrubber is too high tojustify the expenditure. Based on "average" coal for the proposed WCFU, the incremental cost is $28,054 per ton ofadditional removed S02 to go from dry scrubber to wet scrubber, also too expensive tojustify. Comparison ofWet FGD to Dry FGD for WCFU,

Downstream ofLimestone Injection Controls: Costs and Emission Rates Parameter Wet FGD with Limestone Dry FGD with Limestone fuiecti**6ri~for"deSIgi1"c()al -lriiectio~1or**  

### "design"**coai~** 

### Controlled S02 Emission 0.045 0.055 Rate (IbIMMBtu) Overall Control Efficiency 99.1% 98.8% Maximum S02 Emissions 285 350 (tpy) Total Capital Cost ($) 20,211,840 13,379,115 Total Capital Cost ($/kw) 202 134 Total Annual Costs ($/yr) 12,410,610 11,747,546 Annual S02 Removed (tpy) 26,675 26,612 Average Annual Cost per 418 397 Ton ($/ton) Incremental S02 Removed 63


### --- (tpv) Incremental Cost per Ton 10,540



### --- ($/ton) Environmental Impacts ofWet FGD In addition to the adverse economic impacts ofa wet FGD system versus a dry FGD system, there are several collateral adverse environmental impacts associated with a wet FGD 95

### Emission reduction going from baseline to SCR controlled emissions: (0.15 IbIMMBtu

- 0.015 IbIMMBtu) x (1,445 MMBtu/hr) x (8,760 hr/yr)(0.9) (1 

### tonl2,OOO Ib) 

# =769 tons/year The average cost per ton for NOx

### reductions, considering only distillate fuel costs when considering the additional NOx that would be generated by burning distillate fuel: ($12,411,476/ yr) / (769

- 62 ton/yr) 

## =$17,555/ton The incremental cost ofgoing from SNCR to SCR, considering only the distillate fuel costs is calculated as follows: ($12,411,476/ yr) / (370 ton/yr) = 

### $33,545 /ton The incremental cost going from SNCR to SCR, considering only the distillate fuel costs, and considering the additional emissions caused by reheat for SCR, is calculated as follows: ($12,411,476/ yr) / (370

- 62 ton/yr) 

## =$40,297 /ton EPA concludes that the economic impacts associated with a cost ofmore than $40,000**_~~_~~,,_"_~" ~"".,~""pe,Lton_oLpollutanLremo.:\!'edjustify_elimination,o.LSC~asihe_tOtLwntmLQption,~~B~Qth,Jhe,JQlaL~**  

### cost effectiveness and incremental cost effectiveness are considered by EPA as cost-prohibitive for BACT. In addition, ifcapital, installation, and other operational costs for both the SCR and reheat system were considered, the above cost values would increase significantly. b. Selective Non-Catalytic Reduction. Deseret has proposed SNCR as BACT for NOx, 

### which is the next highest ranked control option. Since SCR has been rejected above, and since there are no significant collateral impacts for SNCR, this control option is selected as BACT. 5. Step 5: Proposed NOl!. BACT for CFB Boiler. As stated above, SNCR has been selected as NOx

### BACT. An emission limit must now be established that represents the maximum degree ofreduction achievable for SNCR for this project. The above discussion and analysis indicates that SNCR for the WCFU project can achieve 0.080 IbIMMBtu on a rolling 30-day average. Deseret Power has proposed an emission limit of0.088 IbIMMBtu on a 30-day rolling average. Deseret Power searched the RACT/BACT/LAER Clearinghouse (RBLC) database and found the following determinations:

51

## IPollutant Information 

## IRACT/BACT/LAER Clearinghouse 

## I Clean Air Technology Cent... Page 1 of2

http://dpubl.epa.qov/rIJlc/lI1dex.cfm'action=Perrn,tDNad.PoliutantInfo&.FaCility ,I D=26 740&Process

... ID= 1 06330&Pollutant. 1[)= J49 Last updated on Wednesday, r'larcl1 31, 20W Technology Transfer Network Clean Air Technology Center
- RACTjBACT/LAER Clearinghouse

You are here: EPA Home Air & Radiation TTNWeb
- Technology Transfer Network Clean Air Technology Center RACT/BACT/LAER Clearinghouse RBLC Basic Search RBLC Search Results Pollutant Information


### Pollutant Information Click on the Process Information button to see more information about the process associated with this pollutant. Or click on the Process list button to return to the list of processes.

Help 

## I FINAL
RBLC 10: UT-0070 Corporate/Company: DESERET POWER ELECTRIC COOPERATIVE Facility Name: BONANZA POWER PLANT WASTE COAL FIRED UNIT Process: CIRCULATING FLUIDIZED BED BOILER, 1445 MMBTUjHR WASTE COAL FIRED
Pollutant: Nitrogen Oxides (NOx) CAS Number: 10102 Pollutant Group (s) : Substance Registry System: Nitrogen Oxides (NOx)

Pollution Prevention/Add-on Control Equipment/Both/No Controls Feasible: A**-~**
Test Method: Unspecified EPNOAR Methods 

## I All Other Methods
Percent Efficiency: 0 Compliance Verified: Unknown EMISSION LIMITS:

Case-by-Case Basis: BACT-PSD Other Applicable Requirements: Other Factors Influence Decision: Unknown Emission Limdt 1: 0,0880 LB/MMBTU 30-DAY ROLLING Emission Limdt 2: 0 Standard Emission Limit: 0 COST DATA:

Cost Verified? No Dollar Year Used in Cost Estimates: Cost Effectiveness: 0 $/ton Incremental Cost Effectiveness: 0 $/ton Pollutant Notes: THIS LIMIT APPLIES PRIOR TO THE DATE WHICH IS 12 MONTHS AFTER COMPLETION OF INITIAL PERFORMANCE TESTING Pollution Prevention/Add-on Control Equipment/Both/No Controls Feasible: A P2/Add-on Description: SNCR

Test Method: Unspecified EPNOAR Methods 

## I All Other Methods
Percent Efficiency: Compliance Verified: EMISSION LIMITS:

Case-by-Case Basis: Other Applicable Requirements: Other Factors Influence Decision: Emission Limdt 1. Emission Limdt 2: Standard Emission Limdt: o Unknown BACT-PSD Unknown 0,0800 LB/MMBTU 30-DAY ROLLING o o


### http://cfpub 1.epa.gov/rblc/index.cfm?action=PermitDetail.PollutantInfo&Facility _ID=267

... 3/31/2010

## IPollutant Infonnation 

## IRACT/BACT/LAER Clearinghouse 

## IClean Air Technology Cent... Page 2 of2

COST DATA:

Cost verified? No Dollar Year Used in Cost Estimates: Cost Effectiveness: 0 $/ton Incremental Cost Effectiveness: 0 $/ton Pollutant Notes:



### http://cfpubl.epa.gov/rblc/index.cfm?action=PennitDetai1.PollutantInfo&Facility_ID=267... 3/31/2010

## IPollutant Infonnation 

## IRACT/BACT/LAER Clearinghouse 

## IClean Air Technology Cent... Page 1 of2

http://dpubl.epa.qov/rblc/index.drn'action=PerrmtDetail.PollutantInfo&.Facdity

.. ID=26740&ProceSS

..JD=.106330&Pollulant. ID= .l89 Last updated on Wednesday.**r~arcll** 31. 2010 Technology Transfer Network Clean Air Technology Center
- RACT/BACT/LAER Clearinghouse

You are IJere: EPA Home Air & Radiation TIN Web
- Technoloov Transfer Network Clean Air Technology Center RACT/BACT/LAER Clearinghouse RBLC Basic Search RBLC Search Results Pollutant Infonniltlon 

### Pollutant Information Click on the Process Information button to see more information about the process associated with this pollutant. Or click on the Process List button to return to the list of rocesses.

Help 

## I FINAL RBLC 10: UT-0070 Corporate/Company: DESERET POWER ELECTRIC COOPERATIVE Facility Name: BONANZA POWER PLANT WASTE COAL FIRED UNIT Process: CIRCULATING FLUIDIZED BED BOILER, 1445 MMBTU/HR WASTE COAL FIRED
Pollutant: Sulfur Dioxide (S02) CAS Number: 7446-09-5 Pollutant Group (s) : Substance Registry System: Sulfur Dioxide IS02)

Pollution Prevention/Add-on Control Equipment/Both/No Controls Feasible: A

Test Method: Unspecified EPA/OAR Methods 

## I All Other Methods
Percent Efficiency: 0 Compliance Verified: Unknown EMISSION LIMITS:**Case-~-Case** Basis: BACT-PSD

Other Applicable Requirements: Other Factors Influence Decision: Unknown Emission Limit 1: 0.0550 LB/MMBTU 30-DAY ROLLING Emission Limit 2: 0 Standard Emission Limit: 0 COST DATA:

Cost Verified? No Dollar Year Used in Cost Estimates: Cost Effectiveness: 0 S/ton Incremental Cost Effectiveness: 0 S/ton Pollutant Notes: PRIOR TO THE DATE WHICH IS 12 MONTHS AFTER COMPLETION OF INITIAL PERFORMANCE TESTING. Pollution Prevention/Add-on Control Equipment/Both/No Controls Feasible: A p2/Add-on Description:

Test Method: Unspecified EPA/OAR Methods 

## I All other Methods
Percent Efficiency: Compliance Verified: EMISSION LIMITS:**Case-~-Case** Basis:

Other Applicable Requirements: Other Factors Influence Decision: Emission Limit 1: Emission Limit 2: Standard Emission Limit: o Unknown BACT-PSD Unknown 0.0550 LB/MMBTU 30-DAY ROLLING o LB/MMBTU 30-DAY ROLLING

- SEE NOTES o


### http://cfPub1.epa.gov/rblc/index.cfm?action=PennitDetail.PollutantInfo&Facility _ID=267... 3/31/2010

# IPollutant Information I 

### RACT/BACT/LAER Clearinghouse I 

### Clean Air Technology Cent... Page 2 of2

o $/ton o $/ton BEGINNING ON THE DATE WHICH IS 12 MONTHS AFTER COMPLETION OF INITIAL PERFORMANCE TESTING, AND THEREAFTER FOR ANY BOILER OPERATING DAY WHEN THE UNCONTROLLED S02 EMISSION POTENTIAL OF THE COMBUSTED COAL IS 2.2 LB/MMBTU OR GREATER, ON A 3D-DAY ROLLING AVERAGE. WHEN THE UNCONTROLLED S02 EMISSION POTENTIAL OF THE COMBUSTED COAL IS LESS THAN 2.2 LB/MMBTU, 3D-DAY AVERAGE, THE LIMIT WILL BE COMPUTED AS FOLLOWS. (D.D55A+D.D4DBl/3D LB/MMBTU HEAT INPUT WHERE: A ; NUMBER OF BOD, DURING 30 SUCCESSIVE BODS PRIOR TO THE CALCULATION, WHEN THE UNCONTROLLED S02 EMISSION POTENTIAL OF THE COMBUSTED COAL WAS 1.9 LB/MMBTU OR GREATER, ON A 3D-DAY ROLLING AVERAGE B ; NUMBER OF BOD, DURING 30 SUCCESSIVE BODS PRIOR TO THE CALCULATION, WHEN THE UNCONTROLLED S02 EMISSION POTENTIAL OF THE COMBUSTED COAL WAS LESS THAN 1.9 LB/MMBTU, ON A 3D-DAY ROLLING AVERAGE BOD ; BOILER OPERATING DAY COST DATA:

Cost Verified? No Dollar Year Used in Cost Estimates: Cost Effectiveness: Incremental Cost Effectiveness: Pollutant Notes:



### http://cfpub1.epa.gov/rblc/index.cfm?action=PermitDetaiLPollutantInfo&Facility_ID=267,.. 3/31/2010

### efficiencies greater than 50% are generally achievable using SNCR on a fluidized bed boiler, lower control efficiencies would be expected when using SNCR on the JTA boiler (a fluidized bed boiler) based upon the following: 1) significant variations in NOx 

### emission levels are expected to be experienced, making it difficult to obtain a proper stoichiometric ammonia injection rate; and 2) fluctuations in flame and internal boiler temperature zones will make it difficult to inject ammonia in the optimum temperature zone (approximately 1500 0

### F to 1900 0

### F for SNCR)

. 

## *** Assumes that the JTA Boiler operates at the historical annual capacity factor of 58%. Step 4: Evaluate Most Effective Control and Document Results Control Effectiveness (58% annual capacity factor) NOx Additional Annualized Incremental Cost Emitted NO x Removed Cost Effectiveness Technology (TPY) (TPY) ($) ($/Ton) SNCR 106.7 35.6 276,700 7,772 Existing 142.3


### --- --- --- Combustion

Controls

NOx Additional Annualized Incremental Cost Emitted NO x Removed Cost Effectiveness Technology (TPY) (TPY) ($) ($/Ton) SNCR 128.8 42.9 276,700 6,450 Existing 171.7


### --- --- --- Combustion

Controls 

### Step 5: Select BACT ADM has assumed a 58% annual capacity factor for the JTA Boiler, which results in an incremental cost effectiveness of $7,772 per ton of NOx 

### removed. These costs are considered to be excessive; however, as discussed in Section 2.3.2.1 above, ADM has not demonstrated that the 58% annual capacity factor assumed for the JTA Boiler reflects the**~upper** 

### boundary of the source's ability to physically operate". As shown in the above table, the Department has calculated the incremental cost effectiveness assuming the JTA Boiler operates at a capacity factor of 70%. At a 70% capacity factor the incremental cost effectiveness is**~6,450** 

### periton .of NOx 

### removed, which is considered to be excessive. The Department has determined that BACT for NOx 

### is a NOx 

### emission limit of 0.20 lb/MM Btu on a 30 day rolling average basis. T9 23

### MPCA Technical Support Documents Available at: http://www.pca.state.mn.us/air/pennits/issuedJindex.html NSP

- Black Dog Technical Support Document for Draft Air Emission Pennit No. 03700003-002 GRE

- Lakefield Junction Station TSD for Draft Air Emission Pennit No. 09100058-003 Fibrominn TSD for Draft Air Emission Pennit No. 15100038-001 Mesabi Nugget TSD for Draft Air Emission Pennit No. 13700318-001 NSP, dba Xcel Energy; High Bridge Generating Plant TSD for Draft Air Emission Pennit No. 12300012-004 NSP, dba Xcel Energy; Riverside Plant TSD for Draft Air Emission Pennit No. 05300015-004 Blandin Paper**~---------------------~--TS-D-f{}r-Dr-aft-Ai~-Emission-Fermit-N&.06100()Ol-Oll----------** 

### - .------------ ------- ---------------------------- --------

### Conclusion The MPCA finds that the limits achievable by the proposed new source with Low NOx 

### Burners combined Selective Catalytic Reduction (ammonia injection), is consistent with BACT. 3.1.2 Carbon Monoxide BACT**Ana~vsis** 

### Summary XCEL proposed limits obtainable by "good combustion practices" in its pernlit application. XCEL has requested a 25 ppmv 

### @ 15% 02 value for the combined (EU 026 and EU 027) emission limit at SV 020. This limit would apply only when the combustion turbine (EU 026) is at 70% load (1400 MMBtulhr heat input on a HHV basis) or greater. An 

### annual emission cap of400 tons per year was also requested in an attempt to cost out additional controls. XCEL has requested that the CO emission cap be an annual block average. EU 001 and EU 002

Operating Emission Lb/hour Tons per Tons Annual Cost, Scenario Limit year removed Cost $/ton Combustion 25 ppm 93.0 400 0 Base case Base case Controls limited Oxidation 2.5 ppm 9.13 40.0 360 $872,912 2,425 Catalyst per. tons peryear costper ton are based on base load emissions that are capped at 400 tons per year. CO emission rates for the gas turbine, however, can rise exponentially at sub-base load levels (less than 70% load). XCEL claims that a short-term emission rate of25 ppm is consistent within current acceptable BACT ranges for combined cycle gas turbines. The MPCA concurs that 25 ppm is atthe upper range but within current BACT determinations. Since CO can rise exponentially at lower load ranges, the MPCA requested that XCEL reevaluate the BACT analysis by assuming worst case CO emissions. Worst case emissions occur at a gas turbine load ofapproximately 30 percent. At this load the duct burners would not be in operation. At 30 percent load the potential to emit balloons to approximately 1,650 lbs/hr or 7,227 tons per year. When worst case emissions are used in the cost analysis the cost per ton value for a CO oxidation catalyst drops significantly. XCEL proposes taking a400 ton per year cap to limit operation in the less than base load operating ranges. The table above sununarizes the cost analysis when a400 TPY CO emissions cap is imposed at the combined stack vent SV 020. According to the cost analysis above, the annualized cost per ton for the installation ofa oxidizing catalyst**isl$2,42~** 

### XCEL argues that this value is much higher than any proposed costper ton SIP plan for the removal ofCO from mobile sources when this geographic area was nonattainment for CO. Further, XCEL points out the San Joaquin Valley Unified Air

7

### Pollution Control District BACT policy dated November 9, 1999, cites a cost effectiveness threshold of$300 per ton ofCO. In addition to the cost analysis, XCEL also argues that installation ofa CO catalyst may have negative environmental impacts. The use ofan oxidation catalyst may result in higher PM10 emissions from the further oxidation ofS02 to S03 and the potential reaction with ammonia in the SCR unit to create ammonia salts that may react with moisture to form H2

### S04. 

### The MPCA agrees that PM-10 

### emissions may increase with the installation ofan oxidation catalyst, however, the facility has committed to bum only pipeline quality natural gas and therefore S02 and all subsequent post control PM-10 

### will be minimal. Furthermore, XCEL admits that optimum placement ofthe oxidizing catalyst will greatly limit the oxidation of the already minimal amounts ofS02 in the exhaust stream. Therefore, the potential minimal increase ofPM-l0 emissions is not, by itself, adequatejustification for the omission ofan oxidation catalyst which would reduce significant quantities ofCO, VOC and HAP emISSIOns. XCEL's economic analysis shows that the annualized costper ton for the installation ofan oxidizing catalyst is $2,425. This value is below the cost figures ofotherrecently pemlitted sources in this state and other Region 5 states that have successfully argued out ofinstalling a CO catalyst by estimating costs in excess of$3000 perton. However, the issue ofcost is over shadowed by the fact thatthere exist a significant number ofcombined cycle units that**,---,-~-~,,~** 

## ..**-"~"~"~"are** 

## operating**lii~a** 

# costeffecWvemafifiefWifn oxtclatton**1:am1ystS'tITstrrllt;d~~:Alnrlm'O'st~~'-'---"~'~"-""-"""~"'~-~~"** 

### identical unit also within the Minneapolis/St. Paul metropolitan area isjust one example of such a source. In XCEL's defense, that source and most sources that have installed oxidation catalysts have done so to comply with LAER determinations or to synthetic minor out of LAER determinations. An email survey ofturbine contact people at all Region 5 states and various EPA Regional offices appears to confirm the pointthat CO catalysts have not normally been required ifthe facility is not in or will not significantly impact a CO or Ozone nonattainment area. This is further verified by two recent permits issued by Michigan and Wisconsin where the facility in Michigan, which did not significantly impact a CO or Ozone nonattainment area, was not required to install a CO catalyst. However, the facility in Wisconsin was required to install an oxidation catalyst as LAER for VOCs and thus take credit for that control system as BACT for CO. Based on the MPCA's analysis ofgeneral trends in permitting gas turbines, CO catalysts do not appear to be generally required as BACT unless there are underlying nonattaimnent issue involved.



### 8

### PennitNwnber: 09100058-003 Date: 1120/2004 remain current. 

### To support this analysis, determinations from

# u.s. Environmental Protection Agency (EPA) databases (BACT/LAER Clearing House) and Texas (TNRCC database) have been reviewed, and such information is attached to this document. NOx 

### BACT Status 

### The BACT review for NOx control completed with the previous permit action determined that dry 

### low NOx (DLN) burners combined with selective catalytic reduction (SCR) was economically not feasible. The zero increase in NOx potential to emit (PTE) due to the NOx cap and the increase in adjusted SCR costs result in an increase**tO~j$13** 

### ,204·per ton ofNOx removed, compared to the 1999 determination of$11,185 per ton ofNOx removed. The proposed BACT for NOx 

### is the existing GE 7EA turbine equipped with 9-ppm DLN burner technology. CO BACT Status 

### The updated listing ofsimple cycle projects entered in the EPA's RBLC database identified two simple cycle projects that required a CO catalyst. Both sites are located in areas designated as maintenance for ambient concentrations ofcarbon monoxide, which can be expected to require extra CO reductions as part ofan air quality maintenance plan. The TNRCC list ofturbine projects cites two simple cycle cases requiring CO catalyst. One project has a BACT limit of5 ppm and the other 22 ppm CO. Texas BACT for CO is stated as



### .. ... ..**~._** 

### ...**~.~._** 

### ..**·_~·~·Tsppmorress.~~rrisTiRe1y ;~l5utriotverlfiea~tnattrncOtiIroltec1··e(J~·fF()ffftne-s~e~lIfftts~wolItd~exc-e~e~···~···~~·~··~~·~·~**  

### 25 ppm, thus requiring control technology. However, the DLN burners achieve 25 ppm CO and, as shown in the BACT update, the application ofcontrol beyond the existing controlled emission levels is not cost effective. The decrease in PTE and an increase in adjusted CO catalyst costs result in a slight cost increase**to~$3,266,per** 

### ton ofCO removed, compared to the 1999 determination of$2,938 per ton ofCO removed. The cost ofCO control is still an excessive burden to the project from an economic perspective. The proposed BACT for CO control is the continued effective minimization ofCO (and VOC) emissions by optimized operation ofthe GE 7EA turbine equipped with DLN burner technology. S02 BACT Status 

### The 1999 BACT determination for S02 control proposed very-low-sulfur fuels (natural gas and fuel oil limited to 0.05 percent by weight sulfur). The updated list ofRBLC listings for simple cycle turbine projects did not include determinations for S02 control other than clean fuels. Accordingly, the proposed BACT for S02 control is the currently permitted use ofverylow-sulfur fuels. Particulate and Fine Particulate BACT Status 

### The 1999 BACT determination for particulate control proposed the use ofclean fuels and good combustion practices. Natural gas and distillate fuel oil are very low-ash fuels, therefore limiting mineral ash emissions. The updated list ofRBLC listings for simple cycle turbine projects did not include detenninations for particulate control other than clean fuels.

4

### An argument could be made that a wet sulfur dioxide scrubber could achieve ahigher control efficiency. Wet sulfur dioxide scrubbing systems are known to achieve removal efficiencies greater than 90%. MPCA staffasked Fibrominn its reasons for not choosing awet scrubber. In its response, Fibrominn argues that sulfuric acid emissions are proportional to sulfur dioxide emissions, and are usually emitted at arate 10-31% ofsulfur dioxide emissions. For those sulfuric acid emissions, the proven technology for control is the dry scrubber. That technology reduces sulfuric acid emissions by more than 80%. So, while the wet scrubbing system would reduce the sulfur dioxide emissions with a greater efficiency, there would be very little, ifany control ofsulfuric acid emissions. Fibrominn's emission comparison (Page 2 ofARI's November 12,2001 submittal) projects that for a442 tpy reduction in sulfur dioxide emissions, there couldbe as much as a 655 ton per year increase in sulfuric acid emissions. Fibrominn's comparison is, albeit, a worst case scenario. In its calculations, Fibrominn asswnes that sulfuric acid emissions are 33% ofsulfur dioxide emissions (2% higher than the supporting documentation would indicate as an absolute maximum). Nevertheless, it is clear that there is a tradeoff. This calls into question whether or not the wet scrubber technology is truly best available control. Fibrominn also asserts that wet scrubbers have other negative environmental impacts as well: visibility ofemissions is likely to increase, as sulfuric acid emissions can produce a visible plume; an increase in wastewater generation; a potential increase in solid waste disposal, (Fibrominn plans to sell its flyash for fertilizer, and is**C""""""""~"""~""_·_-~"~~""unsmeTfillaCwoClldbe"p0sSlbIewere"ale{;heliiIca'fPiopertres"~aiiiiijed"1)~wefsem6bnfi)7and~~~"~""~"~~~~"~~~** 

### increased energy consumption (as much or more than twice). Dispersion modeling performed by the company, and approved by MPCA staff, predict that sulfur dioxide emissions from the facility will have less than Significant ImpactLevels in the ambient air, as defined by the new source review program, 40 CFR 52.21. In light ofthat, MPCA staffbelieve that Fibrominn's assertions are valid, that the emission limit achievable with the use ofa spray dryer represents BACT, and that that is reflected in the choice ofthe spray "dryer absorberbeing chosen as BACT in all ofthe more recent waste combustorpermits documented in EPA's BACT/LAER Clearinghouse. 

### NOxBACTAnalysis: The top down control technology list for nitrogen oxides control is; Selective Catalytic Reduction (SCR), Selective Non-catalytic Reduction (SNCR), and combustion modification. The top control technology, SCR was rejected due to 

### the potential ofcatalystplugging and/or slagging, and the potential for catalyst fouling due to contaminants in the exhaust stream. (As discussed below, many ofthe same problems would occur with a CO catalyst.) During the recent permitting ofthe District Energy wood/agricultural waste boiler, District Energy's consultant surveyed operators ofboilers fitted with SCR, and vendors to verify that catalyst fouling was indeed a problem. The results ofthat investigation are attached, (Letter and attachments from Labno Environmental, dated January 29, 2001.) MPCA staffbelieve that Fibrominn is correct in its assertion that SCR is not a proven technology for a poultry litter/agricultural waste fired Pemlit Action Nwnber: Date: 1/14/2004

### boiler. This would be especially true for a "hot side" catalyst (upstream oftheparticulate control). A "cold side" catalystwould be located downstream ofthe particulate control equipment. Locating the control equipment downstream ofthe particulate control mechanism wouldreduce the potential for catalyst fouling due to contaminants. Though unproven, there exists the possibility that the particulate control would reduce contaminants enough that catalystfouling would notbe a significantproblem. As such, Fibrorninnperformed the exercise ofcalculating the costperton SCR would be in this application. That financial analysis is attached. The costs were calculatedto be between $6,513 and $9,016 perton ofpollutantremoved ifpropane were used to reheat the exhaust stream to combustion temperatures. Fibrominn estimates that, at the moment, itmay be less expensive 

### to reheat the exhaust stream with natural gas. Using today's price for natural gas, Fibrominn's calculations for costper ton ofcontrol would beI6;091io)"**~:$g,432.i.!'** 

### In addition, the incremental cost effectiveness when comparedto SNCR, the control technology representing the next most stringent emission limitation, is prohibitive. The incremental cost effectiveness for comparison of65% control by SCRto 50% control by SNCR**is~35,738per'** 

### ton, and for comparison of90% control by SCRto 50% control by SNCR is $13,415 pertOll; Much ofthe cost stems from the fuel needed to reheat the exhaust streamto within temperatures suitable for catalyst operation. Fibrominn estimates that aburner as large as 65 mmBtu per hour would be needed. The MPCA believes that this is too high a fuel cost (about 8% oftotal fuel input to the boiler), and that such a use ofa non-renewable resource is not consistent with the**'~~~'~'~'~~'~·--'-··el1"ITonmenfaTprogram.~~TIie·cosT'eIfecfiveness·ofB'NrR:'o·I1'Tfieoilier·Iiana:·Tsw'eTrwitnin~lfie~'** 

### ...,..**,.~.,~,** 

### .....**,~** 

### range that the MPCA considers to be economically viable;iH,84fFpertOl1i.

### it Ofthe recently permittedwood fired boilers in the BACT/LAER Clearinghouse, 7 of 16 are controlledby SNCR.The others are uncontrolled, or are controlledby good combustion practices. Emission limits range from 0.15 Ib/mmBtu to 0.54Ib/mmBtu. Limits of0.15

. Ib/mmBtu are most common for the boilers controlled with SNCR. Ofthe recently permitted MSW combustors, all were controlled with SNCR. Emission limits range from 0.34 to 0.6 Ib/mmBtu. Fibrominn has chosen the most effective technology thathas been demonstrated and is technologically feasible, SNCR" asBACT, and proposed an emission limit of0.16 Ib/mmBtu on a 30 day average. The averaging time was chosen to be consistent with the applicable NSPS. With the baseline emissions of0.32thatFibrominn expects to see, 50% control results in emissions ofO.16Ib/mmBtu. MPCAstaffbelieve thatthe emission limits that are proposed are consistent with BACT. 

### Carbon Monoxide BACT Analysis: Fibrominn claims that based on operating experience at its Thetford plant, the CO emissions characteristic ofthis proposed boiler andfuel type are unique, and thatthe CO emissions will always be somewhathigherthan when other solid fuels are used. Fibrominn attributes the higher CO emissions to:

• high fuel moisture contentwith significantvariation, Permit Action Nwnber: Date: 1/l4/2004

### Sulfuric acidmist. The RHF has the potential to emit 1122 tons ofsulfuric acid mistperyear without controls. The applicanthas proposed four control technologies (wet scrubber, spray dryer absorption, wet electrostatic precipitator, and dry sorbentinjection). Ofthese, the applicant's BACT submittal indicates that the wet scrubber removes the highest fraction of sulfuric acid mist. Pilotplant dataindicate that 

### 90 percent ofthe sulfuric acid mist was removed by the wet scrubber. However, to maintain this removal, the scrubber water must remain alkaline. The MPCA will set a BACT limit at 25.6 pounds per hour, which the application provides as the RHF's potential to emit sulfuric acid mist after controls. As with sulfur dioxide and fluorides, an initial performance test will be required at scrubber outlet to demonstrate compliance with the pound per hour limit. The test results will also be used to correlate the control ofsulfuric acid mist with that ofS02, which will be monitored continuously. The scrubber optimization study will also address the scrubber's ability to remove sulfuric acid mist emissions. Using data from that study, the MPCA will set a removal efficiency for sulfuric acid mist as BACT. Parametric monitoring and control ofpressure drop, liquid flow, andpH (as a measure ofalkalinity) will indicate ongoing compliance with the removal requirement. Periodic performance tests will be used to ensure that the parameters are set correctly. 

### WNitrogenoxides. '.The rotary hearth furnace operates at temperatures above 

### 2000 OF. Even

,though the furnace has a reducing atmosphere, NOx is generatedby the reaction ofnitrogen in the air or in the raw materials with available oxygen. Uncontrolled, the furnace is expected to generate 

### 902 tons ofNOx. A perusal ofthe RBLC (SCR), selective non-catalytic reduction (SNCR), non-selective catalytic reduction (NSCR), external flue gas recirculation (external FGR), low-NOx burners and induced flue gas recirculation burners, staged fuel combustion at the RHF, low excess air, and other combustion controls. SCR prior to the scrubber was determined to be infeasible since the compounds in the flue gas wouldpoison the catalyst. The applicant also determined SNCR to be infeasible because the injection ofammonia would react with S02 in the flue gas to form ammonium sulfates that would be expected to foul the heat exchangers that are relied on to preheat combustion air. (The ammonia would be injected upstream ofthese heat exchangers because that is where the temperatures are most favorable for the desired reaction.) NSCR is not feasible, again due to the poisoning ofthe catalyst. External FGR requires that flue gas be injectedback into the combustion zone. In this application, external FGR would affect the heat distribution in the RHF and lowerthe furnace's efficiency. 

### It is infeasible in the RHF itself. The applicant also indicates that it is infeasible in the air injection system (where the flue gas, high 

### in CO, is reacted at high temperature with oxygen). The conversion ofCO to C02 would be inhibited by the introduction offlue gas to that system, resulting in higher CO emissions from the source. Low-NOx burners are feasible in this application, but the use ofihternal FGR cannot be used, since it (like external FGR) reduces the flame temperature. Also, due to the high temperatures in

Technical Support Document, Permit Action Number: 13700318-001 Page 17 of 80 Date: 7/9/2007

### the RHF, the effectiveness oflow-NOxburners in this application may be reduced compared to other applications. The reducing environment ofthe RHF requires the use oflow-excess air in at leastparts ofthe furnace. 

### Itis a feasible option that is inherent to the process. The continuous emission monitoring system (CEMS) for NOx will assist in controlling the process to minimize NOx emISSIOns. Some combustion controls are feasible for use in theRHF. There will be some parts ofthe RHF in which staged combustion will be used. The combustion controls commonly used in apower· boiler are not designed for the RHF's reducing environment, so the process control logic used for those controls is not feasible at the Nugget facility. Advanced combustion controls will be used to maintain the reducing atmosphere ofthe RHF, so it may be possibleto tune the furnace to produce the desired product while keeping NOx formation to a minimum. That technology has not yet been developed. The MPCA recommended that the applicant consider SCR located after the wet scrubber. This location was determined to be feasible, although it requires re-heating ofthe flue gas, an additional cost. The options considered feasible were the post-scrubber SCR; staged combustion incorporating low excess air and overfire air; and 10w-NOx burners. The 10w-NOx burners and staged combustion are inherentin the design ofthe RHF process. Although the post-scrubber SCR was the most effective NOx-reduction technology still being considered, the costperton ofNOx controlled**«f$ll,OOO/ton}~exceeded** 

### the costguidelines used in Minnesota. The 10w-NOxburners and staged combustion are both inherentto the design ofthe RHF. BACT is thus "no add-on controls" for this application. The permit will set a limit of 125 ppm (at seven percent oxygen) during normal operation. (This reflects the inclusion'oflow"NOxburners.) The permit willalso contain a limitof205.8 pound ofNOx per hour. A NOx CEMS, including a flow meter and an oxygenmonitor will be installed to demonstrate initial and ongoing compliance with the concentration and poundperhour limits. The permit requires an initial certification ofthe monitoring system and periodic RATAs and CGAs. 

### Carbon monoxide. The RHF requires a reducing environmentto allow the reaction that forms the iron nuggets. Areducing environment is maintainedby limiting the amount ofoxygen in the furnace. This type ofenvironment ensures that significa:p.t amounts ofCO will be formed there. The applicant expects that 2.0 percent ofthe gases leaving the RHF will be CO (ornearly 85,000 tons ofCO peryear). At the pilotplant, an "air injection system" was used to introduce air andmix it into the exhaust gases. At the temperatures leaving the RHF (greaterthan 2000°F.), the introduction ofoxygen leads to the rapid conversion ofCO to CO2. 

### The applicantmeasured the CO emissions after the air injection system and found them to be about 18 ppm. The applicant proposes to use a similar airinjection system at the commercial-scale facility. Additional oxidation technologies, such as thermal oxidation, would be expected only to slightly

Technical Support Document. Permit Action Number: 13700318-001 Page 18 of 80 Date: 7/9/2007GP 005

GP 006, GP 007, SV 001, EU 001- EU 009, EU 012 Title I Conditions: Limits on existing facility operation during combustion turbine shakedown (as defined on page 7 ofthis document) to provide emission credits for netting out for PM, PMlO, and NO

### x Refer to technical support document for Permit No. 12300012-001 for regulatory information about these subject items.

EU017

EU017 (cont.) 40 CFR § 52.21

40 CFR pt. 60, subp. Dc

40 CFR pt. 63, subp. DDDDD New Source Review CO and VOC BACT limits (note that 0.08 lb CO/mmBtu is about 110 ppmvd assuming 0% excess air, which is less than the 400 ppmvd MACT standard) New Source Performance Standards (NSPS) for Industria1- Commercial-Institutional Steam Generating Units National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers and Process Heaters (auxiliary boiler is a new large gaseous-fueled boiler with <100 mmBtu/hr heat input in 'population 

### III' in the boiler MACT ,., 

### r, date is date ofinitial

_.... EU 018 Title 

### I Conditions: CO and Small emergency use-only source VOC BACT limits 

### 3. Technical Information

• New Source ReviewApplicability: 

### The construction ofthe new combined cycle gas turbine facility and phased shutdown ofthe existing coal boiler plant is subject to federal New Source Review permitting requirements. The new facilitywillbe a major source for PM, PM 10, 

### NOx, CO, and VOC before netting, and a minor source for 

### S02 due to fuel type restrictions. The phased shutdown ofthe coal-fired boilerplant allows the Permittee to net out ofPSD requirements for PM, PMIO, 

### and NOx emissions. Also, the Permittee will install NOx controls on the combined cycle gas turbines (lean pre-mix combustors and selective catalytic reduction with ammonia injection). The new facility is a major source for CO and VOC, and therefore is subjectto PSD permitting requirements for these pollutants. The Permittee has elected to not request a comparable to BACT Clean Unit Determination.

• BACTAnalysis: 

### Installation ofthe new gas turbine facility is subjectto BACT for CO and VOC emissions. The Permittee has submitted information tojustify that BACT is Good Combustion Practices (GCP).

Technical Support Document, Permit No. 12300012-004 Page 6 of 19 Date: 1/13/2006

### Discussion: The RACT BACT LAER clearinghouse (RBLC) contains arather diverse listing ofrejected and accepted costper ton data for oxidation catalysts, as well as a large overlap in the achievable ppmvd CO emission concentration for oxidation catalysts and GCP. 

### It is apparent that locations not in attainment with federal ozone and/orCO NAAQS require installation ofan oxidation catalyst to meetLAER. However, in attainment areas justification for use ofa catalyst versus GCP is not well documented in the RBLC. In addition, reports on the atmospheric fate ofCO indicate a rather short lifetime. A December 1990 EPA report to Congress titled 'Policy Options For Stabilizing Global Climate Report To Congress' indicates a global average CO lifespan of2.5 months. This report indicates that CO reacts with hydroxyl to form CO2and H2 0. Also, information furnished by Wisconsin Electric Power Company for their PSD permit for the Port Washington installation ofcombined cycle gas turbines indicated that CO lifetime in the exhaustplume is even shorter because the rate ofconversion ofCO to CO2is temperature dependent, and stackplume temperatures are substantially higher than average global temperature. According to the August 27, 2004, docwnent titled

.



### AnalysisAndPreliminaryDetermination For The ConstmctionAndOperation Permits For The ProposedModification Of The Operation Of The Four Combined Cycle Combustion Turbines With DuctBurnersAndHeatRecoverySteam Generators (HRSG.s), EmergencyDieselEngine, Gas HeaterAndA Storage TankFor WisconsinDNRpermit #04-RV-175 for the Wisconsin Electric Power Company

-Port Washington Generating Station, 146

### South Wisconsin Street, Port Washington, Ozaukee County, Wisconsin**_"".~** 

### ...._..**~~.~** 

### ...**~."."~** 

### .."

...**".~s** 

### ..much".as".6.o

..percent.of.the

...c.O.may"be.con¥erted

..**w.ithin~L5.$econd~after~dischar** 

### .**.ge".from~"""** 

### ....**~"~** 

### ..**""~-".~-~.** 

### the stack. The conversion curve is exponential and conversion drops offrapidly but almost all CO will be converted within 24 hours. Thus, the majority ofCO emitted is converted to CO2before the plume disperses to ground level. For the Xcel High Bridge gas turbine project, an oxidation catalyst cost of$3,30l/ton ofCO was determined (for each turbine, 70 percent control for a 229.0 tpy reduction 

### @ $755,993/yr annualized cost). This costperton is based on emissions generated when the gas turbine and duct burners are operating 8760 hours peryear, without startup or shutdown (when the oxidation catalyst does not operate due to low emission temperatures). Also, the majority ofCO is from duct burners which will likely only operate a small percentage ofthe time. Excluding duct burner CO emissions, the costperton rises to i5,()99/ton ofCO,,·./ Therefore, it is apparentthat an oxidation catalyst is cost-prohibitive, and most or nearly all CO is converted to CO2by the time emissions disperse to ground level. As a result, good combustion practices is determined to be BACT for CO. Also note that about 60 percent of' the projected CO emissions occur during startup and shutdown when an oxidizing catalyst would not be operating. Based on this catalyst operating scenario, on an annualized basis an oxidation catalystwould only reduce CO by about 25 percent, assuming an overall control efficiency of70 percent when the catalyst is operating.

. In addition, the catalyst imposes a fuel conswnption penalty, and converts some S02 back to 

### 803 

### particulate which combines with water to form H2 S04. 

### Finally, spentcatalyst is a waste that mustbe disposed.

Technical Support Document, Permit No. 12300012-004 Page 7 of 19 

### Date: 1/13/2006

### The Permittee projects a construction start date ofJune 2006, with commercial operation starting in May 2009. Assuming initial startup is six months before commercial operation, the initial startup date for the new combustion turbines would be November 2008. Based on these dates, the contemporaneous period starts in June 2001 and ends by November 2008. The permit defmes Combustion Turbine Shakedown (CTS) as the period starting the day that the first turbine engages in initial startup, and ending no laterthan 180 days after the first turbine initial startup date. Requirements for shutdown ofBoilers 6 and 7 and the boiler 8 heat input limit are effective the day priorto the start ofCTS, making the associated emission changes contemporaneous and creditable. Shutdown ofboilers 6 and 7 and the heat input limit for boiler 8 create creditable emissions decreases for all NSR pollutants except boiler 8 NOx. Creditable increasesofBoiler 8 NOx emissions will occurbecause the future permitted NOx allowed by the heat input limit exceeds the baseline boiler 8 NOx emissions. However, the overallNOx net emissions change from the modification is less than the NOx significant emission rate. Coal and ash handling stack and fugitive emissions should decrease during the contemporaneous period due to the shutdown ofBoilers 6 and 7 and the limited operation of Boiler 8. However, to avoid recordkeeping associated with future actual emissions from these sources, the Permittee has elected to determine emission changes from these sources based on future potentials minus past actuals; Emissions from these sources are relatively small compared to the boilers. OP 001 emergency generators are not included in netting calculations because they are not**-~~'~~~~~~~·~U~ndefgoIng·ffiodifica:tloo.~·orichange~·ffi~epeffit.ieii·ffiffing·ffi.€"·centOmpo£aneous~peEOG~~A;fmf··~~·~~~~~·~····~··~** 

### summing all contemporaneous increases and decreases along with the emissions from the modification, the net emissions changes from the proposed modification will only be significant for CO and VOC as defined in 

### § 52.21(b)(23)(i). A separate boiler 8 heat input limit for each ofthe two permitted turbines is included in the permit because (modification) emissions data varies by turbine manufacturer. To determine compliance with the heat input limit, the permitrequires thePermittee to determine hourly heat input according to part 75 Appendix F, equations F-l8 and F-21a. The Permittee already conducts these compliance activities as required by part 75. Finally, the Permittee will permanently shutdown BoilerNo.8 and miscellaneous support equipmentno later than 12 months after the end ofcombustion turbine shakedown so that the total PM, PMIO, 

### S02, and NOx emissions reductions from this projectwill be greaterthan the creditable reductions for these pollutants.



### • BACTAnalysis: Installation ofthe new gas turbine facility is subject to BACT for CO and VOC emissions. The Permittee has submitted information tojustify that BACT is good combustion practices (OCP) for both pollutants forthe turbines and auxiliary boiler.

Technical Support Document, Permit Action Number: 05300015-004 Page 11 of 24 Date: 8/9/2006

### Discussion: The RACT BACT LAER clearinghouse (RBLC) contains arather diverse listing ofrejected and accepted costper ton data for oxidation catalysts, as well as a large overlap in the achievable ppmvd CO emission concentration for oxidation catalysts and GCP. It is apparent that locations not in attainment with federal ozone and/or CO NAAQS require installation ofan oxidation catalyst to meetLAER. However, in attainment areas justification for use ofa catalyst versus GCP is not well documented in the RBLC. In addition, reports on the atmospheric fate ofCO indicate a rather short lifetime. ADecember 1990EPA report to Congress titled 'Policy Options For Stabilizing Global Climate Report To Congress' indicates a global average CO lifespan of2.5 months. This report indicates that CO reacts with hydroxyl to form CO2and H2 0. Also, information furnished by Wisconsin Electric Power Company for their PSD permitfor the PortWashington installation ofcombined cycle gas turbines indicated that CO lifetime in the exhaustplume is even shorterbecause the rate ofconversion ofCO to CO2is temperature dependent, and stack plume temperatures are substantially higherthan average global temperature. According to the August 27,2004, document titled



### AnalysisAndPreliminaryDetermination For The ConstructionAndOperation Permits For The ProposedModification Of The Operation Of The Four Combined Cycle Combustion Turbines With DuctBurnersAndHeatRecoverySteam Generators (HRSGs), EmergencyDieselEngine, GasHeaterAndA Storage TankFor Wisconsin DNRpermit #04-RV-175 for the Wisconsin Electric Power Company

-Port Washington Generating Station, 146

### South Wisconsin Street, Port Washington, Ozaukee County, Wisconsin**_~"~** 

### __e_e_""_e eee_e_e""" eeeee**eee""as"much"as60"1Jercent"0£theenmay~bee"converted":within~15seconds~tet"dischargeeefronL"~ ee_~_"""e_"ee"""**  

### the stack. The conversion curve is exponential and conversion drops offrapidly but almost all COwill be converted within 24 hours. Thus, the majority ofCO emitted is converted to CO2before the plume disperses to ground level. For the Xcel Riverside gas turbine project, an oxidation catalyst cost oflli5,572/tonl ofCO for the MHI turbine (70 percent reduction of 180.9 tpy CO),**andp!7~670/fdiffOfCO** 

### for the GE turbine (70 percentreduction of 131.4 tpy CO) was determined. This costper ton is based on emissions generated when the gas turbines are operating 8760 hours peryear, without startup or shutdoWIl (when the oxidation catalyst does not operate due to low emission temperatures). Therefore, it is apparentthat an oxidation catalystis costprohibitive, and most ornearly all CO

e

### is converted to CO2by the time emissions disperse to ground level. As a result, good combustion practices is determined to be BACT for CO. Also note that most ofthe projected CO emissions occur during startup and shutdown when an oxidizing catalyst would not be operating. Based on this catalyst operating scenario, CO .control efficiency on an annualized basis would be substantially lower than 70 percent. In addition, the catalyst imposes a fuel consumption penalty, and converts some S02 back to S03 particulate which combines with water to form H2 S04• 

### Finally, spentcatalyst is a waste thatmustbe disposed.

Technical Support Document, Permit Action Number: 05300015-004 Page 12 of 24 Date: 

### 8/9/2006The project did require an environmental review due to the increase in timberharvesting. The Permittee, in consultation with Minnesota Department ofNatural Resources (DNR) and the MPCA, elected to conduct an Environmental Impact Statement and DNR was designated as the Responsible Governmental Unit (RGU) for the project. The EIS was placed on public notice on January 30, 2006, and a public meeting was held in Grand Rapids on February 21, 2006. The comment period for the DEIS ended on March 7, 2006. 

### 3.3 

### PSD Analysis The PSD analysis was completed for the proposed projectthrough Air Emission PermitNo. 06100001-009, issued on August 31,2006. The scope ofthe project has not changed. The RACTIBACTILAER Clearinghouse (RBLC) was reviewed for further entries since the original BACT determination was made. There have been no entries that change the determination ofBACT. An update to the PSD analysis from the technical support document for Permit 06100001-009 follows. It has been updated to reflect more current cost estimates. Attachment D includes the BACT summary from: Permit 06100001-009, and the updated RBLC summaries as provided by the Permittee, and supplemented by the MPCA (data since July 6,2007). 

### 3.3.1 Annlicability Analysis Emissions increases were determined for the original analysis by comparing the baseline actual emissions to the future potential emissions. Facilities may use any consecutive 24-month period in the past 10 years to determine baseline actual emissions. Blandin chose the period of200l/2002 as its baseline period; that time periodremains a valid choice at this time, since it is still within the past 10 years. Blandin also performed a netting analysis, by considering all creditable and contemporaneous increases and decreases in addition to the project increases. TIle net emissions changes for each pollutant were then compared to the associated threshold to determine PSD applicability for that pollutant. On May 8,2008, EPA issued final rules governing the implementation ofNSR for particulate matter less than

_.**····~~~~--~·-··7;jmicrometers** ..in·diametedPMnl:

..**·T-he·rttles~eeome..effective** ..on..July

..**j...)..i-200~,** ..:r-he.rules.set

..a.significauL

..... elilissi6risTricreasethiesholdforPM2 .5 at 

### 10 tpy.Since the rules were not in effect at the time Project Thunderhawk was first analyzed, and the application for extension ofthe construction deadline is complete prior to July 15, 2008, analysis ofPM2 .5 is not required. However, since the project results in a net decrease in PM IO, it seems likely that there would also be a net decrease in PM2
.5, and the project would notbe subject to PSD for PM25 . Table 1 ofthis docwnent shows that emissions from NOx, VOC and S02 are over the thresholds and subject to further PSD review. 

### 3.3.2 BACT Analysis The calculations showed that the project is subject to PSD for NOx, VOC and S02. Therefore, a BACT analysis was required and completed for Permit 06100001-009, issued on August 31, 2006. The existing boilers 5 and 6 and coater/dryer no. 6 are not modified and thus are not subject to the BACT analysis. The emission units and associated PSD pollutants evaluated in the BACT analysis are: Pulp and Paper Sources EU015

- Existing PGW (VOC) EU034

- New TMP (VOe) EU039/PM7

- New No.7 paper machine (VOC) 

### EVO 10/PM6

- Existing No.6 paper machine (VOe) Combustion Sources EU033

- New No.9 natural gas-fired boiler (VOC, NOx, S02) New natural gas space heating (VOC, NOx, S02)

Technical Support Document, Permit Action Number: 06100001-011 Page 6 of 11 Date: 9/18/2008Pulp andPaperSources The technologies that were considered for VOC control for the pulp and paper sources were incineration (thermal oxidizers, catalytic oxidizers, recuperative oxidizers, and regenerative thermal oxidizers [RTO]), carbon adsorption, condensation, and biofiltration. All ofthe incineration technologies were considered teclmically feasible, as was condensation. Carbon adsorption was not considered a technically feasible control option due to the concerns of particulates and other contaminants in the airstream causing plugging or fouling ofthe activated carbon, Biofiltration was also not considered technically feasible. Biofiltration requires significant land area, whichis not available at the facility. Also, there has been limiteduse ofbiofiltration, and thus there is uncertainty in the degree and consistency ofVOC control. EUO 15 is currently controlled, with 83 percent combined capture and control ofthe exhaust; this is considered baseline. EUO15 was evaluated for control of 100 percent ofthe PGW exhaust. All the control options analyzed under the 100 percent control scenario were considered to notbe cost effective; the minimum incremental control cost to go from the current operation of83% combined capture/control to 100% control is $ 14,075/ton. The current operation was determined to be BACT. In addition, aproduction limit of750 bone dry tons pulp per day for the PGW was proposed by Blandin as part ofthis project. EU034 was evaluated under two scenarios. Scenario I is for control of 100 percent ofthe EU034 exhaust. Scenario 

### 2 is for 70 percent capture ofthe EU034 exhaust, and 95 percent control ofthe EU034 VOc. All the control options analyzed under Scenario I were considered to not be cost effective; the minimum control cost for this scenario is $30,898/ton. Scenario 2, with overall control of67 percent ofthe VOCs using RTO was determined to be BACT; the cost effectiveness for this scenario is

### $:5'600/t06/ " The paper machines (existing EUOIOIPM6 and new EU0391PM7) were analyzed using two scenarios similar to EU034, The first scenario for each paper machine was controlling all the vents associated with each machine. The second scenario for each paper machine considered partial capture ofthe exhausts from the paper machines. In addition, each scenario was analyzedusing two VOC emission rates, since the pulp from the pulping processeshave different eillissioll rates.**Th~t\v0** rates were

# yog emissions using the lU.axi1llU1TI aIllount of



# _ ..**~~"~~~_~.** 

# _. ..PGWpuIpTwrththelllgher**-VOC~elnlssion- iaie5an,rvoC-emlssloils~using'dle~averagePGW7fMP** **purplnlxture:'~-----_~'-** The control costs for all these options was very high; Scenario 2, which would have lower costs than Scenario I, had costs ranging from $35,000/ton to $50,000/ton for PM6 and ranging from $64,000/ton to $72,OOO/ton for PM7. These costs are not considered to be cost effective, and thus BACT is determined to be no control. The costs for controlling VOC emission from the coaJer/dryer 6 ranged from $15,000/ton to $114,000/ton; these costs are not cost effective. Combustion Sources A BACT analysis was performed for NOx, VOC, and S02 for both Boiler 9 and the additional space heating. The types ofNOx control considered were selective catalytic reduction (SCR), selective non-catalytic reduction (SNCR), flue gas recirculation (FGR), and low NOx burners. All ofthese options are considered to be technically feasible. Although SCR may have been considered cost effective (the cost effectiveness was originally estimated at approximately1f9000/tonXFGR with low NOx burners was determined to be BACT in this case. Although there were determinations listed in the BACTILAER Clearinghouse showing SCR as BACT, upon further

. investigation it was determined that there are no cases ofSCR actually mstalled for this category ofboilers (i.e. natural-gas fired). In addition, in cases where SCR was considered, itwas considerednot to be cost effective, even at costsbeIow the $9000/ton cost calculated by Blandin. VOCs from combustion sources are generally controlled through good combustion practices. VOCs are formed due to incomplete combustion; therefore, controlling the process will result in minimized VOC emissions. VOCs could potentially be controlled by add-on incineration. The cost ofadd-on control is not cost effective;

Technical Support Document, Permit Action Number: 06100001·011 Page 7 of 11 Date: 9/18/2008

### All documents from Mike Owens are available at: ftp://ftp.epa.gov/r8/deseret/administrative record 1) 

### WA Parish Units 5-8 (Texas)

- Document sent via e-mail from Randy Hamilton from Texas 2) 

### Black Hills Corp-Wygen 2 (Wyoming) 

### = Document from Mike Owens and on RACT/BACT Clearinghouse 3) 

### River Hill 

### Power Company (Pennsylvania) = 

### Document from Mike Owens 4) 

### Rocky Mountain Power (Montana) = 

### Analysis available at: www.deq.state.mt.us/AirQuality/ARMpennits/3l85-03 .pdf 5) 

### Omaha Public Power District (Nebraska) 

## =Analysis available at: www.epa.gov/region7/air/nsr/archives/2005/finalpennits/oppd nebraska city final psd pennit.pdf 6) 

### Black Hills Corporation-Wygen 3 (Wyoming) = 

### Document from Mike Owens and on RACT/BACT Clearinghouse 7) 

### LongleafEnergy Associates (Georgia) = 

### Analysis available at: www.gaepd.orglair/airpennit/downloads/pennits/psd/dockets/longleaf/pennitdocs/09900
8) 

### Cargill, Incorporated (Nebraska) = 

### Analysis available at: www.epa.gov/region7/air/nsr/archives/2006/finalpennits/cargill blair final psd pennit.p df 9) 

### ADM Corn Milling Facility (Nebraska) 

## =Analysis available at: www.epa.gov/region7/air/nsr/archives/2006/finalpermits/adm columbus final psd perm it.pdf 10) 

### Basin Electric Dry Fork Station (Wyoming) = 

### Retrieved from Tom's files 11) 

### Southern Montana Electric Highwood Station (Montana) = 

### Analysis available at: www.deq.state.mt.us/AirQuality/ARMpennits/3423-00.pdf 12) 

### Deseret Power Electric Bonanza Station (Utah) = 

### Analysis available at: www.epa.gov/region8/air/pdf/FinalStatementOfBasis.pdf