PART I: GENERAL FACILITY INFORMATION

1

2 Ameren Energy Generating Company

3 1901 Chouteau Avenue, St. Louis, MO 63166

4a Coffeen

4b 861

5 134 CIPS Lane, Coffeen, IL 62017

6

7 Donald Schuh, Sr. Environmental Scientist

8 314-554-2658

Email address dschuh@ameren.com

9

Yes

No X

10

X

X

X

11

X

X

X

12

% %

94 % 94 %

6 % 6 %

% %

% %

% %

13

100 % #2

%

%

lignite

distillate

residual or bunkerC

other

sub bituminous

bituminous

petroleum coke

Coal

Oil

Mass Percentage Btu percentage

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:7,8

Oil

Natural Gas

Other

Other

Name of legal owner of facility:

Name of legal operator of facility

Coal

EIA Plant Code:

Complete street address:

Provide mailing address if different:

Name and title of contact:

Is this facility considered to be owned or operated by a small entity as defined by the Regulatory Flexibility Act?

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

Which of the following fossil fuels or other material(s) are permitted6 to be fired in any steam generating unit at this facility?

Ameren Energy Generating Company

If oil is fired, indicate which type of oil was utilized during the previous 12 months prior to the receipt of this ICR:9

Natural Gas

Address of legal owner or operator:

Plant Name

anthracite

synfuel

Contact telephone number:

AmerenEGC Coffeen
14a

14b

Yes

No X Ameren will continue to burn as long as we are not subject to CAA Section 129

Boiler Chemical Cleaning Wash

Used Oil

Yes

Pet Coke 10% blend with coal

Actually burn

Yes

Permitted to burn Quantity/year

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?

No

No

None in 2009

545 gallons/2009

NA

NA

Yes

Other Material

Yes

Untreated virgin wood 1% blend with coal

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 permitted10 to burn non-fossil fuel(s) or other material(s) even if you do not actually burn them.

Yes

Yes

AmerenEGC Coffeen
15

16

Boiler ID19 Type20

Cyclone SCR Catalyst - Vanadium 

Pentoxide on thin ceramic 

honeycomb Reductant - NH3 Not 

Designed to reduce SO3 (#1)

Over fire Air 2/2000

Other control24 SO2 control22 PM control23 NOx control21

Over fire Air 02/2001

FGC 07/2001 (#2)

6786

Present maximum heat input, (MMBtu/hr)13

Average annual capacity factor for the past 3 years

Applicable NSPS

Estimated year of retirement18

MWe Gross capacity summer

MWe Net capacity summer

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.):

1

2

1005

75

NA

NA

1003

1005

996

Sub bituminous/ 

Bituminous blend

6727

70

NA

NA

590

560

87.5

86.9

2620

2420 2463

1005

1003

1005

987

Sub bituminous/ 

Bituminous blend

Original design gross efficiency (%, HHV)

Design steam reheat temperature (°F)14

Operating steam reheat temperature (°F)15

Fuel16

3282

360

340

87.9

87.3

2628

Hours/year operated17

Design steam pressure (psig)

Operating steam pressure (psig)

Design steam temperature (°F)

Operating steam temperature (°F)

5544

2

coal

5544

Boiler ID11

Original design fuel (i.e. coal rank or type of oil)

Design heat input, (MMBtu/hr)12

1

coal

3282

Present operating gross efficiency (%, HHV)

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.

Cold side ESP 06/2010 (#2) NA

Wet FGD with limestone slurry 

scrubbant 11/2009Wet FGD with 

limestone slurry scrubbant 

11/2009 (#4)

Wet FGD with limestone slurry 

scrubbant 11/2009Wet FGD with 

limestone slurry scrubbant 

02/2010 (#3)

Cyclone SCR 4/2003 Catalyst - Vanadium 

Pentoxide on thin ceramic 

honeycomb Reductant - NH3 Not 

Designed to reduce SO3 (#1) 

Cold side ESP 01/1973 (#3)

AmerenEGC Coffeen
17

NA

18

Boiler 

ID27

NA

19

NA

20

Boiler 

ID30

NA

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) or fuel 

type 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).

Actual start-up 

date

Expected or 

projected start-up 

date

NA NA NA NA NA NA

Coal rank(s) upon which 

guarantee is based

NA NA NA NA

NA NA NA NA

Company (vendor) contact information

NA

NA NA

Sorbent or additive feed 

rate on which guarantee is 

based

NA NA NA

Company (vendor) name Name

Type of control (e.g., 

sorbent and type; chemical 

additive)31

Guaranteed HAP 

emission 

reduction (%) or 

emission rate

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; precombustion boiler chemical additive; combustion boiler chemical additive), the desired HAP emission reduction or rate (if any), and the coal rank(s) in use 

or fuel type 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).

Demonstration 

activity actual startup date

Demonstration 

activity projected 

start-up date

Demonstration 

activity end-date 

or projected enddate

Type of control (e.g., 

sorbent and type; chemical 

additive28)

Desired HAP emission 

reduction (%) or emission 

rate

Coal rank(s) in use

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, etc.) control technology that you have either contracted for, are installing, or have installed for the purpose of providing a nondemonstration, full-scale operating system.

Boiler ID Company (vendor) name

Company (vendor) contact information

Name Telephone Address

Telephone Address

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 project25 (e.g., U.S. Department of Energy program, consent decree, etc.).

Boiler 

ID26

AmerenEGC Coffeen
21

PM1034 PM2.535

HCl 

and/or 

HF

HCN Metal 

HAP36

Other 

organics 

(specify)

Other 

pollutant 

(specify)

1 NA NA NA NA NA NA

OP Limit 

Opacity 

30% 6-

min. avg. 

based on 

COMS

2 NA NA NA NA NA NA

OP Limit 

Opacity 

30% 6-

min. avg. 

based on 

COMS

22

PM10 PM2.5

HCl 

and/or 

HF

HCN Metal 

HAP39 Hg CO

1 NA NA NA NA NA NA NA

2 NA NA NA NA NA NA NA

23

Yes

No X

Please elaborate.

24

PM10 PM2.5

HCl 

and/or 

HF

HCN Metal 

HAP42 Hg CO

1 NA NA NA NA NA

proper 

operation 

SCR/

WFGD

NA

2 NA NA NA NA NA

proper 

operation 

SCR/

WFGD

NA

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

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

Boiler 

ID32

NA

CO

SIP Limit 200 ppm 

corrected to 50% 

excess air

SIP Limit 200 ppm 

corrected to 50% 

excess air

NA

NA

Required Monitoring, Recordkeeping, and Reporting for each pollutant with permitted limit.

Other organics 

(specify) PM41 SO2

.064 lb /mmBtu

Was any other guarantee level sought or offered?

.015#/mmBtu

NA

.064 lb /mmBtu

NA

PM33 Hg

Operating Permit (OP) 

Limit: 0.19 # /MMBtu - 

Method 5 Stack Test

PM38

.015#/mmBtu

Operating Permit (OP) 

Limit: 0.15 # /MMBtu - 

Method 5 Stack Test

SO2

OP Limit - 55,555 

lbs/hr. station total 

based on CEMS 

Boiler ID40

NA

OP Limit - 55,555 

lbs/hr. station total 

based on CEMS 

Stack test as 

requested by 

agency

CEMS Records of 3 hr 

block ave. Quarterly Excess 

emissions Reporting

NA

Stack test as 

requested by 

agency

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

Boiler 

ID37

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

Other organics 

(specify)

Other pollutant 

(specify) SO2

NA

CEMS Records of 3 hr 

block ave. Quarterly Excess 

emissions Reporting

AmerenEGC Coffeen
25

NA

NA

NA

(Include base year for operating costs [e.g., 2006])

26

Low sulfur coal

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.

For the control technologies identified in Part I, questions 17 and 19, provide the cost information requested.43

Total Capital Investment:

Total Annual Operating and Maintenance Costs:

Facility Name / Unit No.:

Retrofit to existing boiler?

Installation on new boiler?

AmerenEGC Coffeen
PART II: FUEL ANALYSIS AND EMISSION DATA

Each facility should provide the following information for each coal and oil shipment received during the preceding 12 calendar months.

1a Coffeen

1b 861

2

State/Country County47 Coal seam48

1 Sub-bituminous Jan-09 27,582.63 1 & 2 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

2 Sub-bituminous Jan-09 207,178.15 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

3 Bituminous Jan-09 1,951.78 1 & 2 Illinois/USA Macoupin IL Crown III Truck

4 Sub-bituminous Feb-09 27,562.72 1 & 2 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

5 Sub-bituminous Feb-09 41,630.48 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

6 Sub-bituminous Feb-09 110,953.78 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

7 Bituminous Feb-09 2,020.60 1 & 2 Illinois/USA Macoupin IL Crown III Truck

8 Sub-bituminous Mar-09 27,698.41 1 & 2 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

9 Sub-bituminous Mar-09 13,976.68 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

10 Sub-bituminous Mar-09 125,062.13 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

11 Bituminous Mar-09 1,896.15 1 & 2 Illinois/USA Macoupin IL Crown III Truck

12 Sub-bituminous Apr-09 27,843.22 1 & 2 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

13 Sub-bituminous Apr-09 42,131.60 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

14 Sub-bituminous Apr-09 138,688.18 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

15 Bituminous Apr-09 5,900.03 1 & 2 IL/USA Macoupin IL Crown III Truck

16 Sub-bituminous May-09 13,796.19 1 & 2 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

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

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

Fuel Analysis44

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):

Sample 

ID 

number

Type of Coal Months

Amount received, dry 

basis, short tons45 

and Barrels

ID # of boiler(s) 

firing fuel46

Fuel source Fuel 

shipment 

method

AmerenEGC Coffeen
17 Sub-bituminous May-09 41,645.18 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

18 Sub-bituminous May-09 27,848.78 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

19 Sub-bituminous May-09 13,855.25 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

20 Bituminous May-09 7,623.72 1 & 2 IL/ USA IL Crown Truck

21 Sub-bituminous Jun-09 41,656.59 1 & 2 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

22 Sub-bituminous Jun-09 41,350.48 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

23 Sub-bituminous Jun-09 29,899.35 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

24 Sub-bituminous Jun-09 180,998.35 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

25 Sub-bituminous Jul-09 55,486.81 1 & 2 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

26 Sub-bituminous Jul-09 55,417.38 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

27 Sub-bituminous Jul-09 27,865.18 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

28 Sub-bituminous Jul-09 194,835.93 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

29 Sub-bituminous Aug-09 13,864.71 1 & 2 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

30 Sub-bituminous Aug-09 27,697.83 1 & 2 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

31 Bituminous Aug-09 13,547.02 1 & 2 IL/USA IL Viper Truck

32 Sub-bituminous Aug-09 41,559.80 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

33 Sub-bituminous Aug-09 27,878.00 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

AmerenEGC Coffeen
34 Sub-bituminous Aug-09 166,469.55 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

35 Sub-bituminous Sep-09 27,829.88 1 & 2 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

36 Bituminous Sep-09 12,734.10 1 & 2 IL/USA IL Viper Truck

37 Sub-bituminous Sep-09 55,618.18 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

38 Sub-bituminous Sep-09 27,900.93 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

39 Sub-bituminous Sep-09 125,335.98 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

40 Bituminous Oct-09 29,626.80 1 & 2 IL/USA Viper Truck

41 Sub-bituminous Oct-09 83,179.80 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

42 Bituminous Oct-09 4,207.97 1 & 2 IL/USA IL Crown III Truck

43 Bituminous Nov-09 32,686.31 1 & 2 IL/USA IL Viper Truck

44 Sub-bituminous Nov-09 69,109.73 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

45 Bituminous Nov-09 4,557.47 1 & 2 IL/USA IL Crown III Truck

46 Sub-bituminous Dec-09 27,363.60 1 & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

47 Sub-bituminous Dec-09 27,538.70 1 & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

48 Bituminous Dec-09 23,972.85 1 & 2 IL/USA IL Viper Truck

49 Sub-bituminous Dec-09 221,670.48 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

50 Bituminous Dec-09 4,748.92 1 & 2 IL/USA IL Crown III Truck

51 #2 Jan-09 867 1 & 2 Illinois/USA Effingham NA Truck

52 #2 Jan-09 698 1 & 2 Illinois/USA Crawford NA Truck

53 #2 Jan-09 2633 1 & 2 Illinois/USA Madison NA Truck

54 #2 Feb-09 350 1 & 2 Illinois/USA Effingham NA Truck

55 #2 Feb-09 695 1 & 2 Illinois/USA Crawford NA Truck

56 #2 Mar-09 698 1 & 2 Illinois/USA Crawford NA Truck

57 #2 Mar-09 1745 1 & 2 Illinois/USA Effingham NA Truck

58 #2 Mar-09 514 1 & 2 Illinois/USA Madison NA Truck

59 #2 Apr-09 2981 1 & 2 Illinois/USA Madison NA Truck

AmerenEGC Coffeen
60 #2 Apr-09 1231 1 & 2 Illinois/USA Effingham NA Truck

61 #2 May-09 3145 1 & 2 Illinois/USA Effingham NA Truck

62 #2 May-09 1745 1 & 2 Illinois/USA Crawford NA Truck

63 #2 May-09 172 1 & 2 Illinois/USA Champaign NA Truck

64 #2 May-09 174 1 & 2 Illinois/USA Madison NA Truck

65 #2 Jun-09 1569 1 & 2 Illinois/USA Crawford NA Truck

66 #2 Jun-09 8355 1 & 2 Illinois/USA Effingham NA Truck

67 #2 Jul-09 6486 1 & 2 Illinois/USA Effingham NA Truck

68 #2 Jul-09 698 1 & 2 Illinois/USA Crawford NA Truck

69 #2 Jul-09 1758 1 & 2 Illinois/USA Champaign NA Truck

70 #2 Aug-09 4213 1 & 2 Illinois/USA Effingham NA Truck

71 #2 Aug-09 352 1 & 2 Illinois/USA Champaign NA Truck

72 #2 Aug-09 700 1 & 2 Illinois/USA Crawford NA Truck

73 #2 Sep-09 876 1 & 2 Illinois/USA Crawford NA Truck

74 #2 Sep-09 1050 1 & 2 Illinois/USA Effingham NA Truck

75 #2 Sep-09 175 1 & 2 Illinois/USA Madison NA Truck

76 #2 Oct-09 520 1 & 2 Illinois/USA Madison NA Truck

77 #2 Oct-09 350 1 & 2 Illinois/USA Crawford NA Truck

78 #2 Oct-09 1400 1 & 2 Illinois/USA Effingham NA Truck

79 #2 Nov-09 1567 1 & 2 Illinois/USA Crawford NA Truck

80 #2 Nov-09 6465 1 & 2 Illinois/USA Effingham NA Truck

81 #2 Dec-09 1045 1 & 2 Illinois/USA Effingham NA Truck

82 #2 Dec-09 345 1 & 2 Illinois/USA Crawford NA Truck

3

NA

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

NA Permit requirements

NA contractual obligations

NA standard operational procedures

NA other(please specify)

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

NA Fuel supplier

NA Other 

6 Name and address of laboratory performing analyses:

NA

For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information49, as available (dry basis)

(indicate N/A if not available):

AmerenEGC Coffeen
7

NA

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.

AmerenEGC Coffeen
Emission Data

8a

See Test Number in 8b

8b

Test 

Report Boiler ID

1 CS 1&2

8c

Yes

No X

If yes, please note which reports and provide a detailed description of the location of the emissions sampling point(s).

8d

Yes

No X

8e

Yes

No X

8f

Yes X

No

The wet limestone FGD was not installed.

8g

Yes

No X

If yes, please note which reports.

Did the unit’s control configuration differ from that shown in Part I, question 16, at the time of these test results?

If yes, please list the unit’s complete control configuration at time of testing in a similar format to Part I, question 16.

Do any of these test reports reflect testing at a location upstream of a post combustion SO2 emission control device (e.g., FGD, SDA, Dry Scrubber)?

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 exhaust gas flow). Note by diagram where 

sampling ports were located in relation to the bypass ductwork

Nov-05 Common Stack Testing

Do any of these test reports reflect testing at a location upstream of any emission control devices?

Were any of these test reports conducted when use of other material(s) or non-fossil fuels were fired in the boiler?

If yes, please note which reports and identify the other material(s) or non-fossil fuels used.

Do any of these test reports reflect testing during periods of startup, shutdown, and malfunction?

Constituents:

Mercury

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.

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:

AmerenEGC Coffeen
9

10

Yes X

No

11

Yes

No X

12

PM54 SO2 HCl/HF/HCN

Metal 

HAP55 Hg56 CO

Other 

organics 

(specify)

Unit Load

Flue gas 

CO2 

Content

CS 1&2 NA 643ppm NA NA 2.3lb/Tbtu NA NA

U1: 358 

MW

U2: 585 

MW

12.4

Are deviation reports available for malfunctions or other periods of noncompliance with permit terms and conditions?

If yes, please note which reports.

Quarterly excess emissions reports; notifications to IEPA for excess emissions due to malfunctions and breakdowns

Quarterly excess emissions reports; notifications to IEPA for excess emissions due to malfunctions and breakdowns

Emissions test results (indicate format of emission data)52,53

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 or permit authority, even if from short-term testing?

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

Boiler ID Date of test

If yes51, 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 CEMS data are being provided to EPA, please note to which 

Office the data are being provided.

What type of deviation reporting is required for violations of permit requirements?

Nov-05

AmerenEGC Coffeen

PART I: GENERAL FACILITY INFORMATION

1

2

3 1901 Chouteau Avenue, St. Louis, MO 63166

4a Duck Creek

4b 6016

5 17751 North Cilco Rd., Canton, IL 61520

6

7 Donald Schuh, Sr. Environmental Scientist

8 314-554-2658

Email address dschuh@ameren.com

9

Yes

No X

10

X

X

X

11

X

X

X

12

% %

66 % 62 %

34 % 38 %

% %

% %

% %

13

100 % #2

%

%

Ameren Energy Resources Generating Company

Mass Percentage Btu percentage

Natural Gas

Other

bituminous

distillate

residual or bunkerC

other

subbituminous

Provide mailing address if different:

Name and title of contact:

lignite

If oil is fired, indicate which type of oil was utilized during the previous 12 months prior to the receipt of this ICR:9

Natural Gas

Coal

Oil

Other

Coal

Oil

Name of legal owner of facility:

Name of legal operator of facility

Address of legal owner or operator:

Plant Name

EIA Plant Code:

Complete street address:

Contact telephone number:

anthracite

synfuel

petroleum coke

Ameren Energy Resources Generating Company

Is this facility considered to be owned or operated by a small entity as defined by the Regulatory Flexibility Act?

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

Which of the following fossil fuels or other material(s) are permitted6 to be fired in any steam generating unit at this facility?

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:7,8

AmerenERGC Duck Creek
14a

Boiler Chemical Cleaning Wash

14b

Yes

No X Ameren will continue to burn as long as we are not subject to CAA Section 129

15

NA

Yes

Yes

Other Material Quantity/year

Untreate virgin wook 1 % blend

NA

No

No

NA

NA

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?

Used Oil

Pet Coke 10% blend with coal

NA

Bituminous/Subbituminous blend

5739

2400

43

Subpart D

1005

1005

1005

1005

4500

400

372

86.7

86.1

2475

Average annual capacity factor for the past 3 years

Applicable NSPS

Estimated year of retirement18

MWe Gross capacity summer

MWe Net capacity summer

Original design gross efficiency (%, HHV)

Design steam reheat temperature (°F)14

Operating steam reheat temperature (°F)15

Fuel16

Hours/year operated17

Design steam pressure (psig)

Operating steam pressure (psig)

Design steam temperature (°F)

Operating steam temperature (°F)

Present maximum heat input, (MMBtu/hr)13

Permitted to burn Actually burn

Design heat input, (MMBtu/hr)12 4500

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 ID11

Original design fuel (i.e. coal rank or type of oil)

1

Coal

Present operating gross efficiency (%, HHV)

No

No

Yes

Yes

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 permitted10 to burn non-fossil fuel(s) or other material(s) even if you do not actually burn them.

AmerenERGC Duck Creek
16

17

NA

18

Boiler 

ID27

NA

19

NA NA NA NA NA

NA NA NA NA

NA NA NA NA

NA NA

FGD 1972 Replaced with 

Wet FGD with limestone 

scrubbant 3/2009 (#3)

Cold Side ESP 1972 

Replaced 3/2009 (#2) NA

Other control24 NOx control21

Low Nox Burner 05/2003

Modified 05/2007

Address

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; precombustion boiler chemical additive; combustion boiler chemical additive), the desired HAP emission reduction or rate (if any), and the coal rank(s) in use 

or fuel type 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).

Demonstration 

activity actual startup date

Demonstration 

activity projected 

start-up date

Demonstration 

activity end-date 

or projected enddate

Type of control (e.g., 

sorbent and type; chemical 

additive28)

Desired HAP emission 

reduction (%) or emission 

rate

Coal rank(s) in use

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 project25 (e.g., U.S. Department of Energy program, consent decree, etc.).

Boiler 

ID26 Company (vendor) name Name

Company (vendor) contact information

Telephone Address

1

Dry Bottom Wall 

fired

PM control23 SO2 control22

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 ID19 Type20

SCR Catalyst - Vanadium 

Pentoxide on thin ceramic 

honeycomb Reductant - NH3 

Designed to reduce SO3 - Yes 

6/2003 (#1)

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, etc.) control technology that you have either contracted for, are installing, or have installed for the purpose of providing a nondemonstration, full-scale operating system.

Boiler ID Company (vendor) name

Company (vendor) contact information

Name Telephone

AmerenERGC Duck Creek
20

Boiler 

ID30

NA

21

PM1034 PM2.535

HCl 

and/or 

HF

HCN Metal 

HAP36

Other 

organics 

(specify)

Other 

pollutant 

(specify)

1 NA NA NA NA NA NA

Opacity 

20% 6-

min. avg. 

based on 

COMS

22

PM10 PM2.5

HCl 

and/or 

HF

HCN Metal 

HAP39 Hg CO

1 NA NA NA NA NA NA NA

23

Yes

No X

Please elaborate.

NA NA NA NA NA NA

Hg

NA

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

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) or fuel 

type 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).

Actual start-up 

date

Expected or 

projected start-up 

date

Type of control (e.g., 

sorbent and type; chemical 

additive)31

Guaranteed HAP 

emission 

reduction (%) or 

emission rate

Boiler 

ID32

PM33 CO

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

Sorbent or additive feed 

rate on which guarantee is 

based

Coal rank(s) upon which 

guarantee is based

SO2

Reg Limit - 1.2 

lb/mmBtu 3-hr rolling 

avg; 5400 lb/hour 3-

hour average 

SIP limit 200 ppm 

corrected to 50% 

excess air based on 

CEMS 

Was any other guarantee level sought or offered?

0.015 lb/MBtu .064 lb SO2/Mbtu NA NA

PM38

Reg. limit - 0.10 

lb/mmBtu Based on 

emission test; 367 

lb/hour 3-hour average

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

Boiler ID37

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

Other organics 

(specify)

Other pollutant 

(specify) SO2

AmerenERGC Duck Creek
24

PM10 PM2.5

HCl 

and/or 

HF

HCN Metal 

HAP42 Hg

1 NA NA NA NA NA

proper 

operation 

SCR/

WFGD

25

NA

NA

NA

NA

(Include base year for operating costs [e.g., 2006])

26

Low sulfur coal

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.

For the control technologies identified in Part I, questions 17 and 19, provide the cost information requested.43

Total Capital Investment:

Total Annual Operating and Maintenance Costs:

Facility Name / Unit No.:

Retrofit to existing boiler?

Installation on new boiler?

SO2

CEMS Records of 3 hr 

block ave.Quarterly Excess 

emissions Reporting

PM41

Records of 3 hr block 

ave.Quarterly Excess 

emissions reporting

CO

Boiler 

ID40

Stack test as 

requested by 

agency

NA

Required Monitoring, Recordkeeping, and Reporting for each pollutant with permitted limit.

Other organics 

(specify)

AmerenERGC Duck Creek
PART II: FUEL ANALYSIS AND EMISSION DATA

Each facility should provide the following information for each coal and oil shipment received during the preceding 12 calendar months.

1a Duck Creek

1b Plant or facility code from Part I, question 4b: 6016

2

State/Country County47 Coal seam48

1 Bituminous Feb-09 55,218.36 1 Illinois/USA IL Viper Truck

2 Bituminous Feb-09 19,369.03 1 Illinois/USA Macoupin IL Crown III Truck

3 Bituminous Mar-09 68,723.17 1 Illinois/USA IL Viper Truck

4 Bituminous Mar-09 6,852.44 1 Illinois/USA IL Crown III Truck

5 Bituminous Apr-09 28,477.75 1 IL/USA IL Viper Truck

6 Sub-bituminous Apr-09 15,554.53 1 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

7 Bituminous Apr-09 2,125.12 1 IL/USA Macoupin IL Crown III Truck

8 Bituminous May-09 27,491.15 1 IL/ USA IL Viper Truck

9 Sub-bituminous May-09 16,105.13 1 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

10 Sub-bituminous May-09 31,590.98 1 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

11 Sub-bituminous May-09 16,364.63 1 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

12 Bituminous Jun-09 23,965.48 1 IL/USA IL Viper Truck

13 Sub-bituminous Jun-09 32,191.93 1 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

14 Sub-bituminous Jun-09 32,559.83 1 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

15 Bituminous Jun-09 7,136.45 1 IL/USA IL Crown III Truck

16 Bituminous Jul-09 32,788.98 1 IL/USA IL Viper Truck

17 Sub-bituminous Jul-09 16,405.28 1 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

18 Sub-bituminous Jul-09 47,008.60 1 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

19 Sub-bituminous Jul-09 32,819.65 1 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

20 Bituminous Jul-09 5,347.04 1 IL/USA IL Crown III Truck

21 Bituminous Aug-09 27,143.04 1 IL/USA IL Viper Truck

Fuel Analysis44

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

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):

Sample 

ID 

number

Type of Coal Months

Amount received, dry 

basis, short tons45 

and barrels

ID # of boiler(s) 

firing fuel46

Fuel source Fuel 

shipment 

method

AmerenERGC Duck Creek
22 Sub-bituminous Aug-09 81,448.50 1 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

23 Bituminous Aug-09 7,408.07 1 IL/USA IL Crown III Truck

24 Sub-bituminous Sep-09 45,631.65 1 Wyoming/USA Campbell PRB Jacobs Ranch Train

25 Bituminous Sep-09 33,028.95 1 IL/USA IL Viper Truck

26 Sub-bituminous Sep-09 48,748.33 1 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

27 Bituminous Sep-09 5,858.33 1 IL/Usa IL CrownIII Truck

28 Sub-bituminous Oct-09 16,229.14 1 Wyoming/USA Campbell PRB Black Thunder Train

29 Bituminous Oct-09 10,419.65 1 IL/USA IL Viper Truck

30 Sub-bituminous Oct-09 64,221.85 1 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

31 Bituminous Oct-09 1,632.02 1 IL/USA IL Crown III Truck

32 Sub-bituminous Nov-09 129,011.65 1 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

33 Sub-bituminous Dec-09 79,873.60 1 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

34 #2 Jan-09 4699 1 Illinois/USA Peoria NA Truck

35 #2 Feb-09 1954 1 Illinois/USA Peoria NA Truck

36 #2 Mar-09 5086 1 Illinois/USA Peoria NA Truck

37 #2 Apr-09 2557 1 Illinois/USA Peoria NA Truck

38 #2 May-09 2028 1 Illinois/USA Peoria NA Truck

39 #2 Jun-09 1996 1 Illinois/USA Peoria NA Truck

40 #2 Jul-09 358 1 Illinois/USA Peoria NA Truck

41 #2 Aug-09 1439 1 Illinois/USA Peoria NA Truck

42 #2 Sep-09 178 1 Illinois/USA Peoria NA Truck

43 #2 Oct-09 1060 1 Illinois/USA Peoria NA Truck

44 #2 Nov-09 2043 1 Illinois/USA Peoria NA Truck

45 #2 Dec-09 909 1 Illinois/USA Peoria NA Truck

3

NA

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

NA Permit requirements

NA contractual obligations

NA standard operational procedures

NA other(please specify)

For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information49, as available

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

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

NA Fuel supplier

NA Other 

6 Name and address of laboratory performing analyses:

NA

7

NA

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.

AmerenERGC Duck Creek
Emission Data

8a

See Test Number in 8b

8b

Test 

Report Boiler ID

1 1

2 1

3 1

8c

Yes

No X

If yes, please note which reports and provide a detailed description of the location of the emissions sampling point(s).

8d

Yes

No X

8e

Yes

No X

8f

Yes

No X

Constituents:

Mercury

PM, CPM, TSP, Trace Metals*, Total Hg, THC, HCl, HF, SO2, SO3. CO (*The 

various trace metals include As, Be, Cd, Cr, Pb, Mn and Ni)

TSP, CPM, FPM, SO2, Hg

If yes, please list the unit’s complete control configuration at time of testing in a similar format to Part I, question 16.

Do any of these test reports reflect testing at a location upstream of any emission control devices?

Were any of these test reports conducted when use of other material(s) or non-fossil fuels were fired in the boiler?

If yes, please note which reports and identify the other material(s) or non-fossil fuels used.

Do any of these test reports reflect testing during periods of startup, shutdown, and malfunction?

If yes, please note which reports.

Did the unit’s control configuration differ from that shown in Part I, question 16, at the time of these test results?

Stack Testing

Aug-09 Stack Testing

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.

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:

May-09 Stack Testing

Oct-05

AmerenERGC Duck Creek
8g

Yes

No X

9

10

Yes X

No

11

Yes

No X

12

Date of 

test SO2 Hg56 CO

Other 

organics 

(specify)

Unit Load 

MW

Flue gas 

CO2 

content

1 Oct-05 201 ppm 0.17lb/Tbtu NA NA 318 12.7

1 Aug-09 0.0133 

lb/MBtu

0.00000305 

lb/MBtu

0.0659 

lb/MBtu

Total 

Hydrocarbons 

'<0.000296 

lb/MBtu

440 NA

1 May-09 0.0382 

lb/mmBtu

1.2E-06 

lb/mmBtu NA NA 420 NA

NA

0.00114/<9.74E-6/NA 

lb/MBtu

Quarterly excess emissions reports; notifications to IEPA for excess emssions due to malfunctions and breakdowns

Metal HAP55

Quarterly excess emissions reports; notifications to IEPA for excess emssions due to malfunctions and breakdowns

NA

As-<4.02E-7; 

Be-<2.01E-8; Cd-

<4.01E-7; Cr5.82E-7; Pb-

<4.80E-7; Mn-

<1.43E-6; Ni7.05E-7 lbs/Mbtu

Emissions test results (indicate format of emission data)52,53

PM54

NA

TSP-0.0106; CPM-0.0100; 

FPM-0.0032 lb/Mbtu

HCl/HF/HCN

Do any of these test reports reflect testing at a location upstream of a post combustion SO2 emission control device (e.g., FGD, SDA, Dry Scrubber)?

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 exhaust gas flow). Note by diagram where 

sampling ports were located in relation to the bypass ductwork

If yes51, 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 CEMS data are being provided to EPA, please note to which Office 

the data are being provided.

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

Boiler ID

What type of deviation reporting is required for violations of permit requirements?

Are deviation reports available for malfunctions or other periods of noncompliance with permit terms and conditions?

If yes, please note which reports.

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 or permit authority, even if from short-term testing?

TSP-0.0162, CPM-0.0073, 

FPM-0.0077 lb/mmBtu NA NA

AmerenERGC Duck Creek
PART I: GENERAL FACILITY INFORMATION

1

2

3 1901 Chouteau Avenue, St. Louis, MO 63166

4a E D Edwards

4b 856

5 7800 South Cilco Ln., Bartonville, IL 61607

6

7 Donald Schuh, Sr. Environmental Scientist

8 314-554-2658

Email address dschuh@ameren.com

9

Yes

No X

10

X

X

X

11

X

X

X

12

%

100 %

%

%

%

%

13

100 % #2

%

% Specify

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

Which of the following fossil fuels or other material(s) are permitted6 to be fired in any steam generating unit at this facility?

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:7,8

Coal

Oil

Natural Gas

Other

Natural Gas

Coal

Oil

Other

synfuel

petroleum coke

lignite

bituminous

subbituminous

anthracite

other

Plant Name

EIA Plant Code:

Is this facility considered to be owned or operated by a small entity as defined by the Regulatory Flexibility Act?

residual or bunkerC

Ameren Energy Resources Generating Company

Contact telephone number:

Name of legal owner of facility:

Name of legal operator of facility

Address of legal owner or operator:

Ameren Energy Resources Generating Company

distillate

Complete street address:

Provide mailing address if different:

Name and title of contact:

If oil is fired, indicate which type of oil was utilized during the previous 12 months prior to the receipt of this ICR:9

AmerenERGC Edwards
14a

14b

Yes

No X Ameren will continue to burn as long as we are not subject to CAA Section 129

15

NA NA NA

1 2

2400

1005

1005

NA

8492

278

7873

65

NA

266

87.6

83.6

1005

Sub-Bituminous

2875

366

345

88.1

64

NA

Sub-Bituminous

7739

1005

1005

85.5

2600

1005

Sub-Bituminous

86.5

1840

1005

2400

1005

1005

Design steam temperature (°F)

Operating steam temperature (°F)

69

1800

1000

1000

1005

115

87.1

Estimated year of retirement18

MWe Gross capacity summer

MWe Net capacity summer

Original design gross efficiency (%, HHV)

Design steam reheat temperature (°F)14

Operating steam reheat temperature (°F)15

Fuel16

Hours/year operated17

Coal

1523

Average annual capacity factor for the past 3 years

Applicable NSPS

3321

Design steam pressure (psig)

Operating steam pressure (psig)

1523

123

Present operating gross efficiency (%, HHV)

Present maximum heat input, (MMBtu/hr)13

Original design fuel (i.e. coal rank or type of oil)

Design heat input, (MMBtu/hr)12

Boiler Chemical Cleaning Wash

Used Oil None in 2009

Actually burn

Coal Coal

4594

4594

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 permitted10 to burn non-fossil fuel(s) or other material(s) even if you do not actually burn them.

3

Yes

Yes

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 ID11

Quantity/year

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 None in 2009

Yes

Permitted to burn

3321

Other Material

AmerenERGC Edwards
16

17

NA

18

Boiler 

ID27

NA

Telephone

NA

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) in use or fuel type 

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).

NA NA

Cold Side ESP 6/1968 (#3)

ESP Upgrade for SO3 

Injection Elimination 2003

ESP Power Supply 

Upgrade 2009

Cold Side ESP 6/1972 (#4)

FGC 1979 (#2)

3

Wall Fired, 

Pressurized, 

Reheat, Natural 

Circulation

Over Fired Air 3/2007

Low NOx Burner 1/1995

NA

Name Address

FGC 1979 (#2)

SCR Catalyst - Vanadium 

Pentoxide on thin ceramic 

honeycomb Reductant - NH3 

Designed to reduce SO3 - No 

5/2003(#1)

Company (vendor) contact information

Activated Carbon 07/2009 

(#1)

Activated Carbon 07/2009 

(#3)

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 project25 (e.g., U.S. Department of Energy program, consent decree, etc.).

Boiler 

ID26 Company (vendor) name

Desired HAP emission 

reduction (%) or emission 

rate

Coal rank(s) in use

2

Wall Fired, 

Pressurized, 

Reheat, Natural 

Circulation

Over Fired Air 8/2008 NA

Low NOx Burner 1/1993

ESP Upgrade for SO3 

Injection Elimination 2003

Cold Side ESP 5/1960 (#3)

PM control23 NOx control21

Over Fired Air

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.):

Other control24 Boiler ID19 Type20

1

Wall Fired, 

Pressurized, 

Reheat, Natural 

Circulation

SO2 control22

FGC 1979 (#2)

Activated Carbon 07/2009 

(#1)

Low NOx Burner 10/1997

NA

Type of control (e.g., 

sorbent and type; chemical 

additive28)

Demonstration 

activity actual start-up 

date

Demonstration 

activity projected 

start-up date

Demonstration 

activity end-date 

or projected enddate

AmerenERGC Edwards
NA

19

1

2

3

20

Boiler 

ID30

1

2

3

NA NA NA NA NA

8101 Southpark Way, Littleton, CO 80120

Name Telephone Address

303-339-8860

NA

Cody Wilson

NA NA

NA NA

7/1/2009 NA

7/1/2009 NA Halogenated ACI NA

Halogenated ACI NA

NA NA

ADA Environmental Solutions 8102 Southpark Way, Littleton, CO 80120

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) or fuel type 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).

Actual start-up date

Expected or 

projected start-up 

date

Type of control (e.g., 

sorbent and type; chemical 

additive)31

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

8100 Southpark Way, Littleton, CO 80120

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, etc.) control technology that you have either contracted for, are installing, or have installed for the purpose of providing a nondemonstration, full-scale operating system.

Boiler ID Company (vendor) name

Company (vendor) contact information

Cody Wilson

Cody Wilson 303-339-8860

ADA Environmental Solutions

Halogenated ACI

303-339-8860

ADA Environmental Solutions

7/1/2009 NA NA

AmerenERGC Edwards
21

PM33 PM1034 PM2.535

HCl 

and/or 

HF

HCN Metal 

HAP36

Other 

organics 

(specify)

Other 

pollutant 

(specify)

1

Operating 

Permit (OP) 

limit - 0.20 

lb/mmBtu 

Based on 

emission test

NA NA NA NA NA NA

Opacity 

30% 6-min. 

avg. based 

on COMS

2

Operating 

Permit (OP) 

limit - 0.15 

lb/mmBtu 

Based on 

emission test

NA NA NA NA NA NA

Opacity 

30% 6-min. 

avg. based 

on COMS

3

Operating 

Permit (OP) 

limit - 0.10 

lb/mmBtu 

Based on 

emission test

NA NA NA NA NA NA

Opacity 

30% 6-min. 

avg. based 

on COMS

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

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

Boiler 

ID32 SO2 Hg

SIP Limit 200 ppm 

corrected to 50% 

excess air 

SIP Limit 200 ppm 

corrected to 50% 

excess air 

NA

SIP Limit 200 ppm 

corrected to 50% 

excess air 

NA

NA

CO

OP Limit - 34,613 lbs/hr station 

total; Boilers 1,2,3 as a group </= 

4.71 lbs/Mbtu; Each boiler shall 

not exceed 6.6 lbs/Mbtu Based on 

CEMS 

OP Limit - 34,613 lbs/hr station 

total; Boilers 1,2,3 as a group </= 

4.71 lbs/Mbtu; Each boiler shall 

not exceed 6.6 lbs/Mbtu Based on 

CEMS 

OP Limit - 34,613 lbs/hr station 

total; Boilers 1,2,3 as a group </= 

4.71 lbs/Mbtu; Each boiler shall 

not exceed 6.6 lbs/Mbtu Based on 

CEMS 

AmerenERGC Edwards
22

PM38 PM10 PM2.5 SO2

HCl 

and/or 

HF

HCN Metal 

HAP39 Hg CO

1 NA NA NA NA NA NA NA NA NA

2 NA NA NA NA NA NA NA NA NA

3 NA NA NA NA NA NA NA NA NA

23

Yes

No X

Please elaborate.

24

PM10 PM2.5

HCl 

and/or 

HF

HCN Metal 

HAP42 Hg CO

1 NA NA NA NA NA NA NA

2 NA NA NA NA NA NA NA

3 NA NA NA NA NA NA NA

Was any other guarantee level sought or offered?

NA

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

NA NA

NA

NA

NA

NA

Other organics 

(specify)

NA

Required Monitoring, Recordkeeping, and Reporting for each pollutant with permitted limit.

Stack test as 

requested by agency

Stack test as 

requested by agency

CEMS Records of 3 hr 

block ave. Quarterly Excess 

emissions Reporting

CEMS Records of 3 hr 

block ave. Quarterly Excess 

emissions Reporting

NA

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

Boiler 

ID37 Other organics 

(specify)

Other pollutant 

(specify)

PM41 SO2

CEMS Records of 3 hr 

block ave. Quarterly Excess 

emissions Reporting

Stack test as 

requested by agency

Boiler 

ID40

AmerenERGC Edwards
25

1

Yes

No

(Include base year for operating costs [e.g., 2006]) 2009 Dollars

2

Yes

No

3

Yes

No

26

Low sulfur coal

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.

For the control technologies identified in Part I, questions 17 and 19, provide the cost information requested.43

Total Capital Investment:

Total Annual Operating and Maintenance Costs:

Facility Name / Unit No.:

Retrofit to existing boiler?

Installation on new boiler?

Installation on new boiler?

Total Capital Investment: $3,099,346.00

Facility Name / Unit No.:

Total Annual Operating and Maintenance Costs: $4,181,261.54

Facility Name / Unit No.:

Retrofit to existing boiler?

Installation on new boiler?

Total Capital Investment:

Total Annual Operating and Maintenance Costs: $2,638,352.85

$3,439,388.00

Retrofit to existing boiler?

$2,560,374.00

$1,862,422.61

AmerenERGC Edwards
PART II: FUEL ANALYSIS AND EMISSION DATA

Each facility should provide the following information for each coal and oil shipment received during the preceding 12 calendar months.

1a ED Edwards

1b 856

2

State/Country County47 Coal seam48

1 Sub-bituminous Feb-09 48,858.20 1, 2 & 3 Wyoming/USA Campbell PRB Black Thunder Train

2 Sub-bituminous Feb-09 47,488.15 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

3 Sub-bituminous Feb-09 31,828.50 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

4 Sub-bituminous Feb-09 64,339.00 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

5 Sub-bituminous Mar-09 48,314.30 1, 2 & 3 Wyoming/USA Campbell PRB Black Thunder Train

6 Sub-bituminous Mar-09 16,469.80 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

7 Sub-bituminous Mar-09 65,604.50 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

8 Sub-bituminous Mar-09 97,484.53 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

9 Sub-bituminous Apr-09 65,454.65 1, 2 & 3 Wyoming/USA Campbell PRB Black Thunder Train

10 Sub-bituminous Apr-09 16,378.50 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

11 Sub-bituminous Apr-09 65,615.78 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

12 Sub-bituminous Apr-09 98,234.23 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

13 Sub-bituminous May-09 49,094.20 1, 2 & 3 Wyoming/USA Campbell PRB Black Thunder Train

14 Sub-bituminous May-09 16,032.85 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

ID # of 

boiler(s) firing 

fuel46

Fuel source Fuel 

shipment 

method

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

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

Fuel Analysis44

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):

Sample

ID

number

Type of Coal Months

Amount received, 

dry basis, short 

tons45 & Barrels

AmerenERGC Edwards
15 Sub-bituminous May-09 81,865.78 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

16 Sub-bituminous May-09 98,738.43 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

17 Sub-bituminous Jun-09 49,020.35 1, 2 & 3 Wyoming/USA Campbell PRB Black Thunder Train

18 Sub-bituminous Jun-09 16,065.73 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

19 Sub-bituminous Jun-09 65,534.43 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

20 Sub-bituminous Jun-09 65,292.65 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

21 Sub-bituminous Jul-09 65,454.60 1, 2 & 3 Wyoming/USA Campbell PRB Black Thunder Train

22 Sub-bituminous Jul-09 229,061.90 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

23 Sub-bituminous Jul-09 16,307.48 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

24 Sub-bituminous Aug-09 65,476.40 1, 2 & 3 Wyoming/USA Campbell PRB Black Thunder Train

25 Sub-bituminous Aug-09 16,288.55 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

26 Sub-bituminous Aug-09 82,172.25 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

27 Sub-bituminous Aug-09 82,298.73 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

28 Sub-bituminous Sep-09 49,302.35 1, 2 & 3 Wyoming/USA Campbell PRB Black Thunder Train

29 Sub-bituminous Sep-09 16,387.35 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

30 Sub-bituminous Sep-09 147,022.63 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

31 Sub-bituminous Sep-09 65,875.80 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

32 Sub-bituminous Oct-09 65,704.30 1, 2 & 3 Wyoming/USA Campbell PRB Black Thunder Train

33 Sub-bituminous Oct-09 32,272.88 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

34 Sub-bituminous Oct-09 32,640.55 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

35 Sub-bituminous Oct-09 82,393.35 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

AmerenERGC Edwards
36 Sub-bituminous Nov-09 65,711.80 1, 2 & 3 Wyoming/USA Campbell PRB Black Thunder Train

37 Sub-bituminous Nov-09 16,522.85 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

38 Sub-bituminous Nov-09 114,810.90 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

39 Sub-bituminous Nov-09 82,820.28 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

40 Sub-bituminous Dec-09 80,534.20 1, 2 & 3 Wyoming/USA Campbell PRB Black Thunder Train

41 Sub-bituminous Dec-09 161,697.45 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

42 Sub-bituminous Dec-09 65,036.25 1, 2 & 3 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

43 #2 Jan-09 500 1, 2 & 3 Missouri/USA St. Louis NA Truck

44 #2 Feb-09 833 1, 2 & 3 Missouri/USA St. Louis NA Truck

45 #2 Mar-09 667 1, 2 & 3 Missouri/USA St. Louis NA Truck

46 #2 Apr-09 500 1, 2 & 3 Missouri/USA St. Louis NA Truck

47 #2 May-09 500 1, 2 & 3 Missouri/USA St. Louis NA Truck

48 #2 May-09 667 1, 2 & 3 Illinois/USA Menard NA Truck

49 #2 Jun-09 333 1, 2 & 3 Illinois/USA Menard NA Truck

50 #2 Jun-09 500 1, 2 & 3 Missouri/USA St. Louis NA Truck

51 #2 Jul-09 833 1, 2 & 3 Illinois/USA Menard NA Truck

52 #2 Aug-09 167 1, 2 & 3 Missouri/USA St. Louis NA Truck

53 #2 Aug-09 839 1, 2 & 3 Illinois/USA Menard NA Truck

54 #2 Sep-09 500 1, 2 & 3 Illinois/USA Menard NA Truck

55 #2 Oct-09 1505 1, 2 & 3 Illinois/USA Menard NA Truck

56 #2 Nov-09 833 1, 2 & 3 Illinois/USA Menard NA Truck

57 #2 Dec-09 505 1, 2 & 3 Illinois/USA Menard NA Truck

3

NA

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

NA Permit requirements

NA contractual obligations

NA standard operational procedures

NA other(please specify)

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

NA Fuel supplier

NA Other 

For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information49, as

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

AmerenERGC Edwards
6 Name and address of laboratory performing analyses:

NA

7

NA

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.

AmerenERGC Edwards
Emission Data Boiler ID 1

8a

See Test Number in 8b

8b

Test 

Report Boiler ID

1 CS 1&2

2 3

3 3

4 CS 1&2

5 2

6 3

7 3

8 2

9 3

10 CS 1&2

11 3

8c

Yes

No X

If yes, please note which reports and provide a detailed description of the location of the emissions sampling point(s).

8d

Yes

No X

8e

Yes

No X

Stack Testing

Stack Testing

Mercury

Mercury speciation

Mercury

Mercury speciation

Mercury

Mercury

Stack Testing

Jul-05 Common Stack Testing

Stack Testing

Feb-09

Jan-09 Duct

Nov-09 Common Stack Testing

Do any of these test reports reflect testing at a location upstream of any emission control devices?

If yes, please note which reports.

Do any of these test reports reflect testing during periods of startup, shutdown, and malfunction?

Were any of these test reports conducted when use of other material(s) or non-fossil fuels were fired in the boiler?

If yes, please note which reports and identify the other material(s) or non-fossil fuels used.

Mercury

Jan-09 Stack Testing Mercury

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.

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:

Jul-05

Constituents:

Mercury

Oct-08 Stack Testing Mercury abbreviated 30B

Nov-09

Nov-09

Nov-09

Nov-08 Stack Testing Mercury abbreviated 30B

Duct

AmerenERGC Edwards
8f

Yes

No X

8g

Yes

No X

9

Quarterly excess emissions reports, notification of excess emissions due to malfunction and breakdowns

10

Yes X

No

11

Yes

No X

12

Date of 

test PM54 SO2 HCl/HF/HCN

Metal 

HAP55 Hg56

Percent 

Elemental 

Hg

Other 

organics 

(specify)

Unit Load 

MW

Flue Gas 

CO2 

content %

DSCFH Flue Gas 

Temp

CS 1&2 Jul-05 NA 490ppm NA NA 10.1lb/Tbtu NA NA U1-115

U2-229 11 NA NA

3 Jul-05 NA 382ppm NA NA 8.6lb/Tbtu NA NA 316 10.7 NA NA

3 Feb-09 NA NA NA NA 4.62lb/Tbtu NA NA 340 NA NA NA

CS 1&2 Nov-09 NA NA NA NA 3.38 lb/Tbtu NA NA U1-113

U2-258 12.4 54679724 302

2 Nov-09 NA NA NA NA 3.42 lb/Tbtu 94 NA 258 NA NA NA

3 Nov-09 NA NA NA NA 2.27lb/Tbtu NA NA 350 12.5 53453254 351

3 Nov-09 NA NA NA NA 2.32lb/Tbtu 95 NA 350 12.5 53453254 351

CS 1&2 Nov-08 NA NA NA NA 4.54ug/m3 NA NA NA NA NA 240

3 Oct-08 NA NA NA NA 5.77ug/m3 NA NA NA NA NA 325

Are continuous emissions monitoring system (CEMS) data available (e.g., mercury, continuous opacity monitoring systems) that are not already being provided 

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

If yes51, please note for which pollutants CEMS data are available and the period of time (both total period and 

Emissions test results (indicate format of emission data)52,53

Boiler ID

Quarterly excess emissions reports, notification of excess emissions due to malfunction and breakdowns

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 

What type of deviation reporting is required for violations of permit requirements?

Are deviation reports available for malfunctions or other periods of noncompliance with permit terms and conditions?

If yes, please note which reports.

Did the unit’s control configuration differ from that shown in Part I, question 16, at the time of these test results?

If yes, please list the unit’s complete control configuration at time of testing in a similar format to Part I, question 16.

Do any of these test reports reflect testing at a location upstream of a post combustion SO2 emission control device (e.g., FGD, SDA, Dry Scrubber)?

AmerenERGC Edwards
Date of 

test

Particulate 

Hg

Oxidize 

Hg

Elemental 

Hg

Total Hg 

gas only

Total Hg 

gas + 

particulate

2 Jan-09 0.095 1.36 5.38 6.73 6.73

3 Jan-09 0.16 1.23 6.1 7.32 7.39

Boiler ID

Mercury Balance Test in ug/m3 corrected to 3% O2

AmerenERGC Edwards
PART I: GENERAL FACILITY INFORMATION

1

2 Ameren Energy Generating Company

3 1901 Chouteau Avenue, St. Louis, MO 63166

4a Hutsonville

4b 863

5 15142 East 1900th Avenue, Hutsonville, IL 62433

6

7 Donald Schuh, Sr. Environmental Scientist

8 314-554-2658

Email address dschuh@ameren.com

9

Yes

No X

10

X

X

X

11

X

X

X

12

%

100 %

%

%

%

%

13

100 % #2

%

% Specify

Natural Gas

Other

Natural Gas

Coal

lignite

bituminous

subbituminous

anthracite

Is this facility considered to be owned or operated by a small entity as defined by the Regulatory Flexibility Act?

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

Which of the following fossil fuels or other material(s) are permitted6 to be fired in any steam generating unit at this facility?

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:7,8

Coal

Oil

Provide mailing address if different:

Name and title of contact:

distillate

residual or bunkerC

other

Oil

Other

synfuel

petroleum coke

Name of legal owner of facility:

Name of legal operator of facility

Address of legal owner or operator:

Plant Name

EIA Plant Code:

Complete street address:

Contact telephone number:

If oil is fired, indicate which type of oil was utilized during the previous 12 months prior to the receipt of this ICR:9

Ameren Energy Generating Company

AmerenEGC Hutsonville
14a

14b

Yes

No X Ameren will continue to burn as long as we are not subject to CAA Section 129

15

Actually burn Quantity/year

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?

None in 2009

None in 2009

Boiler Chemical Cleaning Wash Yes

1005

81

76

88.65

87.85

1005

1005

1005

Sub-bituminous

6901

1650

1500

1005

1005

1500

1005

6731

57

NA

NA

Hours/year operated17

Operating steam temperature (°F)

695

80

75

88.65

1005

Sub-bituminous

87.35

1650

MWe Gross capacity summer

MWe Net capacity summer

Original design gross efficiency (%, HHV)

Design steam reheat temperature (°F)14

Operating steam reheat temperature (°F)15

Fuel16

Design heat input, (MMBtu/hr)12

5

coal

695

Yes

Permitted to burn

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 permitted10 to burn non-fossil fuel(s) or other material(s) even if you do not actually burn them.

Present operating gross efficiency (%, HHV)

Yes

Yes

Present maximum heat input, (MMBtu/hr)13

6

coal

695

695

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.

Original design fuel (i.e. coal rank or type of oil)

Other Material

Used Oil

Design steam pressure (psig)

Operating steam pressure (psig)

Design steam temperature (°F)

Boiler ID11

Average annual capacity factor for the past 3 years

Applicable NSPS

Estimated year of retirement18

58

NA

NA

AmerenEGC Hutsonville
16

17

NA

18

Boiler 

ID27

NA

19

NA

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, etc.) control technology that you have either contracted for, are installing, or have installed for the purpose of providing a nondemonstration, full-scale operating system.

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; precombustion boiler chemical additive; combustion boiler chemical additive), the desired HAP emission reduction or rate (if any), and the coal rank(s) in use 

or fuel type 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).

Demonstration 

activity actual startup date

Demonstration 

activity projected 

start-up date

Demonstration 

activity end-date 

or projected enddate

Type of control (e.g., 

sorbent and type; chemical 

additive28)

Desired HAP emission 

reduction (%) or emission 

rate

Coal rank(s) in use

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 project25 (e.g., U.S. Department of Energy program, consent decree, etc.).

Boiler 

ID26 Company (vendor) name Name

Company (vendor) contact information

Telephone Address

Boiler ID Company (vendor) name

Company (vendor) contact information

Name Telephone Address

FGC, SO2 gas feedstock 

2003

FGC, Dry Sulfur feedstock 

2005 (#1)

FGC, Dry Sulfur feedstock 

2005 (#1)

FGC, SO2 gas feedstock 

2004

Cold Side ESP 1971 (#2)

Cold Side ESP 1971 (#2)

SO2 control22

NA

Boiler ID19 Type20 NOx control21 Other control24 PM control23

5

6

NA

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.):

Tangential, 

Natural 

Circulation, 

w/reheat

Tangential, 

Natural 

Circulation, 

w/reheat

NA

NA NA NA NA

NA NA NA

NA NA

NA NA NA NA

AmerenEGC Hutsonville
20

Boiler 

ID30

NA

21

PM1034 PM2.535

HCl 

and/or 

HF

HCN Metal 

HAP36

Other 

organics 

(specify)

Other 

pollutant 

(specify)

5 NA NA NA NA NA NA

Opacity 

30% 6-

min. avg. 

based on 

COMS

6 NA NA NA NA NA NA

Opacity 

30% 6-

min. avg. 

based on 

COMS

22

PM38 PM10 PM2.5 SO2

HCl 

and/or 

HF

HCN Metal 

HAP39 Hg CO

NA NA NA NA NA NA NA NA NA NA

SIP Limit 200 ppm 

corrected to 50% 

excess air 

SIP Limit 200 ppm 

corrected to 50% 

excess air 

Operating Permit 

(OP) limit - 0.18 

lb/mmBtu Based 

on emission test

Operating Permit 

(OP) limit - 0.18 

lb/mmBtu Based 

on emission test

Actual start-up 

date

Expected or 

projected start-up 

date

Type of control (e.g., 

sorbent and type; chemical 

additive)31

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

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) or fuel 

type 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).

SO2

OP Limit - 8,536 lbs/hr 

station total based on 

CEMS; 3-hr block 

OP Limit - 8,536 lbs/hr 

station total based on 

CEMS; 3-hr block 

PM33

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

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

Hg

Boiler 

ID37 Other organics 

(specify)

Other pollutant 

(specify)

NA

NA NA NA NA NA NA

NA NA

NA

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

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

Boiler 

ID32 CO

AmerenEGC Hutsonville
23

Yes

No X

Please elaborate.

24

PM10 PM2.5

HCl 

and/or 

HF

HCN Metal 

HAP42 Hg CO

5 NA NA NA NA NA NA NA

6 NA NA NA NA NA NA NA

25

NA

NA

NA

(Include base year for operating costs [e.g., 2006])

26

Low sulfur coal

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.

For the control technologies identified in Part I, questions 17 and 19, provide the cost information requested.43

Total Capital Investment:

Total Annual Operating and Maintenance Costs:

Facility Name / Unit No.:

Retrofit to existing boiler?

Installation on new boiler?

PM41 SO2

Was any other guarantee level sought or offered?

NA

CEMS Records of 3 hr 

block ave. Quarterly Excess 

emissions Reporting

Stack test as 

requested by 

agency

NA

Stack test as 

requested by 

agency

CEMS Records of 3 hr 

block ave. Quarterly Excess 

emissions Reporting

Other organics 

(specify)

Required Monitoring, Recordkeeping, and Reporting for each pollutant with permitted limit.

Boiler 

ID40

AmerenEGC Hutsonville
PART II: FUEL ANALYSIS AND EMISSION DATA

Each facility should provide the following information for each coal and oil shipment received during the preceding 12 calendar months.

1a Hutsonville

1b 863

2

State/Countr

y

County47 Coal seam48

1 Sub-bituminous Jan-09 50,622.33 3 & 4 Truck

2 Sub-bituminous Feb-09 48,854.51 3 & 4 Truck

3 Sub-bituminous Mar-09 18,455.72 3 & 4 Truck

4 Sub-bituminous May-09 15,208.88 3 & 4 Truck

5 Sub-bituminous Jun-09 20,350.10 3 & 4 Truck

6 Sub-bituminous Jul-09 29,972.41 3 & 4 Truck

7 Sub-bituminous Aug-09 20,262.41 3 & 4 Truck

8 Sub-bituminous Sep-09 19,580.43 3 & 4 Truck

9 Sub-bituminous Oct-09 22,038.32 3 & 4 Truck

10 Sub-bituminous Nov-09 29,054.68 3 & 4 Truck

11 Sub-bituminous Dec-09 40,389.45 3 & 4 Truck

12 #2 Feb-09 715.00 3 & 4 Illinois/USA Crawford NA Truck

13 #2 Mar-09 728.00 3 & 4 Illinois/USA Crawford NA Truck

14 #2 Apr-09 1,487.00 3 & 4 Illinois/USA Crawford NA Truck

15 #2 May-09 715.00 3 & 4 Illinois/USA Crawford NA Truck

16 #2 Jul-09 715.00 3 & 4 Illinois/USA Crawford NA Truck

17 #2 Sep-09 715.00 3 & 4 Illinois/USA Crawford NA Truck

18 #2 Nov-09 714.00 3 & 4 Illinois/USA Crawford NA Truck

19 #2 Dec-09 536.00 3 & 4 Illinois/USA Crawford NA Truck

3

NA

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

NA Permit requirements

NA contractual obligations

NA standard operational procedures

NA other(please specify)

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

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

Fuel Analysis44

For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information49, as available

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

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):

Sample 

ID 

number

Type of Coal Months

Amount received, dry 

basis, short tons45 & 

Barrels

ID # of 

boiler(s) 

firing fuel46

Fuel source Fuel shipment 

method

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

NA Fuel supplier

NA Other 

6 Name and address of laboratory performing analyses:

NA

7

NA

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.

AmerenEGC Hutsonville
Emission Data

8a

See Test Number in 8b

8b

Test 

Report Boiler ID

1 4

2 4

3 3

4 4

8c

Yes

No X

If yes, please note which reports and provide a detailed description of the location of the emissions sampling point(s).

8d

Yes

No X

8e

Yes

No X

8f

Yes

No X

Were any of these test reports conducted when use of other material(s) or non-fossil fuels were fired in the boiler?

If yes, please note which reports and identify the other material(s) or non-fossil fuels used.

Do any of these test reports reflect testing during periods of startup, shutdown, and malfunction?

If yes, please note which reports.

Did the unit’s control configuration differ from that shown in Part I, question 16, at the time of these test results?

If yes, please list the unit’s complete control configuration at time of testing in a similar format to Part I, question 16.

Do any of these test reports reflect testing at a location upstream of any emission control devices?

Aug-06 Parametric Testing

Mercury

Mercury

Jul-08 Stack Testing Mercury abbreviated 30B

Jul-08 Stack Testing Mercury abbreviated 30B

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.

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:

Nov-05 Stack Testing

AmerenEGC Hutsonville
8g

Yes

No X

9

10

Yes X

11

Yes

No X

12

Date of 

test PM54 SO2 HCl/HF/HCN

Metal 

HAP55 Hg56 CO

Other 

organics 

(specify)

Unit Load 

MW

Flue gas 

CO2 

content

Flue Gas 

Temp

Stack Gas 

Flow 

kscfm

4 Nov-05 NA 416ppm NA NA 6.1 lb/Tbtu 225ppm NA 82 12.5 305 234

3 Jul-08 NA NA NA NA 5.97ug/m3 NA NA NA NA 318 NA

4 Jul-08 NA NA NA NA 5.99ug/m3 NA NA NA NA 314 NA

If yes51, 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 CEMS data are being provided to EPA, please note to which 

Office the data are being provided.

Quarterly excess emissions reports; notifications to IEPA for excess emssions due to malfunctions and breakdowns

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

Boiler ID

Emissions test results (indicate format of emission data)52,53

Do any of these test reports reflect testing at a location upstream of a post combustion SO2 emission control device (e.g., FGD, SDA, Dry Scrubber)?

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 exhaust gas flow). Note by diagram where 

sampling ports were located in relation to the bypass ductwork

What type of deviation reporting is required for violations of permit requirements?

Are deviation reports available for malfunctions or other periods of noncompliance with permit terms and conditions?

If yes, please note which reports.

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 or permit authority, even if from short-term testing?

Quarterly excess emissions reports; notifications to IEPA for excess emssions due to malfunctions and breakdowns

AmerenEGC Hutsonville

PART I: GENERAL FACILITY INFORMATION

1

2

3 1901 Chouteau Avenue, St. Louis, MO 63166

4a Labadie

4b 2103

5 226 Labadie Power Plant Road, Labadie, MO 63055

6

7 Donald Schuh, Sr. Environmental Scientist

8 314-554-2658

Email address dschuh@ameren.com

9

Yes

No X

10

X

X

X

11

X

X

X

12

%

100 %

%

%

% Specify type

%

13

100 % #2

%

% Specify

Provide mailing address if different:

Name and title of contact:

Union Electric Co. dba AmerenUE

Contact telephone number:

Name of legal owner of facility:

Name of legal operator of facility

Address of legal owner or operator:

Plant Name

EIA Plant Code:

Complete street address:

residual or bunker C

other

subbituminous

anthracite

synfuel

petroleum coke

Natural Gas

Coal

Oil

Other

lignite

If oil is fired, indicate which type of oil was utilized during the previous 12 months prior to the receipt of this ICR:9

bituminous

distillate

Is this facility considered to be owned or operated by a small entity as defined by the Regulatory Flexibility Act?

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

Which of the following fossil fuels or other material(s) are permitted6 to be fired in any steam generating unit at this facility?

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:7,8

Coal

Oil

Natural Gas

Other

Union Electric Co. dba AmerenUE

AmerenUE Labadie
14a

Boiler Chemical Cleaning Wash

14b

Yes

No X Ameren will continue to burn as long as we are not subject to CAA Section 129

15

Present maximum heat input, (MMBtu/hr)13

Coal

Spent Demineralizer Resin Yes Yes 11.4 tons/2009

6183 6107

Yes None in 2009

Used Oil Yes Yes Less than 55 gallons

Original design fuel (i.e. coal rank or type of oil)

Design heat input, (MMBtu/hr)12

Coal

6183

Coal

6107

Actually burn Quantity/year

Present operating gross efficiency (%, HHV)

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.

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 permitted10 to burn non-fossil fuel(s) or other material(s) even if you do not actually burn them.

Other Material Permitted to burn

6183

6183

84.96

2625

Boiler ID11 1

Design steam temperature (°F)

Operating steam temperature (°F)

1005

1005

Design steam pressure (psig)

630

602

88.39

Average annual capacity factor for the past 3 years

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?

Coal

2 3 4

Sub-bituminous

7779

71

2625

Applicable NSPS

Estimated year of retirement18

MWe Gross capacity summer

MWe Net capacity summer

Original design gross efficiency (%, HHV)

Design steam reheat temperature (°F)14

Operating steam reheat temperature (°F)15

Fuel16

Hours/year operated17

Operating steam pressure (psig)

1005

NA

NA

623

594

88.39

85.34

2625

2625

1005

1005

1005

NA

1005

1005

1005

Sub-bituminous

8225

80

NA

6107

6107

1005

2625

2625

633

604

87.62

85.15

8218

633

603

87.62

85.20

1005

2625

2625

1005

1005

1005

Sub-bituminous

1005

NA

1005

82

NA

Sub-bituminous

8120

85

NA

NA

Yes

Ethylene Glycol Yes No NA

Used Oil Absorbents Yes Yes Less than 11 tons in 2009

AmerenUE Labadie
16

17

NA

18

Boiler 

ID27

NA

19

NA

Over Fired Air Nov 1994

Over Fired Air Jan 1994

Low NOx Burners Jan 1994

Low NOx Burners Nov 1994

Other control24

Tangential firing

Tangential firing

Tangential firing

PM control23 SO2 control22

Over Fired Air Apr 1992

Over Fired Air May 1993

Low NOx Burners Apr 1992

1

2

3

4

Tangential firing

Address

NA

NA

Cold Side ESP A&B - 1970

Cold Side ESP C - 1983 (#2)

Cold Side ESP A&B - 1971

Cold Side ESP C - 1983 (#2)

NA

NA

Coal rank(s) in use

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, etc.) control technology that you have either contracted for, are installing, or have installed for the purpose of providing a nondemonstration, full-scale operating system.

Boiler ID Company (vendor) name

Company (vendor) contact information

Name Telephone Address

NA

Type of control (e.g., 

sorbent and type; chemical 

additive28)

Desired HAP emission 

reduction (%) or emission 

rate

NA NA

FGC SO3 Injection - 1992 

(#1)

NA NA

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; precombustion boiler chemical additive; combustion boiler chemical additive), the desired HAP emission reduction or rate (if any), and the coal rank(s) in use 

or fuel type 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).

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 project25 (e.g., U.S. Department of Energy program, consent decree, etc.).

Boiler 

ID26 Company (vendor) name Name

Company (vendor) contact information

Telephone

FGC SO3 Injection - 1992 

(#1)

FGC SO3 Injection - 1992 

(#1)

FGC SO3 Injection - 1992 

(#1)

Low NOx Burners May 1993

NOx control21

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 ID19 Type20

NA NA

Cold Side ESP A&B - 1972

Cold Side ESP C - 1983 (#2)

Cold Side ESP A&B - 1973

Cold Side ESP C - 1984 (#2)

NA NA NA

Demonstration 

activity actual startup date

Demonstration 

activity projected 

start-up date

Demonstration 

activity end-date 

or projected enddate

NA NA NA NA

AmerenUE Labadie
20

Boiler 

ID30

NA

21

PM1034 PM2.535

HCl 

and/or 

HF

HCN Metal 

HAP36 Hg CO

1 NA NA NA NA NA NA NA NA NA

2 NA NA NA NA NA NA NA NA NA

3 NA NA NA NA NA NA NA NA NA

4 NA NA NA NA NA NA NA NA NA

22

PM38 PM10 PM2.5 SO2

HCl 

and/or 

HF

HCN Metal 

HAP39 Hg CO

NA NA NA NA NA NA NA NA NA NA

SO2

OP limit: 4.8 

lbs/mmBtu on a 

daily average

OP limit: 4.8 

lbs/mmBtu on a 

daily average

Expected or 

projected start-up 

date

Type of control (e.g., 

sorbent and type; chemical 

additive)31

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

NA

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

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

Boiler 

ID32 Other organics 

(specify)

Other pollutant 

(specify)

Operating Permit (OP) 

Limit: 0.12 #/mmBtu - 

Method 5 Stack Test

PM33

Operating Permit (OP) 

Limit: 0.12 #/mmBtu - 

Method 5 Stack Test

Operating Permit (OP) 

Limit: 0.12 #/mmBtu - 

Method 5 Stack Test

Operating Permit (OP) 

Limit: 0.12 #/mmBtu - 

Method 5 Stack Test

OP limit: 4.8 

lbs/mmBtu on a 

daily average

OP limit: 4.8 

lbs/mmBtu on a 

daily average

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

Boiler 

ID37 Other organics 

(specify)

Other pollutant 

(specify)

NA NA NA NA

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) or fuel 

type 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).

Actual start-up 

date

NA

NA NA

NA

NA

NA

NA

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

AmerenUE Labadie
23

Yes

No X

Please elaborate.

24

PM10 PM2.5

HCl 

and/or 

HF

HCN Metal 

HAP42 Hg CO

1 NA NA NA NA NA NA NA

2 NA NA NA NA NA NA NA

3 NA NA NA NA NA NA NA

4 NA NA NA NA NA NA NA

25

NA

NA

NA

(Include base year for operating costs [e.g., 2006])

26

Low sulfur coal

CAM

CAM

CAM

CEMS Records of daily 

average Quarterly Excess 

emissions Reporting

CEMS Records of daily 

average Quarterly Excess 

emissions Reporting

CEMS Records of daily 

average Quarterly Excess 

emissions Reporting

NA

NA

NA

Required Monitoring, Recordkeeping, and Reporting for each pollutant with permitted limit.

Was any other guarantee level sought or offered?

Installation on new boiler?

Boiler 

ID40 Other organics 

(specify) PM41 SO2

CEMS Records of daily 

average Quarterly Excess 

emissions Reporting

CAM NA

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 

For the control technologies identified in Part I, questions 17 and 19, provide the cost information requested.43

Total Capital Investment:

Total Annual Operating and Maintenance Costs:

Facility Name / Unit No.:

Retrofit to existing boiler?

AmerenUE Labadie
PART II: FUEL ANALYSIS AND EMISSION DATA

Each facility should provide the following information for each coal and oil shipment received during the preceding 12 calendar months.

1a Labadie

1b 2103

2

State/Country County47 Coal seam48

1 Sub-bituminous Jan-09 376,099.10 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

2 Sub-bituminous Jan-09 32,261.08 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

3 Sub-bituminous Jan-09 82,684.85 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

4 Sub-bituminous Jan-09 180,071.66 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

5 Sub-bituminous Jan-09 32,918.54 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

6 Sub-bituminous Jan-09 65,115.85 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

7 Sub-bituminous Jan-09 49,839.47 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

8 Sub-bituminous Jan-09 66,645.78 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

9 Sub-bituminous Jan-09 16,384.14 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

10 Sub-bituminous Jan-09 16,675.28 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

11 Sub-bituminous Jan-09 32,958.78 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

12 Sub-bituminous Feb-09 213,849.55 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

13 Sub-bituminous Feb-09 65,693.00 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

14 Sub-bituminous Feb-09 16,482.50 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

15 Sub-bituminous Feb-09 83,584.58 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

16 Sub-bituminous Feb-09 115,096.88 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

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

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

Fuel Analysis44

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):

Sample 

ID 

number

Type of Coal Months

Amount received, dry 

basis, short tons45 

Barrels

ID # of boiler(s) 

firing fuel46

Fuel source Fuel 

shipment 

method

AmerenUE Labadie
17 Sub-bituminous Feb-09 33,082.25 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

18 Sub-bituminous Feb-09 48,570.41 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

19 Sub-bituminous Feb-09 49,310.18 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

20 Sub-bituminous Feb-09 66,102.07 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

21 Sub-bituminous Feb-09 16,431.15 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

22 Sub-bituminous Feb-09 33,262.39 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

23 Sub-bituminous Feb-09 16,112.68 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

24 Sub-bituminous Mar-09 265,044.60 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

25 Sub-bituminous Mar-09 16,773.95 1, 2, 3 & 4 Wyoming/USA Campbell PRB Coal Creek Train

26 Sub-bituminous Mar-09 82,445.10 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

27 Sub-bituminous Mar-09 33,243.95 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

28 Sub-bituminous Mar-09 65,603.70 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

29 Sub-bituminous Mar-09 132,791.55 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

30 Sub-bituminous Mar-09 16,633.49 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

31 Sub-bituminous Mar-09 49,844.85 1, 2, 3 & 4 Wyoming/USA Campbell PRB Cordero Rojo Train

32 Sub-bituminous Mar-09 32,937.55 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

33 Sub-bituminous Mar-09 66,486.97 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

34 Sub-bituminous Mar-09 16,573.28 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

35 Sub-bituminous Mar-09 33,301.27 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

36 Sub-bituminous Mar-09 33,445.80 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

37 Sub-bituminous Mar-09 33,066.25 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

38 Sub-bituminous Apr-09 132,465.05 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

39 Sub-bituminous Apr-09 82,812.80 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

40 Sub-bituminous Apr-09 16,744.90 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

AmerenUE Labadie
41 Sub-bituminous Apr-09 66,698.95 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

42 Sub-bituminous Apr-09 132,538.63 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

43 Sub-bituminous Apr-09 16,612.21 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

44 Sub-bituminous Apr-09 49,359.95 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

45 Sub-bituminous Apr-09 16,578.93 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

46 Sub-bituminous Apr-09 83,292.79 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

47 Sub-bituminous Apr-09 33,418.97 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

48 Sub-bituminous Apr-09 16,751.65 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

49 Sub-bituminous Apr-09 16,744.68 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

50 Sub-bituminous Apr-09 16,632.18 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

51 Sub-bituminous May-09 50,074.65 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

52 Sub-bituminous May-09 66,625.60 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

53 Sub-bituminous May-09 50,304.95 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

54 Sub-bituminous May-09 66,522.67 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

55 Sub-bituminous May-09 133,083.47 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

56 Sub-bituminous May-09 16,723.49 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

57 Sub-bituminous May-09 49,279.85 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

58 Sub-bituminous May-09 33,353.78 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

59 Sub-bituminous May-09 49,980.49 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

60 Sub-bituminous May-09 33,451.34 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

61 Sub-bituminous May-09 16,549.88 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

62 Sub-bituminous May-09 33,571.51 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

63 Sub-bituminous May-09 16,632.18 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

64 Sub-bituminous Jun-09 133,449.60 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

65 Sub-bituminous Jun-09 81,847.15 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

AmerenUE Labadie
66 Sub-bituminous Jun-09 82,962.55 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

67 Sub-bituminous Jun-09 49,885.75 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

68 Sub-bituminous Jun-09 16,717.08 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

69 Sub-bituminous Jun-09 83,509.23 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

70 Sub-bituminous Jun-09 167,454.87 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

71 Sub-bituminous Jun-09 16,892.25 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

72 Sub-bituminous Jun-09 33,165.00 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

73 Sub-bituminous Jun-09 33,353.32 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

74 Sub-bituminous Jun-09 50,138.83 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

75 Sub-bituminous Jun-09 16,662.28 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

76 Sub-bituminous Jun-09 33,203.35 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

77 Sub-bituminous Jun-09 16,580.95 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

78 Sub-bituminous Jul-09 99,928.35 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

79 Sub-bituminous Jul-09 100,022.60 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

80 Sub-bituminous Jul-09 99,917.05 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

81 Sub-bituminous Jul-09 49,723.90 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

82 Sub-bituminous Jul-09 82,350.66 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

83 Sub-bituminous Jul-09 184,682.84 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

84 Sub-bituminous Jul-09 49,529.93 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

85 Sub-bituminous Jul-09 16,729.10 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

86 Sub-bituminous Jul-09 117,183.33 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

87 Sub-bituminous Jul-09 50,228.77 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

88 Sub-bituminous Jul-09 33,481.33 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

89 Sub-bituminous Aug-09 199,725.85 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

AmerenUE Labadie
90 Sub-bituminous Aug-09 83,478.35 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

91 Sub-bituminous Aug-09 83,434.55 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

92 Sub-bituminous Aug-09 16,710.43 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

93 Sub-bituminous Aug-09 15,353.70 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

94 Sub-bituminous Aug-09 66,734.09 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

95 Sub-bituminous Aug-09 200,463.54 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

96 Sub-bituminous Aug-09 33,541.32 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

97 Sub-bituminous Aug-09 50,076.85 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

98 Sub-bituminous Aug-09 33,643.80 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

99 Sub-bituminous Aug-09 50,075.27 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

100 Sub-bituminous Aug-09 66,473.47 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

101 Sub-bituminous Aug-09 16,872.59 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

102 Sub-bituminous Aug-09 16,794.13 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

103 Sub-bituminous Sep-09 117,025.50 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

104 Sub-bituminous Sep-09 50,581.95 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

105 Sub-bituminous Sep-09 117,316.65 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

106 Sub-bituminous Sep-09 33,317.88 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

107 Sub-bituminous Sep-09 33,397.90 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

108 Sub-bituminous Sep-09 66,549.09 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

109 Sub-bituminous Sep-09 133,718.35 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

110 Sub-bituminous Sep-09 33,617.90 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

111 Sub-bituminous Sep-09 49,807.95 1, 2, 3 & 4 Wyoming/USA Campbell PRB Cordero Train

112 Sub-bituminous Sep-09 16,581.73 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

113 Sub-bituminous Sep-09 33,466.52 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

114 Sub-bituminous Sep-09 83,230.32 1, 2, 3 & 4 Wyoming/USA Campbell PRB Jacobs 

Ranch Train

115 Sub-bituminous Sep-09 16,587.78 1, 2, 3 & 4 Wyoming/USA Campbell PEB Caballo Train

AmerenUE Labadie
116 Sub-bituminous Sep-09 16,783.85 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

117 Sub-bituminous Oct-09 164,744.85 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

118 Sub-bituminous Oct-09 66,210.45 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

119 Sub-bituminous Oct-09 99,613.20 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

120 Sub-bituminous Oct-09 50,022.07 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

121 Sub-bituminous Oct-09 50,090.85 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

122 Sub-bituminous Oct-09 133,631.10 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

123 Sub-bituminous Oct-09 83,010.46 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

124 Sub-bituminous Oct-09 33,443.75 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

125 Sub-bituminous Oct-09 33,212.98 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

126 Sub-bituminous Oct-09 49,690.53 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

127 Sub-bituminous Oct-09 49,769.30 1, 2, 3 & 4 Wyoming/USA Campbell PRB Cordero Train

128 Sub-bituminous Oct-09 33,513.86 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

129 Sub-bituminous Oct-09 13,987.43 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

130 Sub-bituminous Nov-09 132,519.55 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

131 Sub-bituminous Nov-09 99,497.85 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

132 Sub-bituminous Nov-09 133,441.35 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

133 Sub-bituminous Nov-09 33,351.80 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

134 Sub-bituminous Nov-09 49,946.40 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

135 Sub-bituminous Nov-09 150,137.10 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

136 Sub-bituminous Nov-09 66,616.85 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

137 Sub-bituminous Nov-09 83,338.40 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

138 Sub-bituminous Nov-09 49,566.50 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

AmerenUE Labadie
139 Sub-bituminous Nov-09 50,021.53 1, 2, 3 & 4 Wyoming/USA Campbell PRB Cordero Train

140 Sub-bituminous Nov-09 33,363.72 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

141 Sub-bituminous Dec-09 115,168.25 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

142 Sub-bituminous Dec-09 99,070.30 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

143 Sub-bituminous Dec-09 114,451.75 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

144 Sub-bituminous Dec-09 16,492.85 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

145 Sub-bituminous Dec-09 149,640.85 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

146 Sub-bituminous Dec-09 149,188.55 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

147 Sub-bituminous Dec-09 66,989.05 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

148 Sub-bituminous Dec-09 33,249.53 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

149 Sub-bituminous Dec-09 82,089.93 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

150 Sub-bituminous Dec-09 16,239.23 1, 2, 3 & 4 Wyoming/USA Campbell PRB Cordero Train

151 Sub-bituminous Dec-09 33,199.01 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

152 #2 Jan-09 1,624.00 1, 2, 3 & 4 Missouri/USA St. Louis NA Truck

153 #2 Feb-09 3,255.00 1, 2, 3 & 4 Missouri/USA St. Louis NA Truck

154 #2 Apr-09 1,607.00 1, 2, 3 & 4 Missouri/USA St. Louis NA Truck

155 #2 May-09 2,494.00 1, 2, 3 & 4 Missouri/USA St. Louis NA Truck

156 #2 Jun-09 1,772.00 1, 2, 3 & 4 Missouri/USA St. Louis NA Truck

157 #2 Jul-09 887.00 1, 2, 3 & 4 Missouri/USA St. Louis NA Truck

158 #2 Aug-09 708.00 1, 2, 3 & 4 Missouri/USA St. Louis NA Truck

159 #2 Sep-09 2,663.00 1, 2, 3 & 4 Missouri/USA St. Louis NA Truck

160 #2 Oct-09 1,964.00 1, 2, 3 & 4 Missouri/USA St. Louis NA Truck

161 #2 Nov-09 358.00 1, 2, 3 & 4 Missouri/USA St. Louis NA Truck

162 #2 Dec-09 3,241.00 1, 2, 3 & 4 Missouri/USA St. Louis NA Truck

3

NA

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

NA Permit requirements

NA contractual obligations

NA standard operational procedures

NA other(please specify)

For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information49, as available (dry basis)

(indicate N/A if not available):

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

NA Fuel supplier

NA Other 

6 Name and address of laboratory performing analyses:

NA

7

NA

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.

AmerenUE Labadie
Emission Data

8a

See Test Number in 8b

8b

Test 

Report Boiler ID

1 2 Stack Testing

2 2

3 2

4 2

5 2

6 2

7 1

8 2

9 3

10 4

8c

Yes

No X

If yes, please note which reports and provide a detailed description of the location of the emissions sampling point(s).

8d

Yes

No X

8e

Yes

No X

Type:

Parametric Testing

Parametric Testing

Parametric Testing

Mercury

Mercury

Were any of these test reports conducted when use of other material(s) or non-fossil fuels were fired in the boiler?

Aug-07 Mercury

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.

Nov-05

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:

Oct-05

Stack Testing

Constituents:

HCl/HF

HCl/HF

Oct-05 & Nov-05 Mercury

Particulate (CAM Testing)

Particulate (CAM Testing)

Particulate (CAM Testing)

10/25/2005

10/19/2005

If yes, please note which reports and identify the other material(s) or non-fossil fuels used.

Do any of these test reports reflect testing during periods of startup, shutdown, and malfunction?

Parametric Testing

Parametric Testing

Parametric Testing

Parametric Testing

If yes, please note which reports.

Dec-06

Feb-07

10/25/2005

Do any of these test reports reflect testing at a location upstream of any emission control devices?

Parametric Testing

10/19/2005 Particulate (CAM Testing)

AmerenUE Labadie
8f

Yes

No X

8g

Yes

No X

9

10

Yes X

No

11

Yes

No X

12

Boiler ID Date of test Load Moisture CO2 Flue gas 

Temp

2 Oct-05 620 11.74 14.6 316.8

2 Nov-05 NA 11.37 12.4 302.9

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 or permit authority, even if from short-term testing?

Total Suspended Part. = 0.0137 lb/mmBtu 

Condensible Part. = 0.0236 lb/mmBtu 

Combined Part. = 0.0373 lb/mmBtu

HCL = 1.86 lb/hr 

HF = 3.68 lb/hr 

PM54 HCl/HF/HCN

Total Suspended Part. = 0.0152 lb/mmBtu 

Condensible Part. = 0.0195 lb/mmBtu 

Combined Part. = 0.0347 lb/mmBtu

HCL = 1.68 lb/hr 

HF = 4.64 lb/hr 

Quarterly excess emissions reports, notifications to Missouri Department of Natural Resources for deviations from permit conditions within 10 days of 

occurrence

Quarterly excess emissions reports, notifications to Missouri Department of Natural Resources for deviations from permit conditions within 10 days of 

occurrence

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 exhaust gas flow). Note by diagram where 

sampling ports were located in relation to the bypass ductwork

Did the unit’s control configuration differ from that shown in Part I, question 16, at the time of these test results?

If yes, please list the unit’s complete control configuration at time of testing in a similar format to Part I, question 16.

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

If yes51, 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 CEMS data are being provided to EPA, please note to which Office 

the data are being provided.

Do any of these test reports reflect testing at a location upstream of a post combustion SO2 emission control device (e.g., FGD, SDA, Dry Scrubber)?

What type of deviation reporting is required for violations of permit requirements?

Are deviation reports available for malfunctions or other periods of noncompliance with permit terms and conditions?

If yes, please note which reports.

AmerenUE Labadie
Date of test PM54 

lb/mmBtu SO2 Percent 

Moisture

Flue Gas 

Flow 

DSCFH

O2 CO

Flue Gas 

Temp. 

Deg F

CO2

1 3/15/2005 0.041 NA 9.97 85422609 6.4 NA 313.4 12.5

2 3/15/2005 0.0308 NA 9.79 78943733 6.3 NA 317 12.9

3 5/24/2005 0.0298 NA 11.69 81624180 6.1 NA 327.6 12.7

4 5/24/2005 0.0235 NA 10.31 82456723 5.9 NA 328.5 13

Boiler ID

Emissions test results (indicate format of emission data)52,53

AmerenUE Labadie
PART I: GENERAL FACILITY INFORMATION

1

2

3 1901 Chouteau Avenue, St. Louis, MO 63166

4a Meramec

4b 2104

5 8200 Fine Road, St. Louis, MO 63129

6

7 Donald Schuh, Sr. Environmental Scientist

8 314-554-2658

Email address dschuh@ameren.com

9

Yes

No X

10

X

X

X

11

X

X

X

12

%

100 %

%

%

% Specify type

%

13

NA %

NA %

NA % Specify

Union Electric Co. dba AmerenUE

Contact telephone number:

Name of legal owner of facility:

Name of legal operator of facility

Address of legal owner or operator:

Plant Name

EIA Plant Code:

lignite

Natural Gas

Coal

Oil

Other

Coal

Natural Gas

Other

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:7,8

Oil

bituminous

distillate

residual or bunkerC

other

anthracite

synfuel

petroleum coke

If oil is fired, indicate which type of oil was utilized during the previous 12 months prior to the receipt of this ICR:9

Union Electric Co. dba AmerenUE

Is this facility considered to be owned or operated by a small entity as defined by the Regulatory Flexibility Act?

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

Which of the following fossil fuels or other material(s) are permitted6 to be fired in any steam generating unit at this facility?

Complete street address:

Provide mailing address if different:

Name and title of contact:

subbituminous

AmerenUE Meramec
14a

Boiler Chemical Cleaning Wash

14b

Yes

No X Ameren will continue to burn as long as we are not subject to CAA Section 129

15

Coal

Fuel16

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.

1566

Coal

3782

Present operating gross efficiency (%, HHV)

Spent Deminerlalizer Resin Yes

None in 2009

Used Oil Yes

Yes 306 cubic feet

Yes

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 permitted10 to burn non-fossil fuel(s) or other material(s) even if you do not actually burn them.

3782

Boiler ID11

Original design fuel (i.e. coal rank or type of oil)

Design heat input, (MMBtu/hr)12

1

Coal

1566

2

1566

4

MWe Net capacity summer

Original design gross efficiency (%, HHV)

Design steam reheat temperature (°F)14

Operating steam reheat temperature (°F)15

Hours/year operated17

Design steam pressure (psig)

Operating steam pressure (psig)

Design steam temperature (°F)

Operating steam temperature (°F)

1400

1456

950

1566

128

119

88.1

2150

1010

84.23

77

NA

950

950

950

Sub-bituminous

84.99

2150

362

7662

76

NA

NA NA

1010

1010

1010

2266

1010

Sub-bituminous

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?

1010

1010

Sub-bituminous

MWe Gross capacity summer

263

3

82.53

8193

282

88.82

950

1010

343

86.77

83.4

2200

950

88.1

NA NA

Coal

3172

3172

73 64

7557

NA

128

120

8333

950

Sub-bituminous

1400

1456

950

Average annual capacity factor for the past 3 years

Applicable NSPS NA

Estimated year of retirement18

None in 2009

Yes

Other Material Permitted to burn Actually burn Quantity/year

Yes

Present maximum heat input, (MMBtu/hr)13

Paint Solids Yes Yes None in 2009

AmerenUE Meramec
16

17

NA

18

Boiler 

ID27

NA

19

NA

NA NA NA NA

NA 

NA

Other control24 NOx control21

Over Fired Air Nov 2006

Tangential firing NA

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.):

SO2 control22

Cold Side ESP (#1)

Cold Side ESP (#1)

Over Fired Air Jan 2002

Low NOx Burner Jan 2002

Boiler ID19 Type20

1

2

3

Low NOx Burner Apr 2004

NA NA

Low NOx Burner Nov 2006

PM control23

Over Fired Air Apr 2004

Over Fired Air Apr 2004

Low NOx Burner Apr 2004

NA

NA

Cold Side ESP (#1)

NA

Boiler 

ID26 Company (vendor) name Name

Company (vendor) contact information

Telephone Address

NA

Company (vendor) contact information

Name Telephone Address

Demonstration 

activity end-date 

or projected enddate

Type of control (e.g., 

sorbent and type; chemical 

additive28)

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 project25 (e.g., U.S. Department of Energy program, consent decree, etc.).

4

Coal rank(s) in use

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, etc.) control technology that you have either contracted for, are installing, or have installed for the purpose of providing a nondemonstration, full-scale operating system.

Boiler ID Company (vendor) name

NA

Tangential firing NA NA

NA NA NA NA

Wall Fired

Wall Fire

Desired HAP emission 

reduction (%) or emission 

rate

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; precombustion boiler chemical additive; combustion boiler chemical additive), the desired HAP emission reduction or rate (if any), and the coal rank(s) in use 

or fuel type 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).

Demonstration 

activity actual startup date

Demonstration 

activity projected 

start-up date

Cold Side ESP (#1)

NA

NA

AmerenUE Meramec
20

Boiler 

ID30

NA

21

PM1034 PM2.535

HCl 

and/or 

HF

HCN Metal 

HAP36 Hg CO

Other 

organics 

(specify)

Other 

pollutant 

(specify)

1 NA NA NA NA NA NA NA NA NA

2 NA NA NA NA NA NA NA NA NA

3 NA NA NA NA NA NA NA NA NA

4 NA NA NA NA NA NA NA NA NA

OP limit: 2.3 lbs/mmBtu on a 3-hr 

rolling average; can exceed allowable 

rate by not more than 20% for not 

more than 3 days in any one month

Boiler 

ID32

Actual start-up 

date

Coal rank(s) upon which 

guarantee is based

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

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

Operating Permit 

(OP) Limit: 0.12 

#/mmBtu - 

Method 5 Stack 

Test

Operating Permit 

(OP) Limit: 0.12 

#/mmBtu - 

Method 5 Stack 

Test

Guaranteed HAP 

emission 

reduction (%) or 

emission rate

OP limit: 2.3 lbs/mmBtu on a 3-hr 

rolling average; can exceed allowable 

rate by not more than 20% for not 

more than 3 days in any one month

PM33

Operating Permit 

(OP) Limit: 0.12 

#/mmBtu - 

Method 5 Stack 

Test

SO2

OP limit: 2.3 lbs/mmBtu on a 3-hr 

rolling average; can exceed allowable 

rate by not more than 20% for not 

more than 3 days in any one month

OP limit: 2.3 lbs/mmBtu on a 3-hr 

rolling average; can exceed allowable 

rate by not more than 20% for not 

more than 3 days in any one month

Operating Permit 

(OP) Limit: 0.12 

#/mmBtu - 

Method 5 Stack 

Test

Sorbent or additive feed 

rate on which guarantee is 

based

NA NA NA NA NA NA

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) or fuel 

type 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).

Expected or 

projected start-up 

date

Type of control (e.g., 

sorbent and type; chemical 

additive)31

AmerenUE Meramec
22

PM38 PM10 PM2.5 SO2

HCl 

and/or 

HF

HCN Metal 

HAP39 Hg CO

NA NA NA NA NA NA NA NA NA NA

23

Yes

No X

Please elaborate.

24

PM10 PM2.5

HCl 

and/or 

HF

HCN

Metal 

HAP42 Hg CO

1 NA NA NA NA NA NA NA

2 NA NA NA NA NA NA NA

3 NA NA NA NA NA NA NA

4 NA NA NA NA NA NA NA

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

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

NA

NA

Boiler 

ID37 Other organics 

(specify)

Other pollutant 

(specify)

CEMS Records of 3 hr 

rolling average Quarterly 

Excess emissions 

Reporting

CEMS Records of 3 hr 

rolling average Quarterly 

Excess emissions 

Reporting

CAM

CAM

CAM

NA NA

CEMS Records of 3 hr 

rolling average Quarterly 

Excess emissions 

Reporting

NA

CEMS Records of 3 hr 

rolling average Quarterly 

Excess emissions 

Reporting

NA

Boiler 

ID40 Other organics 

(specify) PM41

Required Monitoring, Recordkeeping, and Reporting for each pollutant with permitted limit.

SO2

CAM

Was any other guarantee level sought or offered?

AmerenUE Meramec
25

NA

NA

NA

(Include base year for operating costs [e.g., 2006])

26

Low Sulfur coal

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 

For the control technologies identified in Part I, questions 17 and 19, provide the cost information requested.43

Total Capital Investment:

Total Annual Operating and Maintenance Costs:

Facility Name / Unit No.:

Retrofit to existing boiler?

Installation on new boiler?

AmerenUE Meramec
PART II: FUEL ANALYSIS AND EMISSION DATA

Each facility should provide the following information for each coal and oil shipment received during the preceding 12 calendar months.

1a Meramec

1b 2104

2

State/Country County47 Coal seam48

1 Sub-bituminous Jan-09 78,304.55 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

2 Sub-bituminous Jan-09 47,094.75 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

3 Sub-bituminous Jan-09 94,994.48 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

4 Sub-bituminous Jan-09 31,056.45 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

5 Sub-bituminous Jan-09 15,583.28 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

6 Sub-bituminous Jan-09 15,417.13 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

7 Sub-bituminous Jan-09 47,076.83 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

8 Sub-bituminous Jan-09 31,789.13 1, 2, 3 & 4 Wyoming/USA Campbell PRB Belle Ayr Train

9 Sub-bituminous Feb-09 78,600.75 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

10 Sub-bituminous Feb-09 46,615.15 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

11 Sub-bituminous Feb-09 15,527.40 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

12 Sub-bituminous Feb-09 62,634.50 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

13 Sub-bituminous Feb-09 46,779.38 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

14 Sub-bituminous Feb-09 15,747.29 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

15 Sub-bituminous Feb-09 15,253.75 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

16 Sub-bituminous Feb-09 15,717.28 1, 2, 3 & 4 Wyoming/USA Campbell PRB Belle Ayr Train

17 Sub-bituminous Mar-09 62,881.00 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

18 Sub-bituminous Mar-09 31,409.15 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

19 Sub-bituminous Mar-09 29,631.93 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

20 Sub-bituminous Mar-09 47,097.88 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

21 Sub-bituminous Mar-09 31,040.57 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

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

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

Fuel Analysis44

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):

Sample 

ID 

number

Type of Coal Months

Amount received, dry 

basis, short tons45

ID # of boiler(s) 

firing fuel46

Fuel source Fuel 

shipment 

method

AmerenUE Meramec
22 Sub-bituminous Mar-09 62,724.25 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

23 Sub-bituminous Mar-09 31,453.93 1, 2, 3 & 4 Wyoming/USA Campbell PRB Belle Ayr Train

24 Sub-bituminous Apr-09 15,414.10 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

25 Sub-bituminous Apr-09 31,328.45 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

26 Sub-bituminous Apr-09 78,685.40 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

27 Sub-bituminous Apr-09 15,883.90 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

28 Sub-bituminous Apr-09 31,403.71 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

29 Sub-bituminous Apr-09 31,671.58 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

30 Sub-bituminous Apr-09 15,716.55 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

31 Sub-bituminous Apr-09 13,732.18 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

32 Sub-bituminous Apr-09 13,749.90 1, 2, 3 & 4 Wyoming/USA Campbell PRB Belle Ayr Train

33 Sub-bituminous May-09 31,258.70 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

34 Sub-bituminous May-09 31,383.60 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

35 Sub-bituminous May-09 15,547.35 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

36 Sub-bituminous May-09 62,808.43 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

37 Sub-bituminous May-09 31,504.20 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

38 Sub-bituminous May-09 31,729.47 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

39 Sub-bituminous May-09 31,007.28 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

40 Sub-bituminous May-09 47,378.38 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

41 Sub-bituminous May-09 31,081.83 1, 2, 3 & 4 Wyoming/USA Campbell PRB Belle Ayr Train

42 Sub-bituminous Jun-09 31,084.75 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

43 Sub-bituminous Jun-09 31,394.35 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

44 Sub-bituminous Jun-09 15,683.45 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

45 Sub-bituminous Jun-09 47,147.10 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

46 Sub-bituminous Jun-09 31,380.53 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

47 Sub-bituminous Jun-09 31,374.56 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

48 Sub-bituminous Jun-09 31,652.90 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

AmerenUE Meramec
49 Sub-bituminous Jun-09 31,698.03 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

50 Sub-bituminous Jun-09 15,657.43 1, 2, 3 & 4 Wyoming/USA Campbell PRB Belle Ayr Train

51 Sub-bituminous Jul-09 78,499.95 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

52 Sub-bituminous Jul-09 31,556.45 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

53 Sub-bituminous Jul-09 15,622.75 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

54 Sub-bituminous Jul-09 47,124.78 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

55 Sub-bituminous Jul-09 47,207.50 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

56 Sub-bituminous Jul-09 31,772.28 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

57 Sub-bituminous Jul-09 15,732.75 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

58 Sub-bituminous Jul-09 31,713.35 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

59 Sub-bituminous Jul-09 30,730.10 1, 2, 3 & 4 Wyoming/USA Campbell PRB Belle Ayr Train

60 Sub-bituminous Aug-09 31,503.25 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

61 Sub-bituminous Aug-09 47,048.35 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

62 Sub-bituminous Aug-09 78,532.58 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

63 Sub-bituminous Aug-09 15,731.53 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

64 Sub-bituminous Aug-09 31,669.48 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

65 Sub-bituminous Aug-09 15,728.55 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

66 Sub-bituminous Aug-09 31,556.98 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

67 Sub-bituminous Aug-09 31,273.33 1, 2, 3 & 4 Wyoming/USA Campbell PRB Belle Ayr Train

68 Sub-bituminous Sep-09 15,851.10 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

69 Sub-bituminous Sep-09 31,587.60 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

70 Sub-bituminous Sep-09 78,540.53 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

71 Sub-bituminous Sep-09 15,638.25 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

72 Sub-bituminous Sep-09 31,315.45 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

73 Sub-bituminous Sep-09 15,837.18 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

AmerenUE Meramec
74 Sub-bituminous Sep-09 15,766.40 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

75 Sub-bituminous Sep-09 31,418.68 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

76 Sub-bituminous Sep-09 31,058.13 1, 2, 3 & 4 Wyoming/USA Campbell PRB Belle Ayr Train

77 Sub-bituminous Oct-09 15,461.15 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

78 Sub-bituminous Oct-09 15,606.90 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

79 Sub-bituminous Oct-09 125,448.75 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

80 Sub-bituminous Oct-09 15,743.13 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

81 Sub-bituminous Oct-09 15,821.56 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

82 Sub-bituminous Oct-09 15,718.60 1, 2, 3 & 4 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

83 Sub-bituminous Oct-09 31,216.85 1, 2, 3 & 4 Wyoming/USA Campbell PRB Belle Ayr Train

84 Sub-bituminous Nov-09 34,461.00 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

85 Sub-bituminous Nov-09 15,806.45 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

86 Sub-bituminous Nov-09 62,697.68 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

87 Sub-bituminous Nov-09 47,143.88 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

88 Sub-bituminous Nov-09 15,690.55 1, 2, 3 & 4 Wyoming/USA Campbell PRB Caballo Train

89 Sub-bituminous Nov-09 31,336.03 1, 2, 3 & 4 Wyoming/USA Campbell PRB Belle Ayr Train

90 Sub-bituminous Dec-09 15,931.65 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

91 Sub-bituminous Dec-09 31,073.75 1, 2, 3 & 4 Wyoming/USA Campbell PRB Black 

Thunder Train

92 Sub-bituminous Dec-09 15,784.05 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

93 Sub-bituminous Dec-09 47,055.25 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

94 Sub-bituminous Dec-09 62,869.60 1, 2, 3 & 4 Wyoming/USA Campbell PRB Antelope Train

95 Sub-bituminous Dec-09 15,459.88 1, 2, 3 & 4 Wyoming/USA Campbell PRB Belle Ayr Train

3

NA

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

NA Permit requirements

NA contractual obligations

NA standard operational procedures

NA other(please specify)

For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information49, as available (dry basis)

(indicate N/A if not available):

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

NA Fuel supplier

NA Other 

6 Name and address of laboratory performing analyses:

NA

7

NA

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.

AmerenUE Meramec
Emission Data

8a

See Test Number in 8b

8b

Test 

Report Boiler ID

1 1

2 2

3 3

4 4

5 3

6 4

7 2

8c

Yes

No X

If yes, please note which reports and provide a detailed description of the location of the emissions sampling point(s).

8d

Yes

No X

8e

Yes

No X

8f

Yes

No X

10/25/2005

10/19/2005

Parametric testing Mercury

Particulate (CAM Testing)

Particulate (CAM Testing)

Particulate (CAM Testing)

Particulate (CAM Testing)

Parametric Testing

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.

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:

10/19/2005 Parametric Testing

Parametric Testing

10/25/2005 Parametric Testing

Jun-07 Parametric testing

Jun-07 Parametric testing Mercury

Mercury

Oct-2006 - Nov-2006

Do any of these test reports reflect testing at a location upstream of any emission control devices?

Were any of these test reports conducted when use of other material(s) or non-fossil fuels were fired in the boiler?

If yes, please note which reports and identify the other material(s) or non-fossil fuels used.

Do any of these test reports reflect testing during periods of startup, shutdown, and malfunction?

If yes, please note which reports.

Did the unit’s control configuration differ from that shown in Part I, question 16, at the time of these test results?

If yes, please list the unit’s complete control configuration at time of testing in a similar format to Part I, question 16.

AmerenUE Meramec
8g

Yes

No X

9

10

Yes X

No

11

Yes

No X

12

Date of 

test

PM54 

lb/mmBtu SO2 Percent 

Moisture

Flue Gas 

Flow 

DSCFH

O2 CO

Flue Gas 

Temp. 

Deg F

CO2

1 10/25/2005 0.0292 NA 9.65 22627969 5.4 NA 279.8 14.1

2 10/25/2005 0.0092 NA 11.61 20377090 5.3 NA 315.9 14.1

3 10/19/2005 0.0185 NA 11.33 41219472 5.9 NA 383.2 13.5

4 10/19/2005 0.0103 NA 10.48 58073965 6.3 NA 320.3 13.5

Are deviation reports available for malfunctions or other periods of noncompliance with permit terms and conditions?

If yes, please note which reports.

Quarterly excess emissions reports, notifications to St. Louis County Department of Health (permitting authority) for deviations from permit conditions 

within 10 days of occurrence

Do any of these test reports reflect testing at a location upstream of a post combustion SO2 emission control device (e.g., FGD, SDA, Dry Scrubber)?

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 exhaust gas flow). Note by diagram where 

sampling ports were located in relation to the bypass ductwork

What type of deviation reporting is required for violations of permit requirements?

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 or permit authority, even if from short-term testing?

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

Boiler ID

If yes51, 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 CEMS data are being provided to EPA, please note to which Office 

the data are being provided.

Emissions test results (indicate format of emission data)52,53

Quarterly excess emissions reports, notifications to St. Louis County Department of Health (permitting authority) for deviations from permit conditions 

within 10 days of occurrence

AmerenUE Meramec

PART I: GENERAL FACILITY INFORMATION

1

2 Ameren Energy Generating Company

3 1901 Chouteau Avenue, St. Louis, MO 63166

4a Meredosia

4b 864

5 800 South Washington St., Meredosia, IL 62665

6

7 Donald Schuh, Sr. Environmental Scientist

8 314-554-2658

Email address dschuh@ameren.com

9

Yes

No X

10

X

X

X Used for startup boiler 6

X

11

X

X

X Used for startup boiler 6

X

12

%

100 % Boiler 5

100 % Boilers 1, 2, 3 and 4

%

% Specify type

%

13

100 % #2

%

100 % #4 equivalent blend of oil Used in Boiler 6

Which of the following fossil fuels or other material(s) are permitted6 to be fired in any steam generating unit at this facility?

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:7,8

Oil

Natural Gas

Other

Coal

subbituminous

bituminous

synfuel

petroleum coke

If oil is fired, indicate which type of oil was utilized during the previous 12 months prior to the receipt of this ICR:9

residual or bunkerC

distillate

other

Complete street address:

Provide mailing address if different:

Name and title of contact:

lignite

Natural Gas

Coal

Oil

Other

Is this facility considered to be owned or operated by a small entity as defined by the Regulatory Flexibility Act?

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

anthracite

Ameren Energy Generating Company

Contact telephone number:

Name of legal owner of facility:

Name of legal operator of facility

Address of legal owner or operator:

Plant Name

EIA Plant Code:

AmerenAGC Meredosia
14a

14b

Yes

No X Ameren will continue to burn as long as we are not subject to CAA Section 129

15

2435 2716 2779 2600

16 19 20 20

Note: Average annual capacity factor for past 3 years based on heat input to each boiler

Operating steam pressure (psig)

No

NA

No

NA NA

No

NA

Boiler Chemical Cleaning Wash

Used Oil None in 2009

Design heat input, (MMBtu/hr)12

2

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.

bituminous

NA

900

NA

No

Actually burn

850

850

83.60%

29.5

28

85.20%

29.5

83.90%

Yes None in 2009

NA

Quantity/year

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?

Original design fuel (i.e. coal rank or type of oil)

1

coal

3

Permitted to burn

bituminous

29.5

28

85.20%

84.10% 84.70%

900

NA

bituminous

850

900

850

900

29.5

27.5

85.20%

850

900

900

NA

850

850

MWe Net capacity summer

Original design gross efficiency (%, HHV)

Design steam reheat temperature (°F)14

Average annual capacity factor for the past 3 years

Applicable NSPS

Estimated year of retirement18

900

NA

Operating steam reheat temperature (°F) NA 15

Fuel16

Hours/year operated17

Design steam temperature (°F)

Operating steam temperature (°F)

bituminous

NA

Present maximum heat input, (MMBtu/hr)13

505

900

505

505

MWe Gross capacity summer

27.5

85.20%

850

505 505

505 505 505

Design steam pressure (psig)

coal

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 permitted10 to burn non-fossil fuel(s) or other material(s) even if you do not actually burn them.

4

coal

Yes

Boiler ID11

coal

Other Material

Present operating gross efficiency (%, HHV)

Yes

Yes

AmerenAGC Meredosia
coal Fuel Oil

2784 2052

Original design fuel (i.e. coal rank or type of oil)

166

Boiler ID11 5 6

MWe Gross capacity summer 204 180

Present maximum heat input, (MMBtu/hr)13 2784 2052

Design heat input, (MMBtu/hr)12

MWe Net capacity summer 191

Design steam pressure (psig) 2000

Present operating gross efficiency (%, HHV)

88.16%

88.28%

Original design gross efficiency (%, HHV) 87.42%

85.70%

2400

Design steam temperature (°F) 1050 1000

Operating steam pressure (psig) 2000 2400

Design steam reheat temperature (°F)14 1000 1000

Operating steam temperature (°F) 1025 1000

Operating steam reheat temperature (°F)15 1000 1000

Fuel16 Sub-bituminous #4 equivalent 

blend of oil

Hours/year operated17 6505 59

Average annual capacity factor for the past 3 years 47 0

Applicable NSPS NA Subpart D

Estimated year of retirement18 NA NA

AmerenAGC Meredosia
16

Boiler 

ID19

1

2

3

4

6

17

Phase 1 -

Boiler 5 

(Unit 3) 

Phase 2 -

Boiler 3 

(Unit 2) 

NA

FGC 7/2006 (#1)

FGC 7/2006 (#1)

FGC 7/2006 (#1)

Cold Side ESP 1972 (#2)

FGC 7/2006 (#1)

V3, Tangentially Fired, 

Natural Circulation, Non 

Reheat

V3, Tangentially Fired, 

Natural Circulation, Non 

Reheat

Other control24 PM control23

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.):

NOx control21 SO2 control22

Cold Side ESP 1972 (#2)

Cold Side ESP 1972 (#2)

2895 W. Oxford Avenue, Suite 1, Englewood CO 80110

Ramsay Chang 650-855-2535 3412 Hillview Ave, Palo Alto, CA 94303

Massoud Rostam-Abadi (217) 244-4977 615 East Peabody Drive, Champaign, IL 61820

Name

Over Fired Air 12/2009

Wall Fired, Pressurized, 

Reheat, Natural Circulation

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 project25 (e.g., U.S. Department of Energy program, consent decree, etc.).

Address

Tangentially Fired, 

Controlled Circulation, 

Radiant Reheat, Twin 

Furnace

Low NOx Burners 11/1994

Low NOx Burners 12/2009

Company (vendor) contact information

Telephone

(303) 783-9599

Electric Power Research 

Institute (EPRI)

Apogee Scientific Kevin Fisher

Illinois State Geological 

Survey

Boiler 

ID26 Company (vendor) name

5

Cold Side ESP 1972 (#2)

Type20

V3, Tangentially Fired, 

Natural Circulation, Non 

Reheat

V3, Tangentially Fired, 

Natural Circulation, Non 

Reheat

FGR, OFA 9/1975

NA

NA

Cold Side ESP 1972

Cold Side ESP 11/1992 

(#3)

NA

FGC 3/2003 (#2)

ACI 8/2009 (#1)

NA

NA

NA

NA

NA

NA

NA

NA

AmerenAGC Meredosia
18

Boiler 

ID27

Phase 1 -

Boiler 5 

(Unit 3) 

Phase 2 -

Boiler 3 

(Unit 2) 

19

5

20

Boiler 

ID30

5 5 Lb/mmacf NA

Sorbent or additive feed 

rate on which guarantee is 

based

Dec-08

Sorbent Activation Process (SAP) 

for procuding activated carbon onsite for mercury control

Coal rank(s) in use

Jan-09 Feb-09

NA Activated Carbon NA

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) or fuel type 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).

Actual start-up 

date

Expected or 

projected start-up 

date

Type of control (e.g., 

sorbent and type; chemical 

additive)31

PRB

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) in use or fuel type 

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).

Demonstration 

activity actual startup date

NA

90.00%

Demonstration 

activity projected 

start-up date

Demonstration 

activity end-date 

or projected enddate

Type of control (e.g., 

sorbent and type; chemical 

additive28)

Desired HAP emission 

reduction (%) or emission 

rate

Nov-08 NA

PRB / Illinois bituminous

Sorbent Activation Process (SAP) 

for procuding activated carbon onsite for mercury control

90.00%

8/6/2009

Coal rank(s) upon which 

guarantee is based

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, etc.) control technology that you have either contracted for, are installing, or have installed for the purpose of providing a nondemonstration, full-scale operating system.

Boiler ID Company (vendor) name

Company (vendor) contact information

Name Telephone Address

Guaranteed HAP 

emission 

reduction (%) or 

emission rate

ADA Envronmetal Solutions Cody Wilson 303-339-8860 8100 Southpark Way, Unit B, Littleton, CO 80120

AmerenAGC Meredosia
21

PM1034 PM2.535

HCl 

and/or 

HF

HCN Metal 

HAP36 CO

Other 

organics 

(specify)

1 NA NA NA NA NA NA NA

2 NA NA NA NA NA NA NA

3 NA NA NA NA NA NA NA

4 NA NA NA NA NA NA NA

5 NA NA NA NA NA

SIP Limit 200 

ppm 

corrected to 

50% excess 

air 

Opacity 

30% 6-

min. avg. 

based on 

COMS

6 NA NA NA NA NA NA NA

22

PM38 PM10 PM2.5 SO2

HCl 

and/or 

HF

HCN Metal 

HAP39 Hg CO

NA NA NA NA NA NA NA NA NA NA

23

Yes

No X

Please elaborate.

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

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

Boiler 

ID32

OP Limit: 23,000 SO2 #/hr - 3hr 

ave. facility limit Based on CEMS

NA

NA

NA

Hg

NA NA

Operating Permit (OP) 

Limit: 0.20 #/mmBtu - 

Method 5 Stack Test

NA

Operating Permit (OP) 

Limit: 0.20 #/mmBtu - 

Method 5 Stack Test

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

SO2

OP Limit: 23,000 SO2 #/hr - 3hr 

ave. facility limit Based on CEMS

OP Limit: 23,000 SO2 #/hr - 3hr 

ave. facility limit Based on CEMS

OP Limit: 23,000 SO2 #/hr - 3hr 

ave. facility limit Based on CEMS

Other pollutant 

(specify)

OP Limit: 23,000 SO2 #/hr - 3hr 

ave. facility limit Based on CEMS

OP Limit: 23,000 SO2 #/hr - 3hr 

ave. facility limit Based on CEMS

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

Boiler 

ID37 Other organics 

(specify)

NA

Operating Permit (OP) 

Limit: 0.20 #/mmBtu - 

Method 5 Stack Test

Operating Permit (OP) 

Limit: 0.10 #/mmBtu - 

Method 5 Stack Test

Operating Permit (OP) 

Limit: 0.10 #/mmBtu - 

Method 5 Stack Test

PM33

Operating Permit (OP) 

Limit: 0.20 #/mmBtu - 

Method 5 Stack Test

NA

Was any other guarantee level sought or offered?

AmerenAGC Meredosia
24

PM10 PM2.5

HCl 

and/or 

HF

HCN Metal 

HAP42 Hg CO

1 NA NA NA NA NA NA NA

2 NA NA NA NA NA NA NA

3 NA NA NA NA NA NA NA

4 NA NA NA NA NA NA NA

5 NA NA NA NA NA NA NA

6 NA NA NA NA NA NA NA

25

Boiler 5

Yes

No

(Include base year for operating costs [e.g., 2006]) 2009 Dollars

Boiler 5 & 3

No

No

26

Low sulfur coal

Installation on new boiler?

Retrofit to existing boiler?

Facility Name / Unit No.:

For the control technologies identified in Part I, questions 17 and 19, provide the cost information requested.43

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.

Total Capital Investment:

Total Annual Operating and Maintenance Costs:

Facility Name / Unit No.:

$3,041,546.00

$1,919,253.00

Retrofit to existing boiler?

Installation on new boiler?

Total Project Cost $700,000.00

Stack test as 

requested by 

agency

CEMS Records of 3 hr block ave. 

Quarterly Excess emissions 

Reporting

CEMS Records of 3 hr block ave. 

Quarterly Excess emissions 

Reporting

CEMS Records of 3 hr block ave. 

Quarterly Excess emissions 

Reporting

CEMS Records of 3 hr block ave. 

Quarterly Excess emissions 

Reporting

CEMS Records of 3 hr block ave. 

Quarterly Excess emissions 

Reporting

Stack test as 

requested by 

agency

Stack test as 

requested by 

agency

Stack test as 

requested by 

agency

Stack test as 

requested by 

agency

NA

Other organics (specify)

NA

NA

NA

NA

NA

Boiler 

ID40

Required Monitoring, Recordkeeping, and Reporting for each pollutant with permitted limit.

Stack test as 

requested by 

agency

SO2

CEMS Records of 3 hr block ave. 

Quarterly Excess emissions 

Reporting

PM41

AmerenAGC Meredosia
PART II: FUEL ANALYSIS AND EMISSION DATA

Each facility should provide the following information for each coal and oil shipment received during the preceding 12 calendar months.

1a Meredosia

1b 864

2

State/Country County47 Coal seam48

1 Sub-bituminous Jan-09 48,146.68 5 Wyoming/USA Campbell PRB Antelope Train/Barge

2 Sub-bituminous Jan-09 64,169.38 5 Wyoming/USA Campbell PRB Antelope Train/Barge

3 Sub-bituminous Feb-09 64,593.80 5 Wyoming/USA Campbell PRB Antelope Train/Barge

4 Sub-bituminous Mar-09 16,169.95 5 Wyoming/USA Campbell PRB Antelope Train/Barge

5 Sub-bituminous Mar-09 15,512.00 5 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train/Barge

6 Sub-bituminous Apr-09 15,932.98 5 Wyoming/USA Campbell PRB Antelope Train/Barge

7 Sub-bituminous Jul-09 13,836.40 5 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train/Barge

8 Sub-bituminous Aug-09 64,738.10 5 Wyoming/USA Campbell PRB Antelope Train/Barge

9 Sub-bituminous Sep-09 32,316.23 5 Wyoming/USA Campbell PRB Antelope Train/Barge

10 Sub-bituminous Dec-09 47,898.10 5 Wyoming/USA Campbell PRB Antelope Train

11 #2 Jan-09 848.00 1, 2, 3, 4 & 5 Illinois/USA Menard NA Truck

12 #2 Feb-09 500.00 1, 2, 3, 4 & 5 Illinois/USA Menard NA Truck

13 #2 May-09 676.00 1, 2, 3, 4 & 5 Illinois/USA Menard NA Truck

14 #2 Jun-09 505.00 1, 2, 3, 4 & 5 Illinois/USA Menard NA Truck

15 #2 Aug-09 833.00 1, 2, 3, 4 & 5 Illinois/USA Menard NA Truck

16 #2 Sep-09 505.00 1, 2, 3, 4 & 5 Illinois/USA Menard NA Truck

17 #2 Dec-09 672.00 1, 2, 3, 4 & 5 Illinois/USA Menard NA Truck

3

NA

ID # of boiler(s) 

firing fuel46

Fuel source Fuel 

shipment 

method

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

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

Fuel Analysis44

For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information49, as available (dry basis)

(indicate N/A if not available):

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):

Sample 

ID 

number

Type of Coal Months

Amount received, dry 

basis, short tons45

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

NA Permit requirements

NA contractual obligations

NA standard operational procedures

NA other(please specify)

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

NA Fuel supplier

NA Other 

6 Name and address of laboratory performing analyses:

NA

7

NA

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.

AmerenAGC Meredosia
Emission Data 

8a

See Test Number in 8b

8b

Test 

Report Boiler ID

1 5

2 5

8c

Yes

No X

If yes, please note which reports and provide a detailed description of the location of the emissions sampling point(s).

8d

Yes

No X

8e

Yes

No X

8f

Yes

No X

8g

Yes

No X

Aug-09 Stack Testing Mercury

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.

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:

Sep-05 Stack Testing Mercury

If yes, please list the unit’s complete control configuration at time of testing in a similar format to Part I, question 16.

Do any of these test reports reflect testing at a location upstream of a post combustion SO2 emission control device (e.g., FGD, SDA, Dry Scrubber)?

Do any of these test reports reflect testing at a location upstream of any emission control devices?

Were any of these test reports conducted when use of other material(s) or non-fossil fuels were fired in the boiler?

If yes, please note which reports and identify the other material(s) or non-fossil fuels used.

Do any of these test reports reflect testing during periods of startup, shutdown, and malfunction?

If yes, please note which reports.

Did the unit’s control configuration differ from that shown in Part I, question 16, at the time of these test results?

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 exhaust gas flow). Note by diagram where 

sampling ports were located in relation to the bypass ductwork

AmerenAGC Meredosia
9

10

Yes X

No

11

Yes

No X

12

Date of 

test PM54 SO2 HCl/HF/HCN

Metal 

HAP55 Hg56 CO

Other 

organics 

(specify)

Unit Load 

MW

Flue gas 

CO2 

content

DSCFH Flue Gas 

Temp

5 Sep-05 NA 165ppm NA NA 3.2 lb/Tbtu NA NA 203 12.7 NA NA

5 Aug-09 NA NA NA NA 1.81 lb/Tbtu NA NA 212 12.48 31806632 362

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

Boiler ID

Emissions test results (indicate format of emission data)52,53

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 or permit authority, even if from short-term testing?

If yes51, 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 CEMS data are being provided to EPA, please note to which 

Office the data are being provided.

Quarterly excess emissions reports; notifications to IEPA for excess emssions due to malfunctions and breakdowns

Quarterly excess emissions reports; notifications to IEPA for excess emssions due to malfunctions and breakdowns

What type of deviation reporting is required for violations of permit requirements?

Are deviation reports available for malfunctions or other periods of noncompliance with permit terms and conditions?

If yes, please note which reports.

AmerenAGC Meredosia

PART I: GENERAL FACILITY INFORMATION

1

2 Ameren Energy Generating Company

3 1901 Chouteau Avenue, St. Louis, MO 63166

4a Newton

4b 6017

5 6725 North 500th St., Newton, IL 62448

6

7 Donald Schuh, Sr. Environmental Scientist

8 314-554-2658

Email address dschuh@ameren.com

9

Yes

No X

10

X

X

X

11

X

X

12

%

100 %

%

%

%

%

13

100 % #2

%

% Specify

Ameren Energy Generating Company

Is this facility considered to be owned or operated by a small entity as defined by the Regulatory Flexibility Act?

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

distillate

residual or bunkerC

If oil is fired, indicate which type of oil was utilized during the previous 12 months prior to the receipt of this ICR:9

Natural Gas

Oil

Natural Gas

Other

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:7,8

bituminous

Which of the following fossil fuels or other material(s) are permitted6 to be fired in any steam generating unit at this facility?

Coal

Oil

Other

Coal

other

subbituminous

Name of legal owner of facility:

Name of legal operator of facility

Address of legal owner or operator:

Plant Name

Contact telephone number:

EIA Plant Code:

Complete street address:

Provide mailing address if different:

Name and title of contact:

anthracite

synfuel

petroleum coke

lignite

AmerenEGC Newton
14a

14b

Yes

No X Ameren will continue to burn as long as we are not subject to CAA Section 129

15

Yes

Yes

Other Material

Boiler Chemical Cleaning Wash

Used Oil

Actually burn Quantity/year

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 permitted10 to burn non-fossil fuel(s) or other material(s) even if you do not actually burn them.

Permitted to burn

5500

86

None in 2009

None in 2009

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?

NA

Subpart D

NA

Subpart D

1005

Coal

7720

68

1005

2450

2420

1005

1005

620

588

Average annual capacity factor for the past 3 years

Applicable NSPS

Hours/year operated17

85

86

8146

70

1005

1005

1005

Estimated year of retirement18

1

Coal

5500

5500

629

594

85

Design steam temperature (°F)

Operating steam temperature (°F)

Boiler ID11

Original design fuel (i.e. coal rank or type of oil)

2420

1005

Design heat input, (MMBtu/hr)12

Present maximum heat input, (MMBtu/hr)13

MWe Gross capacity summer

MWe Net capacity summer

Coal

2450

Original design gross efficiency (%, HHV)

Design steam reheat temperature (°F)14

Operating steam reheat temperature (°F)15

Fuel16

Design steam pressure (psig)

Operating steam pressure (psig)

5500

Yes

Yes

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.

2

Coal

Present operating gross efficiency (%, HHV)

AmerenEGC Newton
16

17

NA

18

Boiler 

ID27

NA

19

1

2

NA NA

NA NA

NA NA NA NA

1 Tangential firing

2 Tangential firing

NA NA

ADA Envronmetal Solutions

ADA Envronmetal Solutions

Cody Wilson

Cody Wilson

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; precombustion boiler chemical additive; combustion boiler chemical additive), the desired HAP emission reduction or rate (if any), and the coal rank(s) in use 

or fuel type 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).

Demonstration 

activity projected 

start-up date

Demonstration 

activity end-date 

or projected enddate

Type of control (e.g., 

sorbent and type; chemical 

additive28)

303-339-8860

Telephone

8100 Southpark Way, Unit B, Littleton, CO 80120

303-339-8860 8100 Southpark Way, Unit B, Littleton, CO 80120

Coal rank(s) in use

Desired HAP emission 

reduction (%) or emission 

rate

Company (vendor) contact information

Telephone Address

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, etc.) control technology that you have either contracted for, are installing, or have installed for the purpose of providing a nondemonstration, full-scale operating system.

Boiler ID Company (vendor) name

Company (vendor) contact information

Name

Low NOx Burner 12/1994

NA

NA

Demonstration 

activity actual startup date

ESP cold side 1977 

ESP cold side 1/1997 (#3)

Address

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 project25 (e.g., U.S. Department of Energy program, consent decree, etc.).

Boiler 

ID26 Company (vendor) name Name

ESP cold side 1/1982 (#3)

Activated Carbon 07/2009 

(#2)

Flue Gas Conditioning 

04/2001 (#1)

Activated Carbon 07/2009 

(#2)

Other control24

Overfire Air 04/2001

Overfire Air 12/1994

Low NOx Burner 04/2001

SO2 control22 NOx control21 Boiler ID19 Type20

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.):

Flue Gas Conditioning 

04/2001 (#1)

PM control23

AmerenEGC Newton
20

Boiler 

ID30

1

2

21

PM1034 PM2.535

HCl 

and/or 

HF

HCN Metal 

HAP36

Other 

pollutant 

(specify)

1 NA NA NA NA NA NA NA

Opacity 20% 

6-min. avg. 

based on 

COMS

2 NA NA NA NA NA NA NA

Opacity 20% 

6-min. avg. 

based on 

COMS

22

PM38 PM10 PM2.5 SO2

HCl 

and/or 

HF

HCN

Metal 

HAP39 Hg CO

NA NA NA NA NA NA NA NA NA NA NA NA

Other organics 

(specify)

Reg Limit 0.1 

lb/mmBtu

Emission Test

PM33

Reg Limit 0.1 

lb/mmBtu

Emission Test

Reg Limit - 1.2 

lb/mmBtu (3hr roll) 

Reg Limit - 1.2 

lb/mmBtu (3hr roll) 

NA NA

NA NA

Sorbent or additive feed 

rate on which guarantee is 

based

Coal rank(s) upon which 

guarantee is based

Actual start-up 

date

Expected or 

projected start-up 

date

7/2/2009 NA

7/1/2009

SIP Limit 200 ppm 

corrected to 50% 

excess air

SO2

Halogenated ACI NA

Halogenated ACI

NA

NA

Other pollutant 

(specify)

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

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

Boiler 

ID32 Other organics 

(specify)

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

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

Boiler 

ID37

CO

Guaranteed HAP 

emission 

reduction (%) or 

emission rate

Type of control (e.g., 

sorbent and type; chemical 

additive)31

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) or fuel 

type 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).

SIP Limit 200 ppm 

corrected to 50% 

excess air

Hg

NA

NA

AmerenEGC Newton
23

Yes

No X

Please elaborate.

24

PM10 PM2.5

HCl 

and/or 

HF

HCN Metal 

HAP42 Hg

1 None None None None None None

2 None None None None None None

25

Newton Unit 1

Yes

No

(Include base year for operating costs [e.g., 2006]) 2009 Dollars

Newton Unit 2

No

No

(Include base year for operating costs [e.g., 2006])

26

Low sulfur coal

None

None

CO

200 ppm 

corrected to 50% 

excess air

200 ppm 

corrected to 50% 

excess air

Installation on new boiler?

Total Capital Investment: $ 2,894,539.00 

For the control technologies identified in Part I, questions 17 and 19, provide the cost information requested.43

Facility Name / Unit No.:

Retrofit to existing boiler?

CEMS Records of 3 hr 

block ave. Quarterly Excess 

emissions Reporting

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.

For the control technologies identified in Part I, questions 17 and 19, provide the cost information requested.43

Total Capital Investment:

Total Annual Operating and Maintenance Costs:

Facility Name / Unit No.:

Retrofit to existing boiler?

Installation on new boiler?

Total Annual Operating and Maintenance Costs: $5,249,694.40

$5,249,694.40

 $ 4,564,415.00 

CEMS Records of 3 hr 

block ave. Quarterly Excess 

emissions Reporting

Was any other guarantee level sought or offered?

Boiler 

ID40

Required Monitoring, Recordkeeping, and Reporting for each pollutant with permitted limit.

SO2 Other organics 

(specify) PM41

Stack test as 

requested by 

agency

Stack test as 

requested by 

agency

AmerenEGC Newton
PART II: FUEL ANALYSIS AND EMISSION DATA

Each facility should provide the following information for each coal and oil shipment received during the preceding 12 calendar months.

1a Newton

1b 6017

2

State/Country County47 Coal seam48

1 Sub-bituminous Jan-09 314,123.45 I & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

2 Sub-bituminous Jan-09 68,605.35 I & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

3 Sub-bituminous Jan-09 50,726.43 I & 2 Wyoming/USA Campbell PRB Antelope Train

4 Sub-bituminous Jan-09 32,523.23 I & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

5 Sub-bituminous Feb-09 254,619.03 I & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

6 Sub-bituminous Feb-09 65,395.95 I & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

7 Sub-bituminous Feb-09 50,602.48 I & 2 Wyoming/USA Campbell PRB Antelope Train

8 Sub-bituminous Feb-09 32,264.50 I & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

9 Sub-bituminous Mar-09 342,519.20 I & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

10 Sub-bituminous Mar-09 34,363.75 I & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

11 Sub-bituminous Mar-09 17,042.18 I & 2 Wyoming/USA Campbell PRB Antelope Train

12 Sub-bituminous Mar-09 33,600.05 I & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

13 Sub-bituminous Apr-09 291,391.25 I & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

14 Sub-bituminous Apr-09 34,573.00 I & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

15 Sub-bituminous Apr-09 34,337.70 I & 2 Wyoming/USA Campbell PRB Antelope Train

16 Sub-bituminous Apr-09 50,200.48 I & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

17 Sub-bituminous May-09 344,500.15 I & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

ID # of boiler(s) 

firing fuel46

Fuel source Fuel 

shipment 

method

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

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

Fuel Analysis44

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):

Sample 

ID 

number

Type of Coal Months

Amount received, dry 

basis, short tons45 

and Barrels

AmerenEGC Newton
18 Sub-bituminous May-09 34,605.63 I & 2 Wyoming/USA Campbell PRB Antelope Train

19 Sub-bituminous May-09 50,337.03 I & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

20 Sub-bituminous Jun-09 328,896.80 I & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

21 Sub-bituminous Jun-09 51,171.95 I & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

22 Sub-bituminous Jun-09 34,627.25 I & 2 Wyoming/USA Campbell PRB Antelope Train

23 Sub-bituminous Jun-09 34,558.43 I & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

24 Sub-bituminous Jul-09 242,266.70 I & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

25 Sub-bituminous Jul-09 69,022.80 I & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

26 Sub-bituminous Jul-09 17,568.85 I & 2 Wyoming/USA Campbell PRB Antelope Train

27 Sub-bituminous Jul-09 17,261.38 I & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

28 Sub-bituminous Aug-09 328,799.30 I & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

29 Sub-bituminous Aug-09 69,653.80 I & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

30 Sub-bituminous Aug-09 34,616.53 I & 2 Wyoming/USA Campbell PRB Antelope Train

31 Sub-bituminous Aug-09 34,653.95 I & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

32 Sub-bituminous Sep-09 154,989.20 I & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

33 Sub-bituminous Sep-09 69,125.00 I & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

34 Sub-bituminous Sep-09 16,132.48 I & 2 Wyoming/USA Campbell PRB Antelope Train

35 Sub-bituminous Sep-09 17,417.70 I & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

36 Sub-bituminous Oct-09 259,890.30 I & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

37 Sub-bituminous Oct-09 69,462.95 I & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

38 Sub-bituminous Oct-09 32,284.95 I & 2 Wyoming/USA Campbell PRB Antelope Train

AmerenEGC Newton
39 Sub-bituminous Oct-09 17,345.68 I & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

40 Sub-bituminous Nov-09 312,143.60 I & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

41 Sub-bituminous Nov-09 69,527.45 I & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

42 Sub-bituminous Nov-09 35,257.75 I & 2 Wyoming/USA Campbell PRB Antelope Train

43 Sub-bituminous Nov-09 34,709.70 I & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

44 Sub-bituminous Dec-09 357,305.55 I & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

45 Sub-bituminous Dec-09 69,141.00 I & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

46 Sub-bituminous Dec-09 34,517.78 I & 2 Wyoming/USA Campbell PRB Antelope Train

47 #2 Jan-09 1405 1 & 2 Illinois/USA Crawford NA Truck

48 #2 Feb-09 529 1 & 2 Illinois/USA Crawford NA Truck

49 #2 Feb-09 529 1 & 2 Illinois/USA Effingham NA Truck

50 #2 Mar-09 1929 1 & 2 Illinois/USA Crawford NA Truck

51 #2 Mar-09 703 1 & 2 Illinois/USA Effingham NA Truck

52 #2 Apr-09 1400 1 & 2 Illinois/USA Effingham NA Truck

53 #2 Apr-09 519 1 & 2 Illinois/USA Crawford NA Truck

54 #2 May-09 517 1 & 2 Illinois/USA Effingham NA Truck

55 #2 May-09 171 1 & 2 Illinois/USA Crawford NA Truck

56 #2 May-09 348 1 & 2 Illinois/USA Champaign NA Truck

57 #2 Jun-09 176 1 & 2 Illinois/USA Crawford NA Truck

58 #2 Aug-09 1591 1 & 2 Illinois/USA Crawford NA Truck

59 #2 Sep-09 1586 1 & 2 Illinois/USA Crawford NA Truck

60 #2 Oct-09 1572 1 & 2 Illinois/USA Crawford NA Truck

61 #2 Dec-09 350 1 & 2 Illinois/USA Effingham NA Truck

3

NA

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

NA Permit requirements

NA contractual obligations

NA standard operational procedures

NA other(please specify)

For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information49, as available (dry basis)

(indicate N/A if not available):

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

NA Fuel supplier

NA Other 

6 Name and address of laboratory performing analyses:

NA

7

NA

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.

AmerenEGC Newton
Emission Data

8a

See Test Number in 8b

8b

Test 

Report Boiler ID

1 1

2 1

3 2

4 1

5 2

6 1

7 1

8 2

8c

Yes

No X

If yes, please note which reports and provide a detailed description of the location of the emissions sampling point(s).

8d

Yes

No X

8e

Yes

No X

8f

Yes

No X

Mercury

Mercury

Speciation Mercury

Mercury

Speciation Mercury

Mercury

Were any of these test reports conducted when use of other material(s) or non-fossil fuels were fired in the boiler?

If yes, please note which reports and identify the other material(s) or non-fossil fuels used.

Do any of these test reports reflect testing during periods of startup, shutdown, and malfunction?

Dec-09

Stack Testing Mercury abbreviated 30B

Stack Testing

If yes, please list the unit’s complete control configuration at time of testing in a similar format to Part I, question 16.

Mar-05 Stack Testing

Aug-09 Parametric Testing

Do any of these test reports reflect testing at a location upstream of any emission control devices?

Stack Testing

May-08

Nov-09 Stack Testing

Nov-09 Stack Testing

Nov-09

Did the unit’s control configuration differ from that shown in Part I, question 16, at the time of these test results?

Stack Testing Mercury abbreviated 30B

May-08

If yes, please note which reports.

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.

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:

AmerenEGC Newton
8g

Yes

No X

9

10

Yes X

No

11

Yes

No X

12

Date of 

test PM54 SO2 HCl/HF/HCN

Metal 

HAP55 Hg56 Percent 

Elemental CO

Other 

organics 

(specify)

Unit Load 

MW

Flue gas 

CO2 

content

Flue gas 

Temp DSCFH

1 Mar-05 NA 276ppm NA NA 7.3 lb/Tbtu NA NA NA 595 12.9 315 NA

1 Nov-09 NA NA NA NA 2.83lb/Tbtu NA NA NA 633 14.16 318 79162879

2 Nov-09 NA NA NA NA 2.8 lb/Tbtu 95 NA NA 634 13.04 321 85609743

1 Nov-09 NA NA NA NA 2.75 lb/Tbtu 94 NA NA 633 14.16 318 79162879

2 Dec-09 NA NA NA NA 1.82lb/Tbtu NA NA NA 633 13.16 305 85597602

1 May-08 NA NA NA NA 12.3ug/m3 NA NA NA NA NA 370 NA

2 May-08 NA NA NA NA 6.77ug/m3 NA NA NA NA NA 385 NA

Boiler ID

If yes, please note which reports.

Quarterly excess emissions reports, notifications of excess emissions due to malfunction and breakdowns

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 or permit authority, even if from short-term testing?

If yes51, 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 CEMS data are being provided to EPA, please note to which Office 

the data are being provided.

Emissions test results (indicate format of emission data)52,53

Are deviation reports available for malfunctions or other periods of noncompliance with permit terms and conditions?

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

Do any of these test reports reflect testing at a location upstream of a post combustion SO2 emission control device (e.g., FGD, SDA, Dry Scrubber)?

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 exhaust gas flow). Note by diagram where 

sampling ports were located in relation to the bypass ductwork

What type of deviation reporting is required for violations of permit requirements?

Quarterly excess emissions reports, notifications of excess emissions due to malfunction and breakdowns

AmerenEGC Newton

PART I: GENERAL FACILITY INFORMATION

1

2

3 1901 Chouteau Avenue, St. Louis, MO 63166

4a Rush Island

4b 6155

5 100 Big Hollow Road, Festus, MO 63028

6

7 Donald Schuh, Sr. Environmental Scientist

8 314-554-2658

Email address dschuh@ameren.com

9

Yes

No X

10

X

X

X

11

X

X

X

12

%

100 %

%

%

% Specify type

%

13

100 % #2

%

% Specify

Union Electric Co. dba AmerenUE

Is this facility considered to be owned or operated by a small entity as defined by the Regulatory Flexibility Act?

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

Which of the following fossil fuels or other material(s) are permitted6 to be fired in any steam generating unit at this facility?

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:7,8

Oil

Natural Gas

Other

bituminous

distillate

residual or bunkerC

other

Other

Coal

subbituminous

anthracite

synfuel

petroleum coke

If oil is fired, indicate which type of oil was utilized during the previous 12 months prior to the receipt of this ICR:9

EIA Plant Code:

Complete street address:

Provide mailing address if different:

Name and title of contact:

lignite

Natural Gas

Coal

Oil

Union Electric Co. dba AmerenUE

Contact telephone number:

Name of legal owner of facility:

Name of legal operator of facility

Address of legal owner or operator:

Plant Name

AmerenUE Rush Island
14a

Boiler Chemical Cleaning Wash

14b

Yes

No X Ameren will continue to burn as long as we are not subject to CAA Section 129

15

Yes None in 2009

Other Material Permitted to burn Actually burn Quantity/year

Yes

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 Yes 5500 Gallons

Used Oil Yes

79

NA

NA

1005

1005

1005

1005

Sub-bituminous 

7563 8256

76

NA

NA

614

580

89.09

86.1

2625

2625 2625

1005

1005

1005

1005

Sub-bituminous 

5922

626

594

89.09

86.6

2625

Average annual capacity factor for the past 3 years

Applicable NSPS

Estimated year of retirement18

MWe Gross capacity summer

MWe Net capacity summer

Original design gross efficiency (%, HHV)

Design steam reheat temperature (°F)14

Operating steam reheat temperature (°F)15

Fuel16

Hours/year operated17

Design steam pressure (psig)

Operating steam pressure (psig)

Design steam temperature (°F)

Operating steam temperature (°F)

Present maximum heat input, (MMBtu/hr)13

Boiler ID11

Original design fuel (i.e. coal rank or type of oil)

Design heat input, (MMBtu/hr)12

1

Coal

5922

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 permitted10 to burn non-fossil fuel(s) or other material(s) even if you do not actually burn them.

Coal

5922

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.

2

Spent Demineralizer Resin

5922

Present operating gross efficiency (%, HHV)

Paper Records Yes Yes Not required to weigh

Yes None in 2009

AmerenUE Rush Island
16

Over Fired Air - Jan 1995

Over Fired Air - Jan 1996

17

NA

18

Boiler 

ID27

NA

19

NA

NA

NA

NA

Cold Side ESP - 1976 (#1)

Cold Side ESP - 1977 (#1)

NA NA

NA NA

NA NA

NA NA NA NA

NA NA

Address

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; precombustion boiler chemical additive; combustion boiler chemical additive), the desired HAP emission reduction or rate (if any), and the coal rank(s) in use 

or fuel type 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).

Demonstration 

activity actual startup date

Demonstration 

activity projected 

start-up date

Demonstration 

activity end-date 

or projected enddate

Type of control (e.g., 

sorbent and type; chemical 

additive28)

Desired HAP emission 

reduction (%) or emission 

rate

Coal rank(s) in use

NA NA

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 project25 (e.g., U.S. Department of Energy program, consent decree, etc.).

Boiler 

ID26 Company (vendor) name Name

Company (vendor) contact information

Telephone

2

NOx control21

Low NOx Burners Jan 1995

Low NOx Burners Jan 1996

1 Tangential firing

Tangential firing

NA

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 ID19 Type20 SO2 control22 Other control24 PM control23

Telephone Address

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, etc.) control technology that you have either contracted for, are installing, or have installed for the purpose of providing a nondemonstration, full-scale operating system.

Boiler ID Company (vendor) name Company (vendor) contact information

Name

AmerenUE Rush Island
20

Boiler 

ID30

NA

21

PM1034 PM2.535

HCl 

and/or 

HF

HCN Metal 

HAP36 Hg CO

Other 

pollutant 

(specify)

1 NA NA NA NA NA NA NA NA

2 NA NA NA NA NA NA NA NA

22

PM38 PM10 PM2.5 SO2

HCl 

and/or 

HF

HCN Metal 

HAP39 Hg CO

NA NA NA NA NA NA NA NA NA NA

23

Yes

No X

Please elaborate.

NA NA

NA NA

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

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

Boiler 

ID32 Other organics 

(specify)

NA NA NA NA

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) or fuel 

type 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).

Actual start-up 

date

Expected or 

projected start-up 

date

Type of control (e.g., 

sorbent and type; chemical 

additive)31

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

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

Boiler 

ID37 Other organics 

(specify)

Other pollutant 

(specify)

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

Was any other guarantee level sought or offered?

NA OP limit: 2.3 lbs/mmBtu on 

a 3-hr rolling average

Operating Permit (OP) 

Limit: 0.12 #/mmBtu - 

Method 5 Stack Test

SO2

OP limit: 2.3 lbs/mmBtu on 

a 3-hr rolling average NA

PM33

Operating Permit (OP) 

Limit: 0.12 #/mmBtu - 

Method 5 Stack Test

AmerenUE Rush Island
24

PM10 PM2.5

HCl 

and/or 

HF

HCN Metal 

HAP42 Hg CO

1 NA NA NA NA NA NA NA

2 NA NA NA NA NA NA NA

25

NA

NA

NA

(Include base year for operating costs [e.g., 2006])

26

Low sulfur coal

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.

For the control technologies identified in Part I, questions 17 and 19, provide the cost information requested.43

Total Capital Investment:

Total Annual Operating and Maintenance Costs:

Facility Name / Unit No.:

Retrofit to existing boiler?

Installation on new boiler?

Boiler 

ID40 Other organics 

(specify) PM41

Required Monitoring, Recordkeeping, and Reporting for each pollutant with permitted limit.

SO2

CEMS Records of 3 hr 

rolling average Quarterly 

Excess emissions 

Reporting

CAM NA

CAM NA

CEMS Records of 3 hr 

rolling average Quarterly 

Excess emissions 

Reporting

AmerenUE Rush Island
PART II: FUEL ANALYSIS AND EMISSION DATA

Each facility should provide the following information for each coal and oil shipment received during the preceding 12 calendar months.

1a Rush Island

1b 6155

2

State/Country County47 Coal seam48

1 Sub-bituminous Jan-09 221,863.25 1 & 2 Wyoming/USA Campbell PRB Coal Creek Train

2 Sub-bituminous Jan-09 53,202.50 1 & 2 Wyoming/USA Campbell PRB Cordero Rojo Train

3 Sub-bituminous Jan-09 177,691.67 1 & 2 Wyoming/USA Campbell PRB Buckskin Train

4 Sub-bituminous Jan-09 55,029.44 1 & 2 Wyoming/USA Campbell PRB Caballo Train

5 Sub-bituminous Jan-09 27,699.08 1 & 2 Wyoming/USA Campbell PRB Buckskin Train

6 Sub-bituminous Feb-09 233,848.05 1 & 2 Wyoming/USA Campbell PRB Coal Creek Train

7 Sub-bituminous Feb-09 40,632.55 1 & 2 Wyoming/USA Campbell PRB Cordero Rojo Train

8 Sub-bituminous Feb-09 97,735.16 1 & 2 Wyoming/USA Campbell PRB Buckskin Train

9 Sub-bituminous Feb-09 42,916.08 1 & 2 Wyoming/USA Campbell PRB Caballo Train

10 Sub-bituminous Feb-09 27,346.07 1 & 2 Wyoming/USA Campbell PRB Buckskin Train

11 Sub-bituminous Mar-09 208,329.45 1 & 2 Wyoming/USA Campbell PRB Coal Creek Train

12 Sub-bituminous Mar-09 27,247.35 1 & 2 Wyoming/USA Campbell PRB Caballo Train

13 Sub-bituminous Mar-09 110,364.78 1 & 2 Wyoming/USA Campbell PRB Buckskin Train

14 Sub-bituminous Mar-09 27,240.71 1 & 2 Wyoming/USA Campbell PRB Caballo Train

15 Sub-bituminous Mar-09 41,495.51 1 & 2 Wyoming/USA Campbell PRB Buckskin Train

16 Sub-bituminous Apr-09 74,415.35 1 & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

17 Sub-bituminous Apr-09 135,102.75 1 & 2 Wyoming/USA Campbell PRB Coal Creek Train

18 Sub-bituminous Apr-09 13,490.00 1 & 2 Wyoming/USA Campbell PRB Cordero Rojo Train

19 Sub-bituminous Apr-09 90,692.95 1 & 2 Wyoming/USA Campbell PRB Buckskin Train

20 Sub-bituminous Apr-09 27,395.74 1 & 2 Wyoming/USA Campbell PRB Buckskin Train

21 Sub-bituminous May-09 223,166.45 1 & 2 Wyoming/USA Campbell PRB Coal Creek Train

22 Sub-bituminous May-09 182,567.02 1 & 2 Wyoming/USA Campbell PRB Buckskin Train

23 Sub-bituminous May-09 45,289.98 1 & 2 Wyoming/USA Campbell PRB Buckskin Train

24 Sub-bituminous Jun-09 181,467.30 1 & 2 Wyoming/USA Campbell PRB Coal Creek Train

25 Sub-bituminous Jun-09 157,251.73 1 & 2 Wyoming/USA Campbell PRB Buckskin Train

ID # of boiler(s) 

firing fuel46

Fuel source Fuel 

shipment 

method

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

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

Fuel Analysis44

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):

Sample 

ID 

number

Type of Coal Months

Amount received, dry 

basis, short tons45 

and Barrels
26 Sub-bituminous Jun-09 15,719.88 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train

27 Sub-bituminous Jun-09 30,799.29 1 & 2 Wyoming/USA Campbell PRB Buckskin Train

28 Sub-bituminous Jul-09 199,753.05 1 & 2 Wyoming/USA Campbell PRB Coal Creek Train

29 Sub-bituminous Jul-09 110,295.64 1 & 2 Wyoming/USA Campbell PRB Buckskin Train

30 Sub-bituminous Jul-09 30,095.63 1 & 2 Wyoming/USA Campbell PRB Buckskin Train

31 Sub-bituminous Aug-09 230,955.50 1 & 2 Wyoming/USA Campbell PRB Coal Creek Train

32 Sub-bituminous Aug-09 173,921.95 1 & 2 Wyoming/USA Campbell PRB Buckskin Train

33 Sub-bituminous Aug-09 32,264.89 1 & 2 Wyoming/USA Campbell PRB Buckskin Train

34 Sub-bituminous Sep-09 278,436.50 1 & 2 Wyoming/USA Campbell PRB Coal Creek Train

35 Sub-bituminous Sep-09 140,960.53 1 & 2 Wyoming/USA Campbell PRB Buckskin Train

36 Sub-bituminous Sep-09 31,278.43 1 & 2 Wyoming/USA Campbell PRB Buckskin Truck

37 Sub-bituminous Oct-09 213,997.15 1 & 2 Wyoming/USA Campbell PRB Coal Creek Train

38 Sub-bituminous Oct-09 15,809.35 1 & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

39 Sub-bituminous Oct-09 172,012.27 1 & 2 Wyoming/USA Campbell PRB Buckskin Train

40 Sub-bituminous Oct-09 31440.12 1 & 2 Wyoming/USA Campbell PRB Buckskin Train

41 Sub-bituminous Nov-09 229,861.35 1 & 2 Wyoming/USA Campbell PRB Coal Creek Train

42 Sub-bituminous Nov-09 157,332.47 1 & 2 Wyoming/USA Campbell PRB Buckskin Train

43 Sub-bituminous Nov-09 30,542.28 1 & 2 Wyoming/USA Campbell PRB Buckskin Train

44 Sub-bituminous Dec-09 213,165.95 1 & 2 Wyoming/USA Campbell PRB Coal Creek Train

45 Sub-bituminous Dec-09 109,250.64 1 & 2 Wyoming/USA Campbell PRB Buckskin Train

46 Sub-bituminous Dec-09 47,660.34 1 & 2 Wyoming/USA Campbell PRB Buckskin Train

47 #2 Feb-09 667.00 1 & 2 Illinois/USA Madison NA Truck

48 #2 Mar-09 333.00 1 & 2 Misssouri/USA St. Louis NA Truck

49 #2 May-09 1,470.00 1 & 2 Misssouri/USA St. Louis NA Truck

50 #2 Sep-09 1,714.00 1 & 2 Misssouri/USA St. Louis NA Truck

51 #2 Oct-09 714.00 1 & 2 Misssouri/USA St. Louis NA Truck

52 #2 Nov-09 543.00 1 & 2 Illinois/USA St. Clair NA Truck

53 #2 Nov-09 926.00 1 & 2 Misssouri/USA St. Louis NA Truck

54 #2 Dec-09 1,102.00 1 & 2 Misssouri/USA St. Louis NA Truck

55 #2 Dec-09 186.00 1 & 2 Illinois/USA St. Clair NA Truck

3

NA

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

NA Permit requirements

NA contractual obligations

NA standard operational procedures

NA other(please specify)

For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information49, as available (dry basis)

(indicate N/A if not available):
5 Analyses provided in Part II, question 3 above, supplied by

NA Fuel supplier

NA Other 

6 Name and address of laboratory performing analyses:

NA

7

NA

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.
Emission Data

8a

NA

8b

8c

Yes NA

No NA

If yes, please note which reports and provide a detailed description of the location of the emissions sampling point(s).

8d

Yes NA

No NA

8e

Yes NA

No NA

8f

Yes NA

No NA

8g

Yes NA

No NA

If yes, please list the unit’s complete control configuration at time of testing in a similar format to Part I, question 16.

Do any of these test reports reflect testing at a location upstream of a post combustion SO2 emission control device (e.g., FGD, SDA, Dry Scrubber)?

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 exhaust gas flow). Note by diagram where 

sampling ports were located in relation to the bypass ductwork

Do any of these test reports reflect testing at a location upstream of any emission control devices?

Were any of these test reports conducted when use of other material(s) or non-fossil fuels were fired in the boiler?

If yes, please note which reports and identify the other material(s) or non-fossil fuels used.

Do any of these test reports reflect testing during periods of startup, shutdown, and malfunction?

If yes, please note which reports.

Did the unit’s control configuration differ from that shown in Part I, question 16, at the time of these test results?

NA

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.

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:

NA NA
9

10

Yes X

No

11

Yes

No X

12

Date of 

test PM54 SO2 HCl/HF/HCN

Metal 

HAP55 Hg56 CO

Other 

organics 

(specify)

NA NA NA NA NA NA NA NA NA

Emissions test results (indicate format of emission data)52,53

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 or permit authority, even if from short-term testing?

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

Boiler ID

If yes51, 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 CEMS data are being provided to EPA, please note to which 

Office the data are being provided.

What type of deviation reporting is required for violations of permit requirements?

Are deviation reports available for malfunctions or other periods of noncompliance with permit terms and conditions?

If yes, please note which reports.

Quarterly excess emissions reports, notifications to Missouri Department of Natural Resources for deviations from permit conditions within 10 days 

of occurrence

Quarterly excess emissions reports, notifications to Missouri Department of Natural Resources for deviations from permit conditions within 10 days 

of occurrence
PART I: GENERAL FACILITY INFORMATION

1

2

3 1901 Chouteau Avenue, St. Louis, MO 63166

4a Sioux

4b 2107

5 8501 N. State Route 94, West Alton, MO 63386

6

7 Donald Schuh, Sr. Environmental Scientist

8 314-554-2658

Email address dschuh@ameren.com

9

Yes

No X

10

X

X

X

11

X

X

X

12

% %

75 % 70 %

25 % 30 %

% %

% %

% %

Union Electric Co. dba AmerenUE

Contact telephone number:

Name of legal owner of facility:

Name of legal operator of facility

Address of legal owner or operator:

Plant Name

EIA Plant Code:

Complete street address:

Provide mailing address if different:

Name and title of contact:

lignite

Natural Gas

Coal

Oil

Other

Coal

anthracite

synfuel

petroleum coke

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:7,8

Oil

Natural Gas

Other

bituminous

subbituminous

Is this facility considered to be owned or operated by a small entity as defined by the Regulatory Flexibility Act?

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

Which of the following fossil fuels or other material(s) are permitted6 to be fired in any steam generating unit at this facility?

Union Electric Co. dba AmerenUE

Mass Percentage Btu percentage

AmerenUE Sioux
13

100 % #2

%

% Specify

14a

Boiler Chemical Cleaning Wash

14b

Yes

No X Ameren will continue to burn as long as we are not subject to CAA Section 129

Yes Yes Last burn May 2006

Pet Coke Yes Yes Last burn June 2005

Used Oil Absorbents Yes No NA

Ethylene Glycol Yes Yes None in 2009

Spent Deminerlalizer Resin Yes

If oil is fired, indicate which type of oil was utilized during the previous 12 months prior to the receipt of this ICR:9

Tire Derived Fuel

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 permitted10 to burn non-fossil fuel(s) or other material(s) even if you do not actually burn them.

distillate

residual or bunkerC

other

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 Yes None in 2009

Used Oil Yes

Yes None in 2009

Yes Less than 55 gallons

Other Material Permitted to burn Actually burn Quantity/year

AmerenUE Sioux
15

16

* Projected date for Wet FGD startup

**Has not been used since July 2009 and is currently not operational.

17

NA NA NA

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 project25 (e.g., U.S. Department of Energy program, consent decree, etc.).

RRI/SNCR 2007** Cold Side ESP (#2)

Boiler 

ID26

NA NA

Present operating gross efficiency (%, HHV)

4920

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.

2

Coal

4920

Boiler ID11

Original design fuel (i.e. coal rank or type of oil)

Design heat input, (MMBtu/hr)12

1

Coal

4920

Applicable NSPS

Estimated year of retirement18

MWe Gross capacity summer

MWe Net capacity summer

Original design gross efficiency (%, HHV)

Design steam reheat temperature (°F)14

Operating steam reheat temperature (°F)15

Fuel16

Hours/year operated17

Design steam pressure (psig)

4920

524

495

89.03

Present maximum heat input, (MMBtu/hr)13

Average annual capacity factor for the past 3 years

Operating steam pressure (psig)

Design steam temperature (°F)

Operating steam temperature (°F)

NA

NA

1005

1005

1005

Blend Subbituminous and 

Bituminous 

524

496

89.03

86.9

7737

65

87.3

4000

3883

1005

1005

1005

Blend Subbituminous and 

Bituminous 

8142

4000

3883

1005

1005

66

NA

NA

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 ID19 Type20 NOx control21

Over Fired Air 2001

SO2 control22 Other control24 PM control23

1

Company (vendor) name Name

Company (vendor) contact information

Telephone Address

FGC 1997 (#1)

FGC 1997 (#1)

Cold Side ESP (#2)

2

Over Fired Air 1997

Wet FGD Dec 2010* (#3)

Wet FGD Nov 2010* (#3)

Cyclone

Cyclone

RRI/SNCR 2007**

AmerenUE Sioux
18

Boiler 

ID27

NA

19

NA

20

Boiler 

ID30

NA

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) or fuel 

type 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).

Actual start-up 

date

NA NA NA NA

Guaranteed HAP 

emission 

reduction (%) or 

emission rate

NA

NA NA

Sorbent or additive feed 

rate on which guarantee is 

based

NA NA

Company (vendor) name

Company (vendor) contact information

Name Telephone

NA

Address

NA NA

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; precombustion boiler chemical additive; combustion boiler chemical additive), the desired HAP emission reduction or rate (if any), and the coal rank(s) in use 

or fuel type 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).

Demonstration 

activity actual startup date

Demonstration 

activity projected 

start-up date

Demonstration 

activity end-date 

or projected enddate

Expected or 

projected start-up 

date

Type of control (e.g., 

sorbent and type; chemical 

additive)31

Type of control (e.g., 

sorbent and type; chemical 

additive28)

Desired HAP emission 

reduction (%) or emission 

rate

Coal rank(s) in use

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, etc.) control technology that you have either contracted for, are installing, or have installed for the purpose of providing a nondemonstration, full-scale operating system.

NA NA NA

NA

Boiler ID

Coal rank(s) upon which 

guarantee is based

AmerenUE Sioux
21

PM1034 PM2.535

HCl 

and/or 

HF

HCN Metal 

HAP36 Hg CO

Other 

pollutant 

(specify)

1 NA NA NA NA NA NA NA NA

2 NA NA NA NA NA NA NA NA

22

PM38 PM10 PM2.5 SO2

HCl 

and/or 

HF

HCN Metal 

HAP39 Hg CO

NA NA NA NA NA NA NA NA NA NA

23

Yes

No X

Please elaborate.

24

PM10 PM2.5

HCl 

and/or 

HF

HCN Metal 

HAP42 Hg CO

1 NA NA NA NA NA NA NA

2 NA NA NA NA NA NA NA

PM33 SO2

NA NA

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

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

Boiler 

ID32 Other organics 

(specify)

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

NA

NA

Operating Permit (OP) 

Limit: 0.12 #/mmBtu - 

Method 5 Stack Test

Operating Permit (OP) 

Limit: 0.12 #/mmBtu - 

Method 5 Stack Test

OP limit: 4.8 lbs/mmBtu on 

a daily average; 4.73 

lbs/mmBtu on a daily 

average when burning 

petroleum coke

OP limit: 4.8 lbs/mmBtu on 

a daily average; 4.73 

lbs/mmBtu on a daily 

average when burning 

petroleum coke

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

Boiler 

ID37 Other organics 

(specify)

Other pollutant 

(specify)

CAM

Was any other guarantee level sought or offered?

Boiler ID40 Other organics 

(specify)

Required Monitoring, Recordkeeping, and Reporting for each pollutant with permitted limit.

CAM

SO2

CEMS Records of daily 

average Quarterly Excess 

emissions Reporting

PM41

NA

NA

CEMS Records of daily 

average Quarterly Excess 

emissions Reporting

AmerenUE Sioux
25

NA

NA

NA

(Include base year for operating costs [e.g., 2006])

26

Low sulfur coal

Retrofit to existing boiler?

Installation on new boiler?

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.

For the control technologies identified in Part I, questions 17 and 19, provide the cost information requested.43

Total Capital Investment:

Total Annual Operating and Maintenance Costs:

Facility Name / Unit No.:

AmerenUE Sioux
PART II: FUEL ANALYSIS AND EMISSION DATA

Each facility should provide the following information for each coal and oil shipment received during the preceding 12 calendar months.

1a Sioux

1b 2107

2

State/Country County47 Coal seam48

1 Sub-bituminous Jan-09 147,844.50 1 & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

2 Sub-bituminous Jan-09 27,427.13 1 & 2 Wyoming/USA Campbell PRB Antelope Train

3 Bituminous Jan-09 22,004.30 1 & 2 Illinois/USA IL Elk Creek Barge

4 Sub-bituminous Jan-09 13,754.85 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

5 Sub-bituminous Feb-09 149,873.55 1 & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

6 Sub-bituminous Feb-09 27,163.55 1 & 2 Wyoming/USA Campbell PRB Antelope Train

7 Bituminous Feb-09 42,720.30 1 & 2 Illinois/USA IL Elk Creek Barge

8 Sub-bituminous Feb-09 13,251.45 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

9 Bituminous Feb-09 19,639.50 1 & 2 Illinois/USA IL Gateway Train/Barge

10 Bituminous Feb-09 20,759.80 1 & 2 Illinois/USA IL Gateway Train/Barge

11 Sub-bituminous Mar-09 167,393.20 1 & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

12 Sub-bituminous Mar-09 13,968.25 1 & 2 Wyoming/USA Campbell PRB Antelope Train

13 Bituminous Mar-09 42,857.10 1 & 2 Illinois/USA IL Elk Creek Train/Barge

14 Sub-bituminous Mar-09 28,158.13 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train 

15 Bituminous Mar-09 21,135.10 1 & 2 Illinois/USA IL Gateway Train/Barge

16 Bituminous Mar-09 21,006.70 1 & 2 Illinois/USA IL Gateway Train/Barge

17 Sub-bituminous Apr-09 156,363.65 1 & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

18 Sub-bituminous Apr-09 28,074.60 1 & 2 Wyoming/USA Campbell PRB Antelope Train

19 Bituminous Apr-09 43,295.50 1 & 2 Illinois/USA IL Elk Creek Train/barge

20 Sub-bituminous Apr-09 28,923.83 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochell Train

21 Bituminous Apr-09 20,519.00 1 & 2 Illinois/USA IL Gateway Train/Barge

22 Bituminous Apr-09 20,767.40 1 & 2 Illinois/USA IL Gateway Train/Barge

ID # of boiler(s) 

firing fuel46

Fuel source Fuel 

shipment 

method

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

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

Fuel Analysis44

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):

Sample 

ID 

number

Type of Coal Months Amount received, dry 

basis, short tons45 & 
23 Sub-bituminous May-09 142,722.90 1 & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

24 Bituminous May-09 41,906.60 1 & 2 IL/USA IL Elk Creek Truck

25 Sub-bituminous May-09 42,077.23 1 & 2 Wyoming/USA Campbell PRB North 

Antelope//Rochelle Train

26 Bituminous May-09 62,267.60 1 & 2 IL/USA IL Gateway Truck

27 Sub-bituminous Jun-09 141,923.65 1 & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

28 Sub-bituminous Jun-09 15,736.95 1 & 2 Wyoming/USA Campbell PRB Antelope Train

29 Bituminous Jun-09 42,998.10 1 & 2 IL/USA IL Elk Creek Barge

30 Sub-bituminous Jun-09 15,116.30 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle

31 Bituminous Jun-09 3,923.60 1 & 2 IL/USA IL Gateway Truck/Barge

32 Bituminous Jun-09 37,466.10 1 & 2 IL/USA IL Gateway Truck/Barge

33 Sub-bituminous Jul-09 123,307.65 1 & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

34 Sub-bituminous Jul-09 31,870.10 1 & 2 Wyoming/USA Campbell PRB Antelope Train

35 Bituminous Jul-09 40,846.40 1 & 2 IL/USA IL Elk Creek Barge

36 Bituminous Jul-09 41,275.60 1 & 2 IL/USA IL Gateway Barge

37 Sub-bituminous Aug-09 15,233.20 1 & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

38 Sub-bituminous Aug-09 155,383.40 1 & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

39 Sub-bituminous Aug-09 31,461.45 1 & 2 Wyoming/USA Campbell PRB Antelope Train

40 Bituminous Aug-09 40,691.90 1 & 2 IL/USA IL Elk Creek Train/Barge

41 Sub-bituminous Aug-09 46,986.38 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle

42 Bituminous Aug-09 20,728.10 1 & 2 IL/USA IL Gateway Train/Barge

43 Sub-bituminous Sep-09 46,566.60 1 & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

44 Sub-bituminous Sep-09 142,950.55 1 & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

45 Sub-bituminous Sep-09 15,766.48 1 & 2 Wyoming/USA Campbell PRB Antelope Train

46 Sub-bituminous Sep-09 15,632.55 1 & 2 Wyoming/USA Campbell PRB Antelope Truck

47 Bituminous Sep-09 20,086.50 1 & 2 IL/USA IL. Elk Creek Train/Barge

48 Sub-bituminous Sep-09 15,933.15 1 & 2 Wyoming/USA Campbell PRB North 

Antelope/Rochelle Train
49 Bituminous Sep-09 41,036.10 1 & 2 IL/USA IL Gateway Train/Barge

50 Sub-bituminous Oct-09 15,849.95 1 & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

51 Sub-bituminous Oct-09 110,011.40 1 & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

52 Sub-bituminous Oct-09 15,835.50 1 & 2 Wyoming/USA Campbell PRB Antelope Train

53 Bituminous Oct-09 41,119.40 1 & 2 IL/USA IL Elk Creek Train/Barge

54 Bituminous Oct-09 39,132.10 1 & 2 IL/USA IL Gateway Train/Barge

55 Sub-bituminous Nov-09 110,610.35 1 & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

56 Sub-bituminous Nov-09 15,706.90 1 & 2 Wyoming/USA Campbell PRB Antelope Train

57 Sub-bituminous Dec-09 156,160.40 1 & 2 Wyoming/USA Campbell PRB Black 

Thunder Train

58 Sub-bituminous Dec-09 31,203.03 1 & 2 Wyoming/USA Campbell PRB Antelope Train

59 #2 Jan-09 181.00 1 & 2 Illinois/USA Madison NA Truck

60 #2 Mar-09 95.00 1 & 2 Illinois/USA Madison NA Truck

61 #2 May-09 178.00 1 & 2 Illinois/USA Madison NA Truck

62 #2 Jun-09 533.00 1 & 2 Illinois/USA Madison NA Truck

63 #2 Jul-09 353.00 1 & 2 Illinois/USA Madison NA Truck

64 #2 Sep-09 535.00 1 & 2 Illinois/USA Madison NA Truck

65 #2 Oct-09 1,255.00 1 & 2 Illinois/USA Madison NA Truck

66 #2 Nov-09 1,252.00 1 & 2 Illinois/USA Madison NA Truck

67 #2 Dec-09 173.00 1 & 2 Illinois/USA Madison NA Truck

3

NA

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

NA Permit requirements

NA contractual obligations

NA standard operational procedures

NA other(please specify)

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

NA Fuel supplier

NA Other 

6 Name and address of laboratory performing analyses:

NA

7

NA

For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information49, as available (dry basis)

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.
Emission Data

8a

See Test Number in 8b

8b

Test 

Report Boiler ID

1 1

2 2

8c

Yes

No X

If yes, please note which reports and provide a detailed description of the location of the emissions sampling point(s).

8d

Yes

No X

8e

Yes

No X

8f

Yes

No X

8g

Yes

No X

Particulate (CAM Testing)

Do any of these test reports reflect testing at a location upstream of any emission control devices?

Were any of these test reports conducted when use of other material(s) or non-fossil fuels were fired in the boiler?

If yes, please note which reports and identify the other material(s) or non-fossil fuels used.

Do any of these test reports reflect testing during periods of startup, shutdown, and malfunction?

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.

9/13/2005 Parametric Testing

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:

Particulate (CAM Testing)

9/13/2005 Parametric Testing

If yes, please note which reports.

Do any of these test reports reflect testing at a location upstream of a post combustion SO2 emission control device (e.g., FGD, SDA, Dry Scrubber)?

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 exhaust gas flow). Note by diagram where 

sampling ports were located in relation to the bypass ductwork

Did the unit’s control configuration differ from that shown in Part I, question 16, at the time of these test results?

If yes, please list the unit’s complete control configuration at time of testing in a similar format to Part I, question 16.
9

10

Yes X

No

11

Yes

No X

12

Date of test PM54 

lb/mmBtu SO2 Percent 

Moisture

Flue Gas 

Flow 

DSCFH

O2 CO

Flue Gas 

Temp. 

Deg F

CO2

1 9/13/2005 0.0129 NA 9.05 67908636 5.3 NA 310.5 13.7

2 9/13/2005 0.0224 NA 10.38 59836470 5.8 NA 337 13.2

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

What type of deviation reporting is required for violations of permit requirements?

Quarterly excess emissions reports, notifications to Missouri Department of Natural Resources for deviations from permit conditions within 10 days of 

occurrence

Are deviation reports available for malfunctions or other periods of noncompliance with permit terms and conditions?

If yes, please note which reports.

Quarterly excess emissions reports, notifications to Missouri Department of Natural Resources for deviations from permit conditions within 10 days of 

occurrence

If yes51, 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 CEMS data are being provided to EPA, please note to which Office 

the data are being provided.

Emissions test results (indicate format of emission data)52,53

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 or permit authority, even if from short-term testing?

Boiler ID