### GEORGIA POWER - Submittal for PLANT SCHERER

Electric Utility Steam Generating Unit (EGU) Hazardous Air Pollutant Emissions (HAPs) Information Collection Request (ICR), OMB Control No. 2060-0631 April 5, 2010

PART I: GENERAL FACILITY INFORMATION

Process Information

1Name of legal owner of facility:

Georgia Power, Oglethorpe Power Corporation (OPC), Florida Power & Light (FP&L), Municipal Electric Authority of Georgia (MEAG), Gulf Power, Jacksonville Electric Authority (JEA), and Dalton Utilities (DU). 2Name of legal operator of facility, if different from legal owner:

Georgia Power 3Address of ____ legal owner or _X___ operator:

241 Ralph McGill Blvd NE, Bin 10221 Atlanta, GA 30308 4aPlant Name (as reported on U.S. DOE/EIA Form-860 (2007), "Annual Electric Generator Report", schedule 2, line 1, page 37, question 1) OR Plant Name (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report", schedule 2, page 1, question 1):

Scherer 4bEIA Plant Code (as reported on U.S. DOE/EIA Form-860 (2007), schedule 2, line 1, page 37, question 2) OR Plant ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), schedule 2, page 1, question 2):

6257 5Complete street address of facility (physical location):

10986 Highway 87 Juliette, Georgia 31046 6Provide mailing address if different:

241 Ralph McGill Blvd NE, Bin 10221 Atlanta, GA 30308 7Name and title of contact(s) able to answer technical questions about the completed survey:

Sarah Markham, Engineer II 8Contact(s) telephone number(s):

(205) 257-6780 and e-mail address(es):

sasander@southernco.com 9Is this facility considered to be owned or operated by a small entity as defined by the Regulatory Flexibility Act? ____ Yes

_X__ No____ Don't know

Page 1 of 93 part I, 1-14

### GEORGIA POWER - Submittal for PLANT SCHERER

Electric Utility Steam Generating Unit (EGU) Hazardous Air Pollutant Emissions (HAPs) Information Collection Request (ICR), OMB Control No. 2060-0631 April 5, 2010

PART I: GENERAL FACILITY INFORMATION

10Which of the following fossil fuels or other material(s) are fired in any steam generating unit at this facility?

_X__ coal

__X__ oil (including pet coke)

_ __ natural gas

_ __ other (specify in question 14 below)

11Which of the following fossil fuel or other material(s) are permitted1

### to be fired in any steam generating unit at this facility?

_X__ coal

_X__ oil (including pet coke)

_ __ natural gas

_X__ other (specify in question 14 below)

12If 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:2,3 

### ____ lignite (% _____)

_X___ subbituminous (% _100____) ____ bituminous (% _____) ____ anthracite (% _____) ____ coal refuse (including gob, culm, and subbituminous-derived coal refuse) (% _____) ____ synfuel (including, but not limited to, briquettes, pellets, or extrusions which are formed by binding materials, or processes that recycle materials) (%_____) (please specify the type or form of synfuel used ___________________________________________) ____ petroleum coke (% _____)

13If oil is fired, indicate which type of oil was utilized during the previous 12 months prior to the receipt of this ICR:4



### _X___ distillate (% _100____)

_ _ __ other (specify __________) (% _____) ____ residual or bunker C (% _____)

Page 2 of 93 part I, 1-14

### GEORGIA POWER - Submittal for PLANT SCHERER

Electric Utility Steam Generating Unit (EGU) Hazardous Air Pollutant Emissions (HAPs) Information Collection Request (ICR), OMB Control No. 2060-0631 April 5, 2010

PART I: GENERAL FACILITY INFORMATION

14aIf "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 permitted5

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

14bIf "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____ No Explain: Until the regulations are finalized, we cannot determine with certainty whether we would use these other materials.

1"Permitted" in this context, refers to the fuels that the permit anticipates will be combusted at the facility.

2If the boiler is fired by a blend of coal ranks, please specify percentage (separately, on both a mass and on a Btu basis) of each coal rank (e.g., 85% subbituminuous/15% bituminous).

3In reference to footnote 1, if necessary, a notation can be added to a utilized fuel type that is not listed in the operating permit noting the reason the fuel type was combusted (e.g., "the permitting agency allowed this fuel to be combusted for special testing and research purposes").

4If the boiler is fired by a blend of fuel oil ranks, please specify percentage (separately, on both a volume and on a Btu basis) of each fuel oil rank (e.g., 85% residual oil/15% distillate).

5If necessary, a notation can be added to a utilized fuel type that is not listed in the operating permit noting the reason the fuel was combusted (e.g., "the permitting agency allowed this fuel to be combusted for special testing and research purposes"). None in 2009 None in 2009 None in 2009 

### Quantity/year Actually burn None in 2009 None in 2009 None in 2009 

### Other Material Sawdust Biomass 

### Permitted to burn Yes Yes

Synfuel Yes None in 2009 Used Oil Yes None in 2009



### Page 3 of 93 part I, 1-14

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

15Identification (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. SEE NOTES BELOW for explanations of responses.Boiler ID6Original design fuel (i.e.,coal rank or type of oil)Design heat input,(MMBtu/hr)7Present maximum heatinput, (MMBtu/hr)8MWe Gross capacitysummerMWe Net CapacitysummerOriginal design grossefficiency (%, HHV)Present operating grossefficiency (%, HHV)Design steam pressure(psig)Operating steam pressure(psig)Design steam temperature(oF)Operating steamtemperature (oF)Design steam reheattemperature (oF)9Operating steam reheattemperature (oF)10Fuel11Hours/year operated12Average annual capacityfactor for the past 3 yearsApplicable NSPSEstimated year ofretirement13

1 subbituminous CBI CBI 870 820 87.1 84.6 2400 2404 1000 967 1000 998 sub-bituminous coal (100%), distillate oil (100%) CBI CBI Subpart DNone planned 2 subbituminous CBI CBI 870 820 87.1 87.6 2400 2396 1000 989 1000 1002 sub-bituminous coal (100%), distillate oil (100%) CBI CBI Subpart DNone planned 3 bituminous CBI CBI 880 839 89.3 86.0 2400 2391 1000 1000 1000 999 sub-bituminous coal (100%), distillate oil (100%) CBI CBI Subpart DNone planned 4 bituminous CBI CBI 880 839 89.3 86.2 2400 2398 1000 996 1000 1003 sub-bituminous coal (100%), distillate oil (100%) CBI CBI Subpart DNone planned

6Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).

7Per fuel burned in the boiler. Report this based on higher heating value (HHV).

8Per fuel burned in the boiler. Report this based on higher heating value (HHV).

9Please indicate if more than one steam reheat cycle is utilized, and, if so, please provide information for both.

10Please indicate if more than one steam reheat cycle is utilized, and, if so, please provide information for both.

11Indicate the fuels utilized for the indicated boiler, and percentages, as indicated in questions 11 - 13.

12The "hours/year operated" would be the average of the actual number of hours the unit operated in 1 year based on the last 3 years of operation.

13This can be treated as CBI and can be submitted through the proper CBI procedure if desired. 

### NOTES: Original Design Fuel

Based on the original contract boiler data sheet; only the primary fuel is listed if multiple fuels were included on the data sheet. Design Heat Input Confidential Business Information Present Maximum Heat Input Confidential Business Information MWe Gross Capacity Summer Identifies the gross normal full load. Georgia Power does not change unit capacities season from season. MWe Net Capacity Summer Identifies the net normal full load; taken directly from the 2010 installed and authorized document. Georgia Power does not change unit capacities from season to season. Original Design Gross Efficiency Taken directly from the original contract boiler data sheet.

Page 4 of 93 part I, 15

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

15Identification (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. SEE NOTES BELOW for explanations of responses.Boiler ID6Original design fuel (i.e.,coal rank or type of oil)Design heat input,(MMBtu/hr)7Present maximum heatinput, (MMBtu/hr)8MWe Gross capacitysummerMWe Net CapacitysummerOriginal design grossefficiency (%, HHV)Present operating grossefficiency (%, HHV)Design steam pressure(psig)Operating steam pressure(psig)Design steam temperature(oF)Operating steamtemperature (oF)Design steam reheattemperature (oF)9Operating steam reheattemperature (oF)10Fuel11Hours/year operated12Average annual capacityfactor for the past 3 yearsApplicable NSPSEstimated year ofretirement13



### Present Operating Gross Efficiency Based on the most recent actual test of the boiler efficiency, unless no recent boiler efficiency test was available. Where no recent test was available, that status is indicated. Design Steam Pressure Based on the thermal design of the unit as represented on the turbine heat balance sheet. Operating Steam Pressure Represents the average throttle pressure when the unit operated at gross normal full load over a three year period (January 2007 to December 2009). Design Steam Temperature Based on the thermal design of the unit as represented on the turbine heat balance sheet. Operating Steam Temperature Represents the average steam temperature when the unit operated at gross normal full load over a three year period (January 2007 to December 2009). Design Steam Reheat Temperature Based on the thermal design of the unit as represented on the turbine heat balance sheet. Operating Steam Reheat Temperature Represents the average reheat steam temperature when the unit operated at gross normal full load over a three year period (January 2007 to December 2009). Fuel Indicates the fuels burned in the previous calendar year (January to December 2009). Hours/Year Operated Confidential Business Information Annual Average Capacity Factor for the Past 3 Years Confidential Business Information Applicable NSPS Where no NSPS is identified, the unit is not currently subject to any NSPS. Retirement Year Georgia Power and Plant Scherer co-owners have not committed to actual retirement dates for Units 1-4. Georgia Power continually evaluates retirement scenarios with respect to its generating units for a variety of planning purposes, taking into account a wide range of variables. While the company assumes financial "retirement dates" for accounting purposes, for example, for depreciation schedules or for FERC or Public Service Commission uses, these dates are not indicative of the unit's actual retirement date.

Page 5 of 93 part I, 15

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

16For 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 the first control following the boiler, 2 for the second control following the boiler, etc.): NOTES: SO3 flue gas conditioning systems are operated on an as-needed basis. Dates for future planned controls listed are subject to change. Operation of planned SCRs required during ozone season only. Boiler ID14 

### Type15 

### NOx control16 

### SO2 control17 

### PM control18 

### Other control19

1 tangential-fired (1) overfire air (3/2001) (2) SCR (5/2014), catalyst not yet purchased (6) wet flue gas desulfurization (FGD) (4/2014), calcium-based (4) cold-side electrostaticprecipitator (ESP) (3/1982, hotside ESP original install; conversion to cold-side 5/2003) (3) flue gas conditioning - SO3 injection (5/2003) (5) baghouse with activated carbon injection (mercury control, 12/2009 initial startup, 2/2010 commercial operation)

2 tangential-fired (1) overfire air (1/2002) (2) SCR (6/2013), catalyst not yet purchased (6) wet flue gas desulfurization (FGD) (8/2013), calcium-based. (4) cold-side electrostaticprecipitator (ESP) (2/1984, hotside ESP original install; conversion to cold-side 12/2003) (3) flue gas conditioning - SO3 injection (12/2003) (5) baghouse with activated carbon injection (mercury control, 4/2009 initial startup, 6/2009 commercial operation)

3 tangential-fired (1) overfire air (12/2001) (2) SCR (5/2011), catalyst not yet purchased (5) wet flue gas desulfurization (FGD) (4/2011), calcium-based. (3) cold-side electrostatic precipitator (ESP) (1/1987, original install) (5) baghouse with activated carbon injection (mercury control, 12/2008 initial startup, 2/2009 commercial operation)

4 tangential-fired (1) overfire air (11/2002) (2) SCR (5/2012), catalyst not yet purchased (5) wet flue gas desulfurization (FGD) (8/2012), calcium-based. (3) cold-side electrostatic precipitator (ESP) (2/1989, original install) (5) baghouse with activated carbon injection (mercury control, 4/2010 initial startup, 6/2010 commercial operation)



### Page 6 of 93 part I, 16

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

16For 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 the first control following the boiler, 2 for the second control following the boiler, etc.): NOTES: SO3 flue gas conditioning systems are operated on an as-needed basis. Dates for future planned controls listed are subject to change. Operation of planned SCRs required during ozone season only. Boiler ID14 

### Type15 

### NOx control16 

### SO2 control17 

### PM control18 

### Other control19

14Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).

15Examples: tangential-fired; cyclone; wall-fired; circulating fluidized bed (CFB)

16Examples: low-NOx burners; selective catalytic reduction (SCR); selective non-catalytic reduction (SNCR); over-fire air (OFA). Include specific date that control went online or planned operational date for new installation. If this boiler's control configuration utilizes a SCR, please include the type of material from which the catalyst is manufactured and the type of reductant used in with the SCR (e.g., anhydrous ammonia, urea, other). Also, please note if the catalyst is specifically designed to reduce SO3 formation?

17Examples: wet flue gas desulfurization (FGD; any type); dry scrubbing (any type); specify whether calcium- or sodium-based. Include specific date that control went online or planned operational date for new installation.

18Examples: fabric filter; cold-side electrostatic precipitator (ESP); hot-side ESP; cyclone or multiclone; venturi scrubber. Include specific date that control went online or planned operational date for new installation. 

### January 1, 2009 - December 31, 2009

19Please indicate systems installed specifically to control any other pollutants (e.g., Hg, SO3, etc.). Examples: activated carbon injection (ACI); Powerspan ECO®; dry sorbent injection or wet ESP for SO3 control; flue gas conditioning to control opacity (e.g., SO3 injection, ammonia, other); additive use for mercury control (e.g., bromine; scrubber additives). Include specific date that control went online or planned operational date for new installation. Also include any pollutants controlled by this technology (e.g., control technology [pollutant controlled]).



### Page 7 of 93 part I, 16

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

17For 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 project20

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

Name Telephone Address
1 

### Not applicable Not applicable Not applicable Not applicable 2 

### Not applicable Not applicable Not applicable Not applicable 3 

### Not applicable Not applicable Not applicable Not applicable
4 

### Not applicable Not applicable Not applicable Not applicable

20A control technology demonstration project is defined as a U.S. Government (e.g., U.S. Department of Energy program) sponsored (in whole or in part) project or mandate (e.g., as a result of a consent decree) that adds a HAP control technology to a facility's unit to demonstrate the technology's HAP removal performance.

21Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8). 

### Company (vendor) contact information Boiler ID21 

### Company (vendor) name

Page 8 of 93 part I, 17

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

18For the control technologies identified in Part I, question 17, provide the date of actual start-up of the demonstration (if the control is currently operating), the date of expected or projected start-up, the date the demonstration was completed, the type of HAP control installed (e.g., sorbent and type; pre-combustion boiler chemical additive; combustion boiler chemical additive), the desired HAP emission reduction or rate (if any), and the coal rank(s) upon which the demonstration was conducted. Please specify the format of the target HAP emission reduction rate (e.g., lb/MWh, lb/TBtu, percent reduction, etc.). If the format of the target end-point is percent reduction, provide (1) an estimate of what an equivalent emission rate would be (and specify the format of the equivalent emission rate), and (2) the basis for calculating the percent reduction (i.e., where the "inlet" and "outlet" are).

Boiler ID22 

### Demonstration

activity actual startup date Demonstration

activity projected start-up date Demonstration

activity end-date or projected end-dateType of control (e.g.,

sorbent and type; chemical additive23

### ) Desired HAP

emission reduction (%) or emission rateCoal rank(s) in use

1 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable 2 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable 3 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable 4 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

22Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).

23If additive is used, please indicate injection point.



### Page 9 of 93 part I, 18

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

19For 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 provide a non-demonstration, full-scale operating system.

Name Telephone Address
1 Siemens Energy, Inc (formerly Wheelabrator) Daniel S. Chobirko, PMP412-562-7306 501 Grant Street, Pittsburgh, PA 15219-4429

2 Siemens Energy, Inc (formerly Wheelabrator) Daniel S. Chobirko, PMP412-562-7306 501 Grant Street, Pittsburgh, PA 15219-4429

3 Siemens Energy, Inc (formerly Wheelabrator) Daniel S. Chobirko, PMP412-562-7306 501 Grant Street, Pittsburgh, PA 15219-4429

4 Siemens Energy, Inc (formerly Wheelabrator) Daniel S. Chobirko, PMP412-562-7306 501 Grant Street, Pittsburgh, PA 15219-4429

24Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8). 

### Company (vendor) contact information Boiler ID24 

### Company (vendor) name

Page 10 of 93 part I, 19

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

20For 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-construction boiler chemical additive; combustion of boiler chemical additive), the guaranteed HAP emission reduction or emission rate, the sorbent feed rate upon which the guarantee is based, and the coal rank(s) upon which the guarantee is based. Please specify the format of the guarantee (e.g., lb/MWh, lb/TBtu, percent reduction, etc.). If the format of the guarantee is percent reduction, provide (1) an estimate of what an equivalent emission rate would be (and specify the format of the equivalent emission rate), and (2) the basis for calculating the percent reduction (i.e., where the "inlet" and "outlet" are). NOTE: All guarantees are based on and demonstrated with certain fuel and operating conditions. Guarantees are not necessarily representative of the long term or day to day variability that may occur with changes in fuel specifications, operating conditions, normal wear and tear of equipment over time, startups, shutdowns, and malfunctions.

Boiler ID25

### Actual startup date Expected or

projected start-up date Type of control (e.g.,

sorbent and type; chemical additive)26 

### 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



### 1 12/7/2009 (first gas) Not

applicable baghouse with activated

carbon injection upstream of the baghouse, downstream of the ESP CBI CBI CBI

2 4/27/2009 (first gas) Not

applicable baghouse with activated

carbon injection upstream of the baghouse, downstream of the ESP CBI CBI CBI

3 12/08/2008 (first gas) Not

applicable baghouse with activated

carbon injection upstream of the baghouse, downstream of the ESP CBI CBI CBI

Page 11 of 93 part I, 20

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

20For 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-construction boiler chemical additive; combustion of boiler chemical additive), the guaranteed HAP emission reduction or emission rate, the sorbent feed rate upon which the guarantee is based, and the coal rank(s) upon which the guarantee is based. Please specify the format of the guarantee (e.g., lb/MWh, lb/TBtu, percent reduction, etc.). If the format of the guarantee is percent reduction, provide (1) an estimate of what an equivalent emission rate would be (and specify the format of the equivalent emission rate), and (2) the basis for calculating the percent reduction (i.e., where the "inlet" and "outlet" are). NOTE: All guarantees are based on and demonstrated with certain fuel and operating conditions. Guarantees are not necessarily representative of the long term or day to day variability that may occur with changes in fuel specifications, operating conditions, normal wear and tear of equipment over time, startups, shutdowns, and malfunctions.

Boiler ID25

### Actual startup date Expected or

projected start-up date Type of control (e.g.,

sorbent and type; chemical additive)26 

### Guaranteed HAP emission reduction (%) or emission rate Sorbent or additive feed rate on which guarantee is based Coal rank(s) upon which guarantee is based



### 4 Not applicable4/2010 (first

gas) baghouse with activated

carbon injection upstream of the baghouse, downstream of the ESP CBI CBI CBI

25Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).

26If additive is used, please indicate injection point.



### Page 12 of 93 part I, 20

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

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

PM28 

### PM10(29) 

### PM2.5(30) 

### SO2 HCl and/or HF HCN Metal
HAP31 

### Hg CO Other organics (specify) Other pollutant (specify)

1 0.10 lb/MMBtu (Title V permit; based on 3-run stack test using Method 5 of 17; test conducted every 13 months, but may be deferred for 12 months if test results from the previous annual tests are fifty percent or less of the limit) Not applicableNot

applicable1.2 lb/MMBtu (Title V permit; based on 30-day

rolling average, monitored by coal sulfur and heat content analysis and calculation)

5% of potential combustion concentration (95% removal by FGD), effective Jan 1, 2015 (State rule, Title V permit revision not complete; based on 30-day rolling average, monitored by CEMS at inlet to scrubber and at scrubber stack during scrubber operations, excluding startup, shutdown, malfunction, and other exemptions)Not applicableNot

applicableNot

applicableNot

applicableNot

applicableNot

applicableNOx: 0.7 lb/MMBtu (Title V permit; based on 3-

hour average determined by CEMS) 0.20 lb/MMBtu from May 1 through September 30 OR compliance with 7-plant NOx average of 0.18 lb/MMBtu and Scherer site-average of 0.17 lb/MMBtu (Title V permit; based on 30-day rolling averages determined by CEMS)

Southern Company Phase II NOx Averaging Plan limit of 0.46 lb/MMBtu (average of all units) (Phase II NOx Compliance Plan; based on annual average determined by CEMS)

2 0.10 lb/MMBtu (Title V permit; based on 3-run stack test using Method 5 of 17; test conducted every 13 months, but may be deferred for 12 months if test results from the previous annual tests are fifty percent or less of the limit) Not applicableNot

applicable1.2 lb/MMBtu (Title V permit; based on 30-day

rolling average, monitored by coal sulfur and heat content analysis and calculation)

5% of potential combustion concentration (95% removal by FGD), effective Jan 1, 2014 (State rule, Title V permit revision not complete; based on 30-day rolling average, monitored by CEMS at inlet to scrubber and at scrubber stack during scrubber operations, excluding startup, shutdown, malfunction, and other exemptions)Not applicableNot

applicableNot

applicableNot

applicableNot

applicableNot

applicableNOx: 0.7 lb/MMBtu (Title V permit; based on 3-

hour average determined by CEMS) 0.17 lb/MMBtu from May 1 through September 30 OR compliance with 7-plant NOx average of 0.18 lb/MMBtu and Scherer site-average of 0.17 lb/MMBtu (Title V permit; based on 30-day rolling averages determined by CEMS)

Southern Company Phase II NOx Averaging Plan limit of 0.46 lb/MMBtu (average of all units) (Phase II NOx Compliance Plan; based on annual average determined by CEMS)

3 0.10 lb/MMBtu (Title V permit; based on 3-run stack test using Method 5 of 17; test conducted every 13 months, but may be deferred for 12 months if test results from the previous annual tests are fifty percent or less of the limit) Not applicableNot

applicable1.2 lb/MMBtu (Title V permit; based on 30-day

rolling average, monitored by coal sulfur and heat content analysis and calculation)

5% of potential combustion concentration (95% removal by FGD), effective Jan 1, 2012 (State rule, Title V permit revision not complete; based on 30-day rolling average, monitored by CEMS at inlet to scrubber and at scrubber stack during scrubber operations, excluding startup, shutdown, malfunction, and other exemptions)Not applicableNot

applicableNot

applicableNot

applicableNot

applicableNot

applicableNOx: 0.7 lb/MMBtu (Title V permit; based on 3-

hour average determined by CEMS) 0.15 lb/MMBtu from May 1 through September 30 OR compliance with 7-plant NOx average of 0.18 lb/MMBtu and Scherer site-average of 0.17 lb/MMBtu (Title V permit; based on 30-day rolling averages determined by CEMS)

Southern Company Phase II NOx Averaging Plan limit of 0.46 lb/MMBtu (average of all units) (Phase II NOx Compliance Plan; based on annual average determined by CEMS) 

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

Boiler ID27



### Page 13 of 93 part I, 21

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

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

PM28 

### PM10(29) 

### PM2.5(30) 

### SO2 HCl and/or HF HCN Metal
HAP31 

### Hg CO Other organics (specify) Other pollutant (specify) Permitted emission limit (indicate type of permit and format of emission limit)

Boiler ID27

4 0.10 lb/MMBtu (Title V permit; based on 3-run stack test using Method 5 of 17; test conducted every 13 months, but may be deferred for 12 months if test results from the previous annual tests are fifty percent or less of the limit) Not applicableNot

applicable1.2 lb/MMBtu (Title V permit; based on 30-day

rolling average, monitored by coal sulfur and heat content analysis and calculation)

5% of potential combustion concentration (95% removal by FGD), effective Jan 1, 2013 (State rule, Title V permit revision not complete; based on 30-day rolling average, monitored by CEMS at inlet to scrubber and at scrubber stack during scrubber operations, excluding startup, shutdown, malfunction, and other exemptions)Not applicableNot

applicableNot

applicableNot

applicableNot

applicableNot

applicableNOx: 0.7 lb/MMBtu (Title V permit; based on 3-

hour average determined by CEMS) 0.16 lb/MMBtu from May 1 through September 30 OR compliance with 7-plant NOx average of 0.18 lb/MMBtu and Scherer site-average of 0.17 lb/MMBtu (Title V permit; based on 30-day rolling averages determined by CEMS)

Southern Company Phase II NOx Averaging Plan limit of 0.46 lb/MMBtu (average of all units) (Phase II NOx Compliance Plan; based on annual average determined by CEMS)

27Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).

28If the boiler has separate permitted emission limits for filterable and condensable PM, respectively, please indicate those separate limits. Also include the compliance test method utilized.

29List the compliance test method utilized.

30List the compliance test method utilized.

31Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, phosphorus, and selenium; indicate permit level for all metal HAP for which a permit level has been developed.



### Page 14 of 93 part I, 21

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

22For each boiler noted in Part I, question 15, provide the following information: NOTE: All guarantees are based on and demonstrated with certain fuel and operating conditions. Guarantees are not necessarily representative of the long term or day to day variability that may occur with changes in fuel specifications, operating conditions, normal wear and tear of equipment over time, startups, shutdowns, and malfunctions.

PM33 

### PM10 

### PM2.5 

### SO2 HCl and/or HF HCN Metal
HAP34 

### Hg CO Other organics (specify) Other pollutant (specify)

1 ESP: 99.97 % collection efficiency filterable (expired in 1982) Baghouse: CBI FGD: CBI Not applicableNot

applicableFGD: 98% instantaneous removal efficiency to

meet a 95% 30-day rolling average removal efficiency (not yet demonstrated, expires 18- months after startup) Not applicableNot

applicableNot

applicableNot

applicableNot

applicableNot

applicableNot applicable

2 ESP: 99.97 % collection efficiency filterable (expired in 1984) Baghouse: CBI FGD: CBI Not applicableNot

applicableFGD: 98% instantaneous removal efficiency to

meet a 95% 30-day rolling average removal efficiency (not yet demonstrated, expires 18- months after startup) Not applicableNot

applicableNot

applicableNot

applicableNot

applicableNot

applicableOverfire Air NOx: 0.23 (expired in 2003)

3 ESP: 97.75 % collection efficiency filterable (expired in 1987) Baghouse: CBI FGD: CBI Not applicableNot

applicableFGD: 98% instantaneous removal efficiency to

meet a 95% 30-day rolling average removal efficiency (not yet demonstrated, expires 18- months after startup) Not applicableNot

applicableNot

applicableNot

applicableNot

applicableNot

applicableOverfire Air NOx: 0.13 (expired in 2002)

4 ESP: 97.75 % collection efficiency filterable (expired in 1989) Baghouse: CBI FGD: CBI Not applicableNot

applicableFGD: 98% instantaneous removal efficiency to

meet a 95% 30-day rolling average removal efficiency (not yet demonstrated, expires 18- months after startup) Not applicableNot

applicableNot

applicableNot

applicableNot

applicableNot

applicableOverfire Air NOx: 0.13 (expired in 2003)



### 23Was any other guarantee level sought or offered? ____ Yes

_X___ No Please elaborate.

32Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).

33If the boiler has separate guaranteed emission rate for filterable and condensable PM, respectively, please indicate those separate emission rates.

34Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, cobalt, lead, manganese, nickel, phosphorus, and selenium; indicate permit level for all metal HAP for which a permit level has been developed. 

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

Boiler ID32



### Page 15 of 93 part I, 22-23

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

24For each boiler noted in Part I, question15, provide the following information:

PM36 

### PM10 

### PM2.5 

### SO2 HCl and/or HF HCN Metal
HAP37 

### Hg CO Other organics (specify)
1 Stack test conducted every 13 months, but may be deferred for 12 months if test results from the previous annual tests are fifty percent or less of the limit; under the CAM plan, opacity monitored continuously by COMS, excursions (3-hour block averages greater than 20%) reported quarterly.

The facility shall submit 30-day advance notifications of required testing and test reports within 60 days of completion of the testing. All records related to the Title V permit are retained for five years. Not applicableNot

applicableCoal sulfur content monitored through daily coal sampling;

fuel oil sulfur content monitored through vendor certification; exceedances of 1.2 lb/MMBtu 30-day rolling average limit reported quarterly; records retained for 5
years. Effective Jan 1, 2015, SO2 removal by the scrubber will be monitored by inlet and stack SO2 CEMS operated, maintained, and certified using 40 CFR Part 75 procedures. Data from these monitors will provide the SO2 removal percentage on a 30-day rolling average, excluding startup, shutdown, and malfunction. Exceedances of the 5% limit will be reported quarterly; records retained for 5 years (permit revision not yet issued). Not applicableNot

applicableNot

applicableNot

applicableNot

applicableNot

applicable

2 Stack test conducted every 13 months, but may be deferred for 12 months if test results from the previous annual tests are fifty percent or less of the limit; under the CAM plan, opacity monitored continuously by COMS, excursions (3-hour block averages greater than 20%) reported quarterly.

The facility shall submit 30-day advance notifications of required testing and test reports within 60 days of completion of the testing. All records related to the Title V permit are retained for five years. Not applicableNot

applicableCoal sulfur content monitored through daily coal sampling;

fuel oil sulfur content monitored through vendor certification; exceedances of 1.2 lb/MMBtu 30-day rolling average limit reported quarterly; records retained for 5
years. Effective Jan 1, 2014, SO2 removal by the scrubber will be monitored by inlet and stack SO2 CEMS operated, maintained, and certified using 40 CFR Part 75 procedures. Data from these monitors will provide the SO2 removal percentage on a 30-day rolling average, excluding startup, shutdown, and malfunction. Exceedances of the 5% limit will be reported quarterly; records retained for 5 years (permit revision not yet issued). Not applicableNot

applicableNot

applicableNot

applicableNot

applicableNot

applicable

3 Stack test conducted every 13 months, but may be deferred for 12 months if test results from the previous annual tests are fifty percent or less of the limit; under the CAM plan, opacity monitored continuously by COMS, excursions (3-hour block averages greater than 20%) reported quarterly.

The facility shall submit 30-day advance notifications of required testing and test reports within 60 days of completion of the testing. All records related to the Title V permit are retained for five years. Not applicableNot

applicableCoal sulfur content monitored through daily coal sampling;

fuel oil sulfur content monitored through vendor certification; exceedances of 1.2 lb/MMBtu 30-day rolling average limit reported quarterly; records retained for 5
years. Effective Jan 1, 2012, SO2 removal by the scrubber will be monitored by inlet and stack SO2 CEMS operated, maintained, and certified using 40 CFR Part 75 procedures. Data from these monitors will provide the SO2 removal percentage on a 30-day rolling average, excluding startup, shutdown, and malfunction. Exceedances of the 5% limit will be reported quarterly; records retained for 5 years (permit revision not yet issued). Not applicableNot

applicableNot

applicableNot

applicableNot

applicableNot

applicable 

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

Boiler ID35



### Page 16 of 93 part I, 24

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

24For each boiler noted in Part I, question15, provide the following information:

PM36 

### PM10 

### PM2.5 

### SO2 HCl and/or HF HCN Metal
HAP37 

### Hg CO Other organics (specify) Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a permitted emission limit

Boiler ID35

4 Stack test conducted every 13 months, but may be deferred for 12 months if test results from the previous annual tests are fifty percent or less of the limit; under the CAM plan, opacity monitored continuously by COMS, excursions (3-hour block averages greater than 20%) reported quarterly.

The facility shall submit 30-day advance notifications of required testing and test reports within 60 days of completion of the testing. All records related to the Title V permit are retained for five years. Not applicableNot

applicableCoal sulfur content monitored through daily coal sampling;

fuel oil sulfur content monitored through vendor certification; exceedances of 1.2 lb/MMBtu 30-day rolling average limit reported quarterly; records retained for 5
years. Effective Jan 1, 2013, SO2 removal by the scrubber will be monitored by inlet and stack SO2 CEMS operated, maintained, and certified using 40 CFR Part 75 procedures. Data from these monitors will provide the SO2 removal percentage on a 30-day rolling average, excluding startup, shutdown, and malfunction. Exceedances of the 5% limit will be reported quarterly; records retained for 5 years (permit revision not yet issued). Not applicableNot

applicableNot

applicableNot

applicableNot

applicableNot

applicable

35Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).

36If the boiler's monitoring, recordkeeping, and reporting requirements require your company to monitoring, keep records, and report filterable and condensable PM separately, please describe the separate actions required.

37Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, phosphorus, and selenium; indicate permit level for all metal HAP for which a permit level has been developed.



### Page 17 of 93 part I, 24

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

25For the control technologies identified in Part I, questions 17 and 19, provide the cost information requested.38



### Facility Name/Unit No.: Scherer Unit 1 Retrofit to existing boiler? Yes Installation on a new boiler? No Total Capital Investment: CBI Total Annual Operating and Maintenance Costs: CBI (Include base year for operating costs [e.g., 2006]

Facility Name/Unit No.: Scherer Unit 2 Retrofit to existing boiler? Yes Installation on a new boiler? No Total Capital Investment: CBI Total Annual Operating and Maintenance Costs: CBI (Include base year for operating costs [e.g., 2006] Facility Name/Unit No.: Scherer Unit 3 Retrofit to existing boiler? Yes Installation on a new boiler? No Total Capital Investment: CBI Total Annual Operating and Maintenance Costs: CBI (Include base year for operating costs [e.g., 2006] Facility Name/Unit No.: Scherer Unit 4 Retrofit to existing boiler? Yes Installation on a new boiler? No Total Capital Investment: CBI Total Annual Operating and Maintenance Costs: CBI (Include base year for operating costs [e.g., 2006]

26Are 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. PRB coal for reduction of NOx and SO2.

38This can be treated as CBI and can be submitted through the proper CBI procedure if desired.



### Page 18 of 93 part I, 25-26

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

PART II: FUEL ANALYSIS AND EMISSION DATA

Fuel Analysis39



### 1aPlant or facility name from Part I, question 4a: Scherer 1bPlant or facility code from Part I, question 4b: 6257

39The respondent should reply to this ICR with separate pages 18 through 24 (Part II) for each of their facilities.



### Page 19 of 93 part II, 1

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb 10,240 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 5.94 11,980 10,288 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 6.47 11,920 10,078 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 6.19 11,958 10,302 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 5.83 12,027 10,183 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 5.82 12,031 10,272 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.42 5.9 12,024 10,311 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.41 5.93 12,011 10,241 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.43 6.19 11,984 10,277 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.49 7.09 11,854 10,212 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.45 7.33 11,853 10,258 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.6 6.74 11,898 10,094 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.53 6.74 11,951 10,183 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.57 6.54 11,970 10,219 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.59 6.72 11,956 10,248 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.43 6.32 11,903 10,189 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.52 6.38 12,001 9,854 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.47 6.06 11,918 10,354 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.38 6.06 12,097 10,346 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.49 7.56 11,875 10,184 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.42 6.24 11,945 10,273 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.49 6.36 11,990 10,219 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.44 6.52 11,780 

### Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method

Page 20 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,163 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.51 6.32 11,979 10,263 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.51 6.34 11,950 9,577 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.5 6.18 11,953 9,659 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.54 6.41 11,976 9,533 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.51 6.35 11,956 10,186 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.52 6.89 11,923 10,305 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.4 6.41 11,975 10,233 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.45 6.31 11,985 10,192 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.58 6.55 11,967 10,212 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.57 6.48 11,991 10,242 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.52 6.4 11,991 10,344 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.38 6.23 11,964 10,350 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.39 6.31 11,918 10,380 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.54 6.48 11,940 10,149 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.47 6.34 11,976 10,287 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.53 6.75 11,947 10,462 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.59 6.74 11,920 10,312 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.54 6.76 11,870 10,205 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.47 6.94 11,936 10,387 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.62 7.05 11,872 10,311 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.46 6.46 11,868 10,234 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.51 6.37 11,939



### Page 21 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,243 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.46 6.08 11,960 10,221 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.49 6.18 11,975 10,379 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.55 6.84 11,858 10,340 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.56 6.65 11,892 10,429 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.61 6.76 11,881 10,211 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.5 6.16 11,948 10,173 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.49 6.45 11,912 10,355 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.44 6.89 11,841 10,406 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.58 6.62 11,915 10,369 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.5 6.16 11,916 10,172 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.53 6.22 11,897 10,209 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.6 6.81 11,882 10,393 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.48 6.1 11,952 10,309 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.55 6.4 12,031 10,167 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.61 7.14 12,042 10,252 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.53 6.56 11,961 10,364 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.47 6.42 12,040 10,431 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.62 7.01 11,923 10,065 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.61 6.6 11,978 10,448 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.5 7.73 11,732 10,213 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.63 6.44 11,826 10,230 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.31 5.79 12,026



### Page 22 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,278 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.51 6.57 11,955 10,186 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.52 6.48 11,970 10,233 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.37 5.77 12,022 10,329 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.46 6.02 12,016 10,337 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.54 6.17 11,981 10,295 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.48 6.1 12,032 10,155 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.52 7.33 11,833 10,202 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.52 6.84 11,907 10,275 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.49 6.59 11,936 10,419 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.56 7.33 11,862 10,240 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.55 6.61 11,972 10,174 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.33 4.91 12,137 10,385 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.6 7.29 11,870 10,392 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.52 6.53 11,902 10,070 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.43 6.43 11,907 10,177 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.57 6.94 11,912 9,975 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.49 6.33 11,876 10,396 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.5 6.41 11,953 9,204 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.31 5.61 11,969 10,370 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.49 6.48 11,981 10,308 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.5 6.52 11,995 10,233 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.45 6.56 11,930



### Page 23 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,594 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.51 6.43 11,891 10,180 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.51 7.36 11,975 10,284 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.4 6.39 11,950 10,405 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.36 6.3 11,908 10,235 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.49 6.32 11,985 10,203 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.52 6.4 11,998 10,361 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.51 6.51 11,940 10,213 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.64 7.04 11,916 10,397 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.55 6.81 11,964 10,243 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.56 6.67 11,968 10,157 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.51 6.89 12,049 10,321 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.57 6.66 11,900 9,836 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.47 6.35 11,911 10,350 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.42 6.48 11,906 10,227 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.56 6.59 11,916 10,423 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.56 6.72 11,910 10,364 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.41 6.13 11,898 10,273 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.55 7.18 12,038 10,349 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.45 6.3 11,944 10,177 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.54 6.51 11,945 10,279 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.5 6.43 11,987 10,144 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.42 6.54 11,937



### Page 24 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,323 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.59 6.62 11,936 10,296 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.61 6.55 11,919 10,253 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.58 6.91 12,041 10,376 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.47 6.68 11,838 10,380 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.54 6.46 11,931 10,216 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.52 6.27 11,964 10,424 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.55 6.3 11,914 10,353 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.53 6.44 11,933 10,314 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.48 6.16 12,017 10,221 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.56 7.21 12,024 10,169 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.48 6.38 12,083 10,304 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.58 6.93 11,931 10,625 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.59 6.81 11,838 10,210 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.47 6.75 11,966 10,460 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.45 6.37 11,965 10,419 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.53 6.71 11,879 10,372 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.59 6.57 11,921 10,383 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.52 6.48 11,985 10,344 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.5 6.47 11,988 10,167 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.52 6.59 11,996 10,561 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.51 6.48 11,875 10,116 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.45 6.57 12,022



### Page 25 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,392 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.53 6.82 11,994 10,268 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 6.15 12,001 10,446 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.44 6.61 11,926 10,176 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.35 6.32 12,005 10,298 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 6.82 11,919 10,046 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 4.93 12,212 10,181 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.27 11,774 10,256 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.44 6.3 11,901 10,233 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 5.89 12,042 10,336 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 6.21 12,010 10,284 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.32 11,939 10,168 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 6.26 11,928 10,297 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.45 11,971 10,198 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 6.13 11,966 10,170 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.24 11,934 10,212 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.44 6.2 11,967 10,158 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.29 6.05 12,040 10,177 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.57 6.67 11,804 10,314 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 6.02 11,990 9,339 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.22 5.68 12,045 10,209 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 6.05 11,977 10,185 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.23 5.63 12,095



### Page 26 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,239 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.27 5.64 11,970 10,318 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.27 5.71 12,057 10,115 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.26 6.24 11,971 10,136 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.21 5.94 11,998 10,347 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 6.29 11,929 10,199 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.24 6.01 11,988 10,270 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.23 11,969 10,293 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.44 6.68 11,858 10,337 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.28 6.08 11,975 10,233 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 6.56 11,885 10,278 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.31 5.74 11,990 10,289 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 5.8 12,016 10,339 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.46 6.14 11,963 10,241 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.17 11,938 10,308 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.49 6.86 11,810 10,277 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.49 7.21 11,750 10,231 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 5.91 12,040 10,367 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 6.11 11,943 10,260 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.64 11,922 10,236 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 6.5 11,883 10,312 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 5.82 12,000 10,218 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.45 6.62 11,855



### Page 27 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,260 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.44 6.82 11,928 10,219 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.28 11,980 10,182 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.52 5.56 12,233 10,590 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.51 11,966 10,662 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.63 12,111 10,399 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.17 11,976 10,460 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 5.91 11,994 10,656 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 6.12 12,002 10,536 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.17 12,023 10,542 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.43 12,063 10,631 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 6.48 11,957 10,642 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.21 11,925 10,543 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.79 12,098 10,644 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.06 12,058 10,541 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.8 12,025 10,407 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 5.95 12,032 10,564 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 5.88 12,053 10,788 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.65 11,898 10,183 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.92 12,025 10,461 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.2 6.02 12,006 10,477 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 5.88 12,041 10,674 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 6.16 12,039



### Page 28 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,550 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.33 6.45 11,889 10,580 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 5.19 12,083 10,717 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.02 12,005 10,448 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.07 11,961 10,379 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.2 5.72 11,942 10,605 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 5.83 12,005 10,780 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.6 12,084 10,668 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 5.36 12,062 10,602 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.58 12,074 10,564 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.31 11,912 10,570 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 5.74 11,949 10,512 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 5.85 11,895 10,640 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 6.16 11,927 10,603 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 5.94 11,967 10,581 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 5.99 11,916 10,708 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.65 12,090 10,659 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.24 11,919 10,429 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.63 11,930 10,533 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.34 5.84 11,994 10,625 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.22 5.51 12,133 10,711 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.96 12,063 10,618 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 5.57 12,063



### Page 29 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,524 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.83 12,083 10,604 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 6.2 11,943 10,721 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.4 12,062 10,533 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 5.59 12,025 10,541 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.03 12,045 10,549 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 5.72 12,094 10,660 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.21 6.09 12,015 10,610 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.1 12,027 10,626 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.12 12,083 10,524 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.05 12,059 10,234 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.5 11,914 10,340 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.48 11,919 10,288 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.49 6.63 11,923 10,350 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.44 11,967 10,317 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.23 11,985 10,249 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 5.01 12,082 10,161 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 6.17 11,996 10,309 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 6.16 11,985 10,214 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.53 7.66 11,797 10,263 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 6.02 12,040 10,309 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.21 11,979 10,265 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.09 12,000



### Page 30 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,098 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.35 6.6 11,908 10,333 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 6.17 11,987 10,165 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.26 11,989 10,373 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.37 11,957 10,099 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.28 5.47 12,168 10,121 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 6.42 12,091 10,212 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 5.75 12,086 9,929 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.47 11,911 10,243 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.45 7.7 11,791 10,053 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 6.04 11,896 10,199 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.7 11,896 10,408 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.35 6.34 11,996 10,313 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.46 6.32 11,810 10,198 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.21 12,007 10,371 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.5 6.91 11,863 10,361 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.49 6.48 11,949 10,262 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.46 6.34 11,893 10,326 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 6.04 12,062 10,270 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.56 6.33 11,956 10,192 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.55 7.01 11,901 10,336 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 5.85 12,011 10,241 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.66 11,941



### Page 31 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,313 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.48 6.08 11,933 10,177 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.01 11,993 10,378 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.1 11,989 10,331 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.44 6.69 11,928 10,228 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.45 6.59 11,890 10,158 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.12 11,946 10,297 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.21 11,997 10,384 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 5.96 12,026 10,191 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.31 5.82 12,034 10,171 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 6.02 12,023 10,164 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 5.6 12,048 10,317 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.37 6.19 11,913 10,102 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.31 6.06 11,823 10,088 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.29 5.77 11,855 10,250 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.28 5.36 12,060 10,160 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.29 5.67 12,055 10,242 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 5.79 12,009 10,252 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 6.49 11,883 9,922 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 6.07 12,004 10,194 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 6.35 11,959 10,180 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.44 11,984 10,221 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.25 11,967



### Page 32 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,163 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 5.55 12,053 10,001 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.51 6.72 11,863 10,069 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.35 5.55 12,047 10,068 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 5.55 12,020 10,138 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.35 5.45 12,004 10,157 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.26 5.48 12,080 10,179 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.29 6.05 12,010 10,355 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 5.9 11,966 10,261 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.35 6.1 11,989 10,447 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.35 5.83 12,020 10,153 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.28 5.5 12,097 10,287 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.28 5.88 11,996 10,281 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.22 5.45 12,100 10,188 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.24 6.16 12,004 10,195 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 5.63 12,050 10,182 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 5.7 12,013 10,266 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.01 11,935 10,287 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.31 7.01 11,830 10,249 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 6.78 11,870 10,216 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.24 6.1 11,860 10,178 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 6.01 12,020 10,112 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.23 6.2 11,985



### Page 33 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,222 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.24 6.11 11,997 10,282 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.57 11,879 10,272 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.37 6.32 11,883 10,190 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.29 6.63 11,886 10,283 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 5.92 11,980 10,252 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.35 6.55 11,884 10,097 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.28 6.11 11,989 10,181 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.28 5.88 12,004 10,280 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.25 6.11 11,974 10,241 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 6.28 11,923 10,251 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.31 6.56 11,907 10,199 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.27 5.85 11,918 10,109 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.23 6.06 12,001 10,211 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.25 5.92 11,989 10,292 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 6.41 11,917 10,154 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.16 11,965 10,227 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 6.2 11,964 10,112 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 6.06 11,968 10,319 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 6.74 11,778 10,286 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.37 6.31 11,947 10,287 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.76 11,875 10,330 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.25 6.38 11,929



### Page 34 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,305 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.28 5.95 11,961 10,297 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.28 6.11 11,928 10,189 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.37 6.15 11,927 10,173 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.13 11,933 10,250 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.56 11,861 10,237 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.5 7.27 11,997 10,301 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.35 6.33 11,922 10,174 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 6.07 12,007 10,391 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 6.31 11,878 9,780 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 6.19 11,987 10,264 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 5.81 12,010 10,365 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 6.04 11,995 10,260 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 6.33 11,816 10,228 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 5.88 12,020 10,255 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.1 11,988 10,272 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.1 11,963 10,238 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.29 5.88 11,996 10,314 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 5.64 12,001 10,213 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.32 11,958 10,179 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.07 11,960 10,202 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.47 6.21 11,967 10,307 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.53 6.53 11,829



### Page 35 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,268 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.5 6.46 11,874 10,273 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 5.81 11,967 10,465 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 6.31 11,939 10,220 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.29 6.72 11,753 10,302 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 5.77 12,047 10,195 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 6.3 11,948 10,211 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 5.97 11,985 10,191 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 5.99 11,978 10,241 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 6.36 11,942 10,232 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.37 6.1 11,969 10,267 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 5.88 11,991 10,123 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 5.75 12,059 10,253 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.29 5.93 11,998 10,345 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.45 6.23 11,978 10,178 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 6.31 11,886 10,295 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.51 6.66 11,849 10,186 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.85 11,822 10,163 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 6.15 11,949 10,202 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.44 5.96 11,982 10,167 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.48 6.24 11,950 10,201 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.5 6.35 11,884 10,059 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 5.55 12,051



### Page 36 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,240 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.08 11,985 9,973 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.29 11,988 10,264 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.65 11,879 10,308 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 6.2 12,019 10,288 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.44 6.27 11,940 10,322 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.49 6.68 11,931 10,390 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.51 6.96 11,655 10,324 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.52 6.61 11,877 10,212 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 5.77 12,035 10,243 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 5.71 11,995 10,276 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.44 6.25 11,959 10,285 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.44 6.13 11,957 10,172 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 6 12,023 10,121 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 5.98 12,074 10,281 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.46 6.97 11,934 10,176 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.28 5.79 12,066 10,208 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.9 11,919 10,217 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 5.65 11,990 10,221 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 5.75 12,024 10,274 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.14 11,998 10,374 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.17 11,860 10,080 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 5.99 12,014



### Page 37 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,262 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 5.92 12,038 10,306 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.41 11,921 10,220 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.44 6.11 12,009 10,121 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.31 5.88 12,086 10,252 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6 12,086 10,201 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.15 12,053 10,165 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.25 5.82 12,111 10,232 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.27 5.65 12,142 10,214 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 5.82 12,104 10,286 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.22 5.78 12,093 10,230 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.24 5.46 12,114 10,213 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 5.78 12,043 10,189 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.24 5.83 12,092 10,233 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.24 5.66 12,104 10,127 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 6.44 11,982 10,215 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.24 6.57 12,023 10,293 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.27 5.66 12,132 10,259 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.2 5.47 12,153 10,375 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.47 6.55 11,931 10,287 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 6.77 11,933 10,417 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.73 11,929 10,260 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 6.35 11,936



### Page 38 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,388 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.48 6.44 11,966 10,178 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.45 11,969 10,381 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 6.03 12,032 10,279 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.27 6.36 11,951 10,245 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.28 5.82 12,037 10,291 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 6.85 11,929 10,293 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 6.25 12,018 10,174 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 6.12 12,072 10,365 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.47 6.59 11,978 10,223 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 6.26 12,044 10,291 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.46 6.59 11,965 10,306 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.22 12,030 10,244 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.19 12,019 10,266 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 6.26 12,007 10,143 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 6.3 12,030 10,104 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.35 6.32 12,002 10,354 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.35 6.04 12,040 10,357 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.37 6.42 11,983 10,357 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.84 11,952 10,329 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.37 6.32 11,979 10,386 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.35 11,957 10,303 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.45 6.66 12,026



### Page 39 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,437 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.45 6.7 12,062 10,465 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.5 7.18 11,925 10,316 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.47 6.7 12,007 10,329 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.47 6.91 12,007 10,423 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.42 6.47 12,088 10,409 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.41 5.94 12,099 10,357 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.46 6.62 12,002 10,241 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.45 7.21 11,827 10,283 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.49 6.97 11,922 10,237 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.45 6.36 12,000 10,296 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.48 6.95 11,956 10,302 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.53 7.21 11,974 10,348 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.46 6.7 11,890 10,238 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.52 7.23 11,952 11,066 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.52 7.15 11,932 9,741 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.49 6.6 12,014 10,352 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.46 7.61 11,895 10,231 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.46 6.64 12,025 10,327 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.44 7.27 11,931 10,350 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.48 6.73 11,978 10,343 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.4 6.32 12,024 10,425 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.45 6.27 12,064



### Page 40 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,031 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.44 6.25 12,024 10,311 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.53 7.4 11,886 10,363 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.4 7.22 11,916 10,366 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.47 6.65 11,931 10,251 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.48 6.43 12,058 10,262 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.48 6.54 12,012 10,268 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.54 6.51 12,081 10,298 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.38 5.65 12,221 10,297 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.44 7.48 11,874 10,314 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.41 6.81 12,043 10,223 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.43 6.93 12,007 10,292 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.44 6.52 12,036 9,966 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.49 7.24 11,826 10,163 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.57 7.34 11,809 10,261 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.49 7.06 11,839 10,214 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.45 7.55 11,756 10,256 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.52 7.91 11,756 10,136 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.47 7.06 11,823 10,101 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.46 7.08 11,838 10,217 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.47 7.33 11,783 10,113 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.48 7.36 11,861 10,703 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.46 7.01 11,877



### Page 41 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,208 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.49 7.61 11,820 10,141 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.42 6.93 11,881 10,280 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.4 6.68 11,945 10,229 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.48 6.8 11,855 10,059 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.35 6.4 11,962 10,131 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.42 6.87 11,865 10,150 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.5 7.05 11,804 10,129 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.47 7.17 11,784 10,162 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.51 6.94 11,825 10,184 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.43 7.19 11,763 10,297 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.55 7.41 11,770 10,320 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.44 6.86 11,877 10,198 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.53 7.59 11,719 10,162 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.53 7.13 11,790 10,130 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.43 7.11 11,741 10,234 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.43 6.94 11,828 10,151 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.41 7.18 11,885 10,061 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.33 6.23 11,931 10,149 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.4 7.37 11,733 10,172 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.48 7.24 11,767 10,242 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.38 7.52 11,757 10,209 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.46 6.27 11,881



### Page 42 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,418 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.32 6.77 11,951 10,805 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.3 6.57 11,983 10,846 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.27 7.05 11,909 10,823 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.28 6.72 11,944 10,863 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.28 6.97 11,895 10,877 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.28 7.21 11,890 10,812 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.29 6.51 11,954 10,877 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.31 7.45 11,831 10,818 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.46 6.6 11,954 10,804 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 6.69 11,998 11,068 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 6.54 12,017 10,860 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 8.2 11,731 10,892 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 6.32 11,981 11,015 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.41 6.22 12,008 10,756 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.4 6.09 12,021 10,947 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 6.46 12,003 10,961 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 8.02 11,820 10,894 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 7.84 11,899 10,924 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 6.94 11,988 10,929 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 7.03 11,890 11,105 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.31 8.27 11,670 10,855 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 6.92 11,867



### Page 43 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,979 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.23 7.37 11,887 10,981 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.28 7.77 11,831 10,733 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.29 7.63 11,845 11,032 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.24 6.63 11,991 10,890 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.26 7.33 11,858 10,757 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.31 6.58 11,931 10,743 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.3 6.78 11,912 10,652 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 6.05 12,020 11,011 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 6.17 11,982 10,973 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 7.28 11,846 10,825 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 5.95 11,998 10,990 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 6.08 12,014 10,912 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 7.49 11,847 10,328 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 6.72 11,890 10,854 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.27 6.31 12,021 10,894 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.27 6.25 12,039 10,977 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 7.33 11,826 10,886 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.32 6.44 11,951 11,028 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.29 6.12 12,055 10,828 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.3 6.44 12,003 10,848 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.25 6.21 12,103 10,794 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.27 7.62 11,903



### Page 44 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,862 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.32 6.94 11,889 10,951 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.32 6.72 11,909 10,900 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.26 6.75 11,962 10,704 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.25 6.53 11,944 11,003 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 6.21 11,966 10,912 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 6.54 11,915 10,769 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 7.65 11,788 10,966 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 7.38 11,841 10,966 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.29 7.17 11,900 10,867 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.3 8.05 11,755 10,985 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.33 7.84 11,796 11,020 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.3 7.74 11,743 10,831 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.33 6.4 11,932 10,923 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.39 5.9 12,010 10,925 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.39 6.06 11,986 10,797 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 6.76 11,936 10,922 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.41 8.08 11,751 10,885 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.33 7.69 11,794 10,871 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.26 6.28 12,012 10,842 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.22 6.42 12,000 10,916 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 6.16 11,941 10,872 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.29 7.32 11,838



### Page 45 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,840 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.3 7.85 11,806 10,920 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.3 6.2 11,989 10,972 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.32 6.96 11,830 10,962 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 7.66 11,765 10,954 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.33 6.46 11,911 10,949 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 6.61 11,892 10,930 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.4 6.92 11,924 10,933 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.4 6.12 11,964 10,852 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 6.55 11,996 10,955 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 7.6 11,851 11,001 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.52 7.09 11,819 11,036 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.39 9.19 11,601 10,927 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.42 8.17 11,730 10,844 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 7.05 11,896 10,895 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.33 6.32 11,970 11,024 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 8.01 11,729 10,815 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.24 7 11,963 10,982 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.3 7.64 11,857 10,931 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.31 7.64 11,824 11,035 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 6.67 11,965 11,066 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.42 7.23 11,897 10,888 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.31 6.23 12,051



### Page 46 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,583 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.26 6.92 11,979 10,908 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.32 6.45 12,047 10,961 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 7.25 11,938 N/A 1, 2, 3, 4 WY CONVERSE CANYON TRAIN N/A N/A N/A 10,901 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 6.29 11,998 10,894 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 6.49 12,030 10,839 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 6.15 12,102 10,545 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.75 12,058 10,611 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.33 6.19 11,949 10,725 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.22 11,992 10,623 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.04 12,081 10,507 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.45 12,107 10,593 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.62 11,961 10,763 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.33 6.12 11,930 10,615 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.61 11,954 10,409 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 5.89 12,100 10,569 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 5.78 12,034 10,497 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.91 11,910 10,589 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.31 11,971 10,373 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 4.65 12,110 10,463 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 5.09 12,101 10,434 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.16 11,852



### Page 47 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,644 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.26 11,963 10,595 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 4.72 12,186 10,390 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 6.24 11,964 10,569 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.5 11,905 10,607 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.71 11,881 10,659 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.35 11,896 10,641 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.31 12,006 10,637 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.06 12,016 10,697 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.25 11,991 10,667 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.23 11,998 10,740 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 5.72 12,112 10,630 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.7 12,068 10,796 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 5.26 12,187 10,733 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.87 12,014 10,644 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.96 12,064 10,473 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.12 12,019 10,599 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 6.04 12,028 10,653 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 6.68 11,840 10,569 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.12 12,016 10,604 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.33 5.84 12,005 10,015 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 5.83 12,022 10,765 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 6.13 12,030



### Page 48 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,553 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 5.85 11,936 10,644 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.22 5.82 12,009 10,655 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.33 6.27 11,927 10,522 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.22 5.8 12,008 10,549 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.88 11,884 10,687 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.91 11,856 10,655 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.18 11,907 10,557 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.24 11,960 10,637 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.98 11,975 10,742 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.51 11,888 10,722 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 5.94 11,948 10,571 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 5.92 11,913 10,537 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 5.96 11,988 10,419 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 5.92 12,024 10,535 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.84 11,910 10,543 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.2 6.1 12,016 10,636 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 6.07 12,003 10,615 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.22 6.03 11,995 10,509 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.33 6.28 11,899 10,516 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.71 12,002 10,552 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.5 11,948 10,588 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.33 5.6 12,031



### Page 49 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,621 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6 11,980 10,542 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 5.69 12,060 10,655 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.28 11,958 10,643 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.26 11,977 10,614 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 5.72 12,013 10,565 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.98 12,002 10,514 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.51 11,887 10,461 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.7 11,987 10,731 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 5.66 12,008 10,634 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 5.96 12,011 10,685 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 5.9 12,022 10,781 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 6.22 11,922 10,529 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.22 6.18 11,931 10,619 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.2 11,943 10,619 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 7.03 11,903 10,010 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.05 12,013 10,562 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.13 11,951 10,560 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.18 6.06 11,985 10,561 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.03 11,983 10,606 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.94 11,959 10,699 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.33 6.46 11,918 10,687 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.55 11,888



### Page 50 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,530 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.4 11,908 10,679 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.91 12,011 10,694 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 5.65 12,095 10,659 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.99 11,979 10,551 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 5.45 12,104 10,711 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.25 12,037 10,381 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.33 11,973 10,489 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.14 11,949 10,619 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.24 11,990 10,511 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.2 6.14 12,025 10,593 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 5.57 12,042 10,566 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.94 12,071 10,669 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.36 5.84 12,032 10,670 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.32 11,995 10,571 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 5.55 12,095 10,685 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.02 11,984 10,641 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.6 11,878 10,541 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.82 12,013 10,557 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.35 5.92 11,983 10,495 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 5.76 12,064 10,290 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.22 5.87 11,923 10,530 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.21 6.14 12,001



### Page 51 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method N/A 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN N/A N/A N/A 10,602 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.12 12,032 10,434 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.16 12,034 10,564 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 5.72 12,079 N/A 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN N/A N/A N/A 10,514 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 5.78 12,105 10,349 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 6.35 11,981 10,701 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 7.1 11,896 10,294 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.46 6.62 11,952 10,237 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 6.24 11,990 10,317 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 6.38 11,970 10,277 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.23 11,955 10,269 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 6.49 11,973 10,295 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.47 11,972 10,188 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 6.25 11,967 10,261 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 6 12,105 10,248 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.88 11,939 10,189 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.2 11,972 10,269 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.49 6.82 11,860 10,273 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.56 6.86 11,880 10,381 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 5.56 12,130 10,283 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.31 5.46 12,125



### Page 52 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,333 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 6.74 12,047 10,288 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 6.36 11,962 10,331 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.35 6.25 11,952 10,360 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.26 11,943 10,392 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 6.37 11,995 10,154 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.27 6.05 11,993 10,152 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.33 11,936 10,206 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.37 6.2 11,970 10,254 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.37 5.91 12,038 10,007 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 5.88 12,054 10,226 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.45 6.68 11,873 10,142 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 5.76 12,019 10,085 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 5.95 11,954 10,283 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 5.97 11,962 10,140 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.23 5.77 12,017 10,214 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.23 5.34 12,090 10,242 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 5.88 12,035 10,221 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.13 11,942 10,179 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.24 5.85 12,027 10,231 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 7.69 11,743 10,214 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.28 5.81 12,067 10,230 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.22 6.01 11,984



### Page 53 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,241 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 7 11,935 10,162 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.24 6.11 11,997 10,223 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.31 6.3 11,892 10,202 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.25 5.86 11,924 10,206 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 6.02 11,988 10,221 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.35 6.05 11,978 10,345 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.54 11,906 10,230 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.37 6.59 11,921 10,244 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 6 11,934 10,220 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.31 6.4 11,923 10,315 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.64 11,881 10,318 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 6.33 11,936 10,289 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 6.26 11,919 10,341 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 5.9 11,939 10,297 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 5.98 11,905 10,328 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 5.85 11,981 10,228 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.07 11,927 10,260 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.5 6.84 11,831 10,242 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.47 6.55 11,831 10,156 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.31 5.9 12,020 10,323 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.37 6.78 11,872 10,269 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 6.42 11,949



### Page 54 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,274 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 6.42 11,942 10,260 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 5.98 11,971 10,161 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.29 6.04 12,008 10,283 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.11 11,933 10,211 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.47 6.84 11,744 10,275 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 5.77 12,017 10,205 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 5.93 11,999 10,357 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.33 11,920 10,357 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.32 11,933 10,287 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.47 6.25 11,941 10,300 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 7.3 11,788 10,252 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.44 6.9 11,905 10,210 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.44 6.2 11,998 10,204 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 5.93 12,076 10,208 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.25 5.6 12,124 10,194 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.26 5.84 12,079 10,227 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.27 5.75 12,119 10,318 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 6.09 12,026 10,213 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 6.44 11,982 10,247 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.22 5.67 12,153 10,198 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 6.91 11,909 10,301 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.01 11,992



### Page 55 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,311 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.07 11,980 10,284 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.37 6.07 12,014 10,284 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 6.32 12,010 10,351 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.61 11,968 10,225 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 6.13 12,003 10,093 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.69 11,964 10,338 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.51 6.37 11,984 10,147 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.55 7.5 11,881 10,236 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.49 7.71 11,915 10,068 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.52 7.58 11,889 10,266 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.44 6.74 12,010 10,117 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.45 7.15 11,977 10,351 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.33 6.68 12,042 10,274 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.46 7.31 11,911 10,087 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.44 8.03 11,810 10,307 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.45 8.17 11,800 9,399 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.47 7.03 11,928 10,188 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.4 7.16 12,106 10,169 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.38 8.51 11,879 10,384 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.39 8.34 11,819 10,335 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.4 7.6 11,848 10,309 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.39 7.71 11,817



### Page 56 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,318 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.32 6.64 11,856 10,308 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.38 6.79 11,935 10,414 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.4 6.3 12,040 10,300 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.39 6.55 11,962 10,211 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.42 7.44 11,852 10,290 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.52 7.32 11,920 10,237 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.4 6.63 12,033 10,408 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.47 9.17 11,642 10,114 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.38 7.27 11,815 10,269 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.45 7.6 11,824 10,109 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.47 8.1 11,769 10,289 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.49 7.58 11,911 10,268 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.44 7.35 11,923 10,175 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.53 7.68 11,914 10,311 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.38 8.14 11,834 10,374 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.36 7.91 11,855 10,169 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.39 6.99 11,987 10,281 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.4 7.61 11,903 10,393 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.52 7.37 11,973 10,185 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 6.01 11,947 10,689 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.19 11,987 10,643 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.87 12,045



### Page 57 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,460 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.33 6.48 11,898 10,355 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 6.04 12,035 10,381 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.94 12,048 10,404 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.02 11,960 10,453 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.22 11,972 10,641 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.76 11,943 10,484 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 6.62 11,884 10,502 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.2 11,963 10,708 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.72 11,882 10,620 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.27 11,920 10,572 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 5.93 11,958 10,571 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.35 11,866 10,388 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.2 5.91 11,969 10,369 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.23 11,892 10,525 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.96 11,987 10,503 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 6.51 11,940 10,546 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.1 11,977 10,390 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 6.16 11,938 10,768 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.36 5.59 12,025 10,019 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.78 11,953 10,539 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 6.23 11,933 10,419 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.02 11,917



### Page 58 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,560 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.13 11,986 10,639 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.22 5.96 11,948 10,662 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.12 11,956 10,483 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.14 11,933 10,733 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.36 11,973 10,527 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.83 12,044 10,471 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.98 12,036 10,604 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 5.89 12,089 10,322 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.18 12,007 10,607 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.03 12,044 10,595 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 5.68 12,076 10,537 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.31 11,927 10,440 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.2 11,939 10,352 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.05 11,960 10,608 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.08 11,994 10,658 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.21 5.6 12,084 N/A 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN N/A N/A N/A 10,341 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.31 11,937 10,468 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.35 11,999 10,230 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.09 11,927 10,719 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.67 12,092 10,778 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.22 5.85 12,098



### Page 59 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,367 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.21 11,985 10,663 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 5.33 12,152 10,442 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.1 12,012 9,679 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 5.82 12,026 10,518 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.81 12,060 10,451 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.95 11,998 10,649 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 7.34 11,772 10,416 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.89 11,962 10,548 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.77 12,016 10,486 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 5.89 11,997 10,526 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.28 11,925 10,614 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.98 11,930 10,580 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 5.75 11,941 10,465 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.21 6 11,942 10,470 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.82 12,011 8,622 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 6.33 11,956 10,673 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.19 12,011 10,690 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.38 11,986 10,670 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.63 12,042 10,691 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.66 11,987 10,688 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 5.94 12,028 10,559 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 5.82 12,021



### Page 60 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,604 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.03 11,934 10,428 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.35 11,874 10,534 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 6.3 11,901 10,635 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.21 6.02 11,977 10,501 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.02 11,854 10,465 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 6.4 11,873 10,606 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.34 6.01 12,054 10,680 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 5.53 12,084 10,689 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 6.03 12,011 10,421 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.11 12,025 10,587 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.7 12,007 10,820 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 5.89 12,034 10,538 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 5.54 12,071 10,387 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.56 11,938 10,548 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.11 12,012 10,393 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.97 12,042 10,401 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.06 12,051 10,494 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.45 12,022 10,362 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 6.56 11,898 10,447 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.49 11,957 10,560 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 7.23 11,858 10,130 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.48 7.88 11,938



### Page 61 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb Vendor Analyses Fuel source Amount received, dry basis, short tons40 

### ID # of boiler(s) firing fuel41 

### Fuel shipment method 10,194 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.43 7.41 11,879 10,357 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.37 8.55 11,768

40EPA recognizes that facilities have (sometimes) several months inventory and that the amount received is not necessarily the same as the amount fired.

41Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).

42If known.

43If known.



### Page 62 of 93 part II, 2 (coal)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

State/Country County42 

### Coal seam43
45,219 1, 2, 3, 4 Georgia/USA N/A N/A Truck 30,200 1, 2, 3, 4 Georgia/USA N/A N/A Truck 15,042 1, 2, 3, 4 Georgia/USA N/A N/A Truck 45,149 1, 2, 3, 4 Georgia/USA N/A N/A Truck 45,021 1, 2, 3, 4 Georgia/USA N/A N/A Truck 45,013 1, 2, 3, 4 Georgia/USA N/A N/A Truck 44,895 1, 2, 3, 4 Georgia/USA N/A N/A Truck 44,901 1, 2, 3, 4 Georgia/USA N/A N/A Truck 44,861 1, 2, 3, 4 Georgia/USA N/A N/A Truck 44,828 1, 2, 3, 4 Georgia/USA N/A N/A Truck 44,778 1, 2, 3, 4 Georgia/USA N/A N/A Truck 37,267 1, 2, 3, 4 Georgia/USA N/A N/A Truck 7,452 1, 2, 3, 4 Georgia/USA N/A N/A Truck 44,617 1, 2, 3, 4 Georgia/USA N/A N/A Truck 66,811 1, 2, 3, 4 Georgia/USA N/A N/A Truck 44,504 1, 2, 3, 4 Georgia/USA N/A N/A Truck 22,284 1, 2, 3, 4 Georgia/USA N/A N/A Truck 44,538 1, 2, 3, 4 Georgia/USA N/A N/A Truck 44,532 1, 2, 3, 4 Georgia/USA N/A N/A Truck 37,106 1, 2, 3, 4 Georgia/USA N/A N/A Truck 7,425 1, 2, 3, 4 Georgia/USA N/A N/A Truck 22,324 1, 2, 3, 4 Georgia/USA N/A N/A Truck 37,159 1, 2, 3, 4 Georgia/USA N/A N/A Truck 

### FUEL OIL SHIPMENTS Amount received, gallons40 

### ID # of boiler(s)

firing fuel41 

### Fuel source Fuel shipment method

Page 63 of 93 Part II, 2 (oil)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

State/Country County42 

### Coal seam43 

### FUEL OIL SHIPMENTS Amount received, gallons40 

### ID # of boiler(s)

firing fuel41 

### Fuel source Fuel shipment method 37,163 1, 2, 3, 4 Georgia/USA N/A N/A Truck 37,270 1, 2, 3, 4 Georgia/USA N/A N/A Truck 44,721 1, 2, 3, 4 Georgia/USA N/A N/A Truck 37,249 1, 2, 3, 4 Georgia/USA N/A N/A Truck 29,815 1, 2, 3, 4 Georgia/USA N/A N/A Truck 44,707 1, 2, 3, 4 Georgia/USA N/A N/A Truck 44,919 1, 2, 3, 4 Georgia/USA N/A N/A Truck 44,855 1, 2, 3, 4 Georgia/USA N/A N/A Truck 45,154 1, 2, 3, 4 Georgia/USA N/A N/A Truck 44,937 1, 2, 3, 4 Georgia/USA N/A N/A Truck 44,933 1, 2, 3, 4 Georgia/USA N/A N/A Truck 45,140 1, 2, 3, 4 Georgia/USA N/A N/A Truck 45,129 1, 2, 3, 4 Georgia/USA N/A N/A Truck 22,593 1, 2, 3, 4 Georgia/USA N/A N/A Truck 37,505 1, 2, 3, 4 Georgia/USA N/A N/A Truck 45,115 1, 2, 3, 4 Georgia/USA N/A N/A Truck

40EPA recognizes that facilities have (sometimes) several months inventory and that the amount received is not necessarily the same as the amount fired.

41Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).

42If known.

43If known.



### Page 64 of 93 Part II, 2 (oil)GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

3For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information44, as available (dry basis) (indicate N/A if not available): NOTES: "ND" indicates results are non detect. All results presented on a dry basis. Georgia Power collects this information on select coal shipments on a quarterly basis, but does not have this information available on a shipment by shipment basis. The information Georgia Power provides in this question cannot be linked to the information in Part II, Question 2 because the information comes from two separate databases. Thus the information provided in this question represents only a very small portion of our actual shipments.

Antimony Arsenic Beryllium CadmiumChromium Cobalt Lead ManganeseSelenium

09-313 14,629 0.32 6.91 11,971 0.082 43 48 4.1 <1 0.3 0.3 <0.02 3.5 3.0 2.4 5.7 0.5WY Campbell Wyodak Train 09-300 14,441 0.53 7.06 11,920 0.115 64 64 4.5 <1 1.6 0.4 0.08 4.4 2.5 3.3 13.5 0.8WY Campbell Wyodak Train 09-301 14,169 0.43 6.78 11,925 0.054 55 56 4.7 <1 1.1 0.2 0.05 2.6 1.9 2.4 18.4 0.7WY Campbell Wyodak Train 09-302 14,519 0.28 6 11,962 0.065 60 67 3.0 <1 0.5 0.4 0.05 3.9 2.5 3.1 8.5 0.6WY Campbell Wyodak Train 09-305 14,629 0.34 6.26 12,038 0.058 60 60 3.4 <1 0.4 0.3 0.05 3.4 2.8 2.5 9.4 0.6WY Campbell, Converse Wyodak Train 09-307 14,709 0.44 6.52 12,075 0.091 79 56 3.9 <1 0.7 0.4 0.06 4.0 2.6 3.1 8.6 1.0WY Campbell Wyodak Train 09-309 14,658 0.57 9.22 11,569 0.123 70 81 5.5 <1 2.2 0.5 0.07 8.1 2.6 5.5 13.2 0.9WY Campbell Wyodak Train 09-310 14,617 0.5 8.15 11,630 0.092 64 67 5.1 <1 1.5 0.4 0.07 6.4 2.8 3.9 17.2 0.9WY Campbell Wyodak Train 09-312 14,588 0.28 5.95 12,055 ND ND 32 3.5 ND 0.3 0.3 ND 3.1 2.9 2.4 6.7 0.7WY Campbell Wyodak Train 09-314 14,588 0.29 5.94 12,083 ND ND 32 3.9 ND 1.4 0.3 ND 1.9 2.0 2.2 5.3 0.8WY Campbell Wyodak Train 09-316 14,836 0.42 6.14 11,935 ND 69 44 4.0 <1 0.8 0.4 ND 2.7 2.4 2.5 12.6 0.9WY Campbell Wyodak Train 09-317 14,589 0.41 6.73 11,946 ND ND ND 4.1 ND 0.6 0.1 0.05 4.3 2.4 2.2 9.7 0.9WY Campbell Wyodak Train 09-325 16,045 0.27 6.5 12,079 0.079 37 48 2.8 <1 0.5 0.4 <0.02 2.9 2.5 2.2 5.6 0.7WY Campbell Wyodak Train 09-327 16,001 0.37 7.14 11,968 0.076 37 33 4.6 <1 0.8 0.3 <0.02 3.4 3.3 2.9 4.7 0.6WY Campbell, Converse Wyodak Train 09-321 14,657 0.46 7.44 11,918 0.125 ND 63 5.7 ND 1.4 0.4 0.01 7.0 3.0 4.0 11.6 1.0WY Campbell Wyodak Train 09-322 14,465 0.44 6.53 11,864 ND ND 63 5.1 ND 1.2 2.9 ND 3.0 2.0 2.5 15.5 0.7WY Campbell Wyodak Train 09-328 14,637 0.41 6.25 11,932 ND 72 60 4.0 ND 1.1 0.4 ND 2.9 2.2 2.4 13.5 0.8WY Campbell Wyodak Train 09-329 13,820 0.49 6.33 11,891 ND ND 49 4.2 ND 1.1 0.2 ND 2.1 2.0 2.0 5.3 0.7WY Campbell Wyodak Train 09-330 14,599 0.62 7.43 11,746 0.135 62 56 14.0 ND 1.4 0.4 0.01 4.3 2.7 2.4 13.0 0.7WY Campbell Wyodak Train 09-331 14,252 0.46 6.69 11,959 ND 62 60 4.4 ND 1.1 0.4 0.02 4.0 2.9 2.7 8.2 0.9WY Campbell Wyodak Train 09-332 14,627 0.54 7.43 11,860 ND 60 56 4.8 ND 1.0 0.2 0.07 4.8 2.6 3.3 17.9 0.9WY Campbell Wyodak Train 09-341 14,561 0.49 7.44 11,954 0.069 85 61 6.5 ND 1.9 0.4 ND 6.7 3.5 3.9 9.7 1.1WY Campbell Wyodak Train 09-342 14,583 0.57 6.41 12,013 0.071 95 51 5.3 ND 1.4 0.3 ND 3.1 2.8 2.4 16.0 0.9WY Campbell Wyodak Train 09-343 14,718 0.37 6.36 11,990 ND 88 62 3.7 ND 0.5 0.4 ND 3.3 3.3 2.9 6.8 0.6WY Campbell Wyodak Train 09-346 14,344 0.46 6.12 12,056 ND 94 50 4.7 ND 1.6 0.3 ND 2.5 2.4 2.3 6.8 0.8WY Campbell Wyodak Train 09-347 14,688 0.41 7.17 11,923 ND ND 49 2.9 ND 0.5 0.2 ND 3.2 2.7 2.9 12.3 0.5WY Campbell Wyodak Train 09-348 14,647 0.51 6.56 12,040 0.115 82 51 5.2 ND 1.3 0.4 0.05 4.3 2.9 2.8 8.5 0.9WY Campbell Wyodak Train 09-349 14,594 0.45 7.2 11,869 ND 105 88 15.5 1.3 10.5 3.4 ND 18.5 10.4 8.7 24.6 3.1WY Campbell Wyodak Train

44To the extent that a vendor provides these data or that a facility is required by State or local agency to analyze its fuel for HAP constituents (e.g., Cl, F), and any metallic HAP (e.g., Hg, Pb, As, Se, etc.), EPA wishes the responding facility to provide those fuel analyses results. Otherwise, this 12-month fuel analysis requirement can be bypassed by the respondent.

45Metal HAP includes compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, phosphorus, and selenium. Fuel Shipment Method Total amount of fuel represented by Sample ID # State/ Country County Coal Seam Nickel, ppm Other trace metal HAP, ppm45 Total Sulfur, % Ash

Content, % Heating Value, Btu/lbMercury,

ppm Chlorine,

ppm Fluorine,

ppm

Page 65 of 93 part II, 3

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

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

__X__ permit requirements (for coal) ____ contractual obligations ____ standard operational procedures

__X__ other (please specify _at the discretion of the plant and to support other projects__)

5Analyses provided in Part II, question 3 above, supplied by ____ Fuel supplier (name and address)

__X__ Other (name and address)

Georgia Power Environmental Lab 5131 Maner Road, Smyrna GA 30080 6Name and address of laboratory performing analyses: Georgia Power Environmental Lab (same as above)

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

7In addition to the analyses required in Part II, question 3 above, for samples for which analyses of chlorine and/or any of the HAP metals were conducted, please provide copies of any analyses conducted over the preceding 12 calendar months for (a) complete proximate and ultimate analyses, (b) additional trace metals, and (c) the mineralogy of the ash that are readily available for the oil(s) or coal(s) listed in Part II, question 2 above. The Agency is requesting these data only as they may already be available; no additional sampling or analyses are required to provide these data.

Total

MoistureVolatiles Ash Fixed Carbon CarbonHydrogenNitrogen Total Sulfur Oxygen Barium Copper MagnesiumSodiumVanadium Zinc Al2O3Fe2O3CaO MgOMnO2P2O5 K2O SiO2Na2O SO3 TiO2


### 09-313 26.08 43.52 6.91 49.57 70.56 4.77 1.03 0.32 16.41 390 9.8 0.211 0.063 12.2 19.115.715.7620.615.060.013 1.230.5336.25 1.2311.55 1.07 09-300 29.35 46.13 7.06 46.81 69.06 4.47 0.83 0.53 18.06 363 12.3 0.257 0.080 16.1 8.7 14.8 4.1 17.35.25 ND0.577 ND32.3 1.45 16.9 1.01 09-301 31.61 45.88 6.78 47.34 71.09 4.55 1.18 0.43 15.97 349 7.3 0.247 0.076 9.3 9.7 12 4.420.94.67 ND0.881 ND29.5 1.0821.10.675 09-302 26.54 44.79 6 49.21 69.39 4.45 0.86 0.28 19.03 361 11.0 0.206 0.083 13.5 6.9 154.5418.24.24 ND 1.29 ND35.61.2815.1 1.11 09-305 26.91 45.12 6.26 48.62 72.4 4.45 1.16 0.34 15.39 302 10.6 0.217 0.078 12.9 15.014.35.75 18.34.62 ND 0.6 ND32.3 1.2415.2 1.01 09-307 30.85 45.28 6.52 48.21 70.73 4.53 1.03 0.44 16.76 329 14.3 0.173 0.068 15.7 5.1 12.54.0619.53.71 ND0.781 ND26.2 1.0722.9 1.25 09-309 30.9 44.87 9.22 45.9 66.88 4.35 0.95 0.57 18.03 350 12.5 0.244 0.090 20.5 11.415.44.39 13.53.67 ND0.437 ND41.61.09 12.90.777 09-310 30.38 45.68 8.15 46.16 68.85 4.55 0.98 0.5 16.96 366 16.4 0.191 0.076 20.5 9.015.43.77 15.93.61 ND0.641 ND35.7 1.1816.2 1.14 09-312 28.27 44.91 5.95 49.14 70.27 4.6 0.99 0.28 17.9 346 11.3 0.198 0.074 11.9 9.015.45.3321.85.17 ND 1.29 ND35.2 1.53 12.41.35 09-314 30.84 45.73 5.94 48.32 70.56 4.46 0.95 0.29 17.79 356 7.3 0.245 0.085 7.4 10.9 11.9 5.122.35.58 ND0.954 ND30.9 1.4417.30.908 09-316 30.41 45.53 6.14 48.34 68.16 4.49 0.92 0.42 19.9 381 9.5 0.247 0.077 11.5 6.3 12.33.8619.35.18 ND0.595 ND29.5 1.3521.10.894 09-317 30.48 45.28 6.73 47.99 72.24 4.82 1 0.41 14.8 340 12.9 0.182 0.070 15.8 4.2 14.5 415.83.71 ND0.666 ND32.5 1.27 17.61.22 09-325 27.29 43.79 6.5 49.71 69.81 4.79 0.65 0.27 17.98 340 10.3 0.189 0.074 11.2 7.417.125.0720.274.830.0141.11 0.435.15 1.5312.51 1.13 09-327 26.57 42.74 7.14 50.12 69.41 4.73 0.98 0.37 17.37 380 9.5 0.208 0.057 10.8 12.516.554.8819.324.830.01 1.260.4234.62 1.0814.810.97 09-321 29.84 46.28 7.44 46.29 68.82 4.6 0.83 0.46 17.85 361 16.8 0.184 0.072 23.1 7.3 16.63.99 17.53.31 ND0.846 ND33.7 1.2 15.4 1.2 09-322 31.43 45.62 6.53 47.84 69.24 5.42 0.79 0.44 18.48 322 8.7 0.231 0.087 11.4 11.9 13.45.64 22 4.8 ND ND ND30.3 1.65 170.945 09-328 28.63 46.69 6.25 47.06 68.82 4.53 1.05 0.41 18.94 375 11.2 0.272 0.099 13.2 6.7 15.84.4523.26.02 ND0.618 ND30.61.4922.41.16 09-329 29.63 46.18 6.33 47.25 64.98 4.36 1.06 0.49 22.77 281 8.2 0.219 0.069 8.8 11.9 12.34.8121.75.15 ND0.551 ND30.9 1.220.90.951 09-330 28.8 46.56 7.43 46.01 67.77 4.44 0.96 0.62 18.79 372 12.3 0.243 0.073 14.5 15.5 14.35.19 18.64.37 ND ND ND34.81.2720.1 1.08 09-331 29.34 46.38 6.69 46.94 68.34 4.49 1.12 0.46 18.9 337 15.2 0.184 0.069 16.5 7.414.94.52 19.63.73 ND0.874 ND35.1 1.2 17.81.07 09-332 30.37 46.11 7.43 46.47 67.5 4.66 1.14 0.54 18.73 337 15.2 0.192 0.057 19.7 6.614.54.21 19.23.66 ND0.916 ND 300.927 17.7 1.17 09-341 30.84 45.09 7.44 47.47 68.33 4.44 1.13 0.49 18.17 348 17.1 0.166 0.071 21.9 8.7 18 4.5 19.83.45 ND0.779 ND33.5 1.31 11.41.28 09-342 30.44 45.41 6.41 48.19 68.68 4.57 1.1 0.57 18.67 389 10.5 0.253 0.094 13.5 8.414.54.9522.75.94 ND0.634 ND28.9 1.9415.41.03 09-343 28.18 44.34 6.36 49.31 68.87 4.53 1.09 0.37 18.77 375 11.1 0.209 0.071 12.9 8.9 15.3 4.720.44.96 ND 1.22 ND33.61.559.47 1.13 09-346 31.12 45.62 6.12 48.26 68.52 4.49 1.04 0.46 19.37 315 9.6 0.246 0.089 11.2 10.7 13.35.4423.15.91 ND0.547 ND30.2 1.91 13.2 1.04 09-347 26.57 43.07 7.17 49.76 68.26 4.45 1.1 0.41 18.61 479 9.7 0.219 0.069 12.2 6.412.84.53 18.74.39 ND 1.29 ND37.9 1.2811.2 1.01 09-348 30.74 46.12 6.56 47.33 68.6 4.62 0.95 0.51 18.76 342 15.6 0.188 0.084 16.2 7.2 14.94.4420.94.11 ND0.763 ND29.3 1.414.3 1.26 09-349 31.25 45.14 7.2 47.65 68.42 4.27 0.88 0.45 18.77 315 21.4 0.080 0.043 33.1 13.012.94.89 19.34.43 ND0.536 ND32.5 1.3812.9 1.1 Sample ID # Proximate Analyses, % by wt Ultimate Analyses, % by wt Ash Mineralogy, % by wt Other Trace Metals, ppm, dry basis

Page 67 of 93 part II, 7

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

8aWhat 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.

Report 1Unit 4 Particulate Emissions Test (April 12, 2006) Report 2Unit 3 Particulate Emissions Test (April 13, 2006) Report 3Unit 1 Particulate Emissions Test (June 15, 2006) Report 4Unit 2 Particulate Emissions Test (June 15, 2006) Report 5Unit 3 Particulate Emissions Test (February 19, 2008) Report 6Unit 4 Particulate Emissions Test (February 20, 2008) Report 7Unit 1 Particulate Emissions Test (June 3, 2008 to June 4, 2008) Report 8Unit 2 Particulate Emissions Test (June 5, 2008) Report 9Unit 1 Boiler Optimization (September 20, 2007 to September 25, 2007) Report 10Unit 2 Economizer Performance (August 25, 2009 to August 26, 2009) Report 11Unit 3 Economizer Performance (March 3, 2009) Report 12Unit 4 SCR Baseline (October 24, 2006 to October 31, 2006) Report 13Unit 2 Baghouse Performance (May 28, 2009 to June 1, 2009) Report 14Unit 3 Baghouse Performance (January 28, 2009 to January 29, 2009)

8bPlease 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: Report 1 Date:4/12/2006 Type:stack Constituents:PM Report 2 Date:4/13/2006 Type:stack Constituents:PM Report 3 Date:6/15/2006 Type:stack Constituents:PM Report 4 Date:6/15/2006 Type:stack Constituents:PM Report 5 Date:2/19/2008 Type:stack Constituents:PM Report 6 Date:2/20/2008 Type:stack Constituents:PM Report 7 Date:6/3/2008-6/4/2008 Type:stack Constituents:PM Report 8 Date:6/5/2008 Type:stack Constituents:PM

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### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

Report 9 Date:9/20/2007-9/25/2007 Type:duct Constituents:CO Report 10 Date:8/25/2009-8/26/2009 Type:duct Constituents:CO Report 11 Date:3/3/2009 Type:duct Constituents:CO Report 12 Date:10/24/2006-10/31/2006 Type:duct Constituents:CO Report 13 Date:5/28/2009-6/1/2009 Type:duct/stack Constituents:PM, Hg Report 14 Date:1/28/2009-1/29/2009 Type:duct/stack Constituents:PM, Hg

8cDo any of these test reports reflect testing at a location upstream of any emission control devices? Yes _X

___ No ____If yes, please note which reports and provide a detailed description of the location of the emissions sampling point(s). Although Reports 9, 10, 11, 12 reflect testing at the economizer outlet (upstream of all post-combustion control devices), there are no control devices downstream designed to reduce CO. Reports 13, 14 reflect testing upstream of the baghouse (downstream of the ESP).

8dWere any of these test reports conducted when use of other material(s) or non-fossil fuels were fired in the boiler? Yes ____ No _X

___If yes, please not which reports and identify the other material(s) or non-fossil fuels used.

8eDo any of these test reports reflect testing during periods of startup, shutdown, and malfunction? Yes ____ No _X

___If yes, please note which reports.

Page 69 of 93 part II, 8

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

8fDid the unit's control configuration differ from that shown in Part I, question 16, at the time of these test results? Yes _X

___ No ____If yes, please list the unit's complete control configuration at time of testing in a similar format to Part I, question 16. The control configuration shown below is representative of the conditions present during Reports 1, 2, 3, 4, 5, 6, 7, 8, 9, 12.

Boiler ID Type NOx control SO2 control PM control Other control 1 tangentialfired (1) overfire air (3) cold-side electrostatic precipitator (2) flue gas conditioning (SO3 injection)

2 tangentialfired (1) overfire air (3) cold-side electrostatic precipitator (2) flue gas conditioning (SO3 injection)

3 tangentialfired (1) overfire air (2) cold-side electrostatic precipitator

4 tangentialfired (1) overfire air (2) cold-side electrostatic precipitator



### Page 70 of 93 part II, 8

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

The control configuration shown below is representative of the conditions present during Report 10, 11, 13, 14.

Boiler ID Type NOx control SO2 control PM control Other control 2 tangentialfired (1) overfire air (3) cold-side electrostatic precipitator (4) baghouse with

activated carbon injection

3 tangentialfired (1) overfire air (3) cold-side electrostatic precipitator (3) baghouse with

activated carbon injection



### 8gDo any of these test reports reflect testing at a location before a post combustion SO2 emission control device (e.g., FGD, SDA, Dry Scrubber)? Yes ____ No _X

___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 at the time of testing (including percentage of total scrubber flue gas flow). Note by diagram where sampling ports were located in relation to the bypass ductwork.

Page 71 of 93 part II, 8

### GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

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

Specified deviations are reported quarterly. Emissions exceeding a standard for a period of 4 hours or more are reported within 7 days. Other deviations are reported semiannually. Note: Not all reported deviations are considered violations of permit requirements

10Are deviation reports available for malfunctions or other periods of noncompliance with permit terms and conditions? Yes _X

__No ____If yes, please note which reports.

Deviation reports including periods of malfuncation are available where required in quarterly monitor breakdown reports and excess emissions, exdeedances, and excursion reports. Note: A malfunction is not necessarily a period of noncompliance with permit terms and conditions. Not all reported deviations are considered violations of permit requirements

11Are continuous emissions monitoring system (CEMS) data available (e.g., mercury, continuous opacity monitoring systems) that are not already being provided to the U.S. EPA, even if from short-term testing? Yes _X

__No ____If yes46

### , please note for which pollutants CEMS data are available and the period of time (both total period and calendar period) for which the data are available. If CEM data are being provided to EPA, please note to which Office the data are being provided. Mercury CEMS data are operating for the following periods of time:

Unit 3: January 1, 2009 - December 31, 2009 EPA requested in Footnote 46 to Part II, Question 11 that facilities submit available mercury CEMS data that follow recognized QA/QC procedures. While EPA did not make the submittal mandatory, Georgia Power wishes to provide available mercury CEMS data in a separate submittal to assist the rulemaking process. Georgia Power has installed and operated monitors on certain units that, as closely as possible, follow the QA/QC procedures as written under the vacated Clean Air Mercury Rule ("CAMR"). However, Georgia Power does not regularly submit reports to a regulatory agency on an ongoing basis. Thus, Georgia Power will require additional time to review and prepare the data for submittal to EPA. Georgia Power plans to submit this data by May 3, 2010.
COMS data are available for the last five years or more.

46Where units are monitored by CEMs (either following CAMR, State, or NIST QA/QC procedures), and where data are available, EPA requests that this CEM data by submitted by the respondent. The respondent should also mark the periods of start up, shut down and malfunction events (SSM) in the data sets. 

### Page 72 of 93 part II, 9-11

### GEORGIA POWER - PLANT SCHERER EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

12For each boiler noted in Part I, question 15, provide the following information: NOTE: Net generation data not available in test reports. Other parameters may or may not be available depending on the test report.

Date of test PM49 

### SO2 HCl/HF/HCNMetal HAP50 

### Hg51 

### CO Other organics (specify)

4 4/12/2006 See Attachment 1Not applicableNot applicableNot applicable Not applicable Not applicable Not applicable 3 4/13/2006 See Attachment 2Not applicableNot applicableNot applicable Not applicable Not applicable Not applicable
1 6/15/2006 See Attachment 3Not applicableNot applicableNot applicable Not applicable Not applicable Not applicable
2 6/15/2006 See Attachment 4Not applicableNot applicableNot applicable Not applicable Not applicable Not applicable 3 2/19/2008 See Attachment 5Not applicableNot applicableNot applicable Not applicable Not applicable Not applicable
4 2/20/2008 See Attachment 6Not applicableNot applicableNot applicable Not applicable Not applicable Not applicable
1 6/3/2008-6/4/2008 See Attachment 7Not applicableNot applicableNot applicable Not applicable Not applicable Not applicable
2 6/5/2008 See Attachment 8Not applicableNot applicableNot applicable Not applicable Not applicable Not applicable 3 1/5/2010 See Attachment 9Not applicableNot applicableNot applicable Not applicable Not applicable Not applicable
4 1/5/2010 See Attachment 10Not applicableNot applicableNot applicable Not applicable Not applicable Not applicable
1 9/20/2007-9/25/2007 Not applicable Not applicableNot applicableNot applicable Not applicable See Attachment 11Not applicable
2 8/25/2009-8/26/2009 Not applicable Not applicableNot applicableNot applicable Not applicable See Attachment 12Not applicable 3 3/3/2009 Not applicable Not applicableNot applicableNot applicable Not applicable See Attachment 13Not applicable
4 10/24/2006-10/31/2006 Not applicable Not applicableNot applicableNot applicable Not applicable See Attachment 14Not applicable
2 5/28/2009-6/1/2009See Attachment 15Not applicableNot applicableNot applicableSee Attachment 15 Not applicable Not applicable 3 1/28/2009-1/29/2009See Attachment 16Not applicableNot applicableNot applicableSee Attachment 16 Not applicable Not applicable

47Provide emission test data for all tests conducted since January 1, 2005. Please indicate test data acquired both before and after any control device. Use additional pages as necessary. EPA may, at some future date, request a copy of one or more emission test reports. Data generated to fulfill both Federal and State requirements must be provided. Note that data generated pursuant to CAA Title V must be maintained and available for 5 years. Also include averaging times and measurement units for all pollutants.

48For each emissions test run the respondent should provide the following process information: Unit Load (MW), Net generation during run (MWh net), Flue gas moisture content (%), Flue gas flow rate (dscfm or Nm3/hr), Flue gas oxygen content (%, dry), Flue gas carbon dioxide content (%, dry), Flue gas temperature at sampling point (oF), Flue gas pressure at sampling point (atm), Standard temperature (oF), Standard pressure (atm). 

### Boiler ID Emissions test results (indicate format of emission data)47,48



### Page 73 of 93 part II, 12

### GEORGIA POWER - PLANT SCHERER EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010

12For each boiler noted in Part I, question 15, provide the following information: NOTE: Net generation data not available in test reports. Other parameters may or may not be available depending on the test report.

Date of test PM49 

### SO2 HCl/HF/HCNMetal HAP50 

### Hg51 

### CO Other organics (specify) Boiler ID Emissions test results (indicate format of emission data)47,48

49If emission testing recorded the emissions of filterable and condensable PM, separately, please include those separate emission results. Also, please include separate emission results for total PM, PM10, and PM2.5. 50Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, phosphorus, and selenium; indicate emission level for all metal HAP for which an emission test has been conducted.

51Please provide separate results for total Hg, elemental Hg, oxidized Hg, and particulate Hg, as available. If the emissions testing recorded the amount of unburned carbon in fly ash (as reflected by the "Loss of Ignition" [L.O.I]) at the time of any Hg testing, please include these data.



### Page 74 of 93 part II, 12

## ATTACHMENT 1 - Scherer Report 1 Test Results

Performed By: Spectrum Sy stems, Inc., Pensacola, Florida

Run 1 Run 2 Run 3 Test Date 4/12/2006 4/12/2006 4/12/2006 Run Start Time 7:50 10:00 12:15 Run End Time 9:10 11:20 13:35 Meter Volume (dacf), Vm: 37.158 37.699 37.218 Sqrt Delta P ("wc): 1.38 1.40 1.40 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.68 29.70 29.72 Delta H ("wc): 1.1 1.1 1.1 Volume in Impingers (mls), VIc: 93.4 94.8 94.1 Static Pressure ("wc), Pg: -4.00 -3.90 -4.10 Stack Pressure ("Hg), Ps: 29.39 29.41 29.42 Stack Temperature (F), Ts: 311 325 333 Meter Coefficient (no units), Y: 0.997 0.997 0.997 Pitot Coefficient (no units) Cp: 0.840 0.840 0.840 Meter OutletTemperature (F), Tm: 79 85 89 Stack Diameter (inches): 324 324 324 Area Stack (sq. ft.), As: 572.56 572.56 572.56 Nozzle Diameter (inches), dp: 0.176 0.176 0.176 Area Nozzle (sq. ft.), An: 0.000169 0.000169 0.000169 Percent CO2 (% dry

volume): 13.1 13.0 13.2 Percent O2 (% dry

volume): 6.0 6.0 6.2 Percent (N2 + CO) (% dry volume): 80.8 81.0 80.6 Particulate Collected (mg), Mn: 19.4 18.5 24.5

Molec. Wt. Dry

(lb/lb-mole), Md: 30.343 30.320 30.355 Volume Water (scf), Vwstd 4.396 4.462 4.429 Meter Volume (dscf), Vmstd: 36.104 36.215 35.551 Wet Fraction (v/v), Bws: 0.109 0.110 0.111 Molec. Wt. Wet (lb/lb-mole), Ms: 29.003 28.968 28.986 Stack Gas Sampled (acf), Vma: 60.188 61.479 61.050 Averages Stack Gas Velocity

(fps), Vs: 94.09 96.41 96.66 96 Volumetric Flowrate (dscfm), Qs: 1,938,974 1,950,945 1,933,744 1,941,221 Volumetric Flowrate (acfm), Qa: 3,232,443 3,311,971 3,320,753 3,288,389 Grainloading (gr/dscf), cs: 0.0083 0.0079 0.0106 0.01 Emission Rate (lb/hour), E: 137.97 131.46 176.34 148.6 Percent Isokinetic Sampling (%), I: 104.94 104.62 103.61 104.39

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 8461.58 8532.92 8344.15 8446.22 Emission Rate (lbs/mmBtu), E: 0.02 0.02 0.02 0.02 Allowable Rate (lb/mmBtu): 0.10 0.10 0.10 0.10 Average Unit Gross Load (MW) 862 867 873 867 

### Particulate Emission Results Summary

Scherer Unit 4

Page 75 of 93 Att. 1

## ATTACHMENT 2 - Scherer Report 2 Test Results

Performed By: Spectrum Sy stems, Inc., Pensacola, Florida

Run 1 Run 2 Run 3 Test Date 4/13/2006 4/13/2006 4/13/2006 Run Start Time 7:00 9:10 11:10 Run End Time 8:35 10:35 12:30 Meter Volume (dacf), Vm: 37.343 37.476 36.972 Sqrt Delta P ("wc): 1.39 1.41 1.40 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.75 29.75 29.77 Delta H ("wc): 1.1 1.1 1.1 Volume in Impingers (mls), VIc: 94.6 96.9 93.6 Static Pressure ("wc), Pg: -3.80 -4.00 -3.90 Stack Pressure ("Hg), Ps: 29.47 29.46 29.48 Stack Temperature (F), Ts: 294 314 322 Meter Coefficient (no units), Y: 0.997 0.997 0.997 Pitot Coefficient (no units) Cp: 0.840 0.840 0.840 Meter OutletTemperature (F), Tm: 79 86 92 Stack Diameter (inches): 324 324 324 Area Stack (sq. ft.), As: 572.56 572.56 572.56 Nozzle Diameter (inches), dp: 0.176 0.176 0.176 Area Nozzle (sq. ft.), An: 0.000169 0.000169 0.000169 Percent CO2 (% dry

volume): 12.9 12.8 12.9 Percent O2 (% dry

volume): 6.2 6.3 6.1 Percent (N2 + CO) (% dry volume): 80.9 80.9 81.0 Particulate Collected (mg), Mn: 21.2 21.2 18.0

Molec. Wt. Dry

(lb/lb-mole), Md: 30.312 30.304 30.308 Volume Water (scf), Vwstd 4.453 4.561 4.406 Meter Volume (dscf), Vmstd: 36.380 36.004 35.149 Wet Fraction (v/v), Bws: 0.109 0.112 0.111 Molec. Wt. Wet (lb/lb-mole), Ms: 28.969 28.921 28.937 Stack Gas Sampled (acf), Vma: 59.212 60.396 59.444 Averages Stack Gas Velocity

(fps), Vs: 94.03 96.38 96.40 96 Volumetric Flowrate (dscfm), Qs: 1,984,538 1,973,798 1,958,126 1,972,154 Volumetric Flowrate (acfm), Qa: 3,230,078 3,310,959 3,311,613 3,284,217 Grainloading (gr/dscf), cs: 0.0090 0.0091 0.0079 0.01 Emission Rate (lb/hour), E: 153.07 153.82 132.79 146.6 Percent Isokinetic Sampling (%), I: 103.32 102.81 101.17 102.43

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 8563.33 8478.37 8506.84 8516.18 Emission Rate (lbs/mmBtu), E: 0.02 0.02 0.02 0.02 Allowable Rate (lb/mmBtu): 0.10 0.10 0.10 0.10 Average Unit Gross Load (MW) 873 875 875 874 

### Particulate Emission Results Summary

Scherer Unit 3

Page 76 of 93 Att. 2

## ATTACHMENT 3 - Scherer Report 3 Test Results

Performed By: Spectrum Sy stems, Inc., Pensacola, Florida

Run 1 Run 2 Run 3 Test Date 6/15/2006 6/15/2006 6/15/2006 Run Start Time 7:00 9:15 10:50 Run End Time 8:30 10:25 12:00 Meter Volume (dacf), Vm: 38.814 37.85 37.759 Sqrt Delta P ("wc): 1.48 1.46 1.46 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.10 29.10 29.10 Delta H ("wc): 1.2 1.2 1.2 Volume in Impingers (mls), VIc: 84.8 79.8 80.8 Static Pressure ("wc), Pg: -3.90 -3.80 -4.00 Stack Pressure ("Hg), Ps: 28.81 28.82 28.81 Stack Temperature (F), Ts: 351 358 364 Meter Coefficient (no units), Y: 0.989 0.989 0.989 Pitot Coefficient (no units) Cp: 0.840 0.840 0.840 Meter OutletTemperature (F), Tm: 100 104 109 Stack Diameter (inches): 324 324 324 Area Stack (sq. ft.), As: 572.56 572.56 572.56 Nozzle Diameter (inches), dp: 0.176 0.176 0.176 Area Nozzle (sq. ft.), An: 0.000168 0.000168 0.000168 Percent CO2 (% dry

volume): 12.2 12.4 12.4 Percent O2 (% dry

volume): 6.9 6.8 7.0 Percent (N2 + CO) (% dry volume): 80.9 80.8 80.6 Particulate Collected (mg), Mn: 11.1 9.4 19.7

Molec. Wt. Dry

(lb/lb-mole), Md: 30.232 30.251 30.268 Volume Water (scf), Vwstd 3.992 3.756 3.803 Meter Volume (dscf), Vmstd: 35.303 34.186 33.820 Wet Fraction (v/v), Bws: 0.102 0.099 0.101 Molec. Wt. Wet (lb/lb-mole), Ms: 28.989 29.038 29.028 Stack Gas Sampled (acf), Vma: 62.641 61.018 60.985 Averages Stack Gas Velocity

(fps), Vs: 104.70 103.67 104.30 104 Volumetric Flowrate (dscfm), Qs: 2,027,017 1,995,353 1,987,054 2,003,141 Volumetric Flowrate (acfm), Qa: 3,596,763 3,561,452 3,583,163 3,580,460 Grainloading (gr/dscf), cs: 0.0049 0.0043 0.0090 0.01 Emission Rate (lb/hour), E: 84.38 72.74 152.93 103.4 Percent Isokinetic Sampling (%), I: 98.72 97.11 96.47 97.43

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 8349.96 8258.57 8127.01 8245.18 Emission Rate (lbs/mmBtu), E: 0.01 0.01 0.02 0.01 Allowable Rate (lb/mmBtu): 0.100 0.100 0.100 0.100 Average Unit Gross Load (MW) 852 851 851 851 

### Particulate Emission Results Summary

Scherer Unit 1

Page 77 of 93 Att. 3

## ATTACHMENT 4 - Scherer Report 4 Test Results

Performed By: Spectrum Sy stems, Inc., Pensacola, Florida

Run 1 Run 2 Run 3 Test Date 6/15/2006 6/15/2006 6/15/2006 Run Start Time 7:00 9:15 10:50 Run End Time 8:30 10:25 12:00 Meter Volume (dacf), Vm: 41.08 41.05 41.328 Sqrt Delta P ("wc): 1.58 1.56 1.55 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.10 29.10 29.10 Delta H ("wc): 1.4 1.3 1.3 Volume in Impingers (mls), VIc: 86.2 87.8 85.3 Static Pressure ("wc), Pg: -4.20 -4.00 -3.90 Stack Pressure ("Hg), Ps: 28.79 28.81 28.81 Stack Temperature (F), Ts: 364 364 360 Meter Coefficient (no units), Y: 0.997 0.997 0.99 Pitot Coefficient (no units) Cp: 0.840 0.840 0.840 Meter OutletTemperature (F), Tm: 99 103 107 Stack Diameter (inches): 324 324 324 Area Stack (sq. ft.), As: 572.56 572.56 572.56 Nozzle Diameter (inches), dp: 0.176 0.176 0.176 Area Nozzle (sq. ft.), An: 0.000169 0.000169 0.000169 Percent CO2 (% dry

volume): 11.9 12.0 11.8 Percent O2 (% dry

volume): 7.2 7.3 7.4 Percent (N2 + CO) (% dry volume): 80.8 80.8 80.8 Particulate Collected (mg), Mn: 18.3 18.3 18.6

Molec. Wt. Dry

(lb/lb-mole), Md: 30.199 30.205 30.189 Volume Water (scf), Vwstd 4.057 4.133 4.015 Meter Volume (dscf), Vmstd: 37.730 37.476 37.196 Wet Fraction (v/v), Bws: 0.097 0.099 0.097 Molec. Wt. Wet (lb/lb-mole), Ms: 29.014 28.993 29.002 Stack Gas Sampled (acf), Vma: 67.729 67.459 66.453 Averages Stack Gas Velocity

(fps), Vs: 112.68 111.41 110.34 111 Volumetric Flowrate (dscfm), Qs: 2,156,342 2,126,166 2,121,599 2,134,702 Volumetric Flowrate (acfm), Qa: 3,870,872 3,827,283 3,790,417 3,829,524 Grainloading (gr/dscf), cs: 0.0075 0.0075 0.0077 0.01 Emission Rate (lb/hour), E: 138.28 137.27 140.29 138.6 Percent Isokinetic Sampling (%), I: 98.61 99.34 98.81 98.92

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 8650.60 8508.74 8407.43 8522.26 Emission Rate (lbs/mmBtu), E: 0.02 0.02 0.02 0.02 Allowable Rate (lb/mmBtu): 0.100 0.100 0.100 0.100 Average Unit Gross Load (MW) 870 865 865 867 

### Particulate Emission Results Summary

Scherer Unit 2

Page 78 of 93 Att. 4

## ATTACHMENT 5 - Scherer Report 5 Test Results

Performed By: Spectrum Sy stems, Inc., Pensacola, Florida

Run 1 Run 2 Run 3 Test Date 2/19/2008 2/19/2008 2/19/2008 Run Start Time 8:00 10:15 12:00 Run End Time 9:30 11:35 13:20 Meter Volume (dacf), Vm: 34.588 34.956 34.485 Sqrt Delta P ("wc): 1.34 1.33 1.33 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.40 29.41 29.42 Delta H ("wc): 1.0 1.0 1.0 Volume in Impingers (mls), VIc: 75.8 74.1 73.1 Static Pressure ("wc), Pg: -3.80 -3.90 -3.90 Stack Pressure ("Hg), Ps: 29.12 29.12 29.13 Stack Temperature (F), Ts: 311 315 317 Meter Coefficient (no units), Y: 0.987 0.987 0.987 Pitot Coefficient (no units) Cp: 0.840 0.840 0.840 Meter OutletTemperature (F), Tm: 84 91 95 Stack Diameter (inches): 324 324 324 Area Stack (sq. ft.), As: 572.56 572.56 572.56 Nozzle Diameter (inches), dp: 0.176 0.176 0.176 Area Nozzle (sq. ft.), An: 0.000169 0.000169 0.000169 Percent CO2 (% dry

volume): 14.0 13.9 14.0 Percent O2 (% dry

volume): 5.3 5.3 5.2 Percent (N2 + CO) (% dry volume): 80.8 80.8 80.8 Particulate Collected (mg), Mn: 21.5 16.9 17.8

Molec. Wt. Dry

(lb/lb-mole), Md: 30.445 30.435 30.453 Volume Water (scf), Vwstd 3.568 3.488 3.441 Meter Volume (dscf), Vmstd: 32.606 32.569 31.883 Wet Fraction (v/v), Bws: 0.099 0.097 0.097 Molec. Wt. Wet (lb/lb-mole), Ms: 29.218 29.232 29.240 Stack Gas Sampled (acf), Vma: 54.272 54.349 53.370 Averages Stack Gas Velocity

(fps), Vs: 91.42 91.16 91.46 91 Volumetric Flowrate (dscfm), Qs: 1,886,792 1,876,628 1,877,073 1,880,164 Volumetric Flowrate (acfm), Qa: 3,140,539 3,131,589 3,142,022 3,138,050 Grainloading (gr/dscf), cs: 0.0102 0.0080 0.0086 0.01 Emission Rate (lb/hour), E: 164.62 128.94 138.91 144.2 Percent Isokinetic Sampling (%), I: 97.67 98.09 96.00 97.26

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 8658.48 8611.84 8650.61 8,640.31 Emission Rate (lbs/mmBtu), E: 0.02 0.01 0.02 0.02 Allowable Rate (lb/mmBtu): 0.10 0.10 0.10 0.10 Average Unit Gross Load (MW) 879 880 880 880 

### Particulate Emission Results Summary

Scherer Unit 3

Page 79 of 93 Att. 5

## ATTACHMENT 6 - Scherer Report 6 Test Results

Performed By: Spectrum Sy stems, Inc., Pensacola, Florida

Run 1 Run 2 Run 3 Test Date 2/20/2008 2/20/2008 2/20/2008 Run Start Time 10:00 11:40 13:20 Run End Time 11:15 12:55 14:45 Meter Volume (dacf), Vm: 34.175 34.672 35.497 Sqrt Delta P ("wc): 1.35 1.35 1.36 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.40 29.40 29.41 Delta H ("wc): 1.0 1.0 1.0 Volume in Impingers (mls), VIc: 79.1 78.2 78.3 Static Pressure ("wc), Pg: -4.10 -4.00 -4.00 Stack Pressure ("Hg), Ps: 29.10 29.11 29.12 Stack Temperature (F), Ts: 327 331 333 Meter Coefficient (no units), Y: 0.987 0.987 0.987 Pitot Coefficient (no units) Cp: 0.840 0.840 0.840 Meter OutletTemperature (F), Tm: 88 97 99 Stack Diameter (inches): 324 324 324 Area Stack (sq. ft.), As: 572.56 572.56 572.56 Nozzle Diameter (inches), dp: 0.176 0.176 0.176 Area Nozzle (sq. ft.), An: 0.000169 0.000169 0.000169 Percent CO2 (% dry

volume): 13.7 13.8 13.7 Percent O2 (% dry

volume): 5.4 5.5 5.5 Percent (N2 + CO) (% dry volume): 80.9 80.8 80.8 Particulate Collected (mg), Mn: 16.3 22.0 19.9

Molec. Wt. Dry

(lb/lb-mole), Md: 30.409 30.421 30.417 Volume Water (scf), Vwstd 3.723 3.681 3.686 Meter Volume (dscf), Vmstd: 32.024 31.917 32.620 Wet Fraction (v/v), Bws: 0.104 0.103 0.102 Molec. Wt. Wet (lb/lb-mole), Ms: 29.117 29.137 29.157 Stack Gas Sampled (acf), Vma: 54.804 54.786 56.062 Averages Stack Gas Velocity

(fps), Vs: 93.26 93.64 94.19 111 Volumetric Flowrate (dscfm), Qs: 1,872,186 1,874,116 1,882,680 2,134,702 Volumetric Flowrate (acfm), Qa: 3,203,949 3,216,974 3,235,678 3,829,524 Grainloading (gr/dscf), cs: 0.0079 0.0106 0.0094 0.01 Emission Rate (lb/hour), E: 126.19 170.70 152.06 138.6 Percent Isokinetic Sampling (%), I: 96.40 95.98 97.65 98.92

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 8499.86 8490.29 8510.66 8522.26 Emission Rate (lbs/mmBtu), E: 0.01 0.02 0.02 0.02 Allowable Rate (lb/mmBtu): 0.10 0.10 0.10 0.10 Average Unit Gross Load (MW) 895 895 886 892 

### Particulate Emission Results Summary

Scherer Unit 4

Page 80 of 93 Att. 6

## ATTACHMENT 7 - Scherer Report 7 Test Results

Performed by: TRC Environmental Corporation, Raleigh, North Carolina

RUN NUMBER U1-H-M5-1 U1-H-M5-2 U1-H-M5-3 RUN DATE 6/3/2008 6/4/2008 6/4/2008 AVERAGE RUN TIME 1510-1629 0650-0805 0840-0957

MEASURED DA

TA Meter Box Y 1.0025 1.0025 1.0025 1.0025 Avg Delta H, inches H2O 3.650 3.583 3.450 3.561 Barometric Pressure, inches Hg 29.10 29.04 29.04 29.06 Volume Metered, cubic feet 64.040 63.681 62.790 63.504 Average Meter Temp, deg F 107.1 98.3 102.2 102.53 Static Pressure, inches H2O -3.5 -3.5 -3.5 -3.500 Average Stack Temp, deg F 358.6 339.9 347.3 348.6 Water Collected, mL 178.0 177.0 182.0 179.0 Carbon Dioxide, % 12.66 12.47 12.89 12.673 Oxygen, % 6.95 7.1 6.63 6.893 Nitrogen, % 80.39 80.43 80.48 80.433 Pitot Tube Coefficient 0.84 0.84 0.84 0.84 Avg Sqrt Delta P, (inches H2O)1/2 1.552 1.538 1.510 1.533 Sample Time, min 60.0 60.0 60.0 60.0 Nozzle Diameter, inches 0.226 0.226 0.226 0.226



### CALCULATED DATA Nozzle Area, square feet 2.786E-04 2.786E-04 2.786E-04 2.786E-04 Standard Meter Volume, ft3 58.650 59.104 57.861 58.538 Standard Water Vapor Volume, ft3 8.393 8.346 8.581 8.440 Moisture (gravimetrically), % 12.52 12.37 12.92 12.60 Moisture (at saturation), % NA NA NA NA Moisture (actual) 12.52 12.37 12.92 12.60 Dry Mole Fraction 0.875 0.876 0.871 0.874 Molecular Weight-dry, lb/lb-mole 30.30 30.28 30.33 30.30 Molecular Weight-wet, lb/lb-mole 28.76 28.76 28.74 28.75 Stack Pressure, inches Hg 28.84 28.78 28.78 28.80 Velocity, ft/s 110.67 108.59 107.16 108.81 Stack Area, in2 82,448.0 82,448.0 82,448.0 82,448.0 Stack Area, ft2 572.56 572.56 572.56 572.56 Percent Excess Air 48.7 50.2 45.4 48.1 Volumetric flow, acfm 3,802,036 3,730,298 3,681,385 3,737,906 Volumetric flow, dscfm 2,067,300 2,074,752 2,016,176 2,052,742 Isokinetic Rate, % 97.2 97.6 98.3 97.7 F-factor, DSCF/MMBtu 9780 9780 9780 

### FILTERABLE PARTICULA TE TEST RESULTS SUMMARY PLANT SCHERER UNIT 1 STACK

Page 81 of 93 Att. 7

## ATTACHMENT 7 - Scherer Report 7 Test Results

Performed by: TRC Environmental Corporation, Raleigh, North Carolina

RUN NUMBER U1-H-M5-1 U1-H-M5-2 U1-H-M5-3 RUN DATE 6/3/2008 6/4/2008 6/4/2008 AVERAGE RUN TIME 1510-1629 0650-0805 0840-0957 

### FILTERABLE PARTICULA TE TEST RESULTS SUMMARY PLANT SCHERER UNIT 1 STACK

FILTERABLE PARTICULATE EMISSIONS DATA Filterable Particulate Catch, g 0.0128 0.0096 0.0124 Concen., mg/dscm 7.71 5.74 7.57 7.00 Concen., mg/actual m3 4.19 3.19 4.15 3.84 Concen., gr/dscf 0.003 0.003 0.003 0.003 Concen., gr/dscf@8% Oxygen 0.003 0.002 0.003 0.003 Emission Rate, lb/hr 59.68 44.58 57.15 53.80 Emission Rate, lb/MMBtu 0.007 0.005 0.007 0.006 Gross Load, MW 876 887 879 881



### Page 82 of 93 Att. 7

## ATTACHMENT 8 - Scherer Report 8 Test Results

Performed by: TRC Environmental Corporation, Raleigh, North Carolina

RUN NUMBER U2-H-M5-1 U2-H-M5-2 U2-H-M5-3 RUN DATE 6/5/2008 6/5/2008 6/5/2008 AVERAGE RUN TIME 0630-0747 0825-0939 1010-1123

MEASURED DA

TA Meter Box Y 1.0025 1.0025 1.0025 1.0025 Avg Delta H, inches H2O 3.775 3.833 3.867 3.825 Barometric Pressure, inches Hg 29.13 29.13 29.13 29.13 Volume Metered, cubic feet 64.846 65.740 65.867 65.484 Average Meter Temp, deg F 94.4 98.5 102.0 98.31 Static Pressure, inches H2O -3.5 -3.5 -3.5 -3.500 Average Stack Temp, deg F 355.5 358.8 364 359.4 Water Collected, mL 186.0 188.0 191.0 188.3 Carbon Dioxide, % 12.41 12.76 12.24 12.470 Oxygen, % 7.21 6.8 7.37 7.127 Nitrogen, % 80.38 80.44 80.39 80.403 Pitot Tube Coefficient 0.84 0.84 0.84 0.84 Avg Sqrt Delta P, (inches H2O)1/2 1.586 1.593 1.599 1.593 Sample Time, min 60.0 60.0 60.0 60.0 Nozzle Diameter, inches 0.226 0.226 0.226 0.226



### CALCULATED DATA Nozzle Area, square feet 2.786E-04 2.786E-04 2.786E-04 2.786E-04 Standard Meter Volume, ft3 60.826 61.223 60.964 61.004 Standard Water Vapor Volume, ft3 8.770 8.864 9.006 8.880 Moisture (gravimetrically), % 12.60 12.65 12.87 12.71 Moisture (at saturation), % NA NA NA NA Moisture (actual) 12.60 12.65 12.87 12.71 Dry Mole Fraction 0.874 0.874 0.871 0.873 Molecular Weight-dry, lb/lb-mole 30.27 30.31 30.25 30.28 Molecular Weight-wet, lb/lb-mole 28.73 28.76 28.68 28.72 Stack Pressure, inches Hg 28.87 28.87 28.87 28.87 Velocity, ft/s 112.92 113.63 114.56 113.70 Stack Area, in2 82,448.0 82,448.0 82,448.0 82,448.0 Stack Area, ft2 572.56 572.56 572.56 572.56 Percent Excess Air 51.5 47.1 53.2 50.6 Volumetric flow, acfm 3,879,333 3,903,500 3,935,347 3,906,060 Volumetric flow, dscfm 2,117,502 2,120,896 2,119,360 2,119,253 Isokinetic Rate, % 98.4 98.9 98.6 98.6 F-factor, DSCF/MMBtu 9780 9780 9780



### FILTERABLE PARTICULA TE TEST RESULTS SUMMARY PLANT SCHERER UNIT 2 STACK

Page 83 of 93 Att. 8

## ATTACHMENT 8 - Scherer Report 8 Test Results

Performed by: TRC Environmental Corporation, Raleigh, North Carolina

RUN NUMBER U2-H-M5-1 U2-H-M5-2 U2-H-M5-3 RUN DATE 6/5/2008 6/5/2008 6/5/2008 AVERAGE RUN TIME 0630-0747 0825-0939 1010-1123



### FILTERABLE PARTICULA TE TEST RESULTS SUMMARY PLANT SCHERER UNIT 2 STACK

FILTERABLE PARTICULATE EMISSIONS DATA Filterable Particulate Catch, g 0.0169 0.0176 0.0172 Concen., mg/dscm 9.81 10.15 9.96 9.97 Concen., mg/actual m3 5.36 5.52 5.37 5.41 Concen., gr/dscf 0.004 0.004 0.004 0.004 Concen., gr/dscf@8% Oxygen 0.004 0.004 0.004 0.004 Emission Rate, lb/hr 77.82 80.65 79.09 79.19 Emission Rate, lb/MMBtu 0.009 0.009 0.009 0.009 Gross Load, MW 882 879 879 880



### Page 84 of 93 Att. 8

## ATTACHMENT 9 - Scherer Report 9 Test Results

Performed by: Spectrum Sy stems, Inc., Pensacola, Florida

Run 1 Run 2 Run 3 Test Date 1/5/2010 1/5/2010 1/5/2010 Run Start Time 9:05 10:40 12:10 Run End Time 10:15 11:50 13:20 Meter Volume (dacf), Vm: 33.828 33.589 33.791 Sqrt Delta P ("wc): 1.36 1.35 1.37 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 30.01 30.01 30.01 Delta H ("wc): 1.1 1.0 1.1 Volume in Impingers (mls), VIc: 119.1 120.3 117.6 Static Pressure ("wc), Pg: -2.60 -2.50 -2.70 Stack Pressure ("Hg), Ps: 29.82 29.83 29.81 Stack Temperature (F), Ts: 262 265 270 Meter Coefficient (no units), Y: 0.985 0.985 0.985 Pitot Coefficient (no units) Cp: 0.840 0.840 0.840 Meter OutletTemperature (F), Tm: 52 55 58 Stack Diameter (inches): 324 324 324 Area Stack (sq. ft.), As: 572.56 572.56 572.56 Nozzle Diameter (inches), dp: 0.173 0.173 0.173 Area Nozzle (sq. ft.), An: 0.000164 0.000164 0.000164 Percent CO2 (% dry

volume): 12.6 12.6 12.5 Percent O2 (% dry

volume): 7.0 7.0 7.1 Percent (N2 + CO) (% dry volume): 80.4 80.3 80.4 Particulate Collected (mg), Mn: 5.0 3.1 4.3

Molec. Wt. Dry

(lb/lb-mole), Md: 30.297 30.303 30.289 Volume Water (scf), Vwstd 5.606 5.663 5.535 Meter Volume (dscf), Vmstd: 34.532 34.121 34.123 Wet Fraction (v/v), Bws: 0.140 0.142 0.140 Molec. Wt. Wet (lb/lb-mole), Ms: 28.580 28.552 28.574 Stack Gas Sampled (acf), Vma: 55.098 54.773 54.999 Averages Stack Gas Velocity

(fps), Vs: 90.11 89.68 90.79 90 Volumetric Flowrate (dscfm), Qs: 1,940,079 1,919,224 1,935,036 1,931,446 Volumetric Flowrate (acfm), Qa: 3,095,479 3,080,889 3,118,864 3,098,411 Grainloading (gr/dscf), cs: 0.0022 0.0014 0.0020 0.00 Emission Rate (lb/hour), E: 36.94 22.96 32.41 30.8 Percent Isokinetic Sampling (%), I: 103.82 103.70 102.86 103.46

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 7896.92 7812.03 7838.52 7849.16 Emission Rate (lbs/mmBtu), E: 0.005 0.003 0.004 0.004 Allowable Rate (lb/mmBtu): 0.100 0.100 0.100 0.100 Average Unit Gross Load (MW) 899 898 894 897 

### Particulate Emission Results Summary

Scherer Unit 3

Page 85 of 93 Att. 9

## ATTACHMENT 10 - Scherer Report 10 Test Results

Performed by: Spectrum Sy stems, Inc., Pensacola, Florida

Run 1 Run 2 Run 3 Test Date 1/5/2010 1/5/2010 1/5/2010 Run Start Time 9:05 10:40 12:10 Run End Time 10:15 11:50 13:20 Meter Volume (dacf), Vm: 36.333 35.892 36.915 Sqrt Delta P ("wc): 1.41 1.42 1.41 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 30.01 30.01 30.01 Delta H ("wc): 1.1 1.1 1.1 Volume in Impingers (mls), VIc: 126.0 123.2 121.7 Static Pressure ("wc), Pg: -2.90 -2.80 -2.80 Stack Pressure ("Hg), Ps: 29.80 29.80 29.80 Stack Temperature (F), Ts: 310 314 315 Meter Coefficient (no units), Y: 0.996 0.996 0.996 Pitot Coefficient (no units) Cp: 0.840 0.840 0.840 Meter OutletTemperature (F), Tm: 50 53 56 Stack Diameter (inches): 324 324 324 Area Stack (sq. ft.), As: 572.56 572.56 572.56 Nozzle Diameter (inches), dp: 0.176 0.176 0.176 Area Nozzle (sq. ft.), An: 0.000169 0.000169 0.000169 Percent CO2 (% dry

volume): 13.2 13.2 13.3 Percent O2 (% dry

volume): 5.9 5.8 5.8 Percent (N2 + CO) (% dry volume): 80.9 81.0 81.0 Particulate Collected (mg), Mn: 42.8 28.6 29.7

Molec. Wt. Dry

(lb/lb-mole), Md: 30.347 30.344 30.353 Volume Water (scf), Vwstd 5.931 5.799 5.728 Meter Volume (dscf), Vmstd: 37.658 36.987 37.798 Wet Fraction (v/v), Bws: 0.136 0.136 0.132 Molec. Wt. Wet (lb/lb-mole), Ms: 28.667 28.671 28.728 Stack Gas Sampled (acf), Vma: 63.795 62.985 64.136 Averages Stack Gas Velocity

(fps), Vs: 96.17 96.85 96.41 96 Volumetric Flowrate (dscfm), Qs: 1,950,249 1,953,887 1,951,829 1,951,988 Volumetric Flowrate (acfm), Qa: 3,303,867 3,327,244 3,311,914 3,314,342 Grainloading (gr/dscf), cs: 0.0176 0.0119 0.0121 0.01 Emission Rate (lb/hour), E: 293.50 199.99 203.01 232.2 Percent Isokinetic Sampling (%), I: 109.14 106.99 109.45 108.53

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 8606.20 8660.49 8670.47 8645.72 Emission Rate (lbs/mmBtu), E: 0.034 0.023 0.023 0.027 Allowable Rate (lb/mmBtu): 0.100 0.100 0.100 0.100 Average Unit Gross Load (MW) 883 882 883 883 

### Particulate Emission Results Summary

Scherer Unit 4

Page 86 of 93 Att. 10

## ATTACHMENT 11 - Scherer Report 11 Test Results

Title of Run Description Date Start Time End

Time Unit

Load Avg. Econ. Gas Outlet CO Avg. Econ. Gas Outlet O2 Avg. Econ. Gas Outlet CO2 Avg. Econ. Gas Outlet Temp
MilitaryMilitary 

### MW ppm % Dry% DryDeg F
Test01-0.7% O2 Bias, "A & B Mills Off", Pegasus Off9/20/2007 8:09 9:09 875 902 2.5 16.43 799.7

Test02-0.7% O2 Bias, "A & B Mills Off", Pegasus Off9/20/2007 9:49 10:49 875 902 2.51 16.4 812.7

Test03No O2 Bias, "A & B Mills Off", Pegasus Off9/20/2007 12:56 13:56 875 235 3.29 15.67823.9

Test04No O2 Bias, "A & B Mills Off", Pegasus Off9/20/2007 15:11 16:11 875 289 3.28 15.61 827.9

Test05No O2 Bias, "A & B Mills Off", Pegasus On9/24/2007 12:35 13:35 893 598 3.1 15.79 830.2

Test06No O2 Bias, "A & B Mills Off", Pegasus On9/25/2007 8:29 9:39 873 560 2.82 16.03 816.3

Test07+0.2 O2 Bias, "A & B Mills Off", Pegasus On9/25/2007 13:25 14:25 873 352 3.4 15.42 818.5

Test08+0.2 O2 Bias, "A & B Mills Off", Pegasus On9/25/2007 15:28 16:28 873 304 3.37 15.41 813

Boiler Optimization Test Results Summary

Scherer Unit 1

## ATTACHMENT 12 - Scherer Report 12 Test Results

Title of Run Description Date Start Time End TimeUnit

Load Avg. Econ. Gas Outlet CO Avg.

Econ. Gas Outlet O2 Avg.

Econ. Gas Outlet CO2 Avg. Econ. Gas Outlet Temp 

### MilitaryMilitaryMW ppm % Dry % Dry Deg F
24-1VWO; A&B Mills off 8/25/20097:00 8:24 872 6 4.12 15.14 714 24-2VWO; A&B Mills off 8/25/20098:31 9:55 870 6 4.08 15.1 728 24-3VWO; A&B Mills off 8/25/200910:14 11:38 874 5 4.07 15.12 740 24-4VWO; A&B Mills off 8/25/200911:52 12:52 879 4 4.11 15.02 749 24-5VWO; A&B Mills off 8/25/200913:04 14:28 874 5 4 15.16 753 24-9VWO; A&B Mills off 8/25/200919:48 21:12 873 16 4 15.22 715 24-13VWO; A&B Mills off 8/26/20095:29 6:53 873 12 4.01 15.25 710

Moved JJ Aux Air dmpr to 60% Moved OFA dmpr to 0% Lowered tilts to 0 deg Upper Sofa 90% Lower Sofa 90% B Side Aux Air +10 bias Took all bias out of SOFA dampers Economizer Performance Test Results Summary

Scherer Unit 2

## ATTACHMENT 13 - Scherer Report 13 Test Results

Title of Run Date Start TimeEnd TimeUnit LoadAvg. Econ. Gas Outlet CO Avg. Econ. Gas Outlet O2 Avg. Econ. Gas Outlet CO2 Avg. Econ. Gas Outlet Temp 

### Military Military MW ppm % Dry % Dry Deg F 2 3/3/2009 7:25 8:10 883 166 2.78 16.59 712 3 3/3/2009 8:13 8:58 897 216 2.75 16.65 716 4 3/3/2009 8:59 9:44 895 208 2.78 16.67 717 7 3/3/2009 13:49 14:34 877 142 2.92 16.48 698 8 3/3/2009 14:35 15:20 878 115 2.94 16.4 701

Economizer Performance Test Results Summary

Scherer Unit 3

## ATTACHMENT 14 - Scherer Report 14 Test Results

Title of Run Description Date Start TimeEnd Time Unit Load Avg. Econ. Gas Outlet COAvg.

Econ. Gas Outlet O2Avg. Econ.

Gas Outlet CO2 Avg. Econ. Gas Outlet Temp



### MilitaryMilitary MW ppm % Dry % Dry Deg F
Test 1A & B Mills Off 10/24/2006 8:40 10:04 881 18 3.3 15.86 824 Test 2A & B Mills Off 10/24/200612:45 14:09 881 217 2.31 16.65 830 Test 4A Mills Off 10/25/2006 7:25 8:49 896 191 2.42 16.8 823 Test 6A Mills Off 10/25/200611:30 12:54 894 616 2.28 16.92 834 Test 7J Mills Off 10/26/2006 7:20 8:44 881 147 2.46 16.84 792 Test 7BA Mills Off 10/26/200610:20 11:44 881 160 2.34 16.97 799 Test 8A, B & J Mills Off 10/31/2006 0:05 1:29 682 17 3.12 16.05 754 Test 9A, B, G, H, J Mills Off 10/31/2006 3:05 4:29 351 3 5.22 14.07 635 SCR Baseline Test Results Summary

Scherer Unit 4

## ATTACHMENT 15 - Scherer Report 15 Test Results

Performed by: Weston Solutions



### Unit 2 Stack Summary

of PM Emission Results
Run 1 Run 2 Run 3 Mean 

### Date 5/28/20095/28/20095/28/2009 Time Began 743 1218 1511 Time Ended 1001 1435 1728 Stack Gas Data Temperature, oF 312 317 319 316 Velocity, ft/sec 104 101 100 102 Moisture, % 12 13 12 12 CO2, %vd 12.9 12.8 12.9 12.9 O2, %vd 6.9 6.9 6.8 6.9 VFR, x 10^6 dscfm 2.02 1.97 2.01 2.00 Process Operating Data Gross Load, MW 871.5 875.2 875.1 873.9 F-Factor, dscf/MMBtu 9780 9780 9780 9780 Particulate Matter Isokinetic Sampling Rate, % 104 101 100 102 Concentration, gr/dscf 0.0003 0.0005 0.0008 0.0005 Emission Rate, lb/MMBtu 0.0006 0.0010 0.0017 0.0011
Unit 2 Baghouse Inlet Summary

of Mercury

Emission Results
Run 1 Run 2 Run 3 Mean 

### Date 6/1/2009 6/1/2009 6/1/2009 Time Began 949 1300 1532 Time Ended 1221 1511 1745 Stack Gas Data Temperature, oF 304 309 312 308 Velocity, ft/sec 74 74 77 75 Moisture, % 11 10 11 11 CO2, %vd 12.7 13.1 13 12.9 O2, %vd 6.7 6.6 6.6 6.6 VFR, x 10^6 dscfm 2.36 2.37 2.45 2.39 PAC Injection Rate, lb/hr 787.1 797.3 797.3 793.9 Mercury Baghouse Inlet (30B) Concentration,μg/m^3 5.43 5.6 6.29 5.77 Stack (CMMS) Concentration,μg/m^3 0.23 0.23 0.19 0.22 Removal Efficiency, % 95.7 95.9 96.9 96.2 Stack (CMMS) Emission Factor, lb Hg/Tbtu 0.23 0.23 0.19 0.22

## ATTACHMENT 16 - Scherer Report 16 Test Results

Performed by: Weston Solutions



### Unit 3 Stack Summary

of PM Emission Results
Run 1 Run 2 Run 3 Run 4 Mean 

### Date 1/28/20091/28/20091/29/20091/29/2009 Time Began 1129 1534 951 1402 Time Ended 1345 1743 1227 1613 Stack Gas Data Temperature, oF 287 282 274 278 280 Velocity, ft/sec 92 92 90 90 91 Moisture, % 9.9 10.9 12.2 12.2 11.3 CO2, %vd 14.3 14.4 14.4 14.4 14.4 O2, %vd 5.0 5.0 5.1 5.1 5.1 VFR, x 10^6 wscfm 2.14 2.17 2.14 2.14 2.15 VFR, x 10^6 dscfm 1.93 1.93 1.88 1.88 1.90 Process Operating Data Gross Load, MW 883 894 893 887 889 F-Factor, dscf/MMBtu 9780 9780 9780 9780 9780 Particulate Matter Isokinetic Sampling Rate, % 100 104 101 100 102 Concentration, gr/dscf 0.0005 0.0004 0.0007 0.0019 0.0009 Emission Rate, lb/MMBtu 0.0008 0.0007 0.0014 0.0035 0.0016
Unit 3 Baghouse Inlet Summary

of Mercury

Emission Results
Run 1 Run 2 Run 3 Run 4 Mean 

### Date 1/28/20091/28/20091/29/20091/29/2009 Time Began 1129 1534 951 1402 Time Ended 1342 1743 1220 1603 Stack Gas Data Temperature, oF 284 275 270 273 276 Velocity, ft/sec 58 58 58 57 58 Moisture, % 9.0 10.4 11.5 11.3 10.6 CO2, %vd 14.7 14.9 15 14.9 14.9 O2, %vd 4.8 4.7 4.6 4.6 4.7 VFR, x 10^6 wscfm 2.24 2.25 2.29 2.24 2.25 VFR, x 10^6 dscfm 2.03 2.01 2.02 1.99 2.02 PAC Injection Rate, lb/hr 227.3 230.2 185.6 180.1 205.8 Mercury Baghouse Inlet (30B) Concentration,μg/m^3 5.51 4.39

--- 5.4 5.1 Stack (CMMS) Concentration,μg/m^3 0.77 0.38 0.42 0.50 0.55 Removal Efficiency, % 86 91.4

--- 90.7 89.4 Stack (CMMS) Emission Factor, lb Hg/Tbtu 0.66 0.32 0.37 0.43 0.47

Run 3 was determined void at the Baghouse Inlet because the mercury sorbent Trap A was compromised during the test.

## ATTACHMENT 16 - Scherer Report 16 Test Results

Unit 3 Baghouse Inlet Summary

of 30B and Ontario Hydro Single Point Test Results
Run 1 

### Date 1/27/2009 Time Began 1719 Time Ended 1919 Stack Gas Data Temperature, oF 276 Velocity, ft/sec 58 Moisture, % 13.5 CO2, %vd 14.6 O2, %vd 5.1 VFR, x 10^6 wscfm 2.28 VFR, x 10^6 dscfm 1.97 Mercury - 30B Concentration,μg/m^3 6.86 Mercury - Ontario Hydro Total Concentration,μg/scm 5.59 Elemental Hg,μg/dscm 2.59 Oxidized Hg,μg/dscm 3.87 Particle Bound Hg,μg/dscm 0.01