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 Power Coopcnuivc

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 of Gillette,

Campbell Coumy, WY

Coal Fired Electric Power Generating Slillion

Stewart Griner - Air Quality bngmeer

Cole Anderson - Air Quality Engineer

Don Watzel- Air Quality Specialist

Basin Electric submitted un application 10 construct a coal fired electric power generating station adjacent

to the Dry Fork Mine on Ilighway 59, approximately 7 miles north northeast of Gilletie, Campbell

County, Wyoming. A map of lhe 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 input for the

PC boiler is 3,801 MMBtulhr. The design values used for coal from Dry Fork Mine include a heat valuc

of 8,045 Btullb (7,800 Btu/lb minimum to 8,300 Btu/lb maximum) and a sulfur content of 0.33% (0.25%

minimum to 0.47% ma.ximum). Matcrial handling will includc coal, lime, Oy ash, 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 a 2377 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/Filtcr Exhaust

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.

2 Bascd on NSPS limit of 97x I0.0 Ib/M W-hr, 12 month rolling ayeragc.

1 Based on a maximum of 5 ppm~ ammonia slip.
Basin Electric, Dry Fork 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 per year.

, NO.1(, PM IO , and CO based on Tier [I emissions from 40 CFR Subpal1 89. S02 and VOC based on

AP-42. Annual elllissions based all sao hours per year.

O.llblMMBtu NO,. 0.00061b1MMBlu SO,. 0.081b1MMBlu CO, 0.0075 IblMMBlu PM". and

0.0054 Ib/MMBlll VOC. Limited 102500 hours per year.

- . . Unil No. Emission Unit ~O, SO, CO PM lo VOC

(tOY) (lOY) (tOY) (toy) (tOY)

ESI-02 134 MMBtulhr Auxiliary 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 Inlet Gas HealerJ 1.0 0.01 0.8 0.08 0.06

Total 13.7 0.5 15.4 ~LL_--0._

M . III dl' dF PMlPM S P . IE'

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 a building.

4 Based on Division's Guideline for Fugitivc Dust Emission I;ac(ors for Mining Activities, 50% control

for water sprays on unp..1vcd roads, and 85% control for paved roads.

} Based on AP.42.

atCria . an 1112 all u ••tlve '"" OUfCCS - otenlla .. nuSSIQns

Unit No. Emission Unit PM PM 10

(t'lxLI--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 8c9_

ESI-20 Activated Carbon Silo2 0.1 0.1

ESI-21 and 22 Fly AshlFGD Waste Silo 0.4 0.4 _

FSI-OI Fly Ash/FGD Wastc Truck Loadin"J <0.1 <0.1

FSI-02 Flv AshIFGD Waste Haul Roads 0.2 ,

FS 1-03 Ash/FGD Waste Landfill 1.8 <O~ 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 of Significant Deterioration (PSD) revicw under Chapter 6.

Section 4 ofthc Wyommg Ail' Quality Standards and Regulations (WAQSR) because it io; classified as a

"major emitting faciliIY." Fossil-fuel fired stcam electric plants of more than two hundred and fifty

million Btu/hour hcal input with Ihe potential to emit one hundred tons pcI' ycar or more of any regulmed

pollutant arc considered "major emitting facililies" under Chapler 6. Section 4(aXi) ortile \VAQSR.

Potcntial emission rates from Ihe proposed facility and the PSD significance levels flrc shu.... n in the

following table:
Basin ElcclrIc, Dr)' Fork Simian

Pcnllli Applic:l\ion An<ll)'sis. AP-3546

Page 4

C PSOTI III

MercUlY and Beryllium are excluded from federal PSD regul<ltlons S111CC 1990 per ScctlOn I 12(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/PM IO 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 subject to a Prevention of Significant Dctcrioration (PSD) review consisting of

the following:

I) A Bcst Avnilablc COlltrol Technology (BACT) analysis is required for ull regulated pollutant emitted

in significant amounts.

2) An ambient air quality 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 increment consuming 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 NOx for lhe classification ofthe area (i.e. Class 1or Class 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 CONTROL TECHNOLOGY (BACT),

A best available control technology (BACT) analysis is required ror NOx• SO~, PM/PM IO, CO, VQe.

112504• nuoridcs, mercury, and beryllium because each ofthese pollutants is emitted above PSD

significant emission 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 a post combustion cOlllroltechniquc m which the nuc

gas is combined with vaporized ammonia in the presence or a catalyst and NO>; is reduced 10 nitrogen

and water,

2. Selective Non-Catalytic Reduction (SNCli)· SNCR is similar to SCR in that it involves the InJcction

of a reducing agent such as ammonia or Ufea into the flue gas strcam. The reduction chemistry,

however, takes place without the aid of a catalyst. SNCR systems rely on appropriate injection

temperatures, proper reagent/gas mixing and prolonged retention time in place of lhe catalyst. SNCR

systems arc very sensitive to temperature changes and typically have lower emissions reduction (up (0

fifty or sixty percent) and higher ammonia slip. Basin Electric did nol further consider SNCR because

of the lower emissions reduclion.

3. Low NOx Burners with ovcrfire air - These technologies reduce peak combustion temperatures

therefore lowering NOx emissions.

13asin Electric proposed SCR combined with Low NOx 13umcrsloverfire air. This represents Ihc 101'

control technology so no furthcr cvaluation of other control technologies is required. Basin Electric

originally proposed an emission level ofO.071b1MMBtu and SCR combined with Low NOx

Burnersloverfire air was evaluated at a number of different 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 hour average and an equivalent 30 day average limit would be less. A review ofother

reccntly pcnnlltcd facilities rcvealed four PC boilers achicving emission levels below 0.05 IblMMBtu

using SCR combined with Low NOx burncrs/overfil'c air. W.I\. Parish Generating Stalion Units S. 6, 7

and 8 in IloustOll, Texas have achieved 30 day rolling average NOx emissions of less than 0.05

Ib/MM13tu for one to two years, depending on the unit. Although these units are in a scvere ozone non·

attainment area and are pemlilted under the Ilon·atlainment NSR program rather lhan 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 NOx cmission limit

of 0.06 IblMMBtu, 24 hour average. Discussions with catalyst vendors indicate that a limit of 0.06

IblMMBtu, 24 hour average, is at least as stringent as a limit oro.os IblMMBtu, 30 day average. It is alc;o

noteworthy that the application for Desert Rock Energy Center specifies New Mexico sub·bituminous

coal and states that lower NOx emissions 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 of 0.05 Ib/MMBtu is technically

feasible. As a rcsult oflhesc findings, the Divisiol1requesled Oasin Electric to evaluate JO day averagc

emission limits of 0.05 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 6 and thcn added (Wo standard deviations to the actual 30 day rolling average

emissions to determine values thc) eonsidr:r feasible emission limits. nasin Electric provided a table

comparing actual average cmission levels (design targets) with values they consider a feasible emission

IIt11lt (design target plus two standard deviations) as follows:

Actual Average Emission Level [Design Target] Design Target Plus Two 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 clear to 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 Ihe cost analysis on design target emiSSion levels.

An analysis of cost effectivcness for the design 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 of 0.30 Ib/MM13tll using Low NOx Burners with overfire aIr and the controlled emission rate llsing

SCR. The average cost effectiveness is the total annualized cost for the option, including capital cost and

annual operating and mallltcnancc costs, divided by the emissions reduction. The lower cmission levels

have higher annualizcd costs due to additional layers ofcatalyst, larger ammonia delivery systems,

increased ammonia usc, and more frequent catalyst changes. The Division considers the average cost

effectiveness to be reasonable for nil options.

A C f NO

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 1,5 II

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 1990 New Source Review Workshop Manual provides

a method to evaluate incrememal cost efTe<:tiveness between dominant options known as the least cost

envelope For this method, a plot of annual emissions reduclion vs. total annualil.ed cosl is produced and

the dominant conlrol options are indicated by fitting a curve or line through thc lower and right most

points. Points above and to the len of the line arc considered inferior controls because points on the tine

provide more emissions reduction for less money. The lellst cosl envelope is shown below:
Basm Electric. Dry Fork Station

Pennit Application Analysis, AP-3S46

Page 7

Least Cost Envelope for NOx.

e 5

3950 4000 4050 4100 4150 11200 4250 4300 4350

I

I

/cal.

~se4

e< ,

50

3900

100

c

0 90 -

"-

0 80

u

0

N

- 7 0

,

•

c

c

«

]j 60 0

...

Annual Emissions Reduction (tpy)

All ofthe options are on the curve and arc, therefore, dominant options. The incremental cosl

effecliveness for all the options is calculated In lhe following table. The Incremental emissions reduction

and incremental increase in IOlnl annualized cost is lhe difference in these values for each oplion from the

previous table. The incremental cost effectiveness is the incrcmental increase in total annualiLed cost

divided by fhe incremental emissions reduction.

ncrcmcnlaIeosl EffechvClIc:o;s lclwCCIi oOlllllllllll oJilr10115 f0'- NO,

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 -

Thc dran 1990 New Source Review Workshop Manual also discusses how to detennlnc <In adverse

economic impact and states that. "undue focus on incremental cost effectiveness can give an impression

that the cost of a control altcmalive is unreasonably high, when, in fact, lhe cost effectiveness. in terll1~ of

dollars per ton removed, is well within the normal range of acceptable 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 consider an 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 of 0.043 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. Furlher discussions wilh Basin Electric and catalyst vendors

llldieatcd thai are Sl'vcral issues that necessitate a margin of safety 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 SCR catalyst, contribute to

pluggage of the downstream air heater, and may result in an increase in particulate matter emissions.

A portion of the excess NIIJ slip will be capturcd with the fly ash and may result in ammonia offgassing during handling and in the landfill.

2. Increasing the catalyst activity to increase NOx reduction or reduce NH, slip may result in additional

conversion of SOl to SOj and react with water in the flue gas 10 form sulfuric acid mist. The

additional SOl may also increase generation of ammonium sulfate and ammonium bisulfate with Ihe

associated problems described above.

3. Emission lcvels will increase somewhat during catalyst change outs. Catalysts arc typically changed

by moving the second laycr of catalysl (second 10 come in contact with the nue gas) into the first

layer position 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 of these discussions, Basin Electric agreed to an annual average cmission limit of 0.05

IblMMBtli with a 30 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 range of

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 power OUlput. Emissions in Ib/MMBtu do not

necessarily decrease with power output.

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 Electric evalllaled 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 or calcium sulfate (gypsum). Forced oxidation is commonly used to assure

that only calcium sulfate is produced. Wet FGD can provide a better control efficicncy but uses morc

water than dry FGD and has a visible moisture plume. Wet I-GO results in higher emiSSIons of

particulate malter compared 10 dry FGD because the particulate removal device mUSl be upstream of

the wet FGD. Wet FGD also has lower removal efficiencies for acid gases and may result III higher

mercury emISSions.
Basm Electric, Dry Fork Station

Pennil Application Analysis, AP·)546

Page 9

2. Spray Dryer/Absorber (Dry FOOl - In a spray dryer/absorber, 501 is reacted with a Ca(Ollh slurry

to produce calcium 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 produce calcium

sulfite or calciulll sulfate (gypsum). Although a CDS unit may be able to achieve a slightl) higher

S02 removal efficiency thall a spray dryer/absorber, there are only two units operating in the Unlled

Slates and both have experienced problems with severe corrosion and high lime consumption

(approximalely twice that for a spray 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 Electnc evaluated dry FOD and wet FOD at several emission levels and originally proposed dry

rOD with an emission limit of 0.10 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 a 23%

margin of safety added to the 0.073 Ib/MMBIlI actual emissions for an emission level of 0.09 Ib/MM I3tll.

Basin Electric then proposed 0.10 Ib/MMBtu.

A review 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 boiler burning sub·biluminous coal. The

TS Power Plant has different emission hnllts depending on the sulfur content ofthe coal combusted.

When combuslrng coal with a sulfur content less than 0.45%, the boiler is limited to 0.065 IblMMBtu

(24-hour rolling average) and 91 % remo'val efficiency. When eombusttng coal", itll a sulfur cOlllent

greater than or equal to 0.45%, lhe boiler is limited to 0.09 Ib/MMl3tll (24·hour rolling average) and 95%

removal efficiency. The design coal for Basin Eleetric's proposed facility contains 0.33% sulfur with

sulfur contents rnnging from 0.25% 10 0.4 7%. At the upper end ofsulfur content for Basin Eleclric's

proposed facility (0.47%), a 95% 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-hour rolling average) when cOl1lbusting coal

with sulfur contents equivalenl to those for Basin Electric's proposed facility. As a result of this finding,

the Division requested Basin Electric to evaluate lower emission levels.

Basm Electric provided an analysis of cost effectiveness for wet I-GD with cmission limits of 0.07, 0.08.

and 0.091b/MMBtu and for SOA Wllh emission linuts of 0.09 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 to derive an emission limit of 0.07 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 maintenance costs, divided by the emissions reduction I he Division

considers the average cost effectiveness to be reasonable for all options.
Basin Electric, Dry Fork Slllli(lIl

Penn it Application Analysis, AP·)S46

Page 10

A"cr3fJc Cost Effcctiveness for SO

EllllSSlOn rates derived by dividing proposed cml:iSlon 11ll11lS by 123 Vo fOl SDA lind 129.6Vo fOJ wet

FGO

. ,

Case Design Target Emissions Total Average

Emission Levell Reduction Annualized Cost Cost Effectiveness

(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 cost effectiveness, the draft 1990 New Source Rcview Workshop Manual provides

a method to evaluate incremental cost effectiveness between dominant oplions known as the Icast cost

envclope. For this method, a plot of annual 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 inferior control:.. 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;;,

I

5

120

12200 12300 12400 12500 12600 12700 12800

Annual Emissions Reduction (tpyj
Basin 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 cost efTectiveness 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.

IlCrCmcllt:lIeos! rnC CCllVCIlCSS bclwCCIl I)onllllaul o . -'PIHHlS ror so,

Oplions Compared Incremental Jncremcntallncrease in Incremcntal

Emissions Reduction Total Annualized Cost Cost Effectiveness

(lOY) (Million $) ($iloll)

I-_Cases I and 2 133 1.2 9.296 -- Cases 2: and 5 316 4.8 15.299

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The average cost errectlvcness values for all three dominant options arc reasonable but the Division

considers an incremental cost effectIveness of $15.299/ton excessive when combined with the negauve

cnvironmental Impacts of wet FGO discussed previously (highcr watcr usage, visible moisture plume,

higher PM emissions, lower removal 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 of 0.07) Ib/MMBtll.

As Wilh NOx• it was necessary to determine a reasonable margin between lhe dcsign largct emission level

and an emission limit althis point in the review. Further discussions with Basll1 Electric indicated thai

arc several issues that necessitate a margin ofsafety as discussed below:

I) Basin Electric staled that the lowest emission guarantee available for SDJ\ is 94% removal with a

noer ofO.OS Ib/MMBtu (regardless of S02 loading). With an 502loading of 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 of approximately 40 PPlllv@ )0/0 02) with lower S02 loadings.

Basin Electric originally established a performance target (i.e. design target) of 0.073 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 a dry 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 of these discussions, Basin Electric agreed to an annual average emission limil of 0.08

IblMMBtu with a)O day rolling average limit of 304.1 Ib/hr (based on ),801 MMBtu/hr and 0.08

IblMMBtu). As with Ox. a Iblltr limit for the 30 day avcraging period provides more nexibill!y and

allows the facility to come back. into compliance quickly by lowering po",cr output EmIssions III

Jb/MMBtu do not necessarily decrease with power output.

Thc Division concludes that SDA with emission limits ofO.OS Ib/MM Blu, annual averagc. and 304.1

lb/hr, 30 day average, represents I3ACT for S02.