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

NoX 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 permitted6to 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 Coffeen14a

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 permitted10to burn non-fossil fuel(s) or other material(s) even if you do not actually burn them.

Yes Yes

AmerenEGC Coffeen15

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 2463 2420 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 ESP06/2010 (#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 ESP01/1973 (#3)

AmerenEGC Coffeen17

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).

Demonstrationactivity actual startup date Demonstration

activity projected start-up date Demonstration

activity end-dateor 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 Coffeen21

PM1034PM2.535 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 Coffeen25 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 CoffeenPART 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 County 47 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 Coffeen17 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 Coffeen34 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 Coffeen60 #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 Coffeen7 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 CoffeenEmission Data 8a

See Test Number in 8b 8b Test Report Boiler ID 1 CS 1&2 8c Yes

NoX If yes, please note which reports and provide a detailed description of the location of the emissions sampling point(s). 8d Yes

NoX
8e Yes

NoX
8f YesX

NoThe wet limestone FGD was not installed. 8g Yes

NoX 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 Coffeen9
10 YesX

No

11 Yes

NoX

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 CoffeenPART 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

NoX 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 permitted6to 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 Creek14a

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

NABituminous/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 permitted10to burn non-fossil fuel(s) or other material(s) even if you do not actually burn them.

AmerenERGC Duck Creek16

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).

Demonstrationactivity actual startup date Demonstration

activity projected start-up date Demonstration

activity end-dateor 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 Creek20

Boiler

ID30 NA 21

PM1034PM2.535 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 CO

PM33 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? NA NA

0.015 lb/MBtu .064 lb SO2/Mbtu 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 Creek24 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 CreekPART 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 County 47 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 BituminousMay-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 BituminousAug-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 Creek22 Sub-bituminous Aug-09 81,448.50 1 Wyoming/USA Campbell PRB North Antelope/Rochelle Train 23 BituminousAug-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 BituminousSep-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 BituminousSep-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 Creek5 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 CreekEmission Data 8a

See Test Number in 8b 8b Test Report Boiler ID 1 1 2 1 3 1 8c Yes

NoX If yes, please note which reports and provide a detailed description of the location of the emissions sampling point(s). 8d Yes

NoX
8e Yes

NoX
8f Yes

NoX 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 Creek8g Yes

NoX

9
10 YesX

No

11 Yes

NoX

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 CreekPART 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 NoX 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 permitted6to 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 Edwards14a

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 None in 2009 Used Oil 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 permitted10to 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? None in 2009 Yes Yes Permitted to burn

3321 Other Material

AmerenERGC Edwards16

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

Address

Name 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-dateor projected enddate AmerenERGC EdwardsNA 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 8102 Southpark Way, Littleton, CO 80120 ADA Environmental Solutions 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 303-339-8860 Cody Wilson ADA Environmental Solutions

Halogenated ACI 303-339-8860 ADA Environmental Solutions

NA 7/1/2009 NA

AmerenERGC Edwards21
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 Hg SO2

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 Edwards22
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 Edwards25 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 EdwardsPART 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 County 47 Coal seam48 1 Sub-bituminous Feb-09 48,858.20 1, 2 & 3 Wyoming/USA CampbellPRB 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 CampbellPRB 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 CampbellPRB 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 CampbellPRB 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 Edwards15 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 CampbellPRB 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 CampbellPRB 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 CampbellPRB 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 CampbellPRB 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 CampbellPRB 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 Edwards36 Sub-bituminous Nov-09 65,711.80 1, 2 & 3 Wyoming/USA CampbellPRB 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 CampbellPRB 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 Edwards6 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 EdwardsEmission 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

NoX If yes, please note which reports and provide a detailed description of the location of the emissions sampling point(s). 8d Yes

NoX
8e Yes

NoX 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 Edwards8f Yes

NoX 8g Yes

NoX
9 Quarterly excess emissions reports, notification of excess emissions due to malfunction and breakdowns 10 YesX

No

11 Yes

NoX
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 IDQuarterly 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 EdwardsDate 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 EdwardsPART 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

NoX 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 permitted6to 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 Hutsonville14a

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 Yes Boiler Chemical Cleaning Wash

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 permitted10to 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 Hutsonville16

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).

Demonstrationactivity actual startup date Demonstration

activity projected start-up date Demonstration

activity end-dateor 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 Hutsonville20

Boiler

ID30 NA 21

PM1034PM2.535 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 Hutsonville23 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 HutsonvillePART 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 County 47 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 Hutsonville5 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 HutsonvilleEmission Data 8a

See Test Number in 8b 8b Test Report Boiler ID 1 4 2 4 3 3 4 4 8c Yes

NoX If yes, please note which reports and provide a detailed description of the location of the emissions sampling point(s). 8d Yes

NoX
8e Yes

NoX
8f Yes

NoX 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 Hutsonville8g Yes

NoX

9
10 YesX

11 Yes

NoX

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 HutsonvillePART 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

NoX 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 permitted6to 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 Labadie14a

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 permitted10to 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 4

3

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 Labadie16

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 Demonstrationactivity actual startup date Demonstration

activity projected start-up date Demonstration

activity end-dateor projected enddate

NA NA NA NA

AmerenUE Labadie20

Boiler

ID30 NA 21

PM1034PM2.535 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 Labadie23 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 NA CAM

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 LabadiePART 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 County 47 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 Labadie17 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 Labadie41 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 Labadie66 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 Labadie90 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 Labadie116 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 Labadie139 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-091,624.00 1, 2, 3 & 4 Missouri/USA St. Louis NA Truck 153 #2 Feb-093,255.00 1, 2, 3 & 4 Missouri/USA St. Louis NA Truck 154 #2 Apr-091,607.00 1, 2, 3 & 4 Missouri/USA St. Louis NA Truck 155 #2 May-092,494.00 1, 2, 3 & 4 Missouri/USA St. Louis NA Truck 156 #2 Jun-091,772.00 1, 2, 3 & 4 Missouri/USA St. Louis NA Truck 157 #2 Jul-09887.00 1, 2, 3 & 4 Missouri/USA St. Louis NA Truck 158 #2 Aug-09708.00 1, 2, 3 & 4 Missouri/USA St. Louis NA Truck 159 #2 Sep-092,663.00 1, 2, 3 & 4 Missouri/USA St. Louis NA Truck 160 #2 Oct-091,964.00 1, 2, 3 & 4 Missouri/USA St. Louis NA Truck 161 #2 Nov-09358.00 1, 2, 3 & 4 Missouri/USA St. Louis NA Truck 162 #2 Dec-093,241.00 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 Labadie5 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 LabadieEmission 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

NoX If yes, please note which reports and provide a detailed description of the location of the emissions sampling point(s). 8d Yes

NoX
8e Yes

NoX 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
Particulate (CAM Testing) 10/19/2005

AmerenUE Labadie8f Yes

NoX 8g Yes

NoX

9

10 YesX

No

11 Yes

NoX

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 LabadieDate 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 LabadiePART 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

NoX 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 permitted6to 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 Meramec14a

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 permitted10to 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 NA Applicable NSPS 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 Meramec16

17

NA 18

Boiler ID27 NA 19

NA NA NA NA NA NA

NA Other control24

NOx control21

Over Fired Air Nov 2006 NA Tangential firing 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-dateor 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).

Demonstrationactivity actual startup date Demonstration

activity projected start-up date Cold Side ESP (#1) NA NA

AmerenUE Meramec20

Boiler

ID30 NA 21
PM1034PM2.535 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 Meramec22
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 Meramec25 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 MeramecPART 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 County 47 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 Meramec22 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 Meramec49 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 Meramec74 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 Meramec5 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 MeramecEmission 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

NoX If yes, please note which reports and provide a detailed description of the location of the emissions sampling point(s). 8d Yes

NoX
8e Yes

NoX
8f Yes

NoX 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 Meramec8g Yes

NoX

9

10 YesX

No

11 Yes

NoX

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 MeramecPART 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

NoX 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 permitted6to 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 Meredosia14a

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% None in 2009 Yes

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% 84.70% 84.10%
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 NA Operating steam reheat temperature (°F)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 permitted10to 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 Meredosiacoal 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 Meredosia16 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 3412 Hillview Ave, Palo Alto, CA 94303 Ramsay Chang 650-855-2535
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 Meredosia18

Boiler

ID27 Phase 1 - Boiler 5 (Unit 3) Phase 2 - Boiler 3 (Unit 2) 19

5
20

Boiler ID30 5 NA 5 Lb/mmacf 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).

Demonstrationactivity actual startup date

NA 90.00%

Demonstration activity projected start-up date Demonstration

activity end-dateor 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 8100 Southpark Way, Unit B, Littleton, CO 80120 Cody Wilson 303-339-8860

AmerenAGC Meredosia21

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 Meredosia24 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 MeredosiaPART 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 County 47 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/RochellTrain/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/RochelleTrain/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 Meredosia4 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 MeredosiaEmission Data 8a

See Test Number in 8b 8b Test Report Boiler ID 1 5 2 5 8c Yes

NoX If yes, please note which reports and provide a detailed description of the location of the emissions sampling point(s). 8d Yes

NoX
8e Yes

NoX
8f Yes

NoX 8g Yes

NoX Mercury

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: Constituents: Sep-05 Mercury 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. 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 Meredosia9
10 YesX

No

11 Yes

NoX

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 MeredosiaPART 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

NoX 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 permitted6to 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 Newton14a

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 permitted10to 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 Newton16

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-dateor projected enddate Type of control (e.g.,

sorbent and type; chemical additive28)

303-339-8860 Telephone 8100 Southpark Way, Unit B, Littleton, CO 80120 8100 Southpark Way, Unit B, Littleton, CO 80120 303-339-8860 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

Demonstrationactivity 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 Newton20

Boiler

ID30 1 2 21
PM1034PM2.535 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 Newton23 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 NewtonPART 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 County 47 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 Newton18 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 Newton39 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 Newton5 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 NewtonEmission 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

NoX If yes, please note which reports and provide a detailed description of the location of the emissions sampling point(s). 8d Yes

NoX
8e Yes

NoX
8f Yes

NoX 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

Parametric Testing Aug-09
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 Newton8g Yes

NoX

9
10 YesX

No

11 Yes

NoX

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 NewtonPART 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

NoX 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 permitted6to 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 Island14a

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 8256 7563 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 permitted10to 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 Island16

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).

Demonstrationactivity actual startup date Demonstration

activity projected start-up date Demonstration

activity end-dateor 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 Island20

Boiler

ID30 NA 21
PM1034PM2.535 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 Island24 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 NA CAM

CAM NA CEMS Records of 3 hr rolling average Quarterly Excess emissions Reporting

AmerenUE Rush IslandPART 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 County 47 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 Barrels26 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-09667.00 1 & 2 Illinois/USA Madison NA Truck 48 #2 Mar-09333.00 1 & 2 Misssouri/USA St. Louis NA Truck 49 #2 May-091,470.00 1 & 2 Misssouri/USA St. Louis NA Truck 50 #2 Sep-091,714.00 1 & 2 Misssouri/USA St. Louis NA Truck 51 #2 Oct-09714.00 1 & 2 Misssouri/USA St. Louis NA Truck 52 #2 Nov-09543.00 1 & 2 Illinois/USA St. Clair NA Truck 53 #2 Nov-09926.00 1 & 2 Misssouri/USA St. Louis NA Truck 54 #2 Dec-091,102.00 1 & 2 Misssouri/USA St. Louis NA Truck 55 #2 Dec-09186.00 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 YesNA

NoNA If yes, please note which reports and provide a detailed description of the location of the emissions sampling point(s). 8d YesNA

NoNA
8e YesNA

NoNA
8f YesNA

NoNA 8g YesNA

NoNA 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 NA9

10 YesX

No

11 Yes

NoX

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 occurrencePART 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

NoX 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 permitted6to be fired in any steam generating unit at this facility? 

### Union Electric Co. dba AmerenUE

Mass Percentage Btu percentage

AmerenUE Sioux13 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 permitted10to 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 Actually burn Quantity/year Other Material Permitted to burn

AmerenUE Sioux15

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 1005Blend Subbituminous and Bituminous 524 496 89.03 86.9

7737 65 87.3 4000 3883 1005 1005

1005Blend 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 Sioux18

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).

Demonstrationactivity actual startup date Demonstration

activity projected start-up date Demonstration

activity end-dateor 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 Sioux21

PM1034PM2.535 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 Sioux25 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 SiouxPART 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 County 47 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 Train49 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-09181.00 1 & 2 Illinois/USA Madison NA Truck 60 #2 Mar-0995.00 1 & 2 Illinois/USA Madison NA Truck 61 #2 May-09178.00 1 & 2 Illinois/USA Madison NA Truck 62 #2 Jun-09533.00 1 & 2 Illinois/USA Madison NA Truck 63 #2 Jul-09353.00 1 & 2 Illinois/USA Madison NA Truck 64 #2 Sep-09535.00 1 & 2 Illinois/USA Madison NA Truck 65 #2 Oct-091,255.00 1 & 2 Illinois/USA Madison NA Truck 66 #2 Nov-091,252.00 1 & 2 Illinois/USA Madison NA Truck 67 #2 Dec-09173.00 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

NoX If yes, please note which reports and provide a detailed description of the location of the emissions sampling point(s). 8d Yes

NoX
8e Yes

NoX
8f Yes

NoX 8g Yes

NoX 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 YesX

No

11 Yes

NoX

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