MidAmerican Energy Company

EGU‐ICR Response

Louisa Generating Station

PART I: GENERAL FACILITY INFORMATION

Process InformationNOTE: If any rank of coal or any grade of oil (including petroleum coke [pet

coke]), in any amount, is fired, complete Parts I and II and return to the address

noted earlier. If NO coal or oil is fired, complete only Part I and return to the

address noted earlier.

Blr ID 101

1 Name of legal owner of facility:

2 Name of legal operator of facility, if different from legal owner:

3 Address of legal owner or operator:

4a Plant Name (as reported on U.S. DOE/EIA Form‐860 (2007), “Annual Electric

Generator Report,” schedule 2, line 1, page 37, question 1) OR Plant Name (as

reported on U.S. DOE/EIA Form EIA‐923 (2008), “Power Plant Operations

Report,” schedule 2, page 1, question 1):

4b EIA Plant Code (as reported on U.S. DOE/EIA Form‐860 (2007), schedule 2, line

1, page 37, question 2) OR Plant ID (as reported on U.S. DOE/EIA Form EIA‐923

(2008), schedule 2, page 1, question 2):

5 Complete street address of facility (physical location):

6 Provide mailing address if different:

7 Name and title of contact(s) able to answer technical questions about the

completed survey:

8 Contact(s) telephone number(s):

and e‐mail address(es):

9 Is this facility considered to be owned or operated by a small entity as defined

by the Regulatory Flexibility Act? Yes X No Don’t know

10 Which of the following fossil fuels or other material(s) are fired in any steam

generating unit at this facility? X coal X

oil (including petcoke) X natural gas

other (specify in question 14 below)

11 Which of the following fossil fuels or other material(s) are permitted to be fired

in any steam generating unit at this facility? X coal X

oil (including petcoke) X natural gas

other (specify in question 14 below)

12 If coal or solid fuel, as described below, derived from a fossil source is fired,

indicate which rank of coal or solid fuel was utilized during the previous 12

months prior to the receipt of this ICR:

Fired In Previous

12 Months %

lignite

X 100% subbituminous

bituminousanthracitecoal refuse (including gob, culm, and subbituminous‐derived coal refuse)

synfuel (including, but not limited to, briquettes, pellets, or extrusions which areformed by binding materials, or processes that recycle materials)(please specify the type or form of synfuel used)

petroleum coke

N/AJames D. Wiegand, Manager, EHS

(563) 262‐2872; jdwiegand@midamerican.com

MidAmerican Energy Company; Alliant Energy Corporation ‐ Interstate Power and Light Company; Central Iowa Power

Cooperative; Eldridge Electric and Water Utilities; Geneseo

Municipal Electric Utility; Harlan Municipal Utilities; Tipton

Municipal Utilities; Waverly Light & Power

MidAmerican Energy CompanyPO Box 657Des Moines, IA 50306‐0657

8602 172nd Street

Muscatine, IA 52761

Louisa6664

5/26/2010 ‐ Page 1
MidAmerican Energy Company

EGU‐ICR Response

Louisa Generating Station

13 If oil is fired, indicate which type of oil was utilized during the previous 12

months prior to the receipt of this ICR: Fired In Previous

12 Months %

None distillate

residual or bunker C

other (specify)

14a If “other” was checked in questions 10 or 11 above indicating that any non‐

fossil fuel or other material (including, but not limited to, plastics, treated

wood, rubber belting or gaskets, whole tires, tire‐derived fuel, boiler cleaning

solutions, animal wastes, etc.) is either utilized or permitted to be used, please

indicate below what materials are combusted in the boiler and in what

quantities (specify whether this quantity is on a weight percentage or heat [Btu]

basis). Also indicate (yes/no) whether you are permitted to burn non‐fossil

fuel(s) or other material(s) even if you do not actually burn them.

Other Material

Permitted to

burn

YES/NO

Actually burn

YES/NO Quantity/year

N/A

14b If “other” was checked in questions 10 or 11 above indicating that any non‐

fossil fuel or other material (including, but not limited to, plastics, treated

wood, rubber belting or gaskets, whole tires, tire‐derived fuel, boiler cleaning

solutions, animal wastes, etc.) is either utilized or permitted to be used, were

such material to be classified as “solid waste” under the Resource Conservation

and Recovery Act and, thus, make the utilizing unit subject to CAA section 129,

would you continue to utilize (i.e., use as a fuel) the material?

N/A Yes N/A No

Explain:

15 Identification (or designation) of all coal‐ and oil‐fired steam generating units

(boilers) (as defined by Clean Air Act section 112(a)(8)) located at this facility.

Boiler ID Original design

fuel (i.e. coal

rank or type of

oil)

Design heat input,

(MMBtu)

Present

maximum heat

input, (MMBtu)

MWe Gross

capacity

MWe Net

capacity

Original

design gross

efficiency (%,

HHV)

Present

operating

gross

efficiency (%,

HHV)

Design

steam

pressure

(psig)

Operating

steam pressu

(psig)

101 Subbituminous

Coal/Bituminous

Coal

6971/6701 8624 805 745 85% 85% 2400 2400 

Emission Control Technology

16 For each boiler noted in Part I, question 15, provide the following

information for each current emission control device installed and

operating and/or planned (please designate the order of the emission

controls – 1 for first control following the boiler, 2 for second control

following the boiler, etc.):

Boiler ID Type NOx control SO2 control PM control Other control

101 Pulverized coal;

wall‐fired; dry

bottom

1‐Low Nox burners

w/overfire air (4/29/2005)

2‐Dry scrubber

lime based

(12/11/2007)

3‐Pulse Jet Fabric

filter

(12/11/2007)

N/A

17 For each boiler noted in Part I, question 15, provide the company (prime

vendor) name and company contact information for each HAP‐specific

(e.g., mercury, hydrogen chloride) control technology that you have

either contracted for, are installing, or have installed for the purpose of

participating in a control technology demonstration project (e.g., U.S.

Department of Energy program, consent decree, etc.).

Boiler ID Telephone

101

Address

N/A

Company (vendor) contact information

Company (vendor)

N/A

Name

5/26/2010 ‐ Page 2
MidAmerican Energy Company

EGU‐ICR Response

Louisa Generating Station

18 For the control technologies identified in Part I, question 17, provide the

date of actual start‐up of the demonstration (if the control is currently

operating), the date of expected or projected start‐up, the date the

demonstration was completed, the type of HAP control installed (e.g.,

sorbent and type; pre‐combustion boiler chemical additive; combustion

boiler chemical additive), the desired HAP emission reduction or rate (if

any), and the coal rank(s) upon which the demonstration was conducted.

Please specify the format of the target HAP emission reduction or rate

(e.g., lb/MWh, lb/TBtu, percent reduction, etc.). If the format of the

target end‐point is percent reduction, provide (1) an estimate of what an

equivalent emission rate would be (and specify the format of the

equivalent emission rate), and (2) the basis for calculating the percent

reduction (i.e., where the “inlet” and “outlet” are).

Boiler ID

Demonstration

activity actual

start‐up date

Demonstration activity

projected start‐up date

Demonstration

activity end‐date

or projected end‐

date

Type of control

(e.g., sorbent and

type; chemical

additive)

Desired HAP

emission

reduction (%) or

emission rate

Coal rank(s) in

use

101 N/A

19 For each boiler noted in Part I, question 15, provide the company (prime

vendor) name and company contact information for each HAP (e.g., mercury,

hydrogen chloride) control technology that you have either contracted for, are

installing, or have installed for the purpose of providing a non‐demonstration,

full‐scale operating system.

Boiler ID Telephone

101 865 694‐5247

20 For the control technologies identified in Part I, question 19, provide the

date of actual start‐up (if the control is currently operating), the date of

expected or projected start‐up, the type of HAP control installed (e.g.,

sorbent and type; pre‐combustion boiler chemical additive; combustion

boiler chemical additive), the guaranteed HAP emission reduction or

emission rate, the sorbent feed rate upon which the guarantee is based,

and the coal rank(s) upon which the guarantee is based. Please specify

the format of the guarantee (e.g., lb/MWh, lb/TBtu, percent reduction,

etc.). If the format of the guarantee is percent reduction, provide (1) an

estimate of what an equivalent emission rate would be (and specify the

format of the equivalent emission rate), and (2) the basis for calculating

the percent reduction (i.e., where the “inlet” and “outlet” are).

Boiler ID

Actual start‐up

date

Expected or projected

start‐up date

Type of control

(e.g., sorbent

and type;

chemical

additive)

Guaranteed HAP

emission

reduction (%) or

emission rate

Sorbent or

additive feed

rate on which

guarantee is

based

Coal rank(s)

upon which

guarantee is

based

101 12/11/2007 N/A Lime sorbent

injected in

scrubber

module

CBI CBI CBI

1409 Center Point Blvd

Knoxville, TN 37932‐1962

Company (vendor) contact information

Address

Alstom Mark Fiedler

Company (vendor) Name

5/26/2010 ‐ Page 3
MidAmerican Energy Company

EGU‐ICR Response

Louisa Generating Station

21 For each boiler noted in Part I, question 15, provide the following information:

Boiler ID PM PM10 PM2.5 SO2 HCl and/or HF HCN Metal HAP Hg CO

101 Construction

Permit;

filterable only

0.03 lb/MMBtu,

filterable &

condensible

0.027

lb/MMBtu, 1019

ton/yr; Method

5 with 202,

average of 3 test

runs

Construction Permit;

filterable & condensible

0.027 lb/MMBtu, 258.57

lb/hr, 1019 ton/year,

Method 5 with 202,

average 3 test runs

N/A Construction

permit; 0.40

lb/MMBtu 30‐day

rolling average,

1.2 lbs/mmBtu 3‐

hour average,

3449.6 lbs/hr 30‐

day rolling

average, 15,109

tons/year,

153,600

lbs/calendar day,

6400 lbs/hr not to

exceed five hours

per day

N/A N/A N/A N/A Constructio

Permit; 0.4

lb/MMBtu

calendar da

average, 36

lbs/hr 30‐da

rolling avera

15,864

tons/year

22 For each boiler noted in Part I, question 15, provide the following information:

Boiler ID PM PM10 PM2.5 SO2 HCl and/or HF HCN Metal HAP Hg CO

101 CBI CBI N/A CBI N/A N/A N/A N/A CBI 

23 Was any other guarantee level sought or offered? Yes X No

Please elaborate

Most recent guaranteed emission rate for each pollutant for which there is a permitted emission limit

Permitted emission limit (indicate type of permit and format of emission limit)

5/26/2010 ‐ Page 4
MidAmerican Energy Company

EGU‐ICR Response

Louisa Generating Station

24 For each boiler noted in Part I, question 15, provide the following information:

Boiler ID PM PM10 PM2.5 SO2 HCl and/or HF HCN Metal HAP Hg CO

101 Filterable only

stack test,

filterable &condensiblestack test, stack

test reports,opacitymonitoring,quarterlyopacity reports,broken bagdetection, semi‐

annualmonitoringreport, annualcompliancecertification,annualemissionssummary,records kept forfive years

Stack test, stack test

report, opacitymonitoring, quarterlyopacity reports, brokenbag detection, semi‐annual monitoring report,

annual compliancecertification, annualemissions summary,

records kept for five years,

records kept for five years

N/A CEM's, quarterly

emission reports,

excess emissionreports, semi‐annual monitoring

report, annualcompliancecertification,annual emissionssummary, recordskept for five years

N/A N/A N/A N/A Initial

performancetest data,

CEM's,quarterlyemissionreports, exceemission

reports, semannualmonitoringreport, annucompliancecertification,annualemissionssummary,records kept 

five years

25 For the control technologies identified in Part I, questions 17 and 19,

provide the cost information requested.

Facility Name/Unit No.:

Total Capital

Investment: $

OperatingCosts: $

Louisa Yes Yes /No No Yes /No CBI CBI 2010 Dollars

26 Are any other means of emission control (for any pollutant) employed on any

boiler noted in Part I, question 15 (e.g., low‐ash coal, coal or oil with low trace

constituents, etc.)? Please specify.

PART II: FUEL ANALYSIS AND EMISSION DATA

Fuel AnalysisEach facility should provide the following information for each coal and oil

shipment received during the preceding 12 calendar months.

1a Plant or facility name from Part I, question 4a:

1b Plant or facility code from Part I, question 4b:

2 For each individual coal and oil shipment received during the preceding 12

calendar months, provide the following information, as available (indicate N/A if

not available; use additional pages, as necessary):

State/Country County Coal seam

690,987 101 Wyoming/United States Campbell Wyodak‐Anderson Rail

183,131 101 Wyoming/United States Campbell Wyodak Rail

1,109,847 101 Wyoming/United States Campbell Smith Rail

32,738 101 Wyoming/United States Campbell Wyodak‐Anderson Rail

3 For each individual coal and oil shipment received during the preceding

12 calendar months, provide the following information, as available (dry

basis) (indicate N/A if not available):

Sample ID #

Total amount of

fuel represented

by sample, tons

or gallons Total sulfur, % Ash content, %

Higher heating

value, Btu/lb Mercury, ppm Chlorine, ppm Fluorine, ppm

Nickel,

ppm

Other trac

metal HAP

ppm

Cordero Rojo 690,987 0.45 7.71 12015 0.073 84.81 48.08 4.5 34.44 

Belle Ayr 183,131 0.38 6.43 12128 0.08 <50* 52.82 2.88 31.87 

Caballo 1,109,847 0.48 7.3 12074 0.11 <10* 61 5 22.2 

Black Thunder 32,738 0.41 7.16 12117 0.08 10 50.65 5 23.49 

Caballo (Peabody)Black Thunder (Arch)

Louisa6664

Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a permitted emission limit

Retrofit to existing boiler?

Cordero Rojo (Cloud Peak(formerly Rio Tinto))

Fuel source

Amount

received, dry

basis, short tons

ID # of boiler(s)

firing fuel

Fuel shipment

method

Low‐ash coal for PM control; low‐sulfur coal and low‐sulfur fuel oil for SO2 control.

Installation on new boiler?

Belle Ayr (Alpha)

Notes:For coal sample concentrations that were below the detection thresholds, 1/2 the threshold value was input. The (<) sign indicates

that the average is below the threshold.

5/26/2010 ‐ Page 5
MidAmerican Energy Company

EGU‐ICR Response

Louisa Generating Station

4 Were the data provided in Part II, question 3 above, acquired pursuant to:

permit requirements

X contractual obligations

standard operational procedures

other (please specify )

5 Analyses provided in Part II, question 3 above, supplied by

6 Name and address of laboratory performing analyses:

7 In addition to the analyses required in Part II, question 3 above, for samples for

which analyses of chlorine and/or any of the HAP metals were conducted,

please provide copies of any analyses conducted over the preceding 12 calendar

months for (a) complete proximate and ultimate analyses, (b) additional trace

metals, and (c) the mineralogy of the ash that are readily available for the oil(s)

or coal(s) listed in Part II, question 2 above. The Agency is requesting these data

only as they may already be available; no additional sampling or analyses are

required to provide these data.

None available

Emission Data

8a What emission test report(s), parametric monitoring data, and other data or

monitoring are available for the boilers noted in Part I, question 15, for tests

conducted since January 1, 2005. Please consider reports prepared for all

testing and monitoring programs, for all pollutants, including (but not limited

to) those required under Title V, compliance with State or local requirements,

fulfillment of contractual obligations, U.S. Department of Energy (DOE)

programs, etc. (NOTE: EPA is not requesting copies of the test reports or data at

this time; however we may request actual copies in the future.) Use additional

pages as necessary.

8b Please indicate the date(s) and types (e.g., stack, fuel, parametric, etc.) of the

test(s) and the constituents (including criteria and hazardous air pollutants)

sampled for. Date Type

Blr ID

7/27/2005 Stack 1012/15/2008 Stack 1011/19/2010 Stack 101

8c Do any of these test reports reflect testing at a location before any emission

control devices? Yes X No

If yes, please note which reports and provide a detailed description of the

location of the emissions sampling point(s).

8d Were any of these test reports conducted when use of other material(s) or non‐

fossil fuels were fired in the boiler? Yes X No

If yes, please note which reports and identify the other material(s) or non‐fossil

fuels used.

P.O. Box 3039, Gillette, WY 82717 N/A

N/A

Fuel supplier Other

Name Address Name Address

Cordero Rojo (Cloud Peak) P.O. Box 1449, Gillette, WY 82717 N/A N/A

Belle Ayr (Alpha Natural

Caballo (Peabody Energy) Caller Box 3041, Gillette, WY 82717 N/A

N/A

Black Thunder (Arch Coal)

Particulate Matter (PM & PM10), CO, and VOC compliance stack test; lead stack

test

Constituents

Carbon Monoxide

PM, PM10 and VOC

Lead

Standard Lab's Black Thunder Lab P.O. Box 406, Wright, WY 82732

Black Thunder (Arch Coal) P.O. Box 406, Wright, WY 82732 N/A

P.O. Box 1449, Gillette, WY 82717

N/A

Laboratory Performing Analyses Mine

Name Address

Standard Lab's Cordero Lab Cordero Rojo (Cloud Peak)

SGS Lab 2804 Hackathorne Lane, Gillette, WY 82716

SGS Lab 2804 Hackathorne Lane, Gillette, WY 82716

Belle Ayr (Alpha Natural Resources)

Caballo (Peabody Energy)

5/26/2010 ‐ Page 6
MidAmerican Energy Company

EGU‐ICR Response

Louisa Generating Station

8e Do any of these test reports reflect testing during periods of startup, shutdown,

and malfunction? Yes X No

If yes, please note which reports.

8f Did the unit’s control configuration differ from that shown in Part I, question

16, at the time of these test results? X Yes No

If yes, please list the unit’s complete control configuration at time of testing in a

similar format to Part I, question 16. Boiler ID Type NOx control SO2 control PM control Date of Change

101 Pulverized coal,

wall‐fired, dry

bottom

Low‐NOx Burners with

Overfire Air

None Hot‐side

electrostatic

precipitator with

ADA‐ES

proprietary flue

gas conditioning

reagent

Tests prior to

12/11/2007

8g Do any of these test reports reflect testing at a location before a post

combustion SO2 emission control device (e.g., FGD, SDA, Dry Scrubber)?

Yes X No

If yes, please note which reports and, in addition to the detailed description of

the location of the sampling point(s) (question 8c above), include detail about

how much, if any, bypass of unscrubbed flue gas was utilized at the time of

testing (including percentage of total scrubber flue gas flow). Note by diagram

where sampling ports were located in relation to the bypass ductwork.

9 What type of deviation reporting is required for violations of permit

requirements?

10 Are deviation reports available for malfunctions or other periods of

noncompliance with permit terms and conditions? X Yes No

If yes, please note which reports.

11 Are continuous emissions monitoring system (CEMS) data available (e.g.,

mercury, continuous opacity monitoring systems) that are not already being

provided to the U.S. EPA, even if from short‐term testing?

X Yes No

If yes, please note for which pollutants CEMS data are available and the period

of time (both total period and calendar period) for which data are available. If

CEM data are being provided to EPA, please note to which Office the data are

being provided.

N/AAll emission limit deviations are reported in quarterly emission reports, and in

Title V semi‐annual monitoring reports and annual compliance certification

reports submitted to the state agency. Additionally, most emission deviations

are also orally reported to the state agency within eight hours or at the start of

the next working day following the onset of the incident. A follow‐up written

report is requried for each orally reported deviation. Some opacity deviations of

short duration and of low magnitude of deviation are not required to be

reported outside of the quarterly emission report.

Same as Question 9 (malfunctions included only if the malfunction caused a

violation of a permit condition or emission limit)

CO data available beginning July 27, 2005. Other CEM data is being supplied to

U. S. EPA, Air and Toxics Division, Region 7, 901 N. 5th Street, Kansas City, KS

66101, CEMS Acid Rain data provided to EPA Acid Rain Division

5/26/2010 ‐ Page 7
MidAmerican Energy Company

EGU‐ICR Response

Louisa Generating Station

12 For each boiler noted in Part I, question 15, provide the following

information:

Boiler ID Date of test PM SO2 HCl/HF/HCN Metal HAP Hg CO

Other

organics

(specify) Gross MW 

101 7/27/2005 N/A N/A N/A N/A N/A

130.867 PPM

1086.80 lb/hr

(5 hr) 7

101 2/15/2008

9.80 lb/hr filterable;

52.31 lb/hr filterable &

condensable (average of 3

test runs) N/A N/A N/A N/A N/A

VOC

0.0002

lb/MMBtu

(average of

3 test runs) 7

101 1/19/2010 N/A N/A N/A

Lead 24.33 ug;

11.40 ug/m3;

0.082 lb/hr;

0.0000106

lbs/mmBtu(aver

age of 3 test

runs) N/A N/A N/A 7

Emissions test results (indicate format of emiss

5/26/2010 ‐ Page 8


MidAmerican Energy Company

EGU‐ICR ResponseGeorge Neal North

PART I: GENERAL FACILITY INFORMATION

Process InformationNOTE: If any rank of coal or any grade of oil (including petroleum coke [pet

coke]), in any amount, is fired, complete Parts I and II and return to the address

noted earlier. If NO coal or oil is fired, complete only Part I and return to the

address noted earlier.

Blr ID 1 Blr ID 2 Blr ID 3

1 Name of legal owner of facility:

2 Name of legal operator of facility, if different from legal owner:

3 Address of legal owner or operator:

4a Plant Name (as reported on U.S. DOE/EIA Form‐860 (2007), “Annual Electric

Generator Report,” schedule 2, line 1, page 37, question 1) OR Plant Name (as

reported on U.S. DOE/EIA Form EIA‐923 (2008), “Power Plant Operations

Report,” schedule 2, page 1, question 1):

4b EIA Plant Code (as reported on U.S. DOE/EIA Form‐860 (2007), schedule 2, line

1, page 37, question 2) OR Plant ID (as reported on U.S. DOE/EIA Form EIA‐923

(2008), schedule 2, page 1, question 2):

5 Complete street address of facility (physical location):

6 Provide mailing address if different:

7 Name and title of contact(s) able to answer technical questions about the

completed survey:

8 Contact(s) telephone number(s):

and e‐mail address(es):

9 Is this facility considered to be owned or operated by a small entity as defined

by the Regulatory Flexibility Act? Yes X No Don’t know

10 Which of the following fossil fuels or other material(s) are fired in any steam

generating unit at this facility? X coal

oil (including petcoke) X natural gas

other (specify in question 14 below)

11 Which of the following fossil fuels or other material(s) are permitted to be fired

in any steam generating unit at this facility? X coal X

oil (including petcoke) X natural gas

X other (specify in question 14 below)

12 If coal or solid fuel, as described below, derived from a fossil source is fired,

indicate which rank of coal or solid fuel was utilized during the previous 12

months prior to the receipt of this ICR:

Fired In Previous

12 Months %

lignite

X 100 subbituminous

bituminousanthracitecoal refuse (including gob, culm, and subbituminous‐derived coal refuse)

synfuel (including, but not limited to, briquettes, pellets, or extrusions which are

formed by binding materials, or processes that recycle materials)

(please specify the type or form of synfuel used)

petroleum coke

13 If oil is fired, indicate which type of oil was utilized during the previous 12

months prior to the receipt of this ICR: Fired In Previous

12 Months %

distillateresidual or bunker C

other (specify)

MidAmerican Energy Company MidAmerican Energy Company; Alliant Energy

Corporation ‐ Interstate Power and Light

PO Box 666Sergeant Bluff, IA 51054‐0666

Sam Nelson; Director‐Environmental & Regulatory Compliance

712‐277‐5287; SLNelson@midamerican.com

MidAmerican Energy CompanyMidAmerican Energy CompanyPO Box 657Des Moines, IA 50306‐0657

George Neal North

10911151 260th Street

Sergeant Bluff, IA 51054

5/26/2010 ‐ Page 1
MidAmerican Energy Company

EGU‐ICR ResponseGeorge Neal North

14a If “other” was checked in questions 10 or 11 above indicating that any non‐

fossil fuel or other material (including, but not limited to, plastics, treated

wood, rubber belting or gaskets, whole tires, tire‐derived fuel, boiler cleaning

solutions, animal wastes, etc.) is either utilized or permitted to be used, please

indicate below what materials are combusted in the boiler and in what

quantities (specify whether this quantity is on a weight percentage or heat [Btu]

basis). Also indicate (yes/no) whether you are permitted to burn non‐fossil

fuel(s) or other material(s) even if you do not actually burn them.

Other Material

Permitted to

burn

YES/NO

Actually burn

YES/NO Quantity/year

Used Oil yes no

Used Ethylene

glycol yes no

Small quantity

hazardous waste

per EPA BIF

notification yes no

14b If “other” was checked in questions 10 or 11 above indicating that any non‐

fossil fuel or other material (including, but not limited to, plastics, treated

wood, rubber belting or gaskets, whole tires, tire‐derived fuel, boiler cleaning

solutions, animal wastes, etc.) is either utilized or permitted to be used, were

such material to be classified as “solid waste” under the Resource Conservation

and Recovery Act and, thus, make the utilizing unit subject to CAA section 129,

would you continue to utilize (i.e., use as a fuel) the material?

Yes X No

Explain:

15 Identification (or designation) of all coal‐ and oil‐fired steam generating units

(boilers) (as defined by Clean Air Act section 112(a)(8)) located at this facility.

Boiler ID

Original design

fuel (i.e. coal

rank or type of

oil) Design heat input, (MMBtu)

Present

maximum heat

input, (MMBtu)

MWe Gross

capacity

MWe Net

capacity

Original

design gross

efficiency (%,

HHV)

Present operating

gross efficiency (%,

HHV)

Design

steam

pressure

(psig)

Operating stea

pressure (psig

1 Bituminous 1351 1363 145 135 90.85 85.8 1800 1800 

2 Bituminous 3017 3081 325 300 87.97 84.33 2400 2400 

3 Bituminous 4867 5021 531 515 88.01 84.6 2400 2400 

Emission Control Technology

16 For each boiler noted in Part I, question 15, provide the following

information for each current emission control device installed and

operating and/or planned (please designate the order of the emission

controls – 1 for first control following the boiler, 2 for second control

following the boiler, etc.): Boiler ID Type NOx control SO2 control PM control Other control

1 Cyclone, wet

bottom

1‐Overfire Air (5/15/2006) N/A 2‐Hot side

electrostatic

precipitator

(7/1972)

N/A

2 Pulverized coal,

wall‐fired, dry

bottom

1‐Low NOx Burner, Overfire

Air (10/26/2007)

N/A 2‐Cold‐side

electrostatic

precipitator

(4/1/1972) with

SO3 injection flue

gas conditioning

(11/1977)

N/A

3 Pulverized coal,

wall‐fired, dry

bottom

1‐Low NOx Burner, Overfire

Air (12/18/2004)

N/A 2‐Cold‐side

electrostatic

precipitator

(10/9/1075)

N/A

Current practice is not to combust any waste materials in the boiler.

5/26/2010 ‐ Page 2
MidAmerican Energy Company

EGU‐ICR ResponseGeorge Neal North

17 For each boiler noted in Part I, question 15, provide the company

(prime vendor) name and company contact information for each HAP‐

specific (e.g., mercury, hydrogen chloride) control technology that you

have either contracted for, are installing, or have installed for the

purpose of participating in a control technology demonstration project

(e.g., U.S. Department of Energy program, consent decree, etc.).

Boiler ID Telephone

123

18 For the control technologies identified in Part I, question 17, provide the

date of actual start‐up of the demonstration (if the control is currently

operating), the date of expected or projected start‐up, the date the

demonstration was completed, the type of HAP control installed (e.g.,

sorbent and type; pre‐combustion boiler chemical additive; combustion

boiler chemical additive), the desired HAP emission reduction or rate (if

any), and the coal rank(s) upon which the demonstration was

conducted. Please specify the format of the target HAP emission

reduction or rate (e.g., lb/MWh, lb/TBtu, percent reduction, etc.). If the

format of the target end‐point is percent reduction, provide (1) an

estimate of what an equivalent emission rate would be (and specify the

format of the equivalent emission rate), and (2) the basis for calculating

the percent reduction (i.e., where the “inlet” and “outlet” are).

Boiler ID

Demonstration

activity actual

start‐up date

Demonstration activity

projected start‐up date

Demonstration

activity end‐date

or projected end‐

date

Type of control

(e.g., sorbent and

type; chemical

additive)

Desired HAP

emission

reduction (%)

or emission

rate

Coal rank(s) in

use

123

19 For each boiler noted in Part I, question 15, provide the company (prime

vendor) name and company contact information for each HAP (e.g., mercury,

hydrogen chloride) control technology that you have either contracted for, are

installing, or have installed for the purpose of providing a non‐demonstration,

full‐scale operating system.

Boiler ID Telephone

123

20 For the control technologies identified in Part I, question 19, provide the

date of actual start‐up (if the control is currently operating), the date of

expected or projected start‐up, the type of HAP control installed (e.g.,

sorbent and type; pre‐combustion boiler chemical additive; combustion

boiler chemical additive), the guaranteed HAP emission reduction or

emission rate, the sorbent feed rate upon which the guarantee is based,

and the coal rank(s) upon which the guarantee is based. Please specify

the format of the guarantee (e.g., lb/MWh, lb/TBtu, percent reduction,

etc.). If the format of the guarantee is percent reduction, provide (1) an

estimate of what an equivalent emission rate would be (and specify the

format of the equivalent emission rate), and (2) the basis for calculating

the percent reduction (i.e., where the “inlet” and “outlet” are).

Boiler ID

Actual start‐up

date

Expected or projected start‐

up date

Type of control

(e.g., sorbent

and type;

chemical

additive)

Guaranteed HAP

emission reduction

(%) or emission rate

Sorbent or

additive feed

rate on which

guarantee is

based

Coal rank(s)

upon which

guarantee is

based

123

N/AN/AN/A

Company (vendor) contact information

Company (vendor) Name Address

N/AN/AN/AN/AN/AN/A

Company (vendor) contact information

Company (vendor) Name Address

N/AN/AN/A

5/26/2010 ‐ Page 3
MidAmerican Energy Company

EGU‐ICR ResponseGeorge Neal North

21 For each boiler noted in Part I, question 15, provide the following information:

Boiler ID PM PM10 PM2.5 SO2 HCl and/or HF HCN Metal HAP Hg CO

1 Construction

permit; 0.5

lb/mmBtu,

Method 5 with

202, average of

3 test runs

N/A N/A Construction

permit; 1635.6

lb/hr (3 hr

average), 38,600

lb/day; Title V

Permit ‐ 1.2

lb/mmBtu 3‐hr

average

N/A N/A N/A N/A Construction

permit; 2,507

tons/yr, 1.26

lb/mmBtu 3‐h

avg, 1717.4

lb/hr 1‐hr avg

2 Construction

permit; 0.3

lb/mmBtu,

Method 5 with

202, average of

3 test runs

N/A N/A Construction

permit; 87,253

lb/day; Title V

Permit ‐ 1.2

lb/mmBtu 3‐hr

average

N/A N/A N/A N/A Construction

permit; 7,287

tons/yr, 1.63

lb/mmBtu 3‐h

avg, 5,028.2

lb/hr 1‐hr avg

3 Construction

permit; 0.17

lb/mmBtu,

Method 5 with

202, average of

3 test runs

N/A N/A Construction

permit; 1.2 lb/mBtu

(3 hr avg), 142,194

lb/day

N/A N/A N/A N/A Construction

permit; 9,236

tons/yr 12‐

month rolling

avg, 1.26

lb/mmBtu 1‐h

22 For each boiler noted in Part I, question 15, provide the following information:

Boiler ID PM PM10 PM2.5 SO2 HCl and/or HF HCN Metal HAP Hg CO

1 N/A N/A N/A N/A N/A N/A N/A N/A CBI 2 N/A N/A N/A N/A N/A N/A N/A N/A CBI 3 N/A N/A N/A N/A N/A N/A N/A N/A CBI 

23 Was any other guarantee level sought or offered? Yes X No

Please elaborate

Permitted emission limit (indicate type of permit and format of emission limit)

Most recent guaranteed emission rate for each pollutant for which there is a permitted emission limit

5/26/2010 ‐ Page 4
MidAmerican Energy Company

EGU‐ICR ResponseGeorge Neal North

24 For each boiler noted in Part I, question 15, provide the following information:

Boiler ID PM PM10 PM2.5 SO2 HCl and/or HF HCN Metal HAP Hg CO

1 Filterable &

condensiblestack test, stack

test reports,opacitymonitoring,quarterlyopacity reports,

semi‐annual

monitoringreport, annualcompliancecertification,annualemissionssummary,records kept forfive years

N/A N/A CEM's, quarterly

emission reports,excess emissionreports, semi‐

annual monitoring

report, annualcompliancecertification, annualemissionssummary, records

kept for five years

N/A N/A N/A N/A Initial

performancetest data, CEM

quarterlyemissionreports, excessemissionreports, semi‐annualmonitoring

report, annualcompliancecertification,annualemissionssummary,records kept fo

five years

2 Filterable &

condensiblestack test, stack

test reports,opacitymonitoring,quarterlyopacity reports,semi‐annual

monitoringreport, annualcompliancecertification,annualemissionssummary,records kept forfive years

N/A N/A CEM's, quarterly

emission reports,excess emissionreports, semi‐annual monitoring

report, annual

compliancecertification, annualemissionssummary, records

kept for five years

N/A N/A N/A N/A Initial

performancetest data, CEM

quarterlyemissionreports, excessemissionreports, semi‐annualmonitoringreport, annualcompliancecertification,annualemissionssummary,records kept fo

five years

3 Filterable &

condensible

stack test, stacktest reports,opacitymonitoring,quarterlyopacity reports,semi‐annual

monitoringreport, annualcompliancecertification,annualemissionssummary,records kept forfive years

N/A N/A CEM's, quarterly

emission reports,excess emissionreports, semi‐annual monitoring

report, annualcompliancecertification, annualemissionssummary, records

kept for five years

N/A N/A N/A N/A Initial

performancetest data, CEM

quarterlyemissionreports, excess

emissionreports, semi‐annualmonitoringreport, annual

compliancecertification,annualemissionssummary,records kept fo

five years

25 For the control technologies identified in Part I, questions 17 and 19,

provide the cost information requested.

Facility Name/Unit No.:

Total Capital

Investment: $

OperatingCosts: $

1 N/A Yes /No N/A Yes /No N/A N/A (Include base year for operating costs [e.g., 2006]

2 N/A Yes /No N/A Yes /No N/A N/A (Include base year for operating costs [e.g., 2006]

3 N/A Yes /No N/A Yes /No N/A N/A (Include base year for operating costs [e.g., 2006]

Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a permitted emission limit

Retrofit to existing boiler? Installation on new boiler?

5/26/2010 ‐ Page 5
MidAmerican Energy Company

EGU‐ICR ResponseGeorge Neal North

26 Are any other means of emission control (for any pollutant) employed on any

boiler noted in Part I, question 15 (e.g., low‐ash coal, coal or oil with low trace

constituents, etc.)? Please specify.

PART II: FUEL ANALYSIS AND EMISSION DATA

Fuel Analysis

Each facility should provide the following information for each coal and oil

shipment received during the preceding 12 calendar months.

1a Plant or facility name from Part I, question 4a:

1b Plant or facility code from Part I, question 4b:

2 For each individual coal and oil shipment received during the preceding 12

calendar months, provide the following information, as available (indicate N/A if

not available; use addit ional pages, as necessary):

State/Country County Coal seam

765,847 1, 2, 3 Wyoming/United States Campbell Wyodak‐Anderson Rail

83 1, 2, 3 Wyoming/United States Campbell Wyodak‐Anderson Rail

1,580,142 1, 2, 3 Wyoming/United States Campbell Wyodak Rail

76,528 1, 2, 3 Wyoming/United States Campbell Smith Rail

235,011 1, 2, 3 Wyoming/United States Campbell Wyodak‐Anderson Rail

3 For each individual coal and oil shipment received during the preceding

12 calendar months, provide the following information, as available (dry

basis) (indicate N/A if not available):

Sample ID #

Total amount of

fuel represented

by sample, tons

or gallons Total sulfur, % Ash content, %

Higher heating

value, Btu/lb (dry

basis)

Mercury, ppm

(dry basis)

Chlorine, ppm

(dry basis)

Fluorine, ppm (dry

basis)

Nickel,

ppm (dry

basis)

Other trace

metal HAP,

ppm

Jacobs Ranch 765,847 0.55 7.3 12127 0.09 159 26.4 6 28.07 

Cordero Rojo 83 0.45 7.71 12015 0.073 84.81 48.08 4.5 34.44 

Belle Ayr 1,580,142 0.38 6.43 12128 0.08 <50* 52.82 2.88 31.87 

Caballo 76,528 0.48 7.3 12074 0.11 <10* 61 5 22.2 

Black Thunder 235,011 0.41 7.16 12117 0.08 10 50.65 5 23.49 

4 Were the data provided in Part II, question 3 above, acquired pursuant to:

permit requirements

X contractual obligations

standard operational procedures

other (please specify )

5 Analyses provided in Part II, question 3 above, supplied by

6 Name and address of laboratory performing analyses:

Notes:For coal sample concentrations that were below the detection thresholds, 1/2 the threshold value was input. The (<) sign indicates

that the average is below the threshold.

N/A N/A

2804 Hackathorne Lane, Gillette, WY 82716

Belle Ayr (Alpha Natural P.O. Box 3039, Gillette, WY 82717

Name Address

Standard Lab's Cordero Lab P.O. Box 1449, Gillette, WY 82717

SGS Lab

Mine

Jacobs Ranch (Cloud Peak(formerly Rio Tinto))

Cordero Rojo (Cloud Peak(formerly Rio Tinto))

Belle Ayr (Alpha)Caballo (Peabody)Black Thunder (Arch)

Low‐ash coal for PM control; low‐sulfur coal for SO2 control.

George Neal North

1091

Amount

received, dry

basis, short tons

ID # of boiler(s)

firing fuel

Fuel source Fuel shipment

method

Fuel supplier Other

Black Thunder (Arch Coal) P.O. Box 406, Wright, WY 82732 N/A N/A

Jacobs Ranch (Arch Coal) P.O. Box 406, Wright, WY 82732 N/A N/A

N/A N/A

Caballo (Peabody Energy) Caller Box 3041, Gillette, WY 82717 N/A N/A

Name Address Name Address

Cordero Rojo (Cloud Peak) P.O. Box 1449, Gillette, WY 82717

Laboratory Performing Analyses

Mine

Cordero Rojo (Cloud Peak)

Belle Ayr (Alpha Natural Resources)

SGS Lab 2804 Hackathorne Lane, Gillette, WY 82716 Caballo (Peabody Energy)

Black Thunder (Arch Coal)

Standard Lab's Black Thunder Lab P.O. Box 406, Wright, WY 82732 Jacobs Ranch (Arch Coal)

Standard Lab's Black Thunder Lab P.O. Box 406, Wright, WY 82732

5/26/2010 ‐ Page 6
MidAmerican Energy Company

EGU‐ICR ResponseGeorge Neal North

7 In addition to the analyses required in Part II, question 3 above, for samples for

which analyses of chlorine and/or any of the HAP metals were conducted,

please provide copies of any analyses conducted over the preceding 12 calendar

months for (a) complete proximate and ultimate analyses, (b) additional trace

metals, and (c) the mineralogy of the ash that are readily available for the oil(s)

or coal(s) listed in Part II, question 2 above. The Agency is requesting these data

only as they may already be available; no additional sampling or analyses are

required to provide these data.

N1 08‐27‐09

Special Test ‐ Train Sample

N1 & N2 12‐10‐

09 Special Test

N2 & N3 04‐17‐09

Capablility Test

Emission Data

8a What emission test report(s), parametric monitoring data, and other data or

monitoring are available for the boilers noted in Part I, question 15, for tests

conducted since January 1, 2005. Please consider reports prepared for all

testing and monitoring programs, for all pollutants, including (but not limited

to) those required under Title V, compliance with State or local requirements,

fulfillment of contractual obligations, U.S. Department of Energy (DOE)

programs, etc. (NOTE: EPA is not requesting copies of the test reports or data at

this time; however we may request actual copies in the future.) Use additional

pages as necessary.

8b Please indicate the date(s) and types (e.g., stack, fuel, parametric, etc.) of the

test(s) and the constituents (including criteria and hazardous air pollutants)

sampled for. Date Type

Blr ID

6/6/2006 stack 1

7/12/2006 stack 17/17/2008 stack 11/13/2010 stack 17/13/2006 stack 2

12/12/2007 stack 2

7/16/2008 stack 212/5/2008 stack 22/15/2005 stack 37/11/2006 stack 37/15/2008 stack 31/20/2009 stack 3

8c Do any of these test reports reflect testing at a location before any emission

control devices? Yes X NoIf yes, please note which reports and provide a detailed description of the

location of the emissions sampling point(s).

Particulate Matter (PM) and CO compliance stack test; lead stack test

carbon monoxide

particulate matter

lead

Constituents

particulate matterparticulate matterparticulate matter

lead

carbon monoxide

particulate matterparticulate matter

lead

carbon monoxide

Adobe Acrobat 

Document

Adobe Acrobat 

Document

Adobe Acrobat 

Document

5/26/2010 ‐ Page 7
MidAmerican Energy Company

EGU‐ICR ResponseGeorge Neal North

8d Were any of these test reports conducted when use of other material(s) or non‐

fossil fuels were fired in the boiler? Yes X No

If yes, please note which reports and identify the other material(s) or non‐fossil

fuels used.

8e Do any of these test reports reflect testing during periods of startup, shutdown,

and malfunction? Yes X No

If yes, please note which reports.

8f Did the unit’s control configuration differ from that shown in Part I, question 16,

at the time of these test results? X Yes No

If yes, please list the unit’s complete control configuration at time of testing in a

similar format to Part I, question 16. Boiler ID Type NOx control SO2 control PM control Date of Change

2 Pulverized coal,

wall‐fired, dry

bottom

Low NOx Burner None Cold‐side

electrostatic

precipitator with

SO3 injection flue

gas conditioning

Tests Prior to

10/23/2007

8g Do any of these test reports reflect testing at a location before a post

combustion SO2 emission control device (e.g., FGD, SDA, Dry Scrubber)?

Yes X No

If yes, please note which reports and, in addition to the detailed description of

the location of the sampling point(s) (question 8c above), include detail about

how much, if any, bypass of unscrubbed flue gas was utilized at the time of

testing (including percentage of total scrubber flue gas flow). Note by diagram

where sampling ports were located in relation to the bypass ductwork.

9 What type of deviation reporting is required for violations of permit

requirements?

10 Are deviation reports available for malfunctions or other periods of

noncompliance with permit terms and conditions? X Yes No

If yes, please note which reports.

11 Are continuous emissions monitoring system (CEMS) data available (e.g.,

mercury, continuous opacity monitoring systems) that are not already being

provided to the U.S. EPA, even if from short‐term testing?

X Yes No

If yes, please note for which pollutants CEMS data are available and the period

of time (both total period and calendar period) for which data are available. If

CEM data are being provided to EPA, please note to which Office the data are

being provided.

N/AAll emission limit deviations are reported in quarterly emission reports, and in

Title V semi‐annual monitoring reports and annual compliance certification

reports submitted to the state agency. Additionally, most emission deviations are

also orally reported to the state agency within eight hours or at the start of the

next working day following the onset of the incident. A follow‐up written report is

requried for each orally reported deviation. Some opacity deviations of short

duration and of low magnitude of deviation are not required to be reported

outside of the quarterly emission report.Same as Question 9 (malfunctions included only if the malfunction caused a

violation of a permit condition or emission limit)

CO data (Unit 1 6/6/2006 ‐ present, Unit 2 12/12/2007 ‐ present, Unit 3 1/1/2005‐

present); continuous opacity monitoring system data (01/01/2005 ‐ present),

CEMS Acid Rain data provided to EPA Acid Rain Division

5/26/2010 ‐ Page 8
MidAmerican Energy Company

EGU‐ICR ResponseGeorge Neal North

12 For each boiler noted in Part I, question 15, provide the following

information:

Boiler ID Date of test PM SO2 HCl/HF/HCN

LEAD Metal

HAP Hg CO

Other

organics

(specify) Gross MW 

1 6/6/2006 N/A N/A N/A N/A N/A

107.8 lb/hr, 0.074

lb/mmBtu (5 hr) N/A 1

1 7/12/2006

372.78 lb/hr filterable;

391.54 lb/hr filterable &

condensable (average of 3

test runs) N/A N/A N/A N/A N/A N/A 1

1 7/17/2008

214.79 lb/hr filterable;

266.83 lb/hr filterable &

condensable (average of 3

test runs) N/A N/A N/A N/A N/A N/A 1

1 1/13/2010 N/A N/A N/A

Lead

1.86E‐005

lb/mmBtu

(average of 3

test runs) N/A N/A N/A 1

2 7/13/2006

211.58 lb/hr filterable;

302.86 lb/hr filterable &

condensable (average of 3

test runs) N/A N/A N/A N/A N/A N/A 2

2 12/12/2007 N/A N/A N/A N/A N/A

242.3 lb/hr, 0.088

lb/mmBtu (5 hr) N/A 2

2 7/16/2008

254.15 lb/hr filterable;

314.81 lb/hr filterable &

condensable (average of 3

test runs) N/A N/A N/A N/A N/A N/A 2

2 12/5/2008 N/A N/A N/A

Lead

7.882E‐006

lb/mmBtu

(average of 3

test runs) N/A N/A N/A 2

3 2/15/2005 N/A N/A N/A N/A N/A

2929.38 lb/hr, 0.498

lb/mmBtu (5 hr) N/A 5

3 7/11/2006

47.8 lb/hr filterable;

335.87 lb/hr filterable &

condensable (average of 3

test runs) N/A N/A N/A N/A N/A N/A 5

3 7/15/2008

28.95 lb/hr filterable;

174.78 lb/hr filterable &

condensable (average of 3

test runs) N/A N/A N/A N/A N/A N/A 5

3 1/20/2009 N/A N/A N/A

Lead

1.1125E‐005

lb/mmBtu

(average of 3

test runs) N/A N/A N/A 5

Emissions test results (indicate format of emission data)

5/26/2010 ‐ Page 9
WORK ORDER # 200903892001 200903892002

NEC SAMPLE ID 18630 18634

SAMPLE DATE 12/10/2009 12/11/2009

SAMPLE TYPE UNIT 1,2 UNIT 1,2

SAMPLE DESCRIPTION DAILY BURN DAILY BURN

MOISTURE 29.16 28.7

AS REC'D ASH 5.85 5.4

DRY ASH 8.26 7.58

AS REC'D VOLATILE MATTER 31.93 34.3

DRY VOLATILE MATTER 45.07 48.1

AS REC'D FIXED CARBON 33.06 31.6

DRY FIXED CARBON 46.67 44.32

AS REC'D SULFUR 0.33 0.29

DRY SULFUR 0.47 0.41

AS REC'D BTU 8451 8570

DRY BTU 11929 12020

MAF BTU 13003 13006

ULTIMATE ANALYSIS (%)

AS REC'D NITROGEN 0.7 0.68

DRY NITROGEN 0.99 0.96

AS REC'D CARBON 49.77 50.41

DRY CARBON 70.26 70.7

AS REC'D HYDROGEN 3.52 3.48

DRY HYDROGEN 4.97 4.88

AS REC'D OXYGEN 10.66 11.03

DRY OXYGEN 15.05 15.47

MINERAL ANALYSIS OF ASH (%)

PHOSPHORUS PENTOXIDE 0.8 0.74

SILICON DIOXIDE 35.51 37.05

FERRIC OXIDE 4.63 4.22

ALUMINUM OXIDE 18.49 17.67

TITANIUM DIOXIDE 1.37 1.44

MAGANESE DIOXIDE 0.07 0.07

CALCIUM OXIDE 20.69 21.38

MAGNESIUM OXIDE 3.75 3.99

POTASSIUM OXIDE 0.46 0.46

SODIUM OXIDE 1.22 1.37

SULFUR TRIOXIDE 7.59 7.16

BARIUM OXIDE 0.52 0.6

STRONTIUM 0.39 0.42

UNDETERMINED 4.51 3.43

T250 2273 2267

% ALKALIES AS Na2O 0.13 0.13
WORK ORDER # 200901262001 200901307001

NEC SAMPLE ID 18027 18033

SAMPLE DATE 4/17/2009 4/21/2009

SAMPLE TYPE UNIT 2 UNIT 3

SAMPLE DESCRIPTION CAP TEST

CAP TEST 

BELLE AYR

MOISTURE 28.58 29.1

AS REC'D ASH 4.89 4.51

DRY ASH 6.85 6.36

AS REC'D VOLATILE MATTER 33 33.02

DRY VOLATILE MATTER 46.21 46.57

AS REC'D FIXED CARBON 33.53 33.37

DRY FIXED CARBON 46.94 47.07

AS REC'D SULFUR 0.39 0.27

DRY SULFUR 0.54 0.38

AS REC'D BTU 8704 8565

DRY BTU 12187 12081

MAF BTU 13083 12902

ULTIMATE ANALYSIS (%)

AS REC'D NITROGEN 0.72 0.69

DRY NITROGEN 1.01 0.97

AS REC'D CARBON 51.23 52.22

DRY CARBON 71.73 73.65

AS REC'D HYDROGEN 3.46 3.48

DRY HYDROGEN 4.85 4.91

AS REC'D OXYGEN 10.73 9.73

DRY OXYGEN 15.02 13.73

MINERAL ANALYSIS OF ASH (%)

PHOSPHORUS PENTOXIDE 1.35 0.7

SILICON DIOXIDE 29.65 29.4

FERRIC OXIDE 6.88 6.73

ALUMINUM OXIDE 17.31 14.42

TITANIUM DIOXIDE 1.4 1.4

MAGANESE DIOXIDE 0.08 0.12

CALCIUM OXIDE 22.32 26.49

MAGNESIUM OXIDE 4.25 4.41

POTASSIUM OXIDE 0.33 0.27

SODIUM OXIDE 1.54 1.6

SULFUR TRIOXIDE 10.61 8.7

BARIUM OXIDE 0.49 0.69

STRONTIUM 0.3 0.38

UNDETERMINED 3.49 4.69

T250 2142 2220

% ALKALIES AS Na2O 0.12 0.11
WORK ORDER # 200902722001

NEC SAMPLE ID 18383

SAMPLE DATE 8/27/2009

SAMPLE TYPE SPECIAL TEST

SAMPLE DESCRIPTION UNIT #1 BMNN128

MOISTURE 26.08

AS REC'D ASH 2.68

DRY ASH 3.63

AS REC'D VOLATILE MATTER 32.07

DRY VOLATILE MATTER 43.39

AS REC'D FIXED CARBON 39.17

DRY FIXED CARBON 52.98

AS REC'D SULFUR 0.19

DRY SULFUR 0.26

AS REC'D BTU 9064

DRY BTU 12262

MAF BTU 12724

ULTIMATE ANALYSIS (%)

AS REC'D NITROGEN 0.72

DRY NITROGEN 0.98

AS REC'D CARBON 52.39

DRY CARBON 70.88

AS REC'D HYDROGEN 3.39

DRY HYDROGEN 4.58

AS REC'D OXYGEN 14.54

DRY OXYGEN 19.67

MINERAL ANALYSIS OF ASH (%)

PHOSPHORUS PENTOXIDE 0.22

SILICON DIOXIDE 9.77

FERRIC OXIDE 7.19

ALUMINUM OXIDE 21.56

TITANIUM DIOXIDE 0.65

MAGANESE DIOXIDE 0.11

CALCIUM OXIDE 35.87

MAGNESIUM OXIDE 6.94

POTASSIUM OXIDE 0.41

SODIUM OXIDE 2.58

SULFUR TRIOXIDE 9.51

BARIUM OXIDE 0.63

STRONTIUM 0.37

UNDETERMINED 4.19

T250 2501

% ALKALIES AS Na2O 0.1


MidAmerican Energy Company

EGU‐ICR ResponseGeorge Neal South

PART I: GENERAL FACILITY INFORMATION

Process InformationNOTE: If any rank of coal or any grade of oil (including petroleum coke [pet

coke]), in any amount, is fired, complete Parts I and II and return to the address

noted earlier. If NO coal or oil is fired, complete only Part I and return to the

address noted earlier.

Blr ID 4

1 Name of legal owner of facility:

2 Name of legal operator of facility, if different from legal owner:

3 Address of legal owner or operator:

4a Plant Name (as reported on U.S. DOE/EIA Form‐860 (2007), “Annual Electric

Generator Report,” schedule 2, line 1, page 37, question 1) OR Plant Name (as

reported on U.S. DOE/EIA Form EIA‐923 (2008), “Power Plant Operations

Report,” schedule 2, page 1, question 1):

4b EIA Plant Code (as reported on U.S. DOE/EIA Form‐860 (2007), schedule 2, line

1, page 37, question 2) OR Plant ID (as reported on U.S. DOE/EIA Form EIA‐923

(2008), schedule 2, page 1, question 2):

5 Complete street address of facility (physical location):

6 Provide mailing address if different:

7 Name and title of contact(s) able to answer technical questions about the

completed survey:

8 Contact(s) telephone number(s):

and e‐mail address(es):

9 Is this facility considered to be owned or operated by a small entity as defined

by the Regulatory Flexibility Act? Yes X No Don’t know

10 Which of the following fossil fuels or other material(s) are fired in any steam

generating unit at this facility? X coal X

oil (including pet

coke) natural gas

other (specify in question 14 below)

11 Which of the following fossil fuels or other material(s) are permitted to be fired

in any steam generating unit at this facility? X coal X

oil (including pet

coke) natural gas

X other (specify in question 14 below)

12 If coal or solid fuel, as described below, derived from a fossil source is fired,

indicate which rank of coal or solid fuel was utilized during the previous 12

months prior to the receipt of this ICR:

Fired In Previous

12 Months %

lignite

X 100 subbituminous

bituminousanthracitecoal refuse (including gob, culm, and subbituminous‐derived coal refuse)

synfuel (including, but not limited to, briquettes, pellets, or extrusions which are

formed by binding materials, or processes that recycle materials)

(please specify the type or form of synfuel used)

petroleum coke

13 If oil is fired, indicate which type of oil was utilized during the previous 12

months prior to the receipt of this ICR: Fired In Previous

12 Months %

PO Box 778

Sioux city, IA 51102

Sam Nelson; Director‐Environmental & Regulatory Compliance

712‐277‐5287; SLNelson@midamerican.com

MidAmerican Energy Company; Algona Municipal Utilities;Alliant Energy Corporation ‐ Interstate Power and Light

Company; Bancroft Municipal Utilities; Cedar Falls Utilities;

Coon Rapids Municipal Utilities; Corn Belt Power Cooperative;

Graettinger Municipal Utilities; Laurens Municipal Light &

Power; Milford Municipal Utilities; NorthWestern Energy;

Northwest Iowa Power Cooperative; Spencer Municipal

Utilities; Webster City Light & Power

MidAmerican Energy CompanyPO Box 657Des Moines, IA 50306‐0657

George Neal South

73432761 Port Neal CircleSalix, IA 51051

5/26/2010 ‐ Page 1
MidAmerican Energy Company

EGU‐ICR ResponseGeorge Neal South

X 100 distillate

residual or bunker C

other (specify)

14a If “other” was checked in questions 10 or 11 above indicating that any non‐

fossil fuel or other material (including, but not limited to, plastics, treated

wood, rubber belting or gaskets, whole tires, tire‐derived fuel, boiler cleaning

solutions, animal wastes, etc.) is either utilized or permitted to be used, please

indicate below what materials are combusted in the boiler and in what

quantities (specify whether this quantity is on a weight percentage or heat [Btu]

basis). Also indicate (yes/no) whether you are permitted to burn non‐fossil

fuel(s) or other material(s) even if you do not actually burn them.

Other Material

Permitted to

burn

YES/NO

Actually burn

YES/NO Quantity/year

Used Oil yes no

Used Ethylene

glycol yes no

Small quantity

hazardous waste

per EPA BIF

notification yes no

14b If “other” was checked in questions 10 or 11 above indicating that any non‐

fossil fuel or other material (including, but not limited to, plastics, treated

wood, rubber belting or gaskets, whole tires, tire‐derived fuel, boiler cleaning

solutions, animal wastes, etc.) is either utilized or permitted to be used, were

such material to be classified as “solid waste” under the Resource Conservation

and Recovery Act and, thus, make the utilizing unit subject to CAA section 129,

would you continue to utilize (i.e., use as a fuel) the material?

Yes X No

Explain:

15 Identification (or designation) of all coal‐ and oil‐fired steam generating units

(boilers) (as defined by Clean Air Act section 112(a)(8)) located at this facility.

Boiler ID Original design

fuel (i.e. coal

rank or type of

oil)

Design heat input,

(MMBtu)

Present

maximum heat

input, (MMBtu)

MWe Gross

capacity

MWe Net

capacity

Original

design gross

efficiency (%,

HHV)

Present operating

gross efficiency (%,

HHV)

Design

steam

pressure

(psig)

Operating stea

pressure (psig

4 Subbituminous

coal

6167 6900 682 644 85.48 84.7 2415 2415 

Emission Control Technology

16 For each boiler noted in Part I, question 15, provide the following

information for each current emission control device installed and

operating and/or planned (please designate the order of the emission

controls – 1 for first control following the boiler, 2 for second control

following the boiler, etc.): Boiler ID Type NOx control SO2 control PM control Other control

4 Pulverized coal;

wall‐fired; dry

bottom

1‐Low Nox burners

w/overfire air

(12/16/2005)

N/A 2‐Cold‐side

electrostatic

precipitator

(12/16/1988) with

SO3 injection flue

gas conditioning

(11/18/1989)

N/A

17 For each boiler noted in Part I, question 15, provide the company

(prime vendor) name and company contact information for each HAP‐

specific (e.g., mercury, hydrogen chloride) control technology that you

have either contracted for, are installing, or have installed for the

purpose of participating in a control technology demonstration project

(e.g., U.S. Department of Energy program, consent decree, etc.).

Boiler ID Telephone

4 N/A

Current practice is not to combust any waste materials in the boiler.

Company (vendor) contact information

Company (vendor) Name Address

5/26/2010 ‐ Page 2
MidAmerican Energy Company

EGU‐ICR ResponseGeorge Neal South

18 For the control technologies identified in Part I, question 17, provide the

date of actual start‐up of the demonstration (if the control is currently

operating), the date of expected or projected start‐up, the date the

demonstration was completed, the type of HAP control installed (e.g.,

sorbent and type; pre‐combustion boiler chemical additive; combustion

boiler chemical additive), the desired HAP emission reduction or rate (if

any), and the coal rank(s) upon which the demonstration was

conducted. Please specify the format of the target HAP emission

reduction or rate (e.g., lb/MWh, lb/TBtu, percent reduction, etc.). If the

format of the target end‐point is percent reduction, provide (1) an

estimate of what an equivalent emission rate would be (and specify the

format of the equivalent emission rate), and (2) the basis for calculating

the percent reduction (i.e., where the “inlet” and “outlet” are). Boiler ID

Demonstration

activity actual

start‐up date

Demonstration activity

projected start‐up date

Demonstration

activity end‐date

or projected end‐

date

Type of control

(e.g., sorbent and

type; chemical

additive)

Desired HAP

emission

reduction (%)

or emission

rate

Coal rank(s) in

use

4 N/A

19 For each boiler noted in Part I, question 15, provide the company (prime

vendor) name and company contact information for each HAP (e.g., mercury,

hydrogen chloride) control technology that you have either contracted for, are

installing, or have installed for the purpose of providing a non‐demonstration,

full‐scale operating system.

Boiler ID Telephone

4

20 For the control technologies identified in Part I, question 19, provide the

date of actual start‐up (if the control is currently operating), the date of

expected or projected start‐up, the type of HAP control installed (e.g.,

sorbent and type; pre‐combustion boiler chemical additive; combustion

boiler chemical additive), the guaranteed HAP emission reduction or

emission rate, the sorbent feed rate upon which the guarantee is based,

and the coal rank(s) upon which the guarantee is based. Please specify

the format of the guarantee (e.g., lb/MWh, lb/TBtu, percent reduction,

etc.). If the format of the guarantee is percent reduction, provide (1) an

estimate of what an equivalent emission rate would be (and specify the

format of the equivalent emission rate), and (2) the basis for calculating

the percent reduction (i.e., where the “inlet” and “outlet” are).

Boiler ID

Actual start‐up

date

Expected or projected

start‐up date

Type of control

(e.g., sorbent

and type;

chemical

additive)

Guaranteed HAP

emission reduction

(%) or emission rate

Sorbent or

additive feed

rate on which

guarantee is

based

Coal rank(s)

upon which

guarantee is

based

4

21 For each boiler noted in Part I, question 15, provide the following information:

Boiler ID PM PM10 PM2.5 SO2 HCl and/or HF HCN Metal HAP Hg CO

4 Construction

permit; 0.10

lb/mmBtu,

Method 5 with

202, average of

3 test runs

N/A N/A Construction

permit; 1.2

lb/mBtu, 3‐hr avg

N/A N/A N/A N/A Construction

permit; 12,693

tons/yr 12

month rolling

avg, 0.42

lb/mmBtu dail

avg, 8,694 lb/h

1 hr avg

22 For each boiler noted in Part I, question 15, provide the following information:

Boiler ID PM PM10 PM2.5 SO2 HCl and/or HF HCN Metal HAP Hg CO

4 N/A N/A N/A N/A N/A N/A N/A N/A CBI 

23 Was any other guarantee level sought or offered? Yes X No

Please elaborate

Company (vendor) contact information

Company (vendor) Name Address

N/A

Permitted emission limit (indicate type of permit and format of emission limit)

Most recent guaranteed emission rate for each pollutant for which there is a permitted emission limit

N/A

5/26/2010 ‐ Page 3
MidAmerican Energy Company

EGU‐ICR ResponseGeorge Neal South

24 For each boiler noted in Part I, question 15, provide the following information:

Boiler ID PM PM10 PM2.5 SO2 HCl and/or HF HCN Metal HAP Hg CO

4 Filterable &

condensiblestack test, stack

test reports,opacitymonitoring,quarterlyopacity reports,

semi‐annualmonitoringreport, annualcompliancecertification,annualemissionssummary,records kept for

five years

N/A N/A CEM's, quarterly

emission reports,excess emissionreports, semi‐annual monitoring

report, annualcompliancecertification, annualemissionssummary, records

kept for five years

N/A N/A N/A N/A Initial

performancetest data, CEM'

quarterlyemissionreports, excess

emissionreports, semi‐

annualmonitoring

report, annualcompliancecertification,annualemissionssummary,records kept fo

five years

25 For the control technologies identified in Part I, questions 17 and 19,

provide the cost information requested.

Facility Name/Unit No.:

Total Capital

Investment: $

OperatingCosts: $

4 No Yes /No No Yes /No (Include base year for operating costs [e.g., 2006])

26 Are any other means of emission control (for any pollutant) employed on any

boiler noted in Part I, question 15 (e.g., low‐ash coal, coal or oil with low trace

constituents, etc.)? Please specify.

Low‐ash coal for PM control; low‐sulfur coal and low‐sulfur fuel oil for SO2 control.

Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a permitted emission limit

Retrofit to existing boiler? Installation on new boiler?

5/26/2010 ‐ Page 4
MidAmerican Energy Company

EGU‐ICR ResponseGeorge Neal South

PART II: FUEL ANALYSIS AND EMISSION DATA

Fuel Analysis

Each facility should provide the following information for each coal and oil

shipment received during the preceding 12 calendar months.

1a Plant or facility name from Part I, question 4a:

1b Plant or facility code from Part I, question 4b:

2 For each individual coal and oil shipment received during the preceding 12

calendar months, provide the following information, as available (indicate N/A if

not available; use addit ional pages, as necessary):

State/Country County Coal seam

35,362 4 Wyoming/United States Campbell Wyodak‐Anderson Rail20,081 4 Wyoming/United States Campbell Wyodak‐Anderson Rail

1,596,002 4 Wyoming/United States Campbell Wyodak Rail

43,690 4 Wyoming/United States Campbell Smith Rail

35,814 4 Wyoming/United States Campbell Wyodak‐Anderson Rail67,520 4 N/A N/A N/A Truck

452,679 4 N/A N/A N/A Truck

3 For each individual coal and oil shipment received during the preceding

12 calendar months, provide the following information, as available (dry

basis) (indicate N/A if not available):

Sample ID #

Total amount of

fuel represented

by sample, tons

or gallons Total sulfur, % Ash content, %

Higher heating

value, Btu/lb (dry

basis)

Mercury, ppm

(dry basis)

Chlorine, ppm

(dry basis)

Fluorine, ppm (dry

basis)

Nickel,

ppm (dry

basis)

Other trace

metal HAP,

ppm

Jacobs Ranch 35,362 0.55 7.3 12127 0.09 159 26.4 6 28.07 

Cordero Rojo 20,081 0.45 7.71 12015 0.073 84.81 48.08 4.5 34.44 

Belle Ayr 1,596,002 0.38 6.43 12128 0.08 <50* 52.82 2.88 31.87 

Caballo 43,690 0.48 7.3 12074 0.11 <10* 61 5 22.2 

Black Thunder 35,814 0.41 7.16 12117 0.08 10 50.65 5 23.49 

Hartland Fuel

Products 67,520 <0.0015 N/A N/A N/A N/A N/A N/A N/A 

Sapp Bros.

Petroleum Inc. 452,679 <0.0015 N/A N/A N/A N/A N/A N/A N/A 

4 Were the data provided in Part II, question 3 above, acquired pursuant to:

permit requirements

X contractual obligations

standard operational procedures

other (please specify )

5 Analyses provided in Part II, question 3 above, supplied by

Belle Ayr (Alpha Natural Resources) P.O. Box 3039, Gillette, WY 82717

Caballo (Peabody Energy) Caller Box 3041, Gillette, WY 82717

Black Thunder (Arch Coal) P.O. Box 406, Wright, WY 82732

Jacobs Ranch (Arch Coal) P.O. Box 406, Wright, WY 82732

Mine

Jacobs Ranch (Cloud Peak(formerly Rio Tinto))

Cordero Rojo (Cloud Peak(formerly Rio Tinto))

Belle Ayr (Alpha)Caballo (Peabody)Black Thunder (Arch)

Hartland Fuel ProductsSapp Bros. Petroleum Inc.

George Neal South

7343

Amount received,

dry basis, short

tons

ID # of boiler(s)

firing fuel

Fuel source Fuel shipment

method

Fuel supplier Other

Name Address Name Address

Cordero Rojo (Cloud Peak) P.O. Box 1449, Gillette, WY 82717 N/A N/A

Notes:For coal sample concentrations that were below the detection

thresholds, 1/2 the threshold value was input. The (<) sign

indicates that the average is below the threshold.

For oil sample concentration values, no formal analysis was

provided to MEC. The entry is based on billing documents for

the oil indicating Ultra Low Sulfur Diesel Fuel was purchased.

N/A

N/A N/A

N/A N/A

N/A N/A

N/A

5/26/2010 ‐ Page 5
MidAmerican Energy Company

EGU‐ICR ResponseGeorge Neal South

6 Name and address of laboratory performing analyses:

7 In addition to the analyses required in Part II, question 3 above, for samples for

which analyses of chlorine and/or any of the HAP metals were conducted,

please provide copies of any analyses conducted over the preceding 12 calendar

months for (a) complete proximate and ultimate analyses, (b) additional trace

metals, and (c) the mineralogy of the ash that are readily available for the oil(s)

or coal(s) listed in Part II, question 2 above. The Agency is requesting these data

only as they may already be available; no additional sampling or analyses are

required to provide these data.

None available

Emission Data

8a What emission test report(s), parametric monitoring data, and other data or

monitoring are available for the boilers noted in Part I, question 15, for tests

conducted since January 1, 2005. Please consider reports prepared for all

testing and monitoring programs, for all pollutants, including (but not limited

to) those required under Title V, compliance with State or local requirements,

fulfillment of contractual obligations, U.S. Department of Energy (DOE)

programs, etc. (NOTE: EPA is not requesting copies of the test reports or data at

this time; however we may request actual copies in the future.) Use additional

pages as necessary.

8b Please indicate the date(s) and types (e.g., stack, fuel, parametric, etc.) of the

test(s) and the constituents (including criteria and hazardous air pollutants)

sampled for. Date Type

Blr ID

7/18/2006 stack 49/23/2008 stack 41/12/2010 stack 42/22/2006 stack 4

8c Do any of these test reports reflect testing at a location before any emission

control devices? Yes X NoIf yes, please note which reports and provide a detailed description of the

location of the emissions sampling point(s).

8d Were any of these test reports conducted when use of other material(s) or non‐

fossil fuels were fired in the boiler? Yes X No

If yes, please note which reports and identify the other material(s) or non‐fossil

fuels used.

8e Do any of these test reports reflect testing during periods of startup, shutdown,

and malfunction? Yes X No

If yes, please note which reports.

8f Did the unit’s control configuration differ from that shown in Part I, question 16,

at the time of these test results? Yes X No

If yes, please list the unit’s complete control configuration at time of testing in a

similar format to Part I, question 16.

8g Do any of these test reports reflect testing at a location before a post

combustion SO2 emission control device (e.g., FGD, SDA, Dry Scrubber)?

Yes X No

If yes, please note which reports and, in addition to the detailed description of

the location of the sampling point(s) (question 8c above), include detail about

how much, if any, bypass of unscrubbed flue gas was utilized at the time of

testing (including percentage of total scrubber flue gas flow). Note by diagram

where sampling ports were located in relation to the bypass ductwork.

Mine

Name Address

Standard Lab's Cordero Lab P.O. Box 1449, Gillette, WY 82717 Cordero Rojo (Cloud Peak)

SGS Lab 2804 Hackathorne Lane, Gillette, WY 82716 Belle Ayr (Alpha Natural Resources)

Laboratory Performing Analyses

Caballo (Peabody Energy)

Particulate Matter (PM) and CO compliance stack test; lead stack test

particulate matterparticulate matter

lead

carbon monoxide

SGS Lab 2804 Hackathorne Lane, Gillette, WY 82716

Constituents

N/AStandard Lab's Black Thunder Lab P.O. Box 406, Wright, WY 82732

Standard Lab's Black Thunder Lab P.O. Box 406, Wright, WY 82732 Jacobs Ranch (Arch Coal)

Black Thunder (Arch Coal)

5/26/2010 ‐ Page 6
MidAmerican Energy Company

EGU‐ICR ResponseGeorge Neal South

9 What type of deviation reporting is required for violations of permit

requirements?

10 Are deviation reports available for malfunctions or other periods of

noncompliance with permit terms and conditions? X Yes No

If yes, please note which reports.

11 Are continuous emissions monitoring system (CEMS) data available (e.g.,

mercury, continuous opacity monitoring systems) that are not already being

provided to the U.S. EPA, even if from short‐term testing?

X Yes No

If yes, please note for which pollutants CEMS data are available and the period

of time (both total period and calendar period) for which data are available. If

CEM data are being provided to EPA, please note to which Office the data are

being provided.

12 For each boiler noted in Part I, question 15, provide the following

information:

Boiler ID Date of test PM SO2 HCl/HF/HCN Metal HAP Hg CO

Other

organics

(specify) Gross MW 

4 2/22/2006 N/A N/A N/A N/A N/A 196.3 lb/hr, 0.032

lb/mmBtu (5 hr)

N/A 654 

4 7/18/2006 41.76 lb/hr filterable;

99.05 lb/hr filterable &

condensable (average of

3 test runs)

N/A N/A N/A N/A N/A N/A 641 

4 9/23/2008 124.81 lb/hr filterable;

182.96 lb/hr filterable &

condensable (average of

3 test runs)

N/A N/A N/A N/A N/A N/A 664 

4 1/12/2010 N/A N/A N/A Lead 3.63E‐

006 lb/mmBtu

(average of 3

test runs)

N/A N/A N/A 653 

Same as Question 9 (malfunctions included only if the malfunction caused a

violation of a permit condition or emission limit)

CO data (2/22/2006‐ present); continuous opacity monitoring system data

(01/01/2005 ‐ present), CEMS Acid Rain data provided to EPA Acid Rain Division

Emissions test results (indicate format of emission data)

All emission limit deviations are reported in quarterly emission reports, and in

Title V semi‐annual monitoring reports and annual compliance certification

reports submitted to the state agency. Additionally, most emission deviationsare also orally reported to the state agency within eight hours or at the start of

the next working day following the onset of the incident. A follow‐up written

report is requried for each orally reported deviation. Some opacity deviations of

short duration and of low magnitude of deviation are not required to be

reported outside of the quarterly emission report.

5/26/2010 ‐ Page 7



MidAmerican Energy Company

EGU‐ICR ResponseRiverside Generating Station

PART I: GENERAL FACILITY INFORMATION

Process InformationNOTE: If any rank of coal or any grade of oil (including petroleum coke [pet

coke]), in any amount, is fired, complete Parts I and II and return to the

address noted earlier. If NO coal or oil is fired, complete only Part I and return

to the address noted earlier.

Blr ID 9

1 Name of legal owner of facility:

2 Name of legal operator of facility, if different from legal owner:

3 Address of legal owner or operator:

4a Plant Name (as reported on U.S. DOE/EIA Form‐860 (2007), “Annual Electric

Generator Report,” schedule 2, line 1, page 37, question 1) OR Plant Name (as

reported on U.S. DOE/EIA Form EIA‐923 (2008), “Power Plant Operations

Report,” schedule 2, page 1, question 1):

4b EIA Plant Code (as reported on U.S. DOE/EIA Form‐860 (2007), schedule 2, line

1, page 37, question 2) OR Plant ID (as reported on U.S. DOE/EIA Form EIA‐923

(2008), schedule 2, page 1, question 2):

5 Complete street address of facility (physical location):

6 Provide mailing address if different:

7 Name and title of contact(s) able to answer technical questions about the

completed survey:

8 Contact(s) telephone number(s):

and e‐mail address(es):

9 Is this facility considered to be owned or operated by a small entity as defined

by the Regulatory Flexibility Act? Yes X No Don’t know

10 Which of the following fossil fuels or other material(s) are fired in any steam

generating unit at this facility? X coal

oil (including pet

coke) X natural gas

other (specify in question 14 below)

11 Which of the following fossil fuels or other material(s) are permitted to be

fired in any steam generating unit at this facility? X coal

oil (including pet

coke) X natural gas

X other (specify in question 14 below)

12 If coal or solid fuel, as described below, derived from a fossil source is fired,

indicate which rank of coal or solid fuel was utilized during the previous 12

months prior to the receipt of this ICR:

Fired In

Previous 12

Months %

lignite

X 100 subbituminous

bituminousanthracitecoal refuse (including gob, culm, and subbituminous‐derived coal refuse)synfuel (including, but not limited to, briquettes, pellets, or extrusions which areformed by binding materials, or processes that recycle materials)(please specify the type or form of synfuel used)

petroleum coke

13 If oil is fired, indicate which type of oil was utilized during the previous 12

months prior to the receipt of this ICR:

Fired In

Previous 12

Months %

N/A distillate

residual or bunker C

other (specify)

6001 State StreetBettendorf, IA 52722

MidAmerican Energy Company

MidAmerican Energy CompanyPO Box 657Des Moines, IA 50306‐0657

Riverside1081N/ADave Webb, Chemist

563‐333‐8501; dawebb@midamerican.com

5/26/2010 ‐ Page 1
MidAmerican Energy Company

EGU‐ICR ResponseRiverside Generating Station

14a If “other” was checked in questions 10 or 11 above indicating that any non‐

fossil fuel or other material (including, but not limited to, plastics, treated

wood, rubber belting or gaskets, whole tires, tire‐derived fuel, boiler cleaning

solutions, animal wastes, etc.) is either utilized or permitted to be used, please

indicate below what materials are combusted in the boiler and in what

quantities (specify whether this quantity is on a weight percentage or heat

[Btu] basis). Also indicate (yes/no) whether you are permitted to burn non‐

fossil fuel(s) or other material(s) even if you do not actually burn them.

Other Material

Permitted to

burn

YES/NO

Actually burn

YES/NO Quantity/year

used oil yes no 0

14b If “other” was checked in questions 10 or 11 above indicating that any non‐

fossil fuel or other material (including, but not limited to, plastics, treated

wood, rubber belting or gaskets, whole tires, tire‐derived fuel, boiler cleaning

solutions, animal wastes, etc.) is either utilized or permitted to be used, were

such material to be classified as “solid waste” under the Resource

Conservation and Recovery Act and, thus, make the utilizing unit subject to

CAA section 129, would you continue to utilize (i.e., use as a fuel) the

material?

Yes X No

Explain:

15 Identification (or designation) of all coal‐ and oil‐fired steam generating units

(boilers) (as defined by Clean Air Act section 112(a)(8)) located at this facility.

Boiler ID

Original design

fuel (i.e. coal

rank or type of

oil)

Design heat input,

(MMBtu)

Present

maximum heat

input, (MMBtu) MWe Gross capacity

MWe Net

capacity

Original

design gross

efficiency (%,

HHV)

Present

operating

gross

efficiency

(%, HHV)

Design

steam

pressure

(psig)

Operating

steam

pressure

(psig)

9 bituminous

coal/ natural

gas

coal/gas 1202/1232 1202 139.493 130 87.44/85.22 86.6 1850 1800 

Emission Control Technology

16 For each boiler noted in Part I, question 15, provide the following

information for each current emission control device installed and

operating and/or planned (please designate the order of the emission

controls – 1 for first control following the boiler, 2 for second control

following the boiler, etc.): Boiler ID Type NOx control SO2 control PM control Other control

9 Pulverized coal,

tangential‐fired,

dry bottom

1‐Low‐Nox burners/ over‐

fire air (11/12/1993)

N/A 2‐Cold‐side

electrostatic

precipitator

(11/28/1972), with

SO3 injection flue

gas conditioning

(03/20/1995)

N/A

17 For each boiler noted in Part I, question 15, provide the company

(prime vendor) name and company contact information for each HAP‐

specific (e.g., mercury, hydrogen chloride) control technology that you

have either contracted for, are installing, or have installed for the

purpose of participating in a control technology demonstration project

(e.g., U.S. Department of Energy program, consent decree, etc.).

Boiler ID Telephone

9

Company (vendor) contact information

Company (vendor) Name Address

N/A

Current practice is not to combust any waste materials in the boiler.

5/26/2010 ‐ Page 2
MidAmerican Energy Company

EGU‐ICR ResponseRiverside Generating Station

18 For the control technologies identified in Part I, question 17, provide the

date of actual start‐up of the demonstration (if the control is currently

operating), the date of expected or projected start‐up, the date the

demonstration was completed, the type of HAP control installed (e.g.,

sorbent and type; pre‐combustion boiler chemical additive; combustion

boiler chemical additive), the desired HAP emission reduction or rate (if

any), and the coal rank(s) upon which the demonstration was

conducted. Please specify the format of the target HAP emission

reduction or rate (e.g., lb/MWh, lb/TBtu, percent reduction, etc.). If the

format of the target end‐point is percent reduction, provide (1) an

estimate of what an equivalent emission rate would be (and specify the

format of the equivalent emission rate), and (2) the basis for calculating

the percent reduction (i.e., where the “inlet” and “outlet” are).

Boiler ID

Demonstration

activity actual

start‐up date

Demonstration activity

projected start‐up date

Demonstration

activity end‐

date or

projected end‐

date

Type of control (e.g.,

sorbent and type;

chemical additive)

Desired HAP

emission

reduction (%)

or emission

rate

Coal rank(s)

in use

N/A

19 For each boiler noted in Part I, question 15, provide the company (prime

vendor) name and company contact information for each HAP (e.g., mercury,

hydrogen chloride) control technology that you have either contracted for, are

installing, or have installed for the purpose of providing a non‐demonstration,

full‐scale operating system.

Boiler ID Telephone

N/A

20 For the control technologies identified in Part I, question 19, provide the

date of actual start‐up (if the control is currently operating), the date of

expected or projected start‐up, the type of HAP control installed (e.g.,

sorbent and type; pre‐combustion boiler chemical additive; combustion

boiler chemical additive), the guaranteed HAP emission reduction or

emission rate, the sorbent feed rate upon which the guarantee is based,

and the coal rank(s) upon which the guarantee is based. Please specify

the format of the guarantee (e.g., lb/MWh, lb/TBtu, percent reduction,

etc.). If the format of the guarantee is percent reduction, provide (1) an

estimate of what an equivalent emission rate would be (and specify the

format of the equivalent emission rate), and (2) the basis for calculating

the percent reduction (i.e., where the “inlet” and “outlet” are).

Boiler ID

Actual start‐up

date

Expected or projected

start‐up date

Type of control

(e.g., sorbent

and type;

chemical

additive)

Guaranteed HAP

emission reduction

(%) or emission rate

Sorbent or

additive feed

rate on which

guarantee is

based

Coal rank(s)

upon which

guarantee is

based

N/A

21 For each boiler noted in Part I, question 15, provide the following information:

Boiler ID PM PM10 PM2.5 SO2 HCl and/or HF HCN Metal HAP Hg CO

9 Construction

permit; average

3 test runs 0.39

lbs/mmBtu;

Method 5 with

Method 202

N/A N/A Construction permit;

3 hour rolling

average 1.2

lbs/mmBtu

N/A N/A N/A N/A N/A 

22 For each boiler noted in Part I, question 15, provide the following information:

Boiler ID PM PM10 PM2.5 SO2 HCl and/or HF HCN Metal HAP Hg CO

9 N/A N/A N/A N/A N/A N/A N/A N/A N/A 

23 Was any other guarantee level sought or offered? Yes X No

Permitted emission limit (indicate type of permit and format of emission limit)

Most recent guaranteed emission rate for each pollutant for which there is a permitted emission limit

Company (vendor) contact information

Company (vendor) Name Address

5/26/2010 ‐ Page 3
MidAmerican Energy Company

EGU‐ICR ResponseRiverside Generating Station

Please elaborate

5/26/2010 ‐ Page 4
MidAmerican Energy Company

EGU‐ICR ResponseRiverside Generating Station

24 For each boiler noted in Part I, question 15, provide the following information:

Boiler ID PM PM10 PM2.5 SO2 HCl and/or HF HCN Metal HAP Hg CO

9 Filterable &

condensiblestack test, stack

test reports,opacitymonitoring,quarterlyopacity reports,

semi‐annual

monitoringreport, annual

compliancecertification,annualemissionssummary,records kept for

five years

N/A N/A CEM's, quarterly

emission reports,

excess emissionreports, semi‐annual

monitoring report,annual compliance

certification, annualemissions summary,

records kept for five

years

N/A N/A N/A N/A N/A 

25 For the control technologies identified in Part I, questions 17 and 19,

provide the cost information requested.

Facility Name/Unit No.:

Total Capital

Investment: $

OperatingCosts: $

N/A Yes /No Yes /No (Include base year for operating costs 

Yes /No Yes /No (Include base year for operating costs 

26 Are any other means of emission control (for any pollutant) employed on any

boiler noted in Part I, question 15 (e.g., low‐ash coal, coal or oil with low trace

constituents, etc.)? Please specify.

Low‐ash coal for PM control; low‐sulfur coal for SO2 control.

Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a permitted emission limit

Retrofit to existing boiler? Installation on new boiler?

5/26/2010 ‐ Page 5
MidAmerican Energy Company

EGU‐ICR ResponseRiverside Generating Station

PART II: FUEL ANALYSIS AND EMISSION DATA

Fuel AnalysisEach facility should provide the following information for each coal and oil

shipment received during the preceding 12 calendar months.

1a Plant or facility name from Part I, question 4a:

1b Plant or facility code from Part I, question 4b:

2 For each individual coal and oil shipment received during the preceding 12

calendar months, provide the following information, as available (indicate N/A

if not available; use addit ional pages, as necessary):

State/Country County Coal seam

10,445 9 Wyoming/United States Campbell Wyodak Rail11,115 9 Wyoming/United States Campbell Smith Rail

319,721 9 Wyoming/United States Campbell Wyodak‐Anderson Rail

3 For each individual coal and oil shipment received during the preceding

12 calendar months, provide the following information, as available (dry

basis) (indicate N/A if not available):

Sample ID #

Total amount

of fuel

represented by

sample, tons or

gallons Total sulfur, % Ash content, %

Higher heating value,

Btu/lb (dry basis)

Mercury, ppm

(dry basis)

Chlorine,

ppm (dry

basis)

Fluorine,

ppm (dry

basis)

Nickel,

ppm (dry

basis)

Other trace

metal HAP,

ppm

Belle Ayr 10,445 0.38 6.43 12128 0.08 <50* 52.82 2.88 31.87 

Caballo 11,115 0.48 7.3 12074 0.11 <10* 61 5 22.2 

Black Thunder 319,721 0.41 7.16 12117 0.08 10 50.65 5 23.49 

4 Were the data provided in Part II, question 3 above, acquired pursuant to:

permit requirements

X contractual obligations

standard operational procedures

other (please specify )

5 Analyses provided in Part II, question 3 above, supplied by

6 Name and address of laboratory performing analyses:7 In addition to the analyses required in Part II, question 3 above, for samples

for which analyses of chlorine and/or any of the HAP metals were conducted,

please provide copies of any analyses conducted over the preceding 12

calendar months for (a) complete proximate and ultimate analyses, (b)

additional trace metals, and (c) the mineralogy of the ash that are readily

available for the oil(s) or coal(s) listed in Part II, question 2 above. The Agency

is requesting these data only as they may already be available; no additional

sampling or analyses are required to provide these data.

None available

Black Thunder (Arch Coal)

Caballo (Peabody)Black Thunder (Arch)

Address Name Address

Notes:For coal sample concentrations that were below the detection thresholds, 1/2 the threshold value was input. The (<) sign indicates

that the average is below the threshold.

Caballo (Peabody Energy) Caller Box 3041, Gillette, WY 82717 N/A N/A

Caballo (Peabody Energy)

Belle Ayr (Alpha Natural Resources)

Laboratory Performing Analyses Mine

Name Address

SGS Lab 2804 Hackathorne Lane, Gillette, WY 82716

SGS Lab 2804 Hackathorne Lane, Gillette, WY 82716

Standard Lab's Black Thunder Lab P.O. Box 406, Wright, WY 82732 Black Thunder (Arch Coal)

Mine

P.O. Box 406, Wright, WY 82732 N/A N/A

Belle Ayr (Alpha Natural P.O. Box 3039, Gillette, WY 82717 N/A N/A

Fuel supplier Other

Name

Belle Ayr (Alpha)

1081

Amount

received, dry

basis, short tons

ID # of boiler(s)

firing fuel

Fuel source Fuel shipment

method

Riverside

5/26/2010 ‐ Page 6
MidAmerican Energy Company

EGU‐ICR ResponseRiverside Generating Station

Emission Data

8a What emission test report(s), parametric monitoring data, and other data or

monitoring are available for the boilers noted in Part I, question 15, for tests

conducted since January 1, 2005. Please consider reports prepared for all

testing and monitoring programs, for all pollutants, including (but not limited

to) those required under Title V, compliance with State or local requirements,

fulfillment of contractual obligations, U.S. Department of Energy (DOE)

programs, etc. (NOTE: EPA is not requesting copies of the test reports or data

at this time; however we may request actual copies in the future.) Use

additional pages as necessary.

8b Please indicate the date(s) and types (e.g., stack, fuel, parametric, etc.) of the

test(s) and the constituents (including criteria and hazardous air pollutants)

sampled for. Date Type

N/A N/A N/A N/AN/A N/A N/A N/A

8c Do any of these test reports reflect testing at a location before any emission

control devices? Yes X NoIf yes, please note which reports and provide a detailed description of the

location of the emissions sampling point(s).

8d Were any of these test reports conducted when use of other material(s) or

non‐fossil fuels were fired in the boiler? Yes X No

If yes, please note which reports and identify the other material(s) or non‐

fossil fuels used.

8e Do any of these test reports reflect testing during periods of startup,

shutdown, and malfunction? Yes X NoIf yes, please note which reports.

8f Did the unit’s control configuration differ from that shown in Part I, question

16, at the time of these test results? Yes X No

If yes, please list the unit’s complete control configuration at time of testing in

a similar format to Part I, question 16.

8g Do any of these test reports reflect testing at a location before a post

combustion SO2 emission control device (e.g., FGD, SDA, Dry Scrubber)?

Yes X No

If yes, please note which reports and, in addition to the detailed description of

the location of the sampling point(s) (question 8c above), include detail about

how much, if any, bypass of unscrubbed flue gas was utilized at the time of

testing (including percentage of total scrubber flue gas flow). Note by diagram

where sampling ports were located in relation to the bypass ductwork.

9 What type of deviation reporting is required for violations of permit

requirements?

All emission limit deviations are reported in quarterly emission reports, and in

Title V semi‐annual monitoring reports and annual compliance certification

reports submitted to the state agency. Additionally, most emission deviations

are also orally reported to the state agency within eight hours or at the start of

the next working day following the onset of the incident. A follow‐up written

report is requried for each orally reported deviation. Some opacity deviations of

short duration and of low magnitude of deviation are not required to be

reported outside of the quarterly emission report.

Constituents

N/ANo individual EGU boiler tests available; compliance tests completed on

common stack with non EGU boilers operating.

5/26/2010 ‐ Page 7
MidAmerican Energy Company

EGU‐ICR ResponseRiverside Generating Station

10 Are deviation reports available for malfunctions or other periods of

noncompliance with permit terms and conditions? X Yes No

If yes, please note which reports.

11 Are continuous emissions monitoring system (CEMS) data available (e.g.,

mercury, continuous opacity monitoring systems) that are not already being

provided to the U.S. EPA, even if from short‐term testing? X Yes No

If yes, please note for which pollutants CEMS data are available and the period

of time (both total period and calendar period) for which data are available. If

CEM data are being provided to EPA, please note to which Office the data are

being provided.

12 For each boiler noted in Part I, question 15, provide the following

information:

Boiler ID Date of test PM SO2 HCl/HF/HCN Metal HAP Hg CO

Other

organics

(specify)

N/A N/A N/A N/A N/A N/A N/A N/A N/A

Same as Question 9 (malfunctions included only if the malfunction caused a

violation of a permit condition or emission limit)

continuous opacity monitoring system data (01/01/2005 ‐ present), CEMS Acid

Rain data provided to EPA Acid Rain Division

Emissions test results (indicate format of emission data)

5/26/2010 ‐ Page 8


MidAmerican Energy Company

EGU‐ICR ResponseWalter Scott Energy Center

PART I: GENERAL FACILITY INFORMATION

Process Information

NOTE: If any rank of coal or any grade of oil (including petroleum coke [pet

coke]), in any amount, is fired, complete Parts I and II and return to the

address noted earlier. If NO coal or oil is fired, complete only Part I and return

to the address noted earlier.

Blr ID 1 Blr ID 2 Blr ID 3 Blr ID 4

1 Name of legal owner of facility: MidAmerican Energy

Company

MidAmerican Energy Company

2 Name of legal operator of facility, if different from legal owner:

3 Address of legal owner or operator:

4a Plant Name (as reported on U.S. DOE/EIA Form‐860 (2007), “Annual Electric

Generator Report,” schedule 2, line 1, page 37, question 1) OR Plant Name (as

reported on U.S. DOE/EIA Form EIA‐923 (2008), “Power Plant Operations

Report,” schedule 2, page 1, question 1):

4b EIA Plant Code (as reported on U.S. DOE/EIA Form‐860 (2007), schedule 2,

line 1, page 37, question 2) OR Plant ID (as reported on U.S. DOE/EIA Form

EIA‐923 (2008), schedule 2, page 1, question 2):

5 Complete street address of facility (physical location):

6 Provide mailing address if different:

7 Name and title of contact(s) able to answer technical questions about the

completed survey:

8 Contact(s) telephone number(s):

and e‐mail address(es):

9 Is this facility considered to be owned or operated by a small entity as defined

by the Regulatory Flexibility Act? Yes X No Don’t know

10 Which of the following fossil fuels or other material(s) are fired in any steam

generating unit at this facility? X coal X oil (including pet coke) X natural gas

other (specify in question 14 below)

11 Which of the following fossil fuels or other material(s) are permitted to be

fired in any steam generating unit at this facility? X coal X oil (including pet coke) X natural gas

X other (specify in question 14 below)

12 If coal or solid fuel, as described below, derived from a fossil source is fired,

indicate which rank of coal or solid fuel was utilized during the previous 12

months prior to the receipt of this ICR:

Fired In Previous 12

Months %

lignite

X 100 subbituminous

bituminousanthracitecoal refuse (including gob, culm, and subbituminous‐derived coal refuse)

synfuel (including, but not limited to, briquettes, pellets, or extrusions which are

formed by binding materials, or processes that recycle materials)

(please specify the type or form of synfuel used)

petroleum coke

13 If oil is fired, indicate which type of oil was utilized during the previous 12

months prior to the receipt of this ICR:

Fired In Previous 12

Months %

X 100 distillate

residual or bunker C

other (specify)

14a If “other” was checked in questions 10 or 11 above indicating that any non‐

fossil fuel or other material (including, but not limited to, plastics, treated

wood, rubber belting or gaskets, whole tires, tire‐derived fuel, boiler cleaning

solutions, animal wastes, etc.) is either utilized or permitted to be used,

please indicate below what materials are combusted in the boiler and in what

quantities (specify whether this quantity is on a weight percentage or heat

[Btu] basis). Also indicate (yes/no) whether you are permitted to burn non‐

fossil fuel(s) or other material(s) even if you do not actually burn them.

Other Material

Permitted to burn

YES/NO

Actually burn

YES/NO Quantity/year

Used Oil yes no

Used

Ethylene/Propylene

Glycol yes no

14b If “other” was checked in questions 10 or 11 above indicating that any non‐

fossil fuel or other material (including, but not limited to, plastics, treated

wood, rubber belting or gaskets, whole tires, tire‐derived fuel, boiler cleaning

solutions, animal wastes, etc.) is either utilized or permitted to be used, were

such material to be classified as “solid waste” under the Resource

Conservation and Recovery Act and, thus, make the utilizing unit subject to

CAA section 129, would you continue to utilize (i.e., use as a fuel) the

material? Yes X No

Explain:

15 Identification (or designation) of all coal‐ and oil‐fired steam generating units

(boilers) (as defined by Clean Air Act section 112(a)(8)) located at this facility.

Boiler ID

Original design fuel (i.e. coal rank or

type of oil) Design heat input, (MMBtu)

Present maximum heat

input, (MMBtu) MWe Gross capacity summer MWe Net capacity summer

Original design gross

efficiency (%, HHV)

Present operating

gross efficiency (%,

HHV)

Design steam

pressure (psig)

Operating st

pressure (p

1 Bituminous coal 530 656 45 42 88.7 85.0 1250 1250 

MidAmerican Energy Company; Atlantic Municipal Utilities; Cedar Falls

Utilities; Central Iowa Power Cooperative; Corn Belt Power Cooperative

MidAmerican Energy Company; Alta Municipal Utilities; Cedar Falls Utilities; Central Iowa Power

Cooperative; Corn Belt Power Cooperative; Eldridge Electric and Water Utilities; Lincoln Electric System;

Montezuma Municipal Light & Power; Municipal Energy Agency of Nebraska; New Hampton Light Plant;

Pella Municipal Light and Power; Spencer Municipal Utilities; Sumner Municipal Light Plant; Waverly Light

& Power; West Bend Municipal Utilities

Mark B. Podany, Manager‐Environmental & Regulatory Compliance

(712) 366‐5363; mbpodany@midamerican.com

Current practice is not to combust any waste materials in the boiler.

MidAmerican Energy CompanyPO Box 657Des Moines, IA 50306‐0657

Walter Scott Jr. Energy Center

10827215 Navajo StreetCouncil Bluffs, IA 51501

5/26/2010 ‐ Page 1 Page 1
MidAmerican Energy Company

EGU‐ICR ResponseWalter Scott Energy Center

2 Bituminous coal 840 935 94 88 89.2 85.0 1450 1450 

3 Subbituminous coal 6970 7700 765 720 84.0 85.5 2400 2400 

4 Subbituminous coal 7395 7675 850 800 86.5 86.0 3690 3690 

Emission Control Technology

16 For each boiler noted in Part I, question 15, provide the following

information for each current emission control device installed and

operating and/or planned (please designate the order of the emission

controls – 1 for first control following the boiler, 2 for second control

following the boiler, etc.):

Boiler ID Type NOx control SO2 control PM control Other control

1 Pulverized coal, wall‐fired, dry

bottom 1‐Low‐NOx Burners (11/14/2005) None 2‐Hot‐side ESP (12/1973)

2 Pulverized coal, tangential‐fired, dry

bottom

1‐Low‐NOx Burners with Overfire Air

(5/21/2008) None 2‐Hot‐side ESP (11/1973)

3 Pulverized coal, wall‐fired, dry

bottom

1‐Low‐NOx Burners with Overfire Air

(10/18/2006)

2‐Dry scrubber lime based

(5/15/2009)

3‐Pulse Jet Fabric filter (5/15/2009)

4 Pulverized coal, wall‐fired, dry

bottom

1‐Low‐NOx Burners with Overfire Air; Selective

Catalytic Reduction, Catalyst is titanium

dioxide 50‐90% and molybdenum trioxide 1‐

20%, reductant is urea; (2/1/2007)

3‐Dry scrubber lime based

(2/1/2007)

4‐Pulse Jet Fabric filter (2/1/2007) 2‐Activated Carbon Injection (Hg

control) (2/1/2007)

17 For each boiler noted in Part I, question 15, provide the company

(prime vendor) name and company contact information for each HAP‐

specific (e.g., mercury, hydrogen chloride) control technology that you

have either contracted for, are installing, or have installed for the

purpose of participating in a control technology demonstration project

(e.g., U.S. Department of Energy program, consent decree, etc.).

Boiler ID Telephone

1234

18 For the control technologies identified in Part I, question 17, provide the

date of actual start‐up of the demonstration (if the control is currently

operating), the date of expected or projected start‐up, the date the

demonstration was completed, the type of HAP control installed (e.g.,

sorbent and type; pre‐combustion boiler chemical additive; combustion

boiler chemical additive), the desired HAP emission reduction or rate (if

any), and the coal rank(s) upon which the demonstration was

conducted. Please specify the format of the target HAP emission

reduction or rate (e.g., lb/MWh, lb/TBtu, percent reduction, etc.). If the

format of the target end‐point is percent reduction, provide (1) an

estimate of what an equivalent emission rate would be (and specify the

format of the equivalent emission rate), and (2) the basis for calculating

the percent reduction (i.e., where the “inlet” and “outlet” are).

Boiler ID

Demonstration activity actual start‐

up date

Demonstration activity projected start‐up

date

Demonstration activity end‐

date or projected end‐date

Type of control (e.g., sorbent and type;

chemical additive)

Desired HAP emission reduction

(%) or emission rate Coal rank(s) in use

1 N/A2 N/A3 N/A4 N/A

19 For each boiler noted in Part I, question 15, provide the company (prime

vendor) name and company contact information for each HAP (e.g., mercury,

hydrogen chloride) control technology that you have either contracted for,

are installing, or have installed for the purpose of providing a non‐

demonstration, full‐scale operating system.

Boiler ID Telephone

123 (865) 670‐4474

4 (330) 860‐2522

20 For the control technologies identified in Part I, question 19, provide the

date of actual start‐up (if the control is currently operating), the date of

expected or projected start‐up, the type of HAP control installed (e.g.,

sorbent and type; pre‐combustion boiler chemical additive; combustion

boiler chemical additive), the guaranteed HAP emission reduction or

emission rate, the sorbent feed rate upon which the guarantee is based,

and the coal rank(s) upon which the guarantee is based. Please specify

the format of the guarantee (e.g., lb/MWh, lb/TBtu, percent reduction,etc.). If the format of the guarantee is percent reduction, provide (1) an

estimate of what an equivalent emission rate would be (and specify the

format of the equivalent emission rate), and (2) the basis for calculating

the percent reduction (i.e., where the “inlet” and “outlet” are).

Boiler ID Actual start‐up date Expected or projected start‐up date Type of control (e.g.,

sorbent and type; chemical

additive)

Guaranteed HAP emission reduction (%)

or emission rate

Sorbent or additive feed rate on

which guarantee is based

Coal rank(s) upon which

guarantee is based

3 5/15/2009 N/A Lime sorbent injected in

scrubber module

CBI CBI CBI

4 2/1/2007 N/A Brominated powdered

activated carbon injection

post‐combustion ‐ injected

in flue gas stream after the

air heater and prior to the

scrubber

None N/A Subbituminous

21 For each boiler noted in Part I, question 15, provide the following

information:

Boiler ID PM PM10 PM2.5 SO2 HCl and/or HF HCN Metal HAP Hg CO

1 Construction Permit; filterable &

condensible 0.49 lb/MMBtu;

Methods 5 with 202, average of 3

test runs

Construction Permit; 229.6 lb/hr; Method 201A

with 202, average of 3 test runs

N/A Construction Permit; 787.2 lb/hr 3‐hr

average, 5.0 lb/MMBtu 3‐hr average

N/A N/A N/A N/A Construction P

1206.8 tons/yr 

month rolling 

Permitted emission limit (indicate type of permit and format of emission limit)

N/A

Company (vendor) contact information

Company (vendor) Name Address

N/AN/AN/A

Company (vendor) contact information

Company (vendor) Name Address

Alstom Power Inc. Bill Dousis 1409 Centerpoint Blvd., Knoxville, TN 37932

Babcock and Wilcox Company Thomas Becker 20 South Van Buren Ave., P.O. Box 351, Barberton, Ohio 44203‐0351

N/AN/A

5/26/2010 ‐ Page 2 Page 2
MidAmerican Energy Company

EGU‐ICR ResponseWalter Scott Energy Center

2 Construction Permit; filterable &

condensible 0.49 lb/MMBtu;

Methods 5 with 202, average of 3

test runs

Construction Permit; 327.25 lb/hr; Method

201A with 202, average of 3 test runs

N/A Construction Permit; 1122.0 lb/hr 3‐hr

average, 1.2lb/MMBtu 3‐hr average

N/A N/A N/A N/A Construction P

1524.0 lb/hr 

average, 0.54 lb

30‐day rolling 

3 Construction Permit; 911 tons/yr on

a 12‐month rolling total; filterable &

condensible 0.027 lb/MMBtu;

Method 5 with 202, average of 3 test

runs

Construction Permit; 911 tons/yr on a 12‐

month rolling total; 0.027 lb/MMBtu, 207.9

lb/hr; Method 201A with 202, average of 3 test

runs

N/A Construction Permit; 3,080 lb/hr 30‐day

rolling average, 13,490 tons/yr 12‐month

rolling total, 0.4 lb/MMBtu 30‐day rolling

average, 1.20 lb/MMBtu 3‐hr average

N/A N/A N/A N/A Construction P

14,165 tons/yr 

month rolling to

lb/MMBtu calen

average, 3,23

calendar‐d

4 Construction Permit; filterable &

condensible 0.027 lb/MMBtu;

Method 5 with 202, average of 3 test

runs

Construction Permit; 0.025 lb/MMBtu, 191.9

lb/hr; Method 201A with 202, average of 3 test

runs

N/A Construction Permit; 3,362 tons/yr 12‐

month rolling total, 0.1 lb/MMBtu 30‐day

rolling average, 1.20 lb/MMBtu+reduction

30‐day rolling average, 767.5 lb/hr 3‐hr

average

Construction Permit; 0.0009

lb/MMBtu for total flourides;

Method 13A, average of 3 test

runs

N/A Construction Permit;

Pb: 0.000026

lb/MMBtu, Pb 0.20

lb/hr; Method 12,

average of 3 test runs

N/A Construction P

5,177 tons/yr o

month rolling 

0.154 lb/MMB

calendar‐day a

1,182 lb/hr 1

average

22 For each boiler noted in Part I, question 15, provide the following

information:

Boiler ID PM PM10 PM2.5 SO2 HCl and/or HF HCN Metal HAP Hg CO

1 N/A N/A N/A N/A N/A N/A N/A N/A CBI 2 N/A N/A N/A N/A N/A N/A N/A N/A CBI 3 CBI CBI N/A CBI CBI N/A CBI N/A CBI 4 CBI CBI N/A CBI N/A N/A N/A N/A CBI 

23 Was any other guarantee level sought or offered? Yes X No

Please elaborate

24 For each boiler noted in Part I, question 15, provide the following

information:

Boiler ID PM PM10 PM2.5 SO2 HCl and/or HF HCN Metal HAP Hg CO

1 Filterable & condensible stack test,

stack test reports, opacity

monitoring, quarterly opacity

reports, semi‐annual monitoring

report, annual compliancecertification, annual emissionssummary, records kept for five years

Filterable & condensible stack test, stack test

reports, opacity monitoring, quarterly opacity

reports, semi‐annual monitoring report, annual

compliance certification, annual emissionssummary, records kept for five years

N/A CEM's, quarterly emission reports, excess

emission reports, semi‐annual monitoring

report, annual compliance certification,

annual emissions summary, records kept

for five years

N/A N/A N/A N/A Initial performa

data, CEM's, qu

emission reportemission reportannual monitor

report, annualcompliancecertification, anemissions summrecords kept for 

years

2 Filterable & condensible stack test,

stack test reports, opacitymonitoring, quarterly opacity

reports, semi‐annual monitoring

report, annual compliancecertification, annual emissionssummary, records kept for five years

Filterable & condensible stack test, stack test

reports, opacity monitoring, quarterly opacity

reports, semi‐annual monitoring report, annual

compliance certification, annual emissionssummary, records kept for five years

N/A CEM's, quarterly emission reports, excess

emission reports, semi‐annual monitoring

report, annual compliance certification,annual emissions summary, records kept

for five years

N/A N/A N/A N/A Initial performa

data, CEM's, qu

emission reportemission reportannual monitor

report, annualcompliancecertification, anemissions summrecords kept for 

years

3 Filterable only stack test, filterable &

condensible stack test, stack test

reports, opacity monitoring,

quarterly opacity reports, broken bag

detection, semi‐annual monitoring

report, annual compliancecertification, annual emissionssummary, records kept for five years

Filterable only stack test, filterable &

condensible stack test, stack test reports,

opacity monitoring, quarterly opacity reports,

broken bag detection, semi‐annual monitoring

report, annual compliance certification, annual

emissions summary, records kept for five years

N/A CEM's, quarterly emission reports, excess

emission reports, semi‐annual monitoring

report, annual compliance certification,annual emissions summary, records kept

for five years

N/A N/A N/A N/A Initial performa

data, CEM's, qu

emission reportemission report

annual monitor

report, annualcompliancecertification, anemissions summrecords kept for 

years

4 Filterable only stack test, filterable &

condensible stack test, stack test

reports, opacity monitoring,

quarterly opacity reports, broken bag

detection, semi‐annual monitoring

report, annual compliancecertification, annual emissionssummary, records kept for five years

Filterable only stack test, filterable &

condensible stack test, stack test reports,

opacity monitoring, quarterly opacity reports,

broken bag detection, semi‐annual monitoring

report, annual compliance certification, annual

emissions summary, records kept for five years

N/A Initial performance test, stack test reports,

percent reduction, optimization study,

CEM's, quarterly emission reports, excess

emission reports, semi‐annual monitoring

report, annual compliance certification,

annual emissions summary, records kept

for five years

Initial performance test, stack test

reports, annual compliance

certification, annual emissions

summary, records kept for five

years

N/A Initial performance

test, stack test

reports, annual

compliance

certification, annual

emissions summary,

records kept for five

years

N/A Initial performa

data, CEM's, qu

emission reportemission reportannual monitor

report, annual

compliancecertification, anemissions summrecords kept for 

years

25 For the control technologies identified in Part I, questions 17 and 19,

provide the cost information requested.

Facility Name/ Unit No.: Total Capital Investment: $

Total Annual Operating &

Maintenance Costs: $

WSEC 3 ‐ DFGD with

fabric filter Yes Yes /No No Yes /No

CBI CBI

2010 Dollars

WSEC 4 ‐ DFGD with

fabric filter No Yes /No Yes Yes /No

CBI CBI

2009 Dollars

WSEC 4 ‐ ACI No Yes /No Yes Yes /No CBI CBI 2009 Dollars

26 Are any other means of emission control (for any pollutant) employed on any

boiler noted in Part I, question 15 (e.g., low‐ash coal, coal or oil with low trace

constituents, etc.)? Please specify.

PART II: FUEL ANALYSIS AND EMISSION DATA

Fuel Analysis

Most recent guaranteed emission rate for each pollutant for which there is a permitted emission limit

Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a permitted emission limit

Retrofit to existing boiler? Installation on new boiler?

Low‐ash coal for PM control; low‐sulfur coal and low‐sulfur fuel oil for SO2 control.

5/26/2010 ‐ Page 3 Page 3
MidAmerican Energy Company

EGU‐ICR ResponseWalter Scott Energy Center

Each facility should provide the following information for each coal and oil

shipment received during the preceding 12 calendar months.

1a Plant or facility name from Part I, question 4a:

1b Plant or facility code from Part I, question 4b:

2 For each individual coal and oil shipment received during the preceding 12

calendar months, provide the following information, as available (indicate

N/A if not available; use addit ional pages, as necessary):

State/Country County Coal seam

1,866,817 1, 2, 3, 4 Wyoming/United States Campbell Wyodak‐Anderson Rail

873,795 1, 2, 3, 4 Wyoming/United States Campbell Wyodak Rail

162,145 1, 2, 3, 4 Wyoming/United States Campbell Smith Rail

586,961 1, 2, 3, 4 Wyoming/United States Campbell Wyodak‐Anderson Rail

1,029,539 1, 2, 3, 4 Wyoming/United States Campbell Wyodak Rail

127,801 1, 2, 3, 4 Wyoming/United States Campbell Wyodak‐Anderson Rail

193,086 3, 4 N/A N/A N/A Truck

885,235 3, 4 N/A N/A N/A Truck

58,213 3, 4 N/A N/A N/A Truck

495,052 3, 4 N/A N/A N/A Truck

3 For each individual coal and oil shipment received during the preceding

12 calendar months, provide the following information, as available

(dry basis) (indicate N/A if not available): Sample ID #

Total amount of fuel represented by

sample, tons or gallons Total sulfur, % Ash content, % Higher heating value, Btu/lb (dry basis) Mercury, ppm (dry basis) Chlorine, ppm (dry basis)

Fluorine, ppm (dry

basis)

Nickel, ppm (dry

basis)

Other trace me

ppm

Cordero Rojo 1,866,817 0.45 7.71 12015 0.073 84.81 48.08 4.5 34.44 

Belle Ayr 873,795 0.38 6.43 12128 0.08 <50* 52.82 2.88 31.87 

Caballo 162,145 0.48 7.3 12074 0.11 <10* 61 5 22.2 

Black Thunder 586,961 0.41 7.16 12117 0.08 10 50.65 5 23.49 

Coal Creek 1,029,539 0.52 8.76 11951 0.09 7 40.88 5.75 25.81 

North

Antelope/Rochelle 127,801 0.31 6.5 12011 0.06 13 70 3 15.2 

Fauser Oil Co. Inc. 193,086 <0.0015* N/A N/A N/A N/A N/A N/A N/A 

Hartland Fuel Products 885,235 <0.0015* N/A N/A N/A N/A N/A N/A N/A 

Nebraska Iowa Supply 58,213 <0.0015* N/A N/A N/A N/A N/A N/A N/A 

Sapp Bros. Petroleum 495,052 <0.0015* N/A N/A N/A N/A N/A N/A N/A 

4 Were the data provided in Part II, question 3 above, acquired pursuant to:

permit requirements

X contractual obligations

standard operational procedures

other (please specify )

5 Analyses provided in Part II, question 3 above, supplied by

6 Name and address of laboratory performing analyses:

7 In addition to the analyses required in Part II, question 3 above, for samples

for which analyses of chlorine and/or any of the HAP metals were conducted,

please provide copies of any analyses conducted over the preceding 12

calendar months for (a) complete proximate and ultimate analyses, (b)

additional trace metals, and (c) the mineralogy of the ash that are readily

available for the oil(s) or coal(s) listed in Part II, question 2 above. The Agency

is requesting these data only as they may already be available; no additional

sampling or analyses are required to provide these data.

WSEC3 July2009_PostConstHgCl.pdf

WSEC4 Dec 2009_HgCl.pdf

Emission Data

8a What emission test report(s), parametric monitoring data, and other data or

monitoring are available for the boilers noted in Part I, question 15, for tests

conducted since January 1, 2005. Please consider reports prepared for all

testing and monitoring programs, for all pollutants, including (but not limited

to) those required under Title V, compliance with State or local requirements,

fulfillment of contractual obligations, U.S. Department of Energy (DOE)

programs, etc. (NOTE: EPA is not requesting copies of the test reports or data

at this time; however we may request actual copies in the future.) Use

additional pages as necessary.

8b Please indicate the date(s) and types (e.g., stack, fuel, parametric, etc.) of the

test(s) and the constituents (including criteria and hazardous air pollutants)

sampled for.

Date Type Constituents Blr ID

12/20/2005 Stack test CO 1

6/19/2006 Stack test PM, PM10 36/20/2006 Stack test PM, PM10 26/21/2006 Stack test PM, PM10 1

1/9/2007 Stack test CO 3

Particulate matter (PM & PM10), CO, THC/VOC, SO2, NH3, H2SO4, HCl, Opacity, Hg, Pb, F, Total Selected Metals, and Total Reduced Sulfur

compliance stack tests; optimization studies; sorbent flow rates

SGS Lab 2804 Hackathorne Lane, Gillette, WY 82716 Caballo (Peabody Energy)

Standard Lab's Black Thunder Lab Black Thunder (Arch Coal)

Standard Lab's Coal Creek Lab Coal Creek (Arch Coal)

SGS Lab North Antelope Rochelle (Peabody Energy)

P.O. Box 406, Wright, WY 82732P.O. Box 406, Wright, WY 82732

2804 Hackathorne Lane, Gillette, WY 82716

Laboratory Performing Analyses Mine

Name Address

Standard Lab's Cordero Lab P.O. Box 1449, Gillette, WY 82717 Cordero Rojo (Cloud Peak)

SGS Lab 2804 Hackathorne Lane, Gillette, WY 82716 Belle Ayr (Alpha Natural Resources)

N/A

N/A N/A

North Antelope Rochelle (Peabody Energy) Caller Box 3035, Gillette, WY 82717 N/A N/A

Notes:For coal sample concentrations that were below the detection thresholds, 1/2 the threshold value was input.

The (<) sign indicates that the average is below the threshold.

For oil sample concentration values, no formal analysis was provided to MEC. The entry is based on billing

documents for the oil indicating Ultra Low Sulfur Diesel Fuel was purchased.

Sapp Bros. Petroleum Inc.

Caballo (Peabody)

Black Thunder (Arch)

Coal Creek (Arch)

North Antelope/Rochelle (Peabody)Fauser Oil Co., Inc.

Hartland Fuel ProductsNebraska Iowa Supply Co.

1082

Cordero Rojo (Cloud Peak(formerly Rio Tinto))

Belle Ayr (Alpha)

Walter Scott Jr. Energy Center

Amount received, dry

basis, short tons or

gallons ID # of boiler(s) firing fuel

Fuel source

Fuel shipment method Mine (Coal)/Supplier (Oil)

Coal Creek (Arch Coal) 195 Hoadley Road, Wright, WY 82732

Fuel supplier

Name Address

Cordero Rojo (Cloud Peak) P.O. Box 1449, Gillette, WY 82717

Belle Ayr (Alpha Natural Resources) P.O. Box 3039, Gillette, WY 82717

Caballo (Peabody Energy) Caller Box 3041, Gillette, WY 82717

Black Thunder (Arch Coal) P.O. Box 406, Wright, WY 82732

Other

Name Address

N/A N/A

N/A N/AN/A N/AN/A

Adobe Acrobat 

Document

Adobe Acrobat 

Document

5/26/2010 ‐ Page 4 Page 4
MidAmerican Energy Company

EGU‐ICR ResponseWalter Scott Energy Center

5/8 ‐ 5/13/2007 Stack tests, parametric monitoring

NOx, CO, THC/VOC, SO2, NH3, PM10, H2SO4,

HCl, Opacity, Hg, Pb, F, Total Selected Metals,

Total Redcued Sulfur, CO2, O2

4

8/14‐17/2007 Stack tests, parametric monitoring

NOx, CO, THC/VOC, SO2, NH3, PM10, H2SO4,

HCl, Opacity, Hg, Pb, F, Total Selected Metals,

Total Redcued Sulfur, CO2, O2

4

12/20/2007 Optimization study ‐ parametric modeling Activated carbon feed rate (Hg) 4

12/20‐22/2007 and 1/8‐

13/2008

Optimization study ‐ parametric

modeling SCR feed rate (NOx) 4

1/9‐13/2008 Optimization study ‐ parametric modeling Lime sorbent feed rate (SO2) 4

6/10/2008 Stack test CO 28/12/2008 Stack test PM 38/13/2008 Stack test PM, PM10 2

10/30/2008 Stack test Hg 3

11/25/2008 Stack test PM, PM10 1

6/22/2009 Stack test PM 36/24/2009 Stack test Pb 36/24/2009 Stack test HCl, F 3

7/2/2009 Stack test Hg 38/6/2009 Stack test PM10 3

12/15/2009 Optimization study ‐ stack test NOx 4

12/16‐17/2009 Optimization study ‐ stack test Hg 4

12/15/2009 &

12/17/2009 Optimization study ‐ stack test Acetyldehyde, Isophorone loading, Toluene, Benzene 4

8c Do any of these test reports reflect testing at a location before any emission

control devices?

Yes X No

If yes, please note which reports and provide a detailed description of the

location of the emissions sampling point(s).

8d Were any of these test reports conducted when use of other material(s) or

non‐fossil fuels were fired in the boiler?

Yes X No

If yes, please note which reports and identify the other material(s) or non‐

fossil fuels used.

8e Do any of these test reports reflect testing during periods of startup,

shutdown, and malfunction?

Yes X No

If yes, please note which reports.

8f Did the unit’s control configuration differ from that shown in Part I, question

16, at the time of these test results?

X Yes No

If yes, please list the unit’s complete control configuration at time of testing

in a similar format to Part I, question 16.

Boiler ID Type NOx control SO2 control PM control Date of Change

2 Pulverized coal, tangential‐fired, dry

bottom Overfire Air None Hot‐side ESP Test Prior to 5/21/2008

3 Pulverized coal, wall‐fired, dry

bottom

Low‐NOx Burners

None Cold‐side ESP Test Prior to 10/18/2006

3 Pulverized coal, wall‐fired, dry

bottom

Low‐NOx Burners with Overfire Air

None Cold‐side ESP

Test between 10/18/2006 ‐ 

5/15/2009

8g Do any of these test reports reflect testing at a location before a post

combustion SO2 emission control device (e.g., FGD, SDA, Dry Scrubber)?

Yes X No

If yes, please note which reports and, in addition to the detailed description

of the location of the sampling point(s) (question 8c above), include detail

about how much, if any, bypass of unscrubbed flue gas was utilized at the

time of testing (including percentage of total scrubber flue gas flow). Note by

diagram where sampling ports were located in relation to the bypass

ductwork.

9 What type of deviation reporting is required for violations of permit

requirements?

10 Are deviation reports available for malfunctions or other periods of

noncompliance with permit terms and conditions?

X Yes No

If yes, please note which reports.

11 Are continuous emissions monitoring system (CEMS) data available (e.g.,

mercury, continuous opacity monitoring systems) that are not already being

provided to the U.S. EPA, even if from short‐term testing?

X Yes No

If yes, please note for which pollutants CEMS data are available and the

period of time (both total period and calendar period) for which data are

available. If CEM data are being provided to EPA, please note to which Office

the data are being provided.

12 For each boiler noted in Part I, question 15, provide the following

information:

Boiler ID Date of test PM SO2 HCl/HF/HCN Metal HAP Hg CO

Other organics

(specify) Gross MW 

1 12/20/2005 N/A N/A N/A N/A N/A 88.21 ppm (5 hr) N/A 46.43 

3 6/19/2006

Filterable & condensible: 0.032 lb/mmBtu,

216.05 lb/hr; Filterable: 116.88 lb/hr (average

of 3 test runs) N/A N/A N/A N/A N/A N/A 725 

N/AAll emission limit deviations are reported in quarterly emission reports, and in Title V semi‐annual monitoring reports and annual

compliance certification reports submitted to the state agency. Additionally, most emission deviations are also orally reported to the state

agency within eight hours or at the start of the next working day following the onset of the incident. A follow‐up written report is requried

for each orally reported deviation. Some opacity deviations of short duration and of low magnitude of deviation are not required to be

reported outside of the quarterly emission report.

Same as Question 9 (malfunctions included only if the malfunction caused a violation of a permit condition or emission limit)

CO data (Unit 1 12/20/2005 ‐ present, Unit 2 6/10/2008 ‐ present, Unit 3 1/9/2007‐ present, Unit 4 4/26/2007 ‐ present); Unit 4 SO2 percent

reduction (4/26/2007 ‐ present); continuous opacity monitoring system data Units 1‐3 (01/01/2005 ‐ present), Unit 4 (4/26/2007 ‐ present),

CEMS Acid Rain data provided to EPA Acid Rain Division

Emissions test results (indicate format of emission data)

5/26/2010 ‐ Page 5 Page 5
MidAmerican Energy Company

EGU‐ICR ResponseWalter Scott Energy Center

2 6/20/2006

PM Filterable & condensible: 0.039 lb/mmBtu,

39.59 lb/hr; PM Filterable: 33.82 lb/hr; PM10

Filterable & Condensible: 0.052 lb/mmBtu,

54.58 lb/hr; PM10 Condensible: 30.78 lb/hr

(average of 3 test runs) N/A N/A N/A N/A N/A N/A 87 

1 6/21/2006

PM Filterable & condensible: 0.13 lb/mmBtu,

77.11 lb/hr; PM Filterable: 66.99 lb/hr; PM10

Filterable & Condensible: 0.094 lb/mmBtu,

57.74 lb/hr; PM10 Condensible: 46.68 lb/hr

(average of 3 test runs) N/A N/A N/A N/A N/A N/A 43 

3 1/9/2007 N/A N/A N/A N/A N/A

0.076 lb/mmbtu, 5‐hour

average; 521.71 lb/hr (5‐

hr average) N/A 739 

4 5/8/2007

PM/PM10 Filterable & condensible: 0.009

lb/mmBtu, 70.67 lb/hr; PM Filterable: 0.003

lb/mmBtu (average of 3 test runs) N/A N/A N/A N/A N/A N/A 843 

4 5/8/2007 N/A

0.061 lb/mmBtu, 511.93

lb/hr (average of 3 test runs) N/A N/A N/A N/A N/A 843 

4 5/9/2007 N/A N/A

HCl: 3.8E‐5 lb/mmBtu (average of 3 test

runs) N/A N/A N/A N/A 848 

4 5/12/2007 N/A N/A F: 1.08E‐4 lb/mmBtu N/A N/A N/A N/A 768 

4 5/9/2007 N/A N/A N/A

Pb: 3.0E‐6 lb/mmBtu, 0.02 lb/hr

(average of 3 test runs) N/A N/A N/A 848 

4 5/8‐9/2007 N/A N/A N/A N/A

7.2E‐7 lb/mmBtu

(average of 3 test runs) N/A N/A 846 

4 5/8/2007 N/A N/A N/A N/A N/A

0.039 lb/mmBtu, 330

lb/hr (average of 3

test runs) N/A 843 

4 5/8/2007 N/A N/A N/A N/A N/A N/A

VOC: 2.3E‐3

lb/mmBtu

(average of 3 test

runs) 843 

4 5/11/2007 N/A N/A N/A

TSM Method 29: 9.2E‐5 lb/mmBtu,

0.65 lb/hr (average of 3 test runs) N/A N/A N/A 800 

4 8/14‐15/2007

PM/PM10 Filterable & condensible: 0.019

lb/mmBtu, 150.32 lb/hr; PM filterable: 0.008

lb/mmBtu (average of 3 test runs) N/A N/A N/A N/A N/A N/A 867 

4 8/17/2007 N/A

0.041 lb/mmBtu, 278.38

lb/hr (average of 3 test runs) N/A N/A N/A N/A N/A 869 

4 8/15/2007, 8/17/2007 N/A N/A

HCl: 5.9E‐5 lb/mmBtu (average of 3 test

runs) N/A N/A N/A N/A 873 

4 8/17/2007 N/A N/A F: 2.9E‐5 lb/mmBtu (average of 3 test runs) N/A N/A N/A N/A 865 

4 8/18/2007 N/A N/A N/A

Pb: 2.0E‐7 lb/mmBtu, 0.002 lb/hr

(average of 3 test runs) N/A N/A N/A 874 

4 8/14/2007, 8/15/2007, 8/17/2007 N/A N/A N/A N/A

1.2E‐6 lb/mmBtu

(average of 3 test runs) N/A N/A 873 

4 8/17/2007 N/A N/A N/A N/A N/A

0.003 lb/mmBtu,

19.50 lb/hr (average

of 3 test runs) N/A 869 

4 8/17/2007 N/A N/A N/A N/A N/A N/A

VOC: 0.0023

lb/mmBtu

(average of 3 test

runs) 869 

4 8/17/2007 N/A N/A N/A

TSM Method 29: 3.1E‐5lb/mmBtu,

0.21 lb/hr (average of 3 test runs) N/A N/A N/A 857 

4 12/20/2007 N/A N/A N/A N/A

2.62 μg/m3 (average of 3 test

runs) N/A N/A 844 

4 12/20/2007 N/A N/A N/A N/A

1.98 μg/m3 (average of 3

test runs) N/A N/A 848 

4 12/20/2007 N/A N/A N/A N/A

1.45 μg/m3 (average of 3

test runs) N/A N/A 847 

4 12/20/2007 N/A N/A N/A N/A

1.11 μg/m3 (average of 3

test runs) N/A N/A 842 

4 12/20/2007 N/A N/A N/A N/A

1.12 μg/m3 (average of 3

test runs) N/A N/A 844 

4 1/9/2008 N/A 0.088 lb/mmBtu N/A N/A N/A N/A N/A 602 4 1/10/2008 N/A 0.083 lb/mmBtu N/A N/A N/A N/A N/A 844 4 1/10/2008 N/A 0.072 lb/mmBtu N/A N/A N/A N/A N/A 603 4 1/11/2008 N/A 0.091 lb/mmBtu N/A N/A N/A N/A N/A 844 4 1/11/2008 N/A 0.082 lb/mmBtu N/A N/A N/A N/A N/A 842 4 1/12/2008 N/A 0.092 lb/mmBtu N/A N/A N/A N/A N/A 844 4 1/12/2008 N/A 0.072 lb/mmBtu N/A N/A N/A N/A N/A 844 4 1/13/2008 N/A 0.089 lb/mmBtu N/A N/A N/A N/A N/A 843 2 6/10/2008 N/A N/A N/A N/A N/A 492.82ppm (5 hr) N/A 78 

3 8/12/2008

PM filterable & condensible: 0.024 lbmmbtu,

183.59 lb/hr; PM filterable: 50.03 lb/hr

(average of 3 test runs) N/A N/A N/A N/A N/A N/A 693 

2 8/13/2008

PM filterable & condensible: 0.1039 lb/mmBtu,

119.64 lb/hr; PM filterable: 77.18 lb/hr; PM10

filterable & condensible: 0.083 lb/mmBtu,

96.11 lb/hr; PM10 filterable: 54.72 lb/hr

(average of 3 test runs) N/A N/A N/A N/A N/A N/A 87 

3 10/30/2008 N/A N/A N/A N/A

5.24E‐6 lb/mmBtu, 0.033

lb/hr (average of 3 test

runs) N/A N/A 693 

1 11/25/2008

PM filterable & condensible: 0.2149 lb/mmBtu,

116.28 lb/hr; PM filterable: 106.37 lb/hr; PM10

filterable & condensible: 72.56 lb/hr; PM10

filterable: 47.45 lb/hr (average of 3 test runs) N/A N/A N/A N/A N/A N/A 45 

3 6/22/2009

PM filterable & condensible: 0.020 lb/mmBtu,

150.97 lb/hr; PM filterable: 10.76 lb/hr

(average of 3 test runs) N/A N/A N/A N/A N/A N/A 749 

3 6/24/2009 N/A N/A N/A

Pb: 1.23E‐5 lb/mmBtu, 0.0916

lb/hr (average of 3 test runs) N/A N/A N/A 742 

3 6/24/2009 N/A N/A

HCl: 1.10E‐4 lb/mmBtu, 0.85 lb/hr (average

of 3 test runs) N/A N/A N/A N/A 741 

3 6/24/2009 N/A N/A

F: 1.42E‐4 lb/mmBtu, 1.57 lb/hr (average of

3 test runs) N/A N/A N/A N/A 741 

3 7/2/2009 N/A N/A N/A N/A

4.46E‐6 lb/mmBtu,

0.0302 lb/hr (average of

3 test runs) N/A N/A 731 

3 8/6/2009

PM10 filterable & condensible: 0.0215

lb/mmBtu, 171.54 lb/hr; PM10 filterable: 23.42

lb/hr (average of 3 test runs) N/A N/A N/A N/A N/A N/A 775 

5/26/2010 ‐ Page 6 Page 6
MidAmerican Energy Company

EGU‐ICR ResponseWalter Scott Energy Center

4 12/16/2009 N/A N/A N/A N/A 4.1E‐6 lb/mmBtu (2 hrs) N/A N/A 872 

4 12/16/2009 N/A N/A N/A N/A 3.0E‐6 lb/mmBtu (2 hrs) N/A N/A 867 4 12/16/2009 N/A N/A N/A N/A 2.1E‐6 lb/mmBtu (2 hrs) N/A N/A 872 4 12/17/2009 N/A N/A N/A N/A 2.1E‐6 lb/mmBtu (2 hrs) N/A N/A 871 4 12/17/2009 N/A N/A N/A N/A 1.5E‐6 lb/mmBtu (2 hrs) N/A N/A 871 4 12/17/2009 N/A N/A N/A N/A 1.4E‐6 lb/mmBtu (2 hrs) N/A N/A 871 4 12/17/2009 N/A N/A N/A N/A N/A N/A

Acetaldehyde:

5.27E‐6 lb/mmBtu,

4.42E‐2 lb/hr

(average of 3 test

runs) 871 

4 12/17/2009 N/A N/A N/A N/A N/A N/A

Isophorone: 6.77E‐

6 lb/mmBtu, 5.67

lb/hr (average of 3

test runs) 871 

4 12/15/2009 N/A N/A N/A N/A N/A N/A

Toluene: 3.38E‐4

lb/mmBtu

(average of 3 test

runs) 871 

4 12/15/2009 N/A N/A N/A N/A N/A N/A

Benzene: 2.69E‐5

lb/mmBtu

(average of 3 test

runs) 871 

5/26/2010 ‐ Page 7 Page 7
Hg Cl

SAMPLE RESID TOTAL AS REC'D DRY REC'D DRY REC'D DRY REC'D DRY REC'D DRY MAF

DRY 

BASIS

DRY 

BASIS

WO ID MOIST MOIST ASH ASH VOLATILE VOLATIL F. CARB. F. CARB. SULFUR SULFUR BTU BTU BTU PPM PPM

2009020

87001

RUN 1 7/2/09 

WJ SCOTT 8:40-

10:40 20.12 20.12 5.88 7.36 37.45 46.88 36.55 45.76 0.32 0.4 9629 12054 13012 0.068 8

2009020

87002

RUN 2 7/2/09 

WJ SCOTT 

10:55-12:55 19.33 19.33 6.16 7.64 38.11 47.24 36.4 45.12 0.34 0.42 9718 12047 13044 0.067 10

2009020

87003

RUN 3 7/2/09 

WJ SCOTT 1:15-

3:15 18.59 18.59 5.67 6.96 38.29 47.03 37.45 46.01 0.32 0.39 9850 12099 13004 0.072 9