DEPARTMENT OF ENVIRONMF:NTAL QUALITY DIVISION OF AliI QUALlTV Permit Application Anul)'sis,**NSn~AP~3546** February 5, 2007 COMPANY: \1AILING ADIJIIESS,

RESI'ONSIBLE OFFICIAL:

FACILITV NAME, FACILITY LOCATION,

TYI'E OF FACILITY, REVIEWED BY,

PURPOSE OF APPLICATION, Basin Electric PowerCoopcnuivc 1717 East Interstate Avenue Bismarck, ND 58503 Jerry Mcnge Air Quality Program Coordinator 

### (701) 355-5655 Dry Fork Station Highway 59, Approximately 7 Miles North Northeast ofGillette, Campbell Coumy, WY Coal Fired Electric PowerGeneratingSlillion StewartGriner

- Air Quality bngmeer Cole Anderson

- Air Quality Engineer Don Watzel- AirQuality Specialist

Basin Electric submitted un application 10 construct acoal fired electric powergenerating station adjacent to the Dry Fork Mine on Ilighway 59, approximately 7 miles north northeast ofGilletie, Campbell County, Wyoming. A map oflhe proposed site location is included in Appendix A. The proposed facility includes one pulverized coal (PC) boiler rated at 422 MW (gross) and 385 MW (nel) wilh associated material handling and auxiliary equipment. The maximulll design heat inputfor the PC boileris 3,801 MMBtulhr. The design values used for coal from Dry Fork Mine include aheat valuc of8,045 Btullb (7,800 Btu/lb minimum to 8,300 Btu/lb maximum) and a sulfurcontent of0.33% (0.25% minimum to0.47% ma.ximum). Matcrial handling will includccoal, lime, 

### Oyash, bottom ash, and wasle product from the nue gas dcsulfurization (FGD) system. Auxiliary equipment will include 3n 8.36 MMBtu/hr Inlet Gas Heater, a 360 hp Fire Pump, and a2377 hp Emergency Generator. The application identified the following emission units:Basm Electric, 

### Dry Fork Station Permit Application Analysis, AP-3546 Pugc 2 Emission Unit Number Emission Unit Name 

# --

- 

### £51-01 Unit 

### I Main Boiler

### (S,301 MMBtulhr PC BoileL



### - - 

### £51-02 Auxiliary l3oiler! 134 MMBtu/hr,**Natll~al** Gas Fired)



# - £51-03 360 

### hD Diesel Fire Pump 

### £51-04 Auxiliary Coolinp, Tower 

### £51-05 2377 hp Diesel**Emer~cncy** Generator 

### £51-06 8.36 MMBlu/hr Inlet Gas Ileater 

### £51-07 Coal Storage Silo #1 Dust Collector 

### E51-08 Coal StoraJ,tc Silo #2 Dust Collector 

### E51-09 Coal StoraRe Silo #3 Oust Collector 

### £51-10 Coal Crusher House Dust Collector 

### £5 I-II Plant Coal Silo Transfer Bay Dust Collector

. 

### E51·12 Pebble Lime StOfa2:C Silo Dust Collector



## - £51-13 Pebble Lime Day Silo l3in Vent Filler 

### E51-14 Lime Hydrator Mixer Dust Collector

### #J 

### E5 1·1 5 Lime Hydrator Mixer Dust Collector

### #2 E51-16 Ilydraled Lime Crusher Dust Collector

### #I 

### E51-17 Ilydrated Lime Crusher Dust Collector

### #2 £51-18 Hvdrated Lime Silo 

### #1 Bin Vent Filter 

### E51-19 Ilydrated Lime Silo 

### #2 Bin Vcnt Filter



## - £51·20 Activated Carbon Silo Bin Veil! Filter 

### £51-21 Flv AshlFGD Waste Silo Seoarator/FiltcrExhaust 

### E51-22 Flv AshIFOD Wastc Silo Bin Vcnt Filter 

### F51-01 Fly Ash/FGD Waste Truck Loadin'l. 

### F51-02 Fly Ash/FOD Waste lIaul Roads 

### F51-03 AshlFGD Wastc Landfill 

### F51-04 Bottom Ash Ilandlinc.llaul Roads Emcrgency Coal Truck Unloading HOPl)er**E~IIS510** 

### 55UMMARY, Potential cmlssions for thc 

### PC Boilcr are shown in the following table: 

### PC Boiler-I'olcnti'll rlllissions 

# . " Pollutant Emission Rate Emissions Emissions 

### (lblMMBlu) (I

### blhr) (Ipy) NO, 0.05 (12 month nvp,. 

### 190.1 (lO-dayav,.) 832.4 SO, 0.08 (12 month**av~.** 

### 304.1 (30-day ava.) 1331.8 CO 0.15 570.2 2497 

### PM ID 

### 0.0120 45.6 199.8 VOC 

### 0.0039 148 64.9 HAPs 

## - -

- 

### 8.2 360 Mercury" 

### 016 Ammonia 

### 9.8 428

14.1 tpy hydlOgen chlol1de, 11.5 tpy hydrogen nUOlldc, 9.8 tpy organIc, and 0.5 tpy trace metal IlAPs. 2Bascd on NSPS limit of97xI0.0 Ib/MW-hr, 12 month rolling ayeragc. 1 Based on a maximum of5**ppm~** ammonia slip.

### Basin Electric, DryFork Station Permll Application Analysis, AP-3546 Page 3

Olhcr

### Combustion SOUI'CCS l'Olcntial [missinlls



### 0.04 Ib/MMl3lU NO,. 0.0006 Ib/MMl3lu SO" 0.08Ib/MMIJu. CO, 0.0075 Ib/MMBlll PM", ,lid 0.0054 Ib/MMOtu 

## vac. Annual emissions based on 2000 hours peryear. 

# , NO.1(, PMIO, 

### and CO based onTier [I emissions from 40 CFR Subpal1 89. S02 and VOC basedon

AP-42. Annual elllissions based all

# sao hours peryear. O.llblMMBtu NO,. 0.00061b1MMBlu SO,. 0.081b1MMBlu CO, 0.0075 IblMMBlu PM". and 0.0054 Ib/MMBlll VOC. Limited 102500 hours peryear. 

# - 

# . . UnilNo. Emission Unit

### ~O, SO, CO PMlo VOC (tOY) (lOY) (tOY) (toy) 

### (tOY) ESI-02 134 MMBtulhrAuxiliary Boiler 5.4 0.08 10.7 1.0 0.7 ES 1-03 360 ho Diesel Fire Pumo· 1.0 0.2 0.5 0.03 0.2 ES 1-05 2377 ho Diesel Emert!.encY Generator 6.3 0.2 3.4 0.2 

### 04 ES 1-06 8.36 MMBtulhr InletGas Healer J 

### 1.0 0.01 0.8 0.08 0.06 Total 13.7 0.5 15.4**~LL_--0._**



### . IE' P 

### PMlPM 

### S dF

. III dl' M



### Lstlmate based on 17,000 Spm, 6000 mgt! TDS. and 0.005 Yo 

### dfln loss. 2 

### Based on 0.005 gr/dscf. ) Based on AP-42 and loading trucks Inside abuilding. 4 

### Based on Division's Guideline for Fugitivc Dust Emission I;ac(ors for MiningActivities, 50% control for watersprayson unp..1vcd roads, and 85% control for paved roads. } Based on AP.42. atCria

. an 1112 all 

### u••tlve 

# '"" OUfCCS

- 

### otenlla

..nuSSIQns 

### UnitNo. Emission Unit PM 

### PM10 

### (t'lxL

## I--C!EYL ES 1-04 Auxiliary Coolir1l' Tower 1.1 0.3 ESI-07, 08, 09,10, and II Coailiandlinl! Dust Collectors] 16.7 16.7 

### ESI-12 13,14 15.16.17 18 and 19 Lime Ilandling Dust**Collector~~_** 

### 8.9 8 c9_ ESI-20 ActivatedCarbon Silo2 0.1 0.1 ESI-21 and 22 FlyAshlFGD Waste Silo 0.4 0.4

_ FSI-OI FlyAsh/FGD WastcTruck Loadin"J <0.1 <0.1 FSI-02 FlvAshIFGD Waste Haul Roads 0.2 ,

# <O~ FS 1-03 Ash/FGD

### Waste Landfill 1.8 04 FS 1-04 Bottom Ash Ilaul Road <0.1 <0.1 

### Total 29.2 26.8 

# , ,

CIIAI'TER 6, SECTION 4

- PSD APPLICABILITY, The proposed facility is subject to Prevention ofSignificant Deterioration (PSD) revicw underChapter6. Section 4ofthc Wyommg Ail' Quality Standards and Regulations (WAQSR) because it io; classified as a "majoremitting faciliIY." Fossil-fuel fired stcamelectric plants ofmorethan two hundred and fifty million Btu/hourhcal input with Ihepotential to emitone hundredtons pcI'

### ycaror more ofany regulmed pollutant arc considered "majoremitting facililies" underChapler6. Section 4(aXi) ortile \V

### AQSR. Potcntial emission rates from Iheproposed facility and the PSD significance levels flrc shu

....nin the following table:Basin ElcclrIc, Dr)' Fork Simian Pcnllli Applic:l\ion An<ll)'sis. AP-3546 Page 4 III 

### PSOTI C

MercUlY and Beryllium are excluded from federal PSD regul<ltlons S111CC 

### 1990 per ScctlOn I12(b)(6) of the Clcan Air Act but still included in WAQSR, Chapler 6, Scction4(a)(xxi). om 

### anson to lrcslO(S Pollutant Potential PSD Significant PSD Review Emission Rate Emission Rate Required? (tOY) (IDY) NOx 846.1 40 Yes SO, 1332.3 40 Yes CO 2512.4 100 Yes PM/PMIO 230.3/227.9 25/15 Yes VOC 66.3 40 Yes



## --- I**11S0~** 41.6 7 Yes 

### Lead 0.03 0.6 No**~:luOrjdes** __ 11.5 3 Yes Total Reduced Sulfur(includino 112$) Neelieible 10 No Mercury 0.16 0.1 Yes Berylliuml 0.004 0.0004 Yes



# . 

# .

The proposed facility is subjectto a Prevention ofSignificant Dctcrioration (PSD) review consistingof the following: I) A Bcst Avnilablc COlltrol Technology (BACT) analysis is required forull regulated pollutantemitted in significant amounts. 2) An ambient airquality impact detennination is required for all regulated pollutants emlltcd in significant amounts and any other pollutants required by the Administrator. 3) An increment consumption analysis is required for regulated pollutants based 011 allowable emission rates as well as incrementconsuming emissions from other sources in the region. The lOla1 deterioration determined from this analysis must comply with the allowable increments established for PM 10, S02. and NOxfor lheclassification ofthe area (i.e. Class 1orClass II) in which the increment consumption is predicted. II) An analysis is required to assess the impairment to visibility. soils, <lnd vegetation resulting from the facility and general cOl11lllercial, residential, industrial, and other growth associated with the facility. CIIAI'TEI< 6, SECTION 2 - BEST AVAILABLE CONTROLTECHNOLOGY (BACT), Abest availablecontrol technology (BACT) analysis is required ror NOx•**SO~,** PM/PMIO, CO, VQe. 112504• nuoridcs, mercury, and beryllium because each ofthese pollutants is emitted above PSD significantemission rates.Basin Electric, Dry Fork Station Pennll Application Analysis, AP-3546 Page 5 

### PC Boiler· NOx Basin Eleclric evaluated the following emission control technologies: Selective Catalytic Redu_ction (SCRl

- SCR IS apost combustion cOlllroltechniquc m which the nuc gas is combined with vaporized ammonia in the presence oracatalyst and NO>; is reduced 10nitrogen and water, 2. Selective Non-Catalytic Reduction (SNCli)· SNCR is similarto SCR in that it involves the InJcction ofareducing agent such as ammonia or Ufea into the flue gas strcam. The reduction chemistry, however, takes place without the aid ofacatalyst. SNCR systems rely on appropriate injection temperatures, proper reagent/gas mixing and prolonged retention time in place oflhecatalyst. SNCR systems arc very sensitive to temperature changes and typically have lower emissions reduction (up (0 fifty or sixty percent) and higherammonia slip. Basin Electric did nol furtherconsider SNCR because ofthe loweremissions reduclion. 3. LowNOx Burners with ovcrfire air

- These technologies reduce peakcombustion temperatures therefore loweringNOx emissions. 13asin Electric proposed SCR combined with Low NOx 13umcrsloverfire air. This represents Ihc 101' control technology so no furthcr cvaluation ofothercontrol technologies is required. Basin Electric originally proposed an emission level ofO.071b1MMBtu and SCR combined with Low NOx Burnersloverfireair was evaluated at a numberofdifferent emission levels as discussed below. The lowest emission rate for a PSD pennit shown in EPA's RACTfBACT/l.AER Clearinghouse(RBl.e) is O.0671b1MM13tu for Newmon! Mining Unit I in Nevada. It is worthwhilc to note that this limit is based on a 24 houraverage and an equivalent 30 day average limit would be less. A reviewofother reccntly pcnnlltcd facilities rcvealed four PC boilers achicvingemission levels below 0.05 IblMMBtu using SCR combined with Low NOxburncrs/overfil'c air. W.I\. Parish Generating Stalion Units S. 6, 7 and 8 in IloustOll, Texas have achieved 30 day rolling average NOxemissions ofless than 0.05 Ib/MM13tu forone totwo years, dependingon the unit. Although these units are in ascvere ozone non· attainment area and are pemlilted under the Ilon·atlainment NSR program ratherlhan PSD, they arc relevant because they use the samc controltcchnology prol>osed for this facility. A pcrmll rccently proposed by EPA Rcgion 9 for Descrt Rock Energ) Center III New Mexico contains a NOxcmission limit of0.06 IblMMBtu, 24 hour average. Discussions with catalystvendors indicate that a limit of0.06 IblMMBtu, 24 hour average, is at least as stringent as a limitoro.os IblMMBtu, 30 day average. It is alc;o noteworthy that the application for Desert Rock Energy Centerspecifies New Mexico sub·bituminous coal and states that lower NOxemissions may be achievable with Powder River l1asin Coal. Based on actual emissions below 0.05 Ib/MMl3tu for the four W.A. Parish Units and lhe proposed limit for Deser! Rock Encrgy Center, the Division concludes that lin emissiol1 limit of0.05 Ib/MMBtu is technically feasible. As arcsult oflhesc findings, the Divisiol1requesled Oasin Electric to evaluate JO day averagc emission limits of0.05 and 0.06 IblMMBtu.BtlSln Eleclflc, Dry Fork Station Pennit Appliclltion**Analy~i~,** AI'-3546 !'ugc 

### 6 III responsc, Basin l;lectric evaJuaied the variability In actual emission levels for W.A. Parish Generating Smlion Units 5 and 6and thcn added (Wo standard deviations to the actual 30 day rolling average emissions to determine values thc) eonsidr:rfeasible emission limits. nasin Electric provided atable comparing actual average cmission levels (design targets) with values they consider a feasible emission IIt11lt (design target plus two standard deviations) as follows: Actual AverageEmission Level [Design Target] Design Target PlusTwo Standard Deviations 

### (Ib1MMBlU) (Ib1MMBlu)



# - 0.04 0.056 

## -_

.. 

### 0.043 0.06



# --- 0.05 0.07



# -- 0.057 0.08 .-



# -- 0.064 0.09 Based on this evaluation, Basin Electric slateclthat 0.0561blMMBtu is the lowest feasiblc emission limit. The Division noted that W.A. Parish Units 5 and 6 arc actually emitting approximately 0.030 to 0.045 lblMMBtu on a 30 day average. It was not clearto the Division, at this point in the rcvie\\, whal a reasonable margin would 

### be between the design target clIIlssion level and an emission limit. me Division, therefore, decided to base Ihecost analysis on design target emiSSion levels. An analysis ofcosteffectivcness for thedesign target emission levels in the previous table was performed and the results are shown below. The emissions reduction is the difference betwecn a baseline emission rate of0.30 Ib/MM13tll using Low NOxBurners with overfire aIrand the controlled emission rate llsing SCR. The average cost effectiveness is the total annualized cost for the option, includingcapital cost and annual operatingand mallltcnancc costs, divided by the emissions reduction. The lowercmission levels have higher annualizcd costs due to additional layers ofcatalyst, larger ammoniadelivery systems, increased ammonia usc, and more frequent catalystchanges. The Division considers the average cost effectiveness to be reasonable for nil options. f 

### NO C A C;se vcnl1!C (lSI cct,VCIlCSS or



## - Design Target Emissions Total Average Emission Level Reduction Annualized Cost Cost Effectiveness 

### (lOY) (Million $) ($Ilon5 removed) 

### 1 SCR@0.064 Ib/MMBtu 3929.0 5.6 1,424 _2 SCR 0.0571b1MMBlu 4045.6 5.9 1,453 

## --.l SCR 0.051b1MMBtu 4162.1 6.3 1,5II 4 SCR" 0.043 IblMMBIli 4278.6 7.5 1,751



# - 5 SCR 

### iJ 0.04 IblMMBIli 4328.6 8.7 2.004



# - In addition to average COSI effectiveness, the drnft 1990New Source Review Workshop Manual provides amethod toevaluate incrememal costefTe<:tiveness between dominant options known as the leastcost envelope Forthis method, aplot ofannual emissions reduclion vs. total annualil.ed cosl is produced and the dominant conlrol options are indicated by fitting acurve or line through thc lower and right most points. Points above and to the len ofthe line arc considered inferiorcontrols because points on the tine provide more emissions reduction for less money. The lellstcosl envelope is shown below:Basm Electric. Dry Fork Station Pennit Application Analysis, AP-3S46 Page 7
Least Cost Envelope for NOx.



### e 5

4350 

### 4300 4250 11200 4150 4100 4050 4000 3950 

# I I 

# /cal.

# ~se4

e< 

# , 50 3900 

### 100

c 

### 90 0



# - 

# "

- 80 0 u 0 N



# - 7 0 

## • 

# , c c 

### « ]j 

### 60 0 

# ...

Annual Emissions Reduction (tpy)

All ofthe options are on thecurve and arc, therefore, dominant options. The incremental cosl effecliveness for all theoptions is calculated In lhe following table. The Incremental emissions reduction and incremental increase in IOlnl annualized cost is lhe difference in these values foreach oplion from the previous table. The incremental cost effectiveness is the incrcmental increase in total annualiLed cost divided by fhe incremental emissions reduction. f NO 

# o r o Eff 

## Ie ncrcmcnla osl echvClIc:o;s lclwCCIi Olllllllllll Jil 10115 

### 0'- 

# , Options Compared Incremental Incremental Increase in Incremental Emissions Reduction Total Annualized Cost Cost Effectiveness (tDV) ($) ($lton) Case I and Case 2 117 285,000 2,446 Case 2 and Case 3 117 409,300 3,512



# -- - Case 3 and Case 4 117 1,200,700 

## l- 10,303



# - Case 4 and Case 5 50 1,185,900 23,744

- Thcdran 1990 New Source Review Workshop Manual alsodiscusses how to detennlnc <In adverse economic impact and states that. "undue focus on incremental cost effectiveness can give an impression that the cost ofa control altcmalive is unreasonably high, when, in fact, lhe cost effectiveness. in**terll1~** of dollars per ton removed, is well within the normal range ofacceptable I3ACT costs." [11 this case, the llveragc COSI effectiveness for all options is clearly within the range the DiVision has considered acceptable. The Division considers the incremental cost effectiveness of$IO,303/ton reasonablc for all additional 117 tpy emission reduction but does not consideran incremental cost cffectiveness of $23.744/ton reasonable for an additional 50 tpy emission reduction. Therefore, the incrcmcntal cost effectIveness is considered reasonable for a design target emission level of0.043 lb/MMBtli (Case 

### .1).Ba!\in Electric. Dry Fork Station Pcmlll Application Analysis, AP-3546 Page R Atlhis point in the review, it was nccessary to dctermine 

### a rellsonable margin between the design target emission level 

### and an emission limit. Furlherdiscussions wilh Basin Electric and catalyst vendors llldieatcd thai are Sl'vcral issues that necessitate a margin ofsafety 

### as discussed below: hmissioll guararllces below

### 0.05 IblMMBtu arc associated wilh high ammonia ( rI)) slip values that cause problems elsewhere in the plant. Excess I II) slip reacts with Sal in the fluc 

### gas 10 generate ammoniulll sulfate and ammonium bisulfate which deactivate 

### lhe SCRcatalyst, contribute to pluggage ofthe downstream air heater, and may result in an increase in particulate matter emissions. A portion ofthe excess NIIJ slip will be capturcd with the fly ash and may result in ammonia offgassingduring handling and in the landfill. 

### 2. Increasing the catalyst activity to increase 

### NOxreduction orreduce 

### NH, slip may result in additional conversion ofSOl to SOj and react with water in the flue gas 10 form sulfuric acid mist. The additional SOl may also increase generation ofammonium sulfate and ammonium bisulfate with Ihe associated problems described above. 

### 3. Emission lcvels will increase somewhat during catalystchange outs. Catalysts arc typicallychanged by movingthe second laycrofcatalysl (second 10come in contact with the nue gas) into the first layerposition and putting fresh catalyst in the second layer position. This is done one section at a time while the plant 

### is on line and results in somewhat higher emissions during the change out. As a result ofthesediscussions, Basin Electric agreed to an annual average cmission limit of

### 0.05 IblMMBtli with 

### a30 day rolling average limil of

### 190.1 Ib/hr(based on 

### 3,801 MMBtulhr and

### 0.05 Ib/MMBlu). Basin Electric stated that the performance target(i.e. design target) will be mlhe rangeof 

### 0.04 IblMMBtu with 

### 3.5 10

### 5.0 ppm 

### Nil) slip (maximum) and 

### 1.5% Sal 10 Sal oxidation (maximum). Basin Electric accepted emission limits close to the design target due to the nature ofthe: linilis and thc averaging periods. The annual avcrage Ib/MMBIU limit minimizes the effects ofemission spikes. The (b/hr limll for lhe 

### _,0 duy aveftlgillg period provides more flexibility than a Ib/MMBlU limit and allow!; the facilily to corne back into compliance quickly by luwering powerOUlput. Emissions in Ib/MMBtu do not necessarily decrease with poweroutput. The Division concludes that SCR combined with Low NOx Burners and overfire air with emiSSion limns of

### 0.05 IblMMBt'u, annual average, and 

### 190.1 Iblhr, 

### 30 day avcrage, represents BACT for 

### NOx. PC Boiler

- Sal Basin Electricevalllaled the following emission controltcchnologies: WeI Flue Gas Dc..§.ulfurizalion (FOO)

- For wct FGO, SOl is rc;acted with a limestonc or lime :;Iurry 10 produce calcium sulfite orcalcium sulfate (gypsum). Forced oxidation is commonly used to assure that only calcium sulfate is produced. Wet FGD can provide a bettercontrol efficicncy but uses morc water than dry FGD and has a visible moisture plume. Wet I-GO results in higheremiSSIons of particulate malter compared 10 dry FGD because the particulate removal device mUSl be upstream of the wet FGD. Wet FGD also has lowerremoval efficiencies for acid gases and may result III higher mercuryemISSions.Basm Electric, Dry Fork Station Pennil Application Analysis, AP·)546 Page 9 2. Spray Dryer/Absorber (DryFOOl

- In a spray dryer/absorber, 501 is reacted with a Ca(Ollh slurry to producecalcium sulfate (gypsum). The calcium sulfate is captured downstream ill the fabric filter. Significantly less water is used compared to wei FOD and there is Iyplcally no visible Illoisture plume. 3. Circulating Dry Scrubber (CDS) -In a CDS unit, S02 is reactcd with dry Ca(OI-lh to producecalcium sulfiteorcalciulll sulfate (gypsum). Although a CDS unit may be able to achieve aslightl) higher S02 removal efficiency thall a spray dryer/absorber, there areonly two units operating in the Unlled Slates and both haveexperienced problems with severe corrosion and high lime consumption (approximalely twice that for aspray dryer/absorber) and high energy costs (approx.imalely 1/3 higher than a spray dryer/absorber). Due to the technical and operational problems with CDS, this technology v.as not considered further. Basin Electncevaluated dry FOD and wet FOD at several emission levels and originally proposed dry 

### rOD with an emission limit of0.10 Ib/MMBtll, 30 day rolling average, and 380.1 Ib/hr,3 hour block (based on 0.10 IbfMMBtu). As with NOx, Basin Electric evalul'Iled the variability in actual 30 day rolling average emission levels altwo facilities and added two standard deviations. This equaled to a23% margin ofsafety added to the 0.073 Ib/MMBIlI actual emissions for an emission level of0.09 Ib/MMI3tll. Basin Electric then proposed 0.10 Ib/MMBtu. Areview ofrecently issued PSD perrnits indicates that Newmont Nevada Ener&) Investment's<I S Power Plant uses SOA and has the lowest SOl emission limit for a PC boilerburning sub·biluminous coal. The TS Power Plant has different emission hnllts depending on the sulfurcontent ofthe coal combusted. When combuslrngcoal with a sulfurcontent less than 0.45%, the boiler is limited to 0.065 IblMMBtu (24-hourrolling average) and 91 % remo'val efficiency. When eombusttngcoal", itll a sulfurcOlllent greaterthan orequal to 0.45%, lhe boiler is limited to 0.09 Ib/MMl3tll (24·hourrolling average) and 95% removal efficiency. The design coal for Basin Eleetric's proposed facility contains 0.33% sulfur with sulfurcontents rnnging from 0.25% 10 0.47%. At the upperend ofsulfurcontent for Basin Eleclric's proposed facility (0.47%), a95% removal efficiency results in 0.06 Ib/MMl3tu. Therefore, the TS Power plant would be limited to no more than 0.065 Ib/MM13tll (24-hourrolling average) when cOl1lbusting coal with sulfurcontents equivalenl to those for Basin Electric's proposed facility. As aresult ofthis finding, the Division requested Basin Electric to evaluate loweremission levels. Basm Electric provided an analysis ofcost effectiveness for wet I-GD with cmission limits of0.07, 0.08. and 0.091b/MMBtu and for SOA Wllh emission linuts of0.09 and 0.10 IblMMBtu. As prcvlousl) dls;cussed, !lasin Electric added a 23% margin to the 0.073 Ib/MMBtu design target emission Ic

...e1 for SDA to derive an emiSSion limit ofO.091b1MMBtu. Similarly, they added a 29.6% margin to the 0.054 Ib/MMBtu design target for weI FGD toderive an emission limit of0.07 IblMMl3tu. Therefore. the Division used the economic information provided but divided the proposed emission linuts by 123% for SDA and 129.6% for wet FGD so that the Analysis is based on designlarget levels as with NOx. The results arc shown in the following table. Thc emissions reduction is [he difference between an uncontrolled baseline emission ratc ofO.82Ib/MMBtu and the design targcllevel emission rate using weI FGD or SDA. The average eosl effectiveness is the total annualized cost for the option. Including capilnl cost and annual operating and maintenancecosts, divided by the emissions reduction Ihe Division considers the average costeffectiveness to be reasonable for all options.Basin Electric, Dry Fork Slllli(lIl Pennit Application Analysis, AP·)S46 Page 10 

### A"cr3fJc Cost Effcctiveness forSO

EllllSSlOn rates 

### derived by 

### dividing proposed cml:iSlon 11ll11lS by 

### 123Vo fOl SDA 

### lind 129.6Vo fOJ wet 

### FGO 

# . 

# , Case Design Target Emissions Total Average Emission Levell Reduction Annualized Cost CostEffectiveness 

### (IDY) (MilEon $) ($/Ions removed' 

### I SOi\ (ii' 

### 0.081 Ib/MMOIU 12303 14.3 1•..159

. 

# , SOA @ 

### 0.073 IblMMBtu 12436 15.5 1.246 t-- ] 

### Wet FGO r1i) 

### 0.0691b1MMOtu 12503 17.7 10417 4 Wet FGD (a 0.062 IblMMBtu 

### 12619 19.0 I 504 5 Wet FGO

## Ial 0.054 IbiMMOI" 12753 20.3 1,595 

## , 

# , ,. 

## .. 

# . • •

In addition to average costeffectiveness, 

### thedraft 1990 New Source Rcview Workshop Manual provides amethod to evaluate incremental costeffectiveness between dominant oplions known as the Icastcost envclope. Forthis method, a plot ofannual emissions reduction vs. total annualized cost is produced and the dominant cOlltrol oplions are indicated by fitting a

### curve or 

### line through 

### lhe Jower and rightlllost points as shown below. Points above and to the left ortbe line arc considered inferiorcontrol:.. bec<luse points 011 the line provide morc emissions reduction for less moncy.
Least Cost Envelope for 502
220 21 0 200 

# = 0 190 

# "

- Ie 0 

## • 0 U -0 170 N 160 

# , = = 

# "" 150 

# , 

# - 0 >-- I" 0 130 

# -l

/' Case 

# / 

# 7 .case3/, 

# I**~--ca;e2** 

# ..-ca;;, I5

120 12200 12300 

### 12400 12500 12600 12700 12800 Annual Emissions Reduction (tpyjBasin Electric, Dry Fork Station Pennit Application Analysis, AP·)546 

### Page II The dominant options are Cases I (SDA @0.081 Ib/MMBtu), 2 (SDA 

### @ 0.073 Ib/MMBtu), and 5 (Wet FGO@0.054 Ib/MMBtu). The incremental costefTectiveness for the dominant options is calculated in the following table. The incremental emissions reduction and incremental illcrcasc in tOlal annualil.cd cost is Ihe difference in Ihesc values for each option frollllhc previous table. The incrcmenlal cost errecllveness is the incremental increase in**~olal** annualized cost divided by lhe lOcremenlal emissions reduction. 

## r so 

# o . I) b 

## rn Ie IlCrCmcllt:l os! C CCllVCIlCSS clwCCIl onllllaul -'PIHHlS 

### or 

# , Oplions Compared Incremental Jncremcntallncrease in Incremcntal Emissions Reduction Total Annualized Cost Cost Effectiveness (lOY) 

### (Million $) ($iloll) 

## I-

_ Cases Iand 2 133 1.2 9.296



### -- Cases 

### 2: and 5 316 

### 4.8 15.299



# ----- The average cost errectlvcness values for all three dominant options arc reasonable but the Division considers an incremental costeffectIveness of$15.299/ton excessive when combined with the negauve cnvironmental Impacts ofwet FGO discussed previously (highcr watcrusage, visible moisture plume, higher PM emissions, lowerremoval eflicicncy for acid gases, and possibly higher mercury emissions). Therefore, the incremental COl'I effectiveness is considered rcasonable for SDA with a dcsign target emission level of0.07) Ib/MMBtll. As Wilh NOx • it was necessary to determine areasonable margin between lhe dcsign largct emission level and an emission limit althis point in the review. Furtherdiscussions with Basll1 Electric indicated thai arc several issues that necessitate amargin ofsafety as discussed below: I) Basin Electric staled that the lowest emission guarantee available for SDJ\ is 94% removal with a noerofO.OS Ib/MMBtu (regardless of

### S02 loading). With an 

### 502loadingof 1.33 Ib/MMl3tu. 94% removal results in an emission level ofO.08IblMMBtll. Basin stated that vendors will guaranlee Q4% removal with 

### S02 loadings above 1.33 lb/MM13IU but will not guarantee less than 0.08 Ib/MMBl11 (equivalent to an SOl concentration ofapproximately 40 

### PPlllv@ )0/0

### 02) with lower

### S02 loadings. Basin Electric originally established aperformance target (i.e. design target) of0.073 Ib/MMDIU based on an 

### SO) loading of 1.21 IblMMBtu and 94% removal but subsequently learned that 0.073 IblMMBtu IS below the noer ofO.081b/MMBlu for an emission guarantee. 2) InjectIng additional lime slurry and/or operating Ihc systcm at an outlet temperature approaching saturation may increase**S~** removal bUllhe slurry feed rate is limiled by the requirement 10 operate the SDA above saturation temperature and producc adry**by~product.** Operating the SOA al or below the design limil increases the potential for operating issucs including wall weniHg. scaling, plugging, and operational problems with the downstream fabric filter. As a result ofthese discussions, Basin Electric agreed to an annual average emission limil of0.08 IblMMBtu with a)O day rolling average limit of304.1 Ib/hr(based on ),801 MMBtu/hrand 0.08 IblMMBtu). As with Ox. a Iblltrlimit for the 30 day avcraging period provides more nexibill!y and allows the facility to come back. intocompliance quickly by lowering po",croutput EmIssions III Jb/MMBtu do not necessarily decrease with poweroutput. Thc Division concludes that SDA with emission limits ofO.OS Ib/MMBlu, annual averagc. and 304.1 lb/hr, 30 day average, represents I3ACT for 

### S02.