$ 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~

L\ -L-N\.~ ~~\':.;1J\.:r l oJcn V\OvVJ. vU~-Dfl~

1-F Y\ -c-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. Po lIutantlnfo&FaCility....lD00 25368&ProcessJ D 1001 02&PoliutanCI D~@t.

Last updated on Wednesday, March 31, 2 0

Technology Transfer Network cClean Air Technology Center - RACTjBACTjLAER Clearinghouse

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Pollutant Information

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pollutant.

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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://cfpub l.epa.gov/rblc/index.cfm?action=PermitDetail.PollutantInfo&Facility_ID=253... 3/31/2010
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htlp I/cfpubl epa qov/rblc/lOdex cfm 7 ac110n=PerrnltDelall.PoliutantInfo&Facdlty _ID= 25368&Process ,lD= 100l02&Poliulanl, lD=§92

Last updated on Wednesday. ~1arch 31. 201

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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://cfpub l.epa.gov/rblc/index.cfm?action=PennitDetail.PollutantInfo&Facility_ID=253... 3/31/2010
DEPARTMENT OF ENVIRONMENTAL QUALITY

DIVISION OF AIR QUALITY

Permit Application 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:

Black Hills 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 of one

PC boiler burning coal from the nearby Wyodak coal 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

BaselineI

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 economizer bypass 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!eclpennlt"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 of 0.08 IbIMMBtu. Although Great Plains Power requested 3 years to .

determine if they can comply with the limit as allowed in the Hawthorne Station permit, Missouri DNR

indicated that they do not plan to issue the permit with any exceptions to the 0.08 Ib/MMBtu limit.

The Division evaluated the control efficiency required to meet limits of 0.09, 0.08, and 0.06Ib/MMBtLi

using a baseline of 0.25 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 economizer bypass is

required to achieve emission limits of 0.08 lb/MMBtu or less. Although the BACT analysis indicates an

emission level of 0.06 Ib/MMBtu, Black Hills Corporation has expressed uncertainty about meeting 0'.06

Ib/MMBtu on a continuous basis. The Division and Black Hills 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 of uncertainty in regards to meeting the annual limit and they requested that

the 0.06 Ib/MMBtu limit not become effective until issuance of the 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 Corporation agreed that a

30 day limit of 0.07 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 of Pennsylvania

Department ofEnvironmental Protection

May 2, 2005

Subject: Plan Approval Application Review Memo (PSD, NSR, NSPS, MACT)

River Hill Power Company, LLC

Karthaus Township, Clearfield County

Plan Approval Application # 17-00055A

To: David W. Aldenderfer

Environmental Program Manager

Air Quality Program

From: Cortney A. Danneker

New Source Review Section

Air Quality Program

Sean Wenrich

Facilities Permitting Section

Air Quality Program

Through: Muhammad Q. Zaman

Chief, Facilities Permitting Section

Background

River Hill Power Company, LLC has submitted a plan approval application for the construction of a 290

megawatt waste coal fired electric generating facility to be located in Karthaus Township, Clearfield County.

The electric generating facility will consist of a 2,871 MMBtuIhr bituminous waste" coal fired circulating

fluidized bed (CFB) boiler, a steam turbine generator, a #2 fuel oil fired auxiliary boiler for CFB boiler start-up,

a mechanical draft wet 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 contaminant emissions from these sources will be controlled with source specific

control devices, limited operating hours and limited material throughputs which will be discussed in further

detail later in the review memo.

The facility is expected to have significant environmental and economic benefits by utilizing up to two million

tons ofwaste coal per year and by generating over two million megawatt-hours of electricity on an annual basis.

Economic benefits associated with the facility include stabilization ofelectric rates caused by the lower cost of

electricity generated by coal powered electric plants, the reduced need in fuel oil consumption, the creation of

1,000 or more jobs over the three year construction period as well as up to 60 full time jobs during the plant's

operational life span and the influx ofmillions of dollars into the area to support wages, subcontracted services,

and the purchasing ofmaterials and supplies from local merchants. Additionally, the utilization ofwaste coal

piles will also reduce the huge waste coal piles in Pennsylvania, and over one million tons per year ofash and

combustion byproducts from the facility will be reused to mitigate the affects of abandoned mine drainage.

The company plans to start construction ofthe facility soon after the plan approval is issued with an anticipated

first fire ofthe CFB boiler scheduled for September 2007. The completed construction ofthe entire facility is

scheduled for May 2008 with the beginning of commercial operation scheduled for June 2008.
c;RA;CT~A'J;R:~yi~

"TheS":

10

>". V':'~

. " " .
na3

t, control equipment

«e. ill additi

ich corr

ny's

,t is in company the eeatinput,which

s to a 98.2% S02 control efficiency and i ent 's BACT and BA'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 will allow better

control over tbe CFB tern. On February 28. 2005, th :ralRegisterpublished for commept the

proposed amendments ubpart Da oftheStandewStationary Sources, 40 CFR

60. According to the proposed amenuldbe subject to an S02 emission limit

of2. unds per megawatt hour of gross energy output (equivalenHo 0.2 pounds per million Btu ofheat input

at the maximum design heat rate) on a 30-day rolling average basis. The River Hill Power proposed S02

emission limit of0.2 pounds per million Btu of heat input on a 30-day rolling average satisfies proposed SUbpart

Da amendments as well as BACT and BAT requirements. Therefore, I recommend that an S02 emission limit

of0.2 pounds per million Btu of heat input on a 3D-day roIling average basisshall be established since ,it

satisfies the technical and economic analysis for BACT as well as BAT.

I also recommend that either the spray dryer absorber or the fla$h dryer absorber shall be installed for postustion S02 control in combination with the CFB boiler limestone injection in order to achieve an overall

rate of 0.2 pounds per million Btu ofheat input based on a 30-day rolling average to satisfy BACT and

requirements. The reason for the installation of either the spray dryer absorber or the flash dryerabsother

is because the company was not able to specify which ofthese two dry flue gas desulfurization systems would

be installed since the manufacturer ofthe boiler determines which control device is used andthe boiler·

manufacturer would not be determined until the project is sent out for bid. ill ,addition,the outlet ofeither the

spray dryer absorber or the flash dryer absorber shall be equipped with instrumentation in monitor and'

record the outlet temperature ofthe flue gas entering the fabric collector: The outlet temper onitoring and

recording will provide verification that the temperature ofthe flue gas entering the downstream fabric collector "

is not exceeding the maximum temperature to destroy the fabric filters. The maximum temperature will be

submitted to the Department once the manufacturer ofthe fabric collector has 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 of a pulverized coal-fired (pC-fired) boiler

and a steam turbine, which will drive a 135 MVA class nameplate electric generator to

produce a nominal 116-gross MW of electricpower (11 ~MW ofthe power produced will be

used on average by RMP for plant auxiliary power). The legal description ofthe site location

is the Northwest Y4 of Section 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 12 burners with

opposed firing. The maximum nominal heat input rate to the boiler will be 1,304

MMBtu/hr, which will be used to produce up to approximately 900,000 pounds ofsteam

per hour. 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 boiler will combust coal 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 of Hardin. Using the heat content of 8,700 Btu per pound

(Ib) of Absaloka Mine coal, as provided by Westmoreland 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 of nitrogen 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: 05116/05
b. Eliminate Technically Infeasible Options

All of the above technologies are technically feasib~e for a PC-fired Boiler.

c. Ranking ofControl Technologies 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 of Most 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 (if at all) based on those methods because of

the current proposed use of low 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 of lime makes wet limestone scrubbing themore economically reasonable option

ofthe two. 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 of potential 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 a wet FGD system

is approximately 40% higher than for a dry system. Potentia! collat.eral environmental

impacts can be categorized in the areas of water consumptiori: w~~e water handling, solid

waste handling, and toxic emissions. . . .

3185-02 15 Final: 05116/05
Although 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 of what 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 of lower sulfur fuels or the price of those 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 of Absaloka Coal). There.

is no justification, 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 of condensable particulate matter and

acid gases, neither of which would be controlled with the proposed particulate control

(baghouse). Creation of hazardous air pollutants is of great concern to the community

of Hardin 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 to justify designating that a wet FGD (with or without

WESP, as further described in the PM10 and H2S04 sections) system constitutes

BACT. Therefore, a dry FGD system (in this case, an SDA) constitutes BACT.

The Department investigated the sulfur percentage of the Absaloka Mine coal ("'"

0.61%) in comparison with the sulfur percentage ofthe coal for other recently

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 of time

(information from EPA's Acid Rain database). Control ofS02 becomes 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 of atomizer 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 of the Nebraska Air Quality Regulations, the public has been notified by

prominent advertisement of this proposed modification of an air contaminant source and the thirty (30)

day period allowed for comments has elapsed. This Construction Permit approves the proposed

construction of a 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 of Nebraska City.

Compliance with this permit shall not be a defense to any enforcement action for violation of an

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 of this permit does not relieve the owner/operator of the source from the responsibility

to comply with all applicable portions of the 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 of such failure or incorrect submittal,

promptly submit such supplementary facts or corrected information. If the source wishes to

OPPD Nebraska City Station-S8343cOI.doc

PSD Construction Permit-Page I
engineering 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 of Emission 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 & H6S04 BACT Selection

Because the Wet FOD and Dry FOD can produce an equivalent level of S02 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 of H2S04

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~

H2S04 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 H2S04 emission limitations proposed as BACT under

typical operating ranges for the Unit 2 Boiler.

For short-term periods of spray dryer absorber (SDA) maintenance, higher S02 emissions limits are

needed to allow for changeout of the SDA atomizer every 3-4 months. The atomizer changeout can be

done in a matter of hours, and in normal cirCl,lmstances, is not expected to affect the ability of the 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 of these

will normally be out of service during atomizer changeout, which is expected to take 4 hours or less. The

in-service SDA module will be designed to remove 60% of all 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 of 0.48 Ib/MMBtu (60% control from

1.21b/MMBtu), and 0.1631b/MMBtu, respectively.

1.15 BACT Selection Review For S06 & H6S04

Information concerning recently proposed or permitted coal-fired power projects was obtained from

EPA's Clean Air Technology Center (CATC) website, where a list of nationwide coal-fired power

projects has been compiled and is available for downloading at

OPPD Nebraska City Unit 2-58343tDl.doc

Fact Sheet-Page 10
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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://cfpub l.epa.gov/rblc/index.cfm?action=PermitDetail.PollutantInfo&Facility_ID=266... 3/31/2010
DEPARTMENT OF ENVIRONMENTAL QUALITY

DIVISION OF AIR QUALITY

Permit Application 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:

Black Hills 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 of Gillette in Campbell County, Wyoming. The proposed facility consists of one 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 at the 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 result in .1)0 air emissions. New

coal storage silos will be controlled with bin vent filters connected to the lh1it 3 Boiler baghouse. 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 point associated

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 - PMIPMIO

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:,~~~!~ ..'cost effectiveness 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

a method to evaluate incremental cost effectiveness between dominant options known as the lea!)t cost

envelope. For this method, a plot of annual 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 of the 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 PMIPMIO

Least Cost Envelope

4.0 -------.-------

.....

rn

o

<...>

"C 3.0 +-------------------------:::::;:::..-~7aB_e..;;;f___{ Q,)

N

iO

.....

o

t2.0 +-----r----.,..-----r----:....,..----r-----r----.,..-----------{

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.
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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

..-.----.--.---~-'--P21Md~lQn--Deseri-pt-;;on-'-DRY-FGD-'-----"'-"----'------.- ..-.-----.--.------.--.-.-.---..----------.------------ ---..... ----- ..----....- ...-.--------....--..---.------.----

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://cfpub l.epa.gov/rblclindex.cfm?action=PermitDetai1.Pollutantlnfo&Facility_ID=266... 3/31/2010
~f\S~~~"

w~",.~o-etd. D"f') /o:Xv!a\ f ~\T JdcDW'\\oa.A.<;J p.evm\\<;. JFS.J../

J DC\!-t..-\<;; I \DY\~~){' cJIp-<cV ",\-\;d.DCS./ rfI'IOO~pd.pJ+

Prevention of Significant Air Quality Deterioration Review

Of the Longleaf Energy Associates, LLC

Longleaf Energy Station

To be located in Early County, Georgia

PRELIMINARY DETERMINATION

SIP Permit Application No. 15846

July 2006

Department of Natural 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 Branch
PSD Preliminary Determination Page 62 of 205

Sulfuric acid mist emissions are better controlled by a dry scmbber system as

compared to a wet 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 of Estimated Water Consumption of Scrubbers for I,200 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 FACILITY OR ACTIVITY:

Cargill, Inc. (Cargill) operates a com wet milling facility in Washington County near Blair, 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 to the com wet milling facility, the Cargill Blair

Complex also includes the following facilities:

• PGLA-I, which is a Cargill joint venture

• NatureWorks, which was originally a Cargill joint venture (Cargill Dow, LLC) but is

now wholly owned by Cargill

• Cargill Polyols, which was originally a Cargill joint venture (M & C Sweeteners) but

is now wholly owned by Cargill

• Degussa, which was originally a Cargill joint venture (Midwest Lysine) but is now

"wholly owned by Degussa

• Purac

Cargill is proposing to construct an expansion to their existing 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

revision on June 16,2006. The proposed project will increase the com processing rate for the facility

from 200,000 bushels of com per day to 340,000 bushels per day to allow an increase in ethanol

production from the current 100 million gallons per year to 240 million gallons per year. The project will

also include the addition ofa solid fuel-fired steam generating boiler for 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 most cases, are replicates ofexisting emission points

sized to process the increased corn throughput of 140,000 bushels per day. The project will also include a

permitted increase to the existing com truck unloading bay and several new emission units/points for the

conveying and storageofgluten and germ. In addition, capacity for the existing com unloading

conveyors (EP 1) will be increased, tanks in the existing millhouse (EP 7) will be modified slightly, air

flow in the existing fiber flash dryer (EP 12) will be modified to a semi-closed loop recirculating system,

and the air flow for the fabric filter for the existing fiber bin filter rece,iver (EP 59) will be 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 of new types of processes or products.

The addition of a solid fuel-fired steam generating boiler will consist ofa circulating fluidized bed (CFB)

boiler capable ofcombusting a variety offuels. Coal from the Powder River Basin (subbituminous) will

be the primary fuel for the CFB boiler.

The existing natural gas-fired boilers 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 CONTAMINANT EMISSIONS ANTICIPATED:

Cargill, Inc.-S7902fll.doc

Fact Sheet-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 percent control provided bY;~~ ,".. '., .. . '," .. . 'J1JInit for the CFB boiler was proposed in the draft

p '.received during the public notice period, 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 SCR process involves the injection ofa nitrogenbas¢d.t¢dmn,l1,gf,igent, such as ammonia, to reduce the NO. in the flue gas to N2and H20. The reagent is

.~.

'*;.

pel'

unstated reasons,.As;ii::t~'i:lit;

FGDsystem.

The permit application for the<La~ar Utilities Board facility did not propose the use of a dry FGD system

in conjunction with limestone injection. During the permit review process the EPA commented on the

potential for a polishing scrubber (dry FGD) and information was supplied by the permittee to address the

site-specific application ofsuch.·The final permit indicated that a polishing scrubber was cost prohibitive

~~~~~...~~..~......and.had.additionaLde.trimentaLenyjronmeolaL~Q.QQ..l<J1l~Jmc!:las additj.QJill.l \Vl!!~LfonsulUption and waste .. .. . . ,. ,~._.. ;,~gill) _._.. _._~~.~

Cargill, Inc,-57902f11 ,doc

Fact Sheet-Page 12
FACT SHEET

Archer Daniels Midland Company

3000 East 8th Street

Columbus, Nebraska 68601-9073

August 4, 2006

DESCRIPTION OF THE FACILITY OR ACTIVITY:

Archer Daniels Midland Company (ADM) owns and operates a wet com milling and ethanol production

plant located at 3000 East 8th Street in Columbus, Nebraska. This plant, owned by Minnesota Com

Processors, LLC until 2002, was constructed in 1991. The plant operates under primary Standard

Industrial Classification (SIC) Code 2046 (Wet Com milling) and secondary SIC 2869 (Industrial

Organic Chemicals).

The facility consists ofthe following major production steps/areas:

• grain receiving, storing, and wet com milling;

• germ, gluten, starch separation;

• germ, gluten, and starch drying;

• fermentation and distillation;

• ethanol and denaturant storage and loadout;

• sweeteners production;

• steam generation;

• emergency power generation.

This permit is intended to address several outstanding regulatory requirements, as well as to permit

expansion ofthe existing ethanol plant. First, this permit addresses requirements contained in a Consent

Decree negotiated under UnitedStates v. ADM (C.D. IL, NO. 03-CV-2066), which was filed with the

U.S. District Court - Central District ofIllinois 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

of ethanol per year to 120 million gallons of ethanol per year. Finally, this permit addresses the

requirements and associated injunctive reliefrelated to compliance with Title 129, Chapter 27, Section

002 (Best Available Control Technology requirements for sources of hazardous air pollutants) ofthe

Nebraska Administrative Code.

The major regulatory actions required by the Consent Decree which are addressed in this permit include:

• submittal of a PSD permit application to identify and correct any non-compliance with the

National Ambient Air Quality Standards (NAAQS);

• 95%VOC control (or control to 20 ppmvd) on the Germ Dryers, the Millhouse Vent, the

Distillation Scrubber Vent, the Fermentation Vent, and the Stillage MR Vents;

• identification and inclusion/revision ofCO and VOC emission limits for existing sources; and

., modification and optimization of existing control devices and emission units to reduce emissions.

Concerning the plant expansion, this permit authorizes the construction and modification ofthe following

emission units:

Archer Daniels Midland Company-39285F06.DOC

Fact Sheet·Page I
90% \\lith no increase in NO._or COemissions. 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, use of a wet scrubber wiH also result reduction in HAP emissions of 1.7 tons per year.

Since the wet scrubber has been determined to be BACT for VOC, ADM concludes that BACT for HAP emissions

should be compliance with the VOC BACT limit of 1.5 Iblhr.

Table 1-9. Economic, Energy and Environmelltallmpacts of

Applying Wet Scrubbing and Thermal Oxidation to tbe Columbus FBGD

BaselineVOC Emissions (tnv)

Reduction efticiencv

VOC Emis.sions Reduction (tov)

Annuafjz~d Cost ($10")

Cost Eff'e-ctiveness ($Iton)

Environmental Impacts

Energy Impacts

Thermal Q~dati()n -,

32.9

95%

31.2

$2.12

Increased NO. Emissions of 9.1

tpy

Reduced HAP Emissions of 3.1

tPY

Net Reduction in CO Emissions

of 10.8 tov

1,880 MWH/yr of electricity

consumed

365 -" lamra I l!as

consumed

32.9

80%

26.3

$0.14

Reduced S02 emissions of 18

tpy.

Redl,lced HAP emissions of 1.7

-tPy

No impact on NO. or CO

emissions

308 MWH/yr ofelectricity

consumed

No natural gas

Secondary sources or organic HAP emissions from germ processing are the Germ Cooling baghouses (SV-9 and

SV-12). ADM has conservatively estimated that HAP emissions from these sources are at most 1.2 Ib/hr in a flow

stream of 108,000 scfm. These emissions represent organic HAP that may remain in the product after drying and

then be stripped from the germ by the air used to convey and cool the germ. Because the HAP concentration in this

stream is much more dilute than the concentration in the dryer exhaust, the cost of control will be much higher than

the cost ofcontrol for the germ dryers. ADM estimates that the HAP control cost-effectiveness ofthermal oxidation

for this combined stream exceeds $750,000 per ton. The added HAP reductions that would be provided by this

technology cannot be justified 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 plant result from incomplete combustion ofthe natural gas in the

dryer's burner. To identifY the types ofCO controls used in similar dryers, the RBLC database was searched for

germ dryer BACT determinations, from 1994 to present. This review was used to identifY the control technologies

that in the past have been used in the industry, as well as the accompanying control efficiencies and BACT emission

limits ofeach controls listed. The resultS ofthis search as it relates to CO emissions are summarized in Table 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

a CO emissions factor of 84 IbIMMSCF(AP-42, Table 1.4-1, 7/98 edition), a thermal oxidizer is projected to

produce about 2.8lb/hr ofCO emissions from the gas combusted in the oxidizer burner. The current baseline CO

emissions limit for this dryer is 5.9 Iblhr and the increase in capacity is projected to result in a CO emissions limit of

Archer Daniels Midland Company-39285F06,DOC

Fact Sheet-Appendix B-Page 14
Table 1-4. Economic, Energy, and Environmental Impacts of SNCR 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 of NH3 Slip: 43 22 II

TonsJler Year of Increased Particulate: __ 168 42 21 .- -

Annual Emissions Reduction (NO,-NH3-PMIO): 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 of SNCR

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 of control. The

assumed molar ratios for the three levels of control 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 of SNCR

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 8
from the reaction ofslip ammonia with S03 to form ammonium salts. The increased presence of the ammonium

salts is the cause ofthe increase in stack opacity. In an effort to quantify the overall impact of NOx emission

reductions with increase in ammonia slip and fine particulates, the change in total annual emissions of these three

pollutants (NO" NH3, PMIO) is calculated by subtracting the estimated emissions of ammonia and ammonium

sulfate (fine particulate matter) from the decrease in NOx emissions. This calculation shows that the overall

emissions impact of reducing NO, emissions from 0.07Ib/MMBtu to 0.05 Ib/MMBtu is negative. In other words,

the decrease in tons of NO, emissions is more than offset by an increase in the tons of NH3and 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 of calcium 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 of more frequent replacement of plugged 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 of 0.07 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 of S02 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 H2S04. Emissions of F result

from the volatilization of fluorides contained in solid fuels and limestone. During combustion, the majority of the

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 of FGD 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 of Electricity: 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 a particulate matter emission limit of 0.0 15, the costs of a 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 of a conventional ESP was developed

based on an inlet particulate matter loading of 0.03 Ib/MMBtu.

To assess the economic costs ofa SDFGD system, the U.S. EPA CUECost model was used. The economics of the

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 of the base cost of the 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 is judged 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 of the 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 of the 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 18
To account for 90.0 percent reduction of S02 in the CFB boiler using 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 of limestone 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 of these 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 of wet FGD and wet ESP might be a slight decrease in emissions ofF and H2S04

over the other S02 control options, However, quantification of this benefit is not feasible considering the low

expected emissions of these pollutants under any ofthe S02 scenarios evaluated.

1.2.8 Proposed BACT Limit for S02, H2S04, and F Emissions

Based on the above analysis, ADM proposes LI at 90 percent overall S02, H2S04, and F emission control as BACT.

The BACT selection rationale follows:

LI plus Wet FGD is rejected as BACT because of the:

• High incremental cost effectiveness of approximately $28,000 per ton over LI+SDFGD, of approximately

$15,000 per ton over LI+DIFGD, and of approximately $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 of the:

•

• 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, HzS04, 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;

per boiler - compliance determined using USEPA reference

Method 8; and

per boiler.,- compliance determined using USEPA reference

Method 13,

The emission rate for HzS04 and F are difficult to determine because the available information on HzS04 and F

removals for different types of SOz 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 HzS04 and F,

ADM proposes limestone injection with baghouse control as BACT for HzS04 emissions. A review of Table 1-8,

which presents the results of the RBLC review and review of other permits, shows that HzS04 permit limits range

from 0,0 I0 Ib/MMBtu to 0.015 Ib/MMBtu. ADM proposes a per boiler BACT limitation of 7.5 pounds per hour,

This limit is equal to a HzS04 emission rate of 0.010 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 of other permits, shows that F permit limits range from 0.0004

Ib/MMBtu to 0.0053 IbIMMBtu. ADM proposes a per boiler BACT limitation of 0.9 pounds per hour. This limit is

equal to a F emission rate of 0.0012 Ib/MMBtu. This limit is consistent with a recent BACT emissions limit found

in Table 1-8.

Table 1-8.

Summary of Emission 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 OF FACILITY:

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 of GiBette,

Campbell County, WY .

Coal Fired Electric Power Generating Station

REVIEWED BY: Stewart Griner-Air Quality Engineer -~-~~~--~-~~~---~~-~~~~~~~~----~-~-------~------~~------------~--~ce:1c7'i:AEteFso~ Kit~HaJit~!-ER-g:HroorDon Watzel- Air Quality Specialist

PURPOSE OF APPLICATION:

Basin Electric submitted an application to construct a coal fired electric-power generating station adjacent

to the Dry Fork Mine on Highway 59, approximately 7 miles north nOltheast of Gillette, Campbell

County, Wyoming. A map ofthe 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

(net) with associated material handling and auxiliary equipment. The maximum design heat input for the

PC boiler is 3,80 I MMBtu/hr. The design values used for coal fi'om Dry Fork Mine include a heat value

of 8,045 Btu/lb (7,800 Btu/lb minimum to 8,300 Btu/lb maximum) and a sulfur content of 0.33% (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 equipment will inciudean 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:
'.,

Basin Electric, Dry Fork Station

PennitApplication Analysis, AP-3546

Page 6

,rating

that 0.056 Ib/MMBtu is the lowest feasible 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 of cost effectiveness for the design target emission levels in the previous table was performed

_~.. ....,_.. _.._ .~~ .. ~.aJ1!Lth~Lr~~l,lltL!!reshoV(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 . " . ',' ,'. r the 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 on the 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 catalyst vendors

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) sl ip values that

cause problems elsewhere in the plant. Excess NH3slip 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 of the 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 of S02 to SO) and react with water in the flue gas to form sulfuric acid mist. The

·additional S03 may also increase gelieration of ammonium sulfate and ammonium bisulfate with the

associated problems described above. . . .

3. Emission levels will increase somewhat during catalyst change outs. Catalysts are typically ~hanged

by moving the second layer of catalyst (second to come in contact with the flue gas) into the first

laye~ position and putting fi'eshcatalyst in the second layer position. This is done one section at a

time while the plant is on line and ~esults in somewhat higher emissions during the change out.

jJ;reed to an annual average emission limit of 0.05

...... 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 of emission 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 Desu Ifurization (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

that only calcium sulfate is p '.' 'Wr;':":," ":"~ciencybut uses more

water than dry FGD and has ~", . ".~Jt;: . "kS';mff.j!itier emissions 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 Cost Effectiveness for 802

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 cost effectiveness between dominant options known as the least cost

envelope. For this method, a plot of annual 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

~o·

15 0 +------~----=-..::::..-----------------------<1

:J ase 1 j

.... 14.0 +---'----..;;..;..--:.----------,--------------11

1 13.0 -1------------------'--------------'

12400 12500 12600 12700 12800

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 cost divided by the incremental emissions

reduction. . j '."" .

Incremental

Cost Effectiveness

s for S02

Options Compared

five

(;)n :r usage, visible moisture plume,

hi T. .. Yfor acid gases, and possibly higher mercury emissions).

Th~;itW:l~~$if~' is considered reasonable for SDA with a design target

emission level of 0.073 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. FUliher diSCUSSions with BaSin Electnc IOcltcated that

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

I) Basin Electric stpted that the lowest emission guarantee available for SDA is 94% removal with a

floor of 0.08 IblMMBtu (regardless of S02 loading). With an S02 loading of 1.33 Ib/MMBtu,94%

removal results in an emission level of 0.08 Ib/MMBtu. Basin stated that vendors will guarantee 94%

removal with S02 loadings above 1.33 IblMMBtu but will not guarantee less than 0.08 Ib/MMBtu

(~quivalcnt to an S02 concentration of approximately 40 PPITIv @ 3% 02) with lower S02 loadings.

Basin Electric originally established a performance target (Le. design target) of 0.073 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 of 0.08 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 a dry 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....~missionlimit of 0.08

lb/MM Btu with a 30 day rolling average limit of 304.1 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-~:26 790

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i Facility Information IRACT/BACT/LAER Clearinghouse IClean Air Technology Cente... Page 1 of2

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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 KEY FAUVER

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
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pollutant.

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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 IMillper";<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

Pennit Final:

AFS #013-0038

An air quality permit, with conditions, is hereby granted to Southern Montana Electric Generation and

Transmission Cooperative - Highwood Generating Station (SME-HGS), pursuant to Sections 75-2-204

and 211 ofthe Montana Code Annotated (MCA), as amended, and Administrative Rules ofMontana

(ARM) 17.8.740, et seq., 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 bed boiler (CFB Boiler). Auxiliary power to operate the facility is

estimated to be approximately 20 MW resulting in an approximate net power production·

capacity of250 MW. Emissions from the CFB-Boiler are controlled by 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 approximately 720 acres of property 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. Current Permit Action

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 behalf of SME-HGS, verbally notified the Department of additional

emitting units that were not previously analyzed and permitted under the preliminary

determination and were deemed necessary for the construction and operation ofthe CFB

Boiler. Specifically, SME-HGS detennined that during the CFB Boiler construction phase

and periodically thereafter, as necessary, SME-HGS would need to operate portable/

temporary propane-fired heaters for the purpose of curing the CFB Boiler refractory 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: 05/11/07
atmosphere. Another negative environmental impact associated with a wet

FGD system is related to water usage. 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 or limestone 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 of concern.

Even though wet FGD systems use more water and generate a wastewater

sludge, wet FGD systems cannot be eliminated from further investigation

under the BACT analysis and are therefore evaluated further for economic and

energy impacts. The dual-alkali wet scrubber will be eliminated from further

investigation due to the material handling and disposal issues (e.g., leachate

polluting the ground water causing 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 compared in the SME-HGS application using

estimated annualized capital, operating, and maintenance costs. Cost estimates

were provided from commercial suppliers ofthis type of equipment. Where

appropriate, constant operation and maintenanQ~g"1QIs-w.erejdentified~d~~~~" """~~~""~~~"~"""~"­

""~"~""~~~"""~" "~""""""""~"""""-apptietrc::l)nsistent1ytO~coritrol optionS:

iii. Energy Impacts

.Both wet and dry FGD systems require electricity to operate. The wet FGD

system uses electricitJ primarily for the ill fan, re-circulation pumps, reagent

handling, and for wet waste dewatering. The dry FGD uses electricity

primarily for the ID fan, limellimestone handling equipment and FFB lJlowers.

Wet FGD system power consumption is approximately 40% greater than that

ofthe dry FGD system. With a HAR system, there is no recirculation pump,

wet waste dewatering and reduced power consumption for the reagent

(lime/limestone) handling system. None ofthe control options are eliminated

based on energy impacts.

3423-00 23 DD: 05/1 1/07
E. SOz BACT Detennination

SME-HGS proposed the use of CFB Boiler technology with limestone injection,

low sulfur coal, and HAR to maintain compliance with a proposed SOz BACT

emission limit of 0.038 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 power plants 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

of all 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 of pennit issuance, compliance with the applicable SOz BACT emission

limit had not been demonstrated at the AES facility or the 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 of 0.038 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 of ash from the

combustion of fuel, 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 of a 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

PMIO (filterable and condensable) BACT Analysis and Detennination).

A. Identification of Available 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: 05/30107
C. Ranking ofAvailable and Technically Feasible NOxControl Options by Efficiency

Various information sources evaluated by the Department through the NOxBACT

analysis process assigned varying NOxcontrol efficiencies for each ofthe identified

available NOxcontrol technologies/strategies. The following analysis uses the

average of expected control efficiencies reported for each strategy:

NOxControl Option NOxEmission Rate Estimated NOx

(lb/MMBtu) Control Efficiency

CFB Boiler with SCR 0.014 90.00%

CFB Boiler with SNCR 0.07 50.00%

CFB Boiler without 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 environmental impacts from both SCR and SNCR result from the

handling ofthe anhydrous ammonia. Spent catalyst from an SCR will have to

be properly disposed of as a possible 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 NOx control options cannot be eliminated based on

these concerns.

ji. Energy Impacts

SCR would cause significant backpressure in the CFB Boiler leading to lost

boiler efficiency and, thus, a loss of power production. Along with the power

loss, SME-HGS would be subject to the additional cost ofreheating the

exhaust gas, which would be expensive at the current price of natural gas. The

energy impacts from an SNCR are. minimal and an SNCR does not cause a loss

of power output from the facility. Even though there are energy impact

concerns with SCR, the control options cannot be eliminated based on these

concerns. The impacts of additional cost due to reheating the exhaust gas are

included in the annual cost of operating an SCR unit, 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. Cost estimates for SCR and SNCR

were derived from Chapter 4 in the OAQPS COST Control Manual (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:{~ Ad~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 a proposed 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 Department determined that the proposed NOx emission

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 cost per ton 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 of SCR and leads to a substantial increase in

emissions from the reheat process summarized. Finally, the Department is unaware

of any CFB Boiler permitted or in operation in the United States, which has an SCR

unit installed for NOxemission control.

The BACT determined NOxemission limit is equal to the lowest NOxBACT

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 Boiler operating 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/or high cost to

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 Proper Design and Combustion (no add-on control); and

ii. CFB Boilers with Catalytic or Thermal Oxidizers.

3423-00 33 DD: 05/11107
~~CI) Ptv~ t?: ®

\f'J 'NoN •.e{'<A ''3°''1y~, ChBIq" y I ~-f/ e,V\<JS-IRUVjeY\Wt i(?,a.s\<; ,pd-f'-

III. Conditional Permit to Construct

A. General Infonnation

Pennit number:

AFSnumber:

SIC Code and SIC Description:

Site Location

Bonanza Power Plant

12500 East 25500 South

Vernal, Utah 84078

PSD-OU-0002-04.00

049-047-00001

4911 - Electric services

Corporate Office Location

Deseret Power Electric Cooperative

10714 South Jordan Gateway

South Jordan, Utah 84095

The equipment listed in this pennit shall be constructed by Deseret Power at the

following location:

Bonanza Power Plant

Latitude 400 OS' 11" N, Longitude 1090 16' 48" W

~5 miles southeast ofVernal, Utah '

B. Process Description: The Waste Coal Fired Unit (WCFU) will consist of a circulating ~c.~~.~~ -~~~~ 0 _c_~ c--fluiClizeaoeo1CFBro6i1erana assoCiatea~eqtiTpmenl at tlieeXIsfingBonanzapowerpraiif. 0 ··_~~c~~.~~~~._~~~~

The WCFU will have a nominal capacity of up to 119 megawatts gross electrical'output.

The CFB boiler will supply superheated steam to the extracting/condensing turbine, to

drive an electrical generator and supply cycle and plant auxiliary stc::am through

uncontrolled extraction from the turbine.

The CFB boiler will be fired on western bituminous coal from the Deserado mine.

Deseret Power ha.s designed the project to be fired on waste coal alone, but has also

requested operational flexibility in the permit to Use a blend ofwaste coal and run-ofmine coal at any time, as needed, at up to a 50150 ratio by weight (equivalent to coal with

heat content of approximately 6,500 Btu/lb). Run-of-mine coal is raw coal from the mine

that has not been washed in the coal washing plant at the mine. During emergencies that

would prevent the waste coal from being delivered and placed into the WCFU, Deseret

Power has requested pennit flexibility to use either run-of-mine coal or washed coal from

the Deserado mine.

The waste coal is pr.oduced as an unavoidable byproduct ofthe coal washing process at

the Deserado mine. The waste coal has a nominal heating value range of approximately

3,000 to 5,400 Btu/lb, with an average heating value of approximately 4,000 Btu/lb. The

waste coal will b~ delivered via an existing electric train line from the Deserado mine,

approximately 35 miles east ofthe Bonanza power plant. The run-of-mine coal has a

heating value ranging from 8,500 to 10,000 Btu/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 S02 emission rates, and maximum

annual S02 emissions, associated with wet and dry FGD systems based on the design sulfur coal.

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 S02 control

system. A detailed summary of the cost estimates used in this BACT determination is attached.

A CFB boiler with limestone injection is an inherently low S02 emitting technology, and

can be designed to remove approximately 85% of the potential S02 with limestone injection.

The incremental cost of $10,540 per ton of removed S02 to install a wet scrubber rather than a

dry scrubber is too high to justify the expenditure. Based on "average" coal for the proposed

WCFU, the incremental cost is $28,054 per ton of additional removed S02 to go from dry

scrubber to wet scrubber, also too expensive to justify.

Comparison of Wet FGD to Dry FGD for WCFU,

Downstream of Limestone Injection Controls:

Costs and Emission Rates

Parameter Wet FGD with Limestone Dry FGD with Limestone

fuiecti6ri~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 of Wet FGD

In addition to the adverse economic impacts of a 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 of going 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 of more 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, if capital, 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 of reduction 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 of 0.088 IbIMMBtu on a 30-day rolling average. Deseret Power searched the

RACT/BACT/LAER Clearinghouse (RBLC) database and found the following determinations:

51
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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

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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://cfpub l.epa.gov/rblc/index.cfm?action=PennitDetai1.PollutantInfo&Facility_ID=267... 3/31/2010
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pollutant.

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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

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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 19000 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 NOx 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 NOx 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 of 400 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 per year cost per 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 of 25 ppm is consistent within current

acceptable BACT ranges for combined cycle gas turbines. The MPCA concurs that 25 ppm

is at the 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 of approximately 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

a 400 ton per year cap to limit operation in the less than base load operating ranges. The

table above sununarizes the cost analysis when a 400 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 of a

oxidizing catalyst isl$2,42~ XCEL argues that this value is much higher than any proposed

cost per 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 of CO.

In addition to the cost analysis, XCEL also argues that installation of a CO catalyst may have

negative environmental impacts. The use of an oxidation catalyst may result in higher PM10 emissions from the further oxidation of S02 to S03 and the potential reaction with

ammonia in the SCR unit to create ammonia salts that may react with moisture to form

H2S04 .

The MPCA agrees that PM-10 emissions may increase with the installation of an 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 of S02 in the exhaust stream. Therefore, the potential minimal

increase of PM-l 0 emissions is not, by itself, adequate justification for the omission of an

oxidation catalyst which would reduce significant quantities ofCO, VOC and HAP

emISSIOns.

XCEL's economic analysis shows that the annualized cost per ton for the installation of an

oxidizing catalyst is $2,425. This value is below the cost figures of other recently pemlitted

sources in this state and other Region 5 states that have successfully argued out of installing

a CO catalyst by estimating costs in excess of $3000 per ton. However, the issue of cost is

over shadowed by the fact that there exist a significant number of combined cycle units that

,---,-~-~,,~.. -"~"~"~"are operating lii~a cost effecWve mafifiefWifn oxtclatton 1:am1ystS'tITstrrllt;d~~:Alnrlm'O'st~~'-'---"~'~"-""-"""~"'~-~~"

identical unit also within the Minneapolis/St. Paul metropolitan area is just 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 of turbine contact people at all Region 5 states and

various EPA Regional offices appears to confirm the point that 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 of general

trends in permitting gas turbines, CO catalysts do not appear to be generally required as

BACT unless there are underlying nonattaimnent issue involved.

8
Pennit Nwnber: 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 of NOx removed,

compared to the 1999 determination of $11,185 per ton of NOx 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 of carbon monoxide, which can be expected to require

extra CO reductions as part of an air quality maintenance plan.

The TNRCC list of turbine projects cites two simple cycle cases requiring CO catalyst. One

project has a BACT limit of 5 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 of control 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 of CO (and

VOC) emissions by optimized operation of the 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 of verylow-sulfur fuels.

Particulate and Fine Particulate BACT Status

The 1999 BACT determination for particulate control proposed the use of clean fuels and good

combustion practices. Natural gas and distillate fuel oil are very low-ash fuels, therefore limiting

mineral ash emissions. The updated list of RBLC 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 a higher control

efficiency. Wet sulfur dioxide scrubbing systems are known to achieve removal efficiencies

greater than 90%. MPCA staff asked Fibrominn its reasons for not choosing a wet scrubber.

In its response, Fibrominn argues that sulfuric acid emissions are proportional to sulfur dioxide

emissions, and are usually emitted at a rate 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, if any

control ofsulfuric acid emissions.

Fibrominn's emission comparison (Page 2 of ARI's November 12,2001 submittal) projects that

for a 442 tpy reduction in sulfur dioxide emissions, there could be 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 of emissions 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 Impact Levels in the

ambient air, as defined by the new source review program, 40 CFR 52.21. In light ofthat,

MPCA staff believe 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 absorber being chosen as BACT in all ofthe more recent waste combustor permits

documented in EPA's BACT/LAER Clearinghouse.

NOx BACTAnalysis: 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 of catalyst plugging 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 of boilers 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 staff believe 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 ofthe particulate

control).

A "cold side" catalyst would be located downstream ofthe particulate control equipment.

Locating the control equipment downstream ofthe particulate control mechanism would reduce

the potential for catalyst fouling due to contaminants. Though unproven, there exists the

possibility that the particulate control would reduce contaminants enough that catalyst fouling

would not be a significant problem. As such, Fibrorninn performed the exercise of calculating

the cost per ton SCR would be in this application. That financial analysis is attached. The costs

were calculated to be between $6,513 and $9,016 per ton of pollutant removed if propane were

used to reheat the exhaust stream to combustion temperatures. Fibrominn estimates that, at the

moment, it may be less expensive to reheat the exhaust stream with natural gas. Using today's

price for natural gas, Fibrominn's calculations for cost per ton of control would beI6;091io)"

~:$g,432.i.!'

In addition, the incremental cost effectiveness when compared to SNCR, the control technology

representing the next most stringent emission limitation, is prohibitive. The incremental cost

effectiveness for comparison of 65% control by SCR to 50% control by SNCR is~35,738per'

ton, and for comparison of90% control by SCR to 50% control by SNCR is $13,415 per tOll;

Much of the cost stems from the fuel needed to reheat the exhaust stream to within temperatures

suitable for catalyst operation. Fibrominn estimates that a burner as large as 65 mmBtu per hour

would be needed. The MPCA believes that this is too high a fuel cost (about 8% of total fuel

input to the boiler), and that such a use of a 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 permitted wood fired boilers in the BACT/LAER Clearinghouse, 7 of 16 are

controlled by SNCR.The others are uncontrolled, or are controlled by good combustion

practices. Emission limits range from 0.15 Ib/mmBtu to 0.54Ib/mmBtu. Limits of 0.15 .

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 that has been demonstrated and is

technologically feasible, SNCR" asBACT, and proposed an emission limit of 0.16 Ib/mmBtu on

a 30 day average. The averaging time was chosen to be consistent with the applicable NSPS.

With the baseline emissions of 0.32 that Fibrominn expects to see, 50% control results in

emissions ofO.16Ib/mmBtu. MPCAstaff believe that the emission limits that are proposed are

consistent with BACT.

Carbon Monoxide BACTAnalysis: Fibrominn claims that based on operating experience at its

Thetford plant, the CO emissions characteristic ofthis proposed boiler and fuel type are unique,

and that the CO emissions will always be somewhat higher than when other solid fuels are used.

Fibrominn attributes the higher CO emissions to:

• high fuel moisture content with significant variation,

Permit Action Nwnber:

Date: 1/l4/2004
Sulfuric acid mist. The RHF has the potential to emit 1122 tons ofsulfuric acid mist per year

without controls. The applicant has 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. Pilot plant data indicate 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 of S02, 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, and pH (as

a measure of alkalinity) 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 generated by the reaction of nitrogen 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

would poison the catalyst. The applicant also determined SNCR to be infeasible because the

injection of ammonia 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 of these 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 injected back into the combustion zone. In this

application, external FGR would affect the heat distribution in the RHF and lower the 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-NOx burners in this application may be reduced compared to

other applications.

The reducing environment ofthe RHF requires the use oflow-excess air in at least parts ofthe

furnace. It is 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 a power·

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 possible to 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 inherent in the design ofthe RHF process. Although the post-scrubber SCR was

the most effective NOx-reduction technology still being considered, the cost per ton of NOx

controlled «f$ll,OOO/ton}~exceeded the cost guidelines used in Minnesota.

The 10w-NOx burners and staged combustion are both inherent to 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"NOx burners.) The

permit willalso contain a limit of205.8 pound ofNOx per hour.

A NOx CEMS, including a flow meter and an oxygen monitor will be installed to demonstrate

initial and ongoing compliance with the concentration and pound per hour limits. The permit

requires an initial certification ofthe monitoring system and periodic RATAs and CGAs.

Carbon monoxide. The RHF requires a reducing environment to allow the reaction that forms

the iron nuggets. A reducing environment is maintained by limiting the amount of oxygen in the

furnace. This type of environment 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 (or nearly 85,000

tons ofCO per year).

At the pilot plant, an "air injection system" was used to introduce air and mix it into the exhaust

gases. At the temperatures leaving the RHF (greater than 2000°F.), the introduction of oxygen

leads to the rapid conversion ofCO to CO2. The applicant measured the CO emissions after the

air injection system and found them to be about 18 ppm.

The applicant proposes to use a similar air injection 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: 7/9/2007
GP 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

of this document) to provide emission

credits for netting out for PM, PMlO, and

NOx

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 of initial

_....

EU 018 Title I Conditions: CO and Small emergency use-only source

VOC BACT limits

3. Technical Information

• New Source Review Applicability: The construction of the 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,

PM10, NOx, CO, and VOC before netting, and a minor source for S02 due to fuel type

restrictions. The phased shutdown ofthe coal-fired boiler plant allows the Permittee to net

out of PSD 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 subject to 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 subject to BACT for CO and

VOC emissions. The Permittee has submitted information to justify 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 a rather diverse

listing ofrejected and accepted cost per 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 of an oxidation catalyst to meet LAER. However, in attainment areas

justification for use of a catalyst versus GCP is not well documented in the RBLC. In

addition, reports on the atmospheric fate of CO 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 H20. Also, information furnished by

Wisconsin Electric Power Company for their PSD permit for the Port Washington

installation of combined cycle gas turbines indicated that CO lifetime in the exhaust plume

is even shorter because the rate of conversion of CO to CO2 is temperature dependent, and

stack plume temperatures are substantially higher than average global temperature.

According to the August 27, 2004, docwnent titled .

Analysis And Preliminary Determination For The Constmction And Operation Permits

For The Proposed Modification OfThe Operation OfThe Four Combined Cycle

Combustion Turbines With Duct Burners And Heat Recovery Steam Generators (HRSG.s),

Emergency Diesel Engine, Gas Heater AndA Storage Tank For WisconsinDNR permit

#04-RV-175for 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 of CO 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 cost per ton is based on emissions generated when the

gas turbine and duct burners are operating 8760 hours per year, 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 cost per ton rises to i5,()99/ton ofCO,,·./

Therefore, it is apparent that an oxidation catalyst is cost-prohibitive, and most or nearly all

CO is converted to CO2 by 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 catalyst would only reduce CO by about 25 percent, assuming an overall control

efficiency of 70 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 H2S04. Finally, spent catalyst is a waste

that must be 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 later than 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 prior to the start ofCTS, making the associated

emission changes contemporaneous and creditable. Shutdown of boilers 6 and 7 and the heat

input limit for boiler 8 create creditable emissions decreases for all NSR pollutants except

boiler 8 NOx. Creditable increases ofBoiler 8 NOx emissions will occur because 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 of Boilers 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 of the 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 permit requires the Permittee 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 Boiler No.8 and miscellaneous support equipment no later than

12 months after the end of combustion turbine shakedown so that the total PM, PMIO, S02,

and NOx emissions reductions from this project will be greater than 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 to justify 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 a rather diverse

listing ofrejected and accepted cost per 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 of an oxidation catalyst to meet LAER. However, in attainment areas

justification for use of a 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 H20. Also, information furnished by

Wisconsin Electric Power Company for their PSD permit for the Port Washington

installation of combined cycle gas turbines indicated that CO lifetime in the exhaust plume

is even shorter because the rate of conversion ofCO to CO2is temperature dependent, and

stack plume temperatures are substantially higher than average global temperature.

According to the August 27,2004, document titled

Analysis And Preliminary Determination For The Construction And Operation Permits

For The Proposed Modification OfThe Operation OfThe Four Combined Cycle

Combustion Turbines With Duct Burners And Heat Recovery Steam Generators (HRSGs),

Emergency Diesel Engine, Gas Heater AndA Storage Tank For Wisconsin DNR permit

#04-RV-175for the Wisconsin Electric Power Company - Port Washington Generating

Station, 146 South Wisconsin Street, Port Washington, Ozaukee County, Wisconsin

_~"~__e_e_""_eeee_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 percent reduction of 131.4 tpy CO) was determined. This cost per ton is

based on emissions generated when the gas turbines are operating 8760 hours per year,

without startup or shutdoWIl (when the oxidation catalyst does not operate due to low

emission temperatures). Therefore, it is apparent that an oxidation catalyst is costprohibitive, and most or nearly all COe 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 H2S04• Finally, spent catalyst is a waste

that must be disposed.

Technical Support Document, Permit Action Number: 05300015-004

Page 12 of 24

Date: 8/9/2006
The project did require an environmental review due to the increase in timber harvesting. The Permittee, in

consultation with Minnesota Department of Natural 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 project through Air Emission Permit No. 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 period remains

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 of PM2.5 is not required. However, since the project results in a net decrease in PMIO,

it seems likely that there would also be a net decrease in PM2.5, and the project would not be 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)

EVO10/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: 9/18/2008
Pulp and Paper Sources

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, which is not

available at the facility. Also, there has been limited use ofbiofiltration, and thus there is uncertainty in the degree

and consistency ofVOC control.

EUO15 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 not be cost effective; the minimum incremental

control cost to go from the current operation of 83% combined capture/control to 100% control is $ 14,075/ton.

The current operation was determined to be BACT. In addition, a production limit of 750 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 of the 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 of 67 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 analyzed using two VOC emission rates, since the pulp from the pulping

processes have 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/tonX FGR 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 of boilers (i.e.

natural-gas fired). In addition, in cases where SCR was considered, it was considered not 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 of add-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) Longleaf Energy 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