### GEORGIA POWER - Submittal for PLANT BRANCH

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

3Address of _X__ legal owner or ____ 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):

Harllee Branch 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):

709 5Complete street address of facility (physical location):

US Highway 441 Truck Route, P.O. Box 990 Milledgeville, Georgia 31061 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 67 part I, 1-14

### GEORGIA POWER - Submittal for PLANT BRANCH

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 (% _____) ____ subbituminous (% _____)

_X__ bituminous (% _100____) ____ 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 67 part I, 1-14

### GEORGIA POWER - Submittal for PLANT BRANCH

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 or not.

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"). 

### Quantity/year Actually burn None in 2009 

### Permitted to burn

Synfuel 

### Other Material Sawdust Biomass None in 2009 None in 2009 Used Oil
Yes None in 2009 None in 2009 Yes None in 2009

None in 2009 Yes Yes None in 2009



### Page 3 of 67 part I, 1-14

### GEORGIA POWER - PLANT BRANCH

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 bituminous CBI CBI 267 252 89.3 89.5 2400 2400 1000 999 1000 998 bituminous coal (100%), distillate oil (100%) CBI CBI Not applicable None

planned

2 bituminous CBI CBI 332 316 89.3 89.19 2400 2399 1000 997 1000 1000 bituminous coal (100%), distillate oil (100%) CBI CBI Not applicable None

planned

3 bituminous CBI CBI 513 488 87 89.23 3500 3501 1000 994 1000 1001 bituminous coal (100%), distillate oil (100%) CBI CBI Not applicable None

planned

4 bituminous CBI CBI 520 490 86.8 90.2 3500 3499 1000 998 1000 1000 bituminous coal (100%), distillate oil (100%) CBI CBI Not applicable None

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.

Page 4 of 67 part I, 15

### GEORGIA POWER - PLANT BRANCH

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



### 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. 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 has not committed to actual retirement dates for Plant Branch 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 67 part I, 15

### GEORGIA POWER - PLANT BRANCH

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/NH3 flue gas conditioning and lime injection systems are operated on an as-needed basis. Dates for future planned controls listed are subject to change. Boiler ID14 

### Type15 

### NOx control16 

### SO2 control17 

### PM control18 

### Other control19
1 cell burner (1) low NOx burners (2/2003) (2) SCR (12/31/2014), catalyst not yet purchased (6) wet flue gas desulfurization (FGD) (12/31/2014). (4) cold-side electrostatic precipitator (ESP) (6/1965, original install; 1/1978, retrofit ESP arranged in series with original ESP) (3) flue gas conditioning (SO3 injection) (1998) (5) hydrated lime injection (SO3 control, 12/31/2014)

2 dry bottom wallfired (1) low NOx burners (2007,

replacement of equipment installed 3/2002) (2) SCR (12/31/2014), catalyst not yet purchased (6) wet flue gas desulfurization (FGD) (12/31/2014). (4) cold-side electrostatic precipitator (ESP) (6/1967, original install; 12/1977, retrofit ESP arranged in series with original ESP) (3) flue gas conditioning (SO3 injection) (1998) (5) hydrated lime injection (SO3 control, 12/31/2014)

3 cell burner (1) low NOx burners (3/2003) (2) SCR (12/31/2013), catalyst not yet purchased (6) wet flue gas desulfurization (FGD) (12/31/2013). (3) cold-side electrostatic precipitator (ESP) (7/1968, original install; 11/1981, retrofit ESP arranged in parallel with original ESP) (5) hydrated lime injection (SO3 control, 12/31/2013)

4 cell burner (1) low NOx burners (5/2002) (2) SCR (6/1/2014), catalyst not yet purchased (6) wet flue gas desulfurization (FGD) (6/1/2014). (3) cold-side electrostatic precipitator (ESP) (6/1969, original install; 3/1982, retrofit ESP arranged in parallel with original ESP) (5) hydrated lime injection (SO3 control, 6/1/2014)



### Page 6 of 67 part I, 16

### GEORGIA POWER - PLANT BRANCH

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/NH3 flue gas conditioning and lime injection systems are operated on an as-needed basis. Dates for future planned controls listed are subject to change. 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.
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 67 part I, 16

### GEORGIA POWER - PLANT BRANCH

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 67 part I, 17

### GEORGIA POWER - PLANT BRANCH

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-date Type of control (e.g.,

sorbent and type; chemical additive23

### ) Desired HAP

emission reduction (%) or emission rate Coal 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 67 part I, 18

### GEORGIA POWER - PLANT BRANCH

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 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

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 67 part I, 19

### GEORGIA POWER - PLANT BRANCH

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).

Boiler ID25 

### Actual start-up 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 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

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 11 of 67 part I, 20

### GEORGIA POWER - PLANT BRANCH

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 0.24 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 applicable Not

applicable 3% fuel sulfur content (Title V permit; based on

analysis of coal sample acquired for each operating day and supplier certification statement for No. 2 oil)
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 applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable NOx: 0.55 lb/MMBtu from May 1 through

September 30 OR compliance with 7-plant NOx average of 0.18 lb/MMBtu (Title V permit; based on 30-day rolling averages determined by CEMS)
Other NOx Multi-Unit Plans: Southern Company Phase II NOx Averaging Plan 0.46 lb/MMBtu annual average over all units; 7-plant NOx cap 32, 335.8 tons from May 1 to September 30 (Title V permit; determined by CEMS)

2 0.24 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 applicable Not

applicable 3% fuel sulfur content (Title V permit; based on

analysis of coal sample acquired for each operating day and supplier certification statement for No. 2 oil)
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 applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable NOx: 0.55 lb/MMBtu from May 1 through

September 30 OR compliance with 7-plant NOx average of 0.18 lb/MMBtu (Title V permit; based on 30-day rolling averages determined by CEMS)
Other NOx Multi-Unit Plans: Southern Company Phase II NOx Averaging Plan 0.46 lb/MMBtu annual average over all units; 7-plant NOx cap 32, 335.8 tons from May 1 to September 30 (Title V permit; determined by CEMS).

3 0.24 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 applicable Not

applicable 3% fuel sulfur content (Title V permit; based on

analysis of coal sample acquired for each operating day and supplier certification statement for No. 2 oil)
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 applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable NOx: 0.45 lb/MMBtu from May 1 through

September 30 OR compliance with 7-plant NOx average of 0.18 lb/MMBtu (Title V permit; based on 30-day rolling averages determined by CEMS)
Other NOx Multi-Unit Plans: Southern Company Phase II NOx Averaging Plan 0.46 lb/MMBtu annual average over all units; 7-plant NOx cap 32, 335.8 tons from May 1 to September 30 (Title V permit; determined by CEMS). 

### Permitted emission limit (indicate type of permit and format of emission limit)
Boiler ID27



### Page 12 of 67 part I, 21

### GEORGIA POWER - PLANT BRANCH

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 0.24 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 applicable Not

applicable 3% fuel sulfur content (Title V permit; based on

analysis of coal sample acquired for each operating day and supplier certification statement for No. 2 oil)
5% of potential combustion concentration (95% removal by FGD), effective June 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 applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable NOx: 0.45 lb/MMBtu from May 1 through

September 30 OR compliance with 7-plant NOx average of 0.18 lb/MMBtu (Title V permit; based on 30-day rolling averages determined by CEMS)
Other NOx Multi-Unit Plans: Southern Company Phase II NOx Averaging Plan 0.46 lb/MMBtu annual average over all units; 7-plant NOx cap 32, 335.8 tons from May 1 to September 30 (Title V permit; 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 13 of 67 part I, 21

### GEORGIA POWER - PLANT BRANCH

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

22For each boiler noted in Part I, question 15, provide the following information: NOTES: 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 1A and 1B rebuild: 75.0 % collection efficiency filterable (expired in 2000) ESP 1C and 1C: 98.5 % collection efficiency filterable (expired in 1978) Not applicable Not

applicable Not applicable Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable Low NOx burners: 0.45 lb/MMBtu (expired in

2004)

2 ESP 2A and 2B rebuild: 98.0 % collection efficiency filterable (expired in 2000) ESP 2C and 2C: 98.5 % collection efficiency filterable (expired in 1977) Not applicable Not

applicable Not applicable Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable Low NOx burners: 0.48 lb/MMBtu (expired in

2003)

3 ESP rebuild: 98.7 % collection efficiency filterable (expired in 2009) Not applicable Not

applicable Not applicable Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable Low NOx burners: 0.45 lb/MMBtu (expired in

2004)

4 ESP rebuild: 0.1 lb/MMBtu filterable (expired in 1999) Not applicable Not

applicable Not applicable Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable Low NOx burners: 0.45 lb/MMBtu (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 14 of 67 part I, 22-23

### GEORGIA POWER - PLANT BRANCH

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 36%) 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 applicable Not

applicable Coal sulfur content monitored through daily coal sampling;

fuel oil sulfur content monitored through vendor certification; exceedances of 3% 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 applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

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 36%) 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 applicable Not

applicable Coal sulfur content monitored through daily coal sampling;

fuel oil sulfur content monitored through vendor certification; exceedances of 3% 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 applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

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 40%) 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 applicable Not

applicable Coal sulfur content monitored through daily coal sampling;

fuel oil sulfur content monitored through vendor certification; exceedances of 3% 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 applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable 

### Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a permitted emission limit
Boiler ID35



### Page 15 of 67 part I, 24

### GEORGIA POWER - PLANT BRANCH

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 40%) 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 applicable Not

applicable Coal sulfur content monitored through daily coal sampling;

fuel oil sulfur content monitored through vendor certification; exceedances of 3% limit reported quarterly; records retained for 5 years. Effective June 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 applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

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 16 of 67 part I, 24

### GEORGIA POWER - PLANT BRANCH

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.: Not applicable Retrofit to existing boiler? Not applicable Installation on a new boiler? Not applicable Total Capital Investment:

- $ Total Annual Operating and Maintenance Costs:

- $ (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. No.

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



### Page 17 of 67 part I, 25-26

### GEORGIA POWER - PLANT BRANCH

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:

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

709

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



### Page 18 of 67 part II, 1

### GEORGIA POWER - PLANT BRANCH

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

9,777 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.25 12.02 13,058

10,245 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.43 12.94 12,865

10,166 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.19 11.91 13,104

9,789 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.29 13.63 12,803

9,988 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.35 14.67 12,595

10,072 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.23 12.72 12,947

9,746 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.06 12.39 12,982

9,792 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.03 13.14 12,885 

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

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

### Fuel shipment method

Page 19 of 67 part II, 2 (coal)

### GEORGIA POWER - PLANT BRANCH

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

10,012 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 0.95 13 12,934

10,222 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.2 11.92 13,055

9,711 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.33 13.37 12,828

9,654 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 0.92 13.93 12,710

9,757 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 0.92 11.7 13,132

9,781 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 0.92 13.73 12,763

9,936 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.27 11.92 13,005

10,053 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.57 12.65 12,943



### Page 20 of 67 part II, 2 (coal)

### GEORGIA POWER - PLANT BRANCH

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

9,539 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.51 12.72 12,949

10,012 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.37 12.39 12,960

9,681 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.41 12.83 12,965

9,711 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.31 13.77 12,826

10,149 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.31 11.8 13,073

10,474 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.28 11.72 13,154

10,066 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.39 13.36 12,817

10,117 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.39 12.06 13,020



### Page 21 of 67 part II, 2 (coal)

### GEORGIA POWER - PLANT BRANCH

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

10,377 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.63 12.85 12,845

9,872 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.53 13.5 12,742

9,596 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.45 12.54 12,916

9,974 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.3 13.13 12,854

9,892 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.4 12.62 12,876

10,081 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.43 12.16 12,964

10,414 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.73 12.66 12,933

9,980 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.63 12.58 12,916



### Page 22 of 67 part II, 2 (coal)

### GEORGIA POWER - PLANT BRANCH

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

9,959 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.42 11.26 13,074

10,079 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.61 12.85 12,890

10,487 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.52 12.29 13,066

10,070 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.37 11.37 13,183

10,017 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.28 12.56 13,005

10,439 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.54 11.9 13,189

9,910 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.3 11.32 13,165

9,892 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.47 12.63 13,027



### Page 23 of 67 part II, 2 (coal)

### GEORGIA POWER - PLANT BRANCH

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

9,966 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.23 11.82 13,177

10,132 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.51 12.27 13,015

9,913 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.4 12.89 12,962

9,837 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.51 12.6 12,984

9,952 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.19 12.78 12,916

9,564 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.34 13.66 12,789

9,665 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.28 12.63 12,904

10,010 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.39 11.41 13,232



### Page 24 of 67 part II, 2 (coal)

### GEORGIA POWER - PLANT BRANCH

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

10,084 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.3 12.77 12,952

10,154 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.38 12.78 13,021

10,071 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.46 13.79 12,767

9,915 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.16 11.93 13,009

9,933 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.14 13.4 12,717

9,923 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.21 12.88 12,946

9,982 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.19 11.7 13,112

9,995 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.2 13.34 12,793



### Page 25 of 67 part II, 2 (coal)

### GEORGIA POWER - PLANT BRANCH

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

9,969 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.04 12.99 12,901

9,321 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.05 13.54 12,696

10,013 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.08 13.76 12,836

9,944 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.21 13.11 12,781

10,057 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.28 12.72 12,776

10,326 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.36 12.42 13,010

9,955 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.54 11.23 13,159

10,092 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.48 12.59 12,957



### Page 26 of 67 part II, 2 (coal)

### GEORGIA POWER - PLANT BRANCH

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

9,846 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.3 11.89 13,067

9,911 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.57 12.16 13,024

10,068 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.51 13.17 12,801

10,162 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.52 11.95 13,100

9,793 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.35 12.46 12,916

9,984 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.51 13.09 12,845

10,179 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.33 13.13 12,812

9,891 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.56 13.27 12,860



### Page 27 of 67 part II, 2 (coal)

### GEORGIA POWER - PLANT BRANCH

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

9,923 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.6 11.72 13,169

10,252 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.44 12.48 12,926

9,894 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.25 12.42 12,803

10,122 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.45 14.26 12,690

10,106 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.44 12.21 12,977

9,732 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.65 12.2 13,033

10,059 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.58 13.2 12,869

10,158 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.26 13.12 12,837



### Page 28 of 67 part II, 2 (coal)

### GEORGIA POWER - PLANT BRANCH

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

9,887 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.4 11.62 13,091

10,067 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.55 13.2 12,805

9,970 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.17 14.08 12,798

10,127 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.25 14 12,789

10,047 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.16 13.56 12,843

10,422 1, 2, 3, 4 KY KNOTT 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.18 14.78 12,603 9,839 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.55 9.73 13,603 10,127 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.13 8.66 13,717 10,023 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.39 7.94 13,866 9,819 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.7 9.29 13,582 9,868 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.37 7.8 13,878 10,645 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.46 9.22 13,709



### Page 29 of 67 part II, 2 (coal)

### GEORGIA POWER - PLANT BRANCH

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

10,472 1, 2, 3, 4 KY PERRY, LETCHER AMBURGY, HAZARD #4,

HAZARD TRAIN 0.93 10.62 13,460

9,504 1, 2, 3, 4 KY PERRY, LETCHER AMBURGY, HAZARD #4,

HAZARD TRAIN 0.87 10.94 13,342

10,477 1, 2, 3, 4 KY PERRY, LETCHER AMBURGY, HAZARD #4,

HAZARD TRAIN 1.03 9.48 13,658

10,660 1, 2, 3, 4 KY PERRY, LETCHER AMBURGY, HAZARD #4,

HAZARD TRAIN 1.02 10.19 13,564

10,390 1, 2, 3, 4 KY PERRY, LETCHER AMBURGY, HAZARD #4,

HAZARD TRAIN 0.74 10.8 13,441

10,393 1, 2, 3, 4 KY PERRY, LETCHER AMBURGY, HAZARD #4,

HAZARD TRAIN 0.88 9.36 13,651

10,486 1, 2, 3, 4 KY PERRY, LETCHER AMBURGY, HAZARD #4,

HAZARD TRAIN 0.89 11.15 13,312

10,442 1, 2, 3, 4 KY PERRY, LETCHER AMBURGY, HAZARD #4,

HAZARD TRAIN 0.78 9.32 13,648

10,504 1, 2, 3, 4 KY PERRY, LETCHER AMBURGY, HAZARD #4,

HAZARD TRAIN 0.97 10.16 13,783

10,478 1, 2, 3, 4 KY PERRY, LETCHER AMBURGY, HAZARD #4,

HAZARD TRAIN 0.95 9.79 13,595

10,384 1, 2, 3, 4 KY PERRY, LETCHER AMBURGY, HAZARD #4,

HAZARD TRAIN 1.1 9.65 13,578

10,568 1, 2, 3, 4 KY PERRY, LETCHER AMBURGY, HAZARD #4,

HAZARD TRAIN 0.91 8.91 13,782



### Page 30 of 67 part II, 2 (coal)

### GEORGIA POWER - PLANT BRANCH

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

10,714 1, 2, 3, 4 KY PERRY, LETCHER AMBURGY, HAZARD #4,

HAZARD TRAIN 1.11 8.8 13,695

10,524 1, 2, 3, 4 KY PERRY, LETCHER AMBURGY, HAZARD #4,

HAZARD TRAIN 0.88 9.29 13,641

10,512 1, 2, 3, 4 KY PERRY, LETCHER AMBURGY, HAZARD #4,

HAZARD TRAIN 0.87 10.27 13,515

10,507 1, 2, 3, 4 KY PERRY, LETCHER AMBURGY, HAZARD #4,

HAZARD TRAIN 0.78 9.67 13,530

10,238 1, 2, 3, 4 KY PERRY, LETCHER AMBURGY, HAZARD #4,

HAZARD TRAIN 0.98 9.91 13,519

10,720 1, 2, 3, 4 KY PERRY, LETCHER AMBURGY, HAZARD #4,

HAZARD TRAIN 0.97 9.49 13,554

10,802 1, 2, 3, 4 KY PERRY, LETCHER AMBURGY, HAZARD #4,

HAZARD TRAIN 0.89 9.52 13,631

10,358 1, 2, 3, 4 KY PERRY, LETCHER AMBURGY, HAZARD #4,

HAZARD TRAIN 0.81 10.47 13,492

10,462 1, 2, 3, 4 KY PERRY, LETCHER AMBURGY, HAZARD #4,

HAZARD TRAIN 0.79 10.3 13,484

10,583 1, 2, 3, 4 KY PERRY, LETCHER AMBURGY, HAZARD #4,

HAZARD TRAIN 0.88 10.04 13,497

10,639 1, 2, 3, 4 KY PERRY, LETCHER AMBURGY, HAZARD #4,

HAZARD TRAIN 1.01 9.06 13,595

10,664 1, 2, 3, 4 KY PERRY, LETCHER AMBURGY, HAZARD #4,

HAZARD TRAIN 0.9 8.78 13,705



### Page 31 of 67 part II, 2 (coal)

### GEORGIA POWER - PLANT BRANCH

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

10,666 1, 2, 3, 4 KY PERRY, LETCHER AMBURGY, HAZARD #4,

HAZARD TRAIN 1.06 9.64 13,583

10,394 1, 2, 3, 4 KY PIKE ELKHORN #2, ELKHORN #3 TRAIN 1.49 8.99 13,689

10,450 1, 2, 3, 4 KY PIKE ELKHORN #2, ELKHORN #3 TRAIN 1.48 9.09 13,635

10,397 1, 2, 3, 4 KY PIKE ELKHORN #2, ELKHORN #3 TRAIN 1.48 8.75 13,714

10,158 1, 2, 3, 4 KY PIKE ELKHORN #2, ELKHORN #3 TRAIN 1.58 10.44 13,393

10,603 1, 2, 3, 4 KY PIKE ELKHORN #2, ELKHORN #3 TRAIN 1.63 8.75 13,710

10,502 1, 2, 3, 4 KY PIKE ELKHORN #2, ELKHORN #3 TRAIN 1.35 8.39 13,822

10,486 1, 2, 3, 4 KY PIKE ELKHORN #2, ELKHORN #3 TRAIN 1.37 8.19 13,866

10,424 1, 2, 3, 4 KY PIKE ELKHORN #2, ELKHORN #3 TRAIN 1.41 7.96 13,864

10,566 1, 2, 3, 4 KY PIKE ELKHORN #2, ELKHORN #3 TRAIN 1.47 7.92 13,899

10,387 1, 2, 3, 4 KY PIKE ELKHORN #2, ELKHORN #3 TRAIN 1.47 8.95 13,627

10,036 1, 2, 3, 4 KY PIKE ELKHORN #2, ELKHORN #3 TRAIN 1.5 8.5 13,987



### Page 32 of 67 part II, 2 (coal)

### GEORGIA POWER - PLANT BRANCH

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

10,459 1, 2, 3, 4 KY LETCHER LOW SPLINT, HIGH SPLINT, WINIFREDE, HARLAN TRAIN 0.95 11.64 13,289 10,501 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.29 13.15 12,928 10,426 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.01 13.45 12,868 10,419 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.05 12.95 12,918 10,488 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.08 13.11 12,759 10,324 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.09 13.54 12,781 10,632 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.1 13.24 12,833 10,474 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.05 12.86 12,855 10,429 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1 12.84 12,916 10,429 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.18 13.67 12,847 10,725 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.14 12.47 13,040 10,529 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.22 13.13 12,873 10,474 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.35 12.54 12,969 10,696 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.28 13.37 12,869 10,668 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.26 13.12 12,891 10,500 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.18 13.22 12,875 10,474 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.25 12.28 13,068 10,450 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.2 13.13 12,884 10,387 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.51 13.29 12,823 10,621 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.36 13.09 12,881



### Page 33 of 67 part II, 2 (coal)

### GEORGIA POWER - PLANT BRANCH

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 10,613 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.29 12.51 12,999 10,424 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.29 12.84 12,979 10,596 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.24 12.76 12,914 10,722 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.28 13.24 12,858 10,683 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.3 12.82 12,895 10,656 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.37 12.87 12,920 10,318 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.33 11.51 13,045 10,082 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.05 12.38 13,025 10,608 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.27 12.61 12,934 10,250 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.22 11.95 13,046 10,647 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.41 12.54 12,940 10,476 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.35 12.18 12,968 10,468 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.41 12.14 13,032 10,598 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.32 11.85 13,047 10,401 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.34 12.32 12,975 10,643 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.27 11.62 13,139 10,571 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.32 12.16 13,004 10,661 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.28 11.99 13,031 10,716 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.28 12.07 13,026 10,706 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.31 11.58 13,101 10,583 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.45 11.45 13,162 10,589 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.34 11.57 13,111



### Page 34 of 67 part II, 2 (coal)

### GEORGIA POWER - PLANT BRANCH

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 10,728 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.36 11.6 13,112 10,529 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.26 11.72 13,062 10,533 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.4 11.72 13,069 10,552 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.23 11.51 13,159 10,773 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.23 11.72 13,065 10,653 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.33 12.02 13,012 10,596 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.36 10.77 13,256 10,497 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.35 11.76 13,068 10,552 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.3 11.67 13,112 10,672 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.31 11.36 13,140 10,749 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.41 12.67 12,919 10,715 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.31 11.81 13,028 10,577 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.35 11.42 13,106 10,549 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.14 11.2 13,124 10,024 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.4 11.33 13,107 10,667 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.39 12.71 12,923 10,581 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.48 11.55 13,094 10,651 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.29 12.23 13,039 10,664 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.47 11.57 13,112 10,494 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.39 11.84 13,087 10,651 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.39 12.3 13,051 10,659 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.33 11.71 13,078



### Page 35 of 67 part II, 2 (coal)

### GEORGIA POWER - PLANT BRANCH

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 10,868 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.24 11.54 13,109 10,710 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.2 12.42 12,959 10,780 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.23 12.53 12,972 10,670 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.26 12.53 12,976 10,717 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.26 12.21 12,984 10,667 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.25 12.11 13,067 10,577 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.27 13.12 12,870 10,567 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.25 13.07 12,839 10,694 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.27 11.81 13,078 10,567 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.34 12.24 13,020 10,663 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.24 13.68 12,796 10,536 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.32 13.22 12,860 10,713 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.26 13.02 12,879 10,550 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.06 11.41 13,129

10,070 1, 2, 3, 4 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1.03 10.71 13,534

10,107 1, 2, 3, 4 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1.01 9.61 13,694

10,073 1, 2, 3, 4 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1 9.78 13,599



### Page 36 of 67 part II, 2 (coal)

### GEORGIA POWER - PLANT BRANCH

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

10,442 1, 2, 3, 4 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1.04 9.87 13,607

10,342 1, 2, 3, 4 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1.04 9.5 13,731

10,717 1, 2, 3, 4 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1.02 9.91 13,552

9,910 1, 2, 3, 4 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.97 9.33 13,760

10,295 1, 2, 3, 4 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1.06 9.68 13,741

10,358 1, 2, 3, 4 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.96 10.47 13,549 9,795 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.69 10.42 13,473 9,820 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.69 10.32 13,495 10,599 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.68 13.07 13,045 9,994 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.14 9.23 13,617 9,760 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.15 9.22 13,610 9,704 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.37 9.45 13,569



### Page 37 of 67 part II, 2 (coal)

### GEORGIA POWER - PLANT BRANCH

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 9,888 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.32 8.2 13,770 10,042 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.2 8.96 13,669 10,008 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.36 8.29 13,717 10,079 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.71 9 13,587 10,577 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.68 8.67 13,621 10,537 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.38 9.89 13,601 10,089 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.72 11.37 13,330 10,173 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1 11 13,376 10,288 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.73 10.06 13,562 10,130 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.72 9.84 13,612 10,360 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.75 11.64 13,285 10,407 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.77 10.94 13,417 10,151 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.72 12.19 13,162 10,411 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.97 10.78 13,409 10,357 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.76 11.67 13,245 10,308 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.81 11.61 13,496 10,512 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.81 10.61 13,439 10,289 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.75 10.5 13,493 10,466 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.94 11.02 13,384 10,472 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.94 11.94 13,246 10,576 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.04 9.51 13,650 10,446 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.87 9.17 13,667



### Page 38 of 67 part II, 2 (coal)

### GEORGIA POWER - PLANT BRANCH

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 10,568 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.86 10.82 13,368 10,327 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.87 10.81 13,402 9,969 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.83 10.29 13,500 10,673 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.07 9.21 13,665 10,675 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.89 10.88 13,412 10,658 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.04 9.89 13,523 10,741 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.03 9.44 13,643 10,502 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.04 10.83 13,423 10,610 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.79 9.24 13,676 10,645 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.82 10.13 13,485 10,560 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1 10.32 13,449 10,439 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.1 9.57 13,619 10,614 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.17 9.82 13,593 10,604 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.83 11.33 13,303 10,771 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.1 9.75 13,575 10,464 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.9 10.26 13,388 10,698 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.91 10.09 13,498 10,410 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.86 11.23 13,259 10,367 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.9 10.35 13,465 10,606 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.25 10.31 13,515 10,510 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.94 11.07 13,309 10,793 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.84 10.58 13,413



### Page 39 of 67 part II, 2 (coal)

### GEORGIA POWER - PLANT BRANCH

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 10,425 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.86 10.36 13,460 10,674 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.96 10.57 13,427 10,583 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.86 10.53 13,442 10,438 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.86 11.06 13,378 10,429 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.83 10.29 13,456 10,622 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.09 10.08 13,535 10,624 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.83 10.38 13,475 10,657 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1 9.56 13,542 10,526 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.11 8.36 13,810 10,663 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.04 9.64 13,623 10,613 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1 9.12 13,685 10,429 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.83 10.6 13,421 10,423 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.48 8.75 13,650 10,350 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.48 9.11 13,698 10,146 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.52 9.45 13,596 9,945 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.62 9.04 13,653 10,502 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.65 9.37 13,584 10,584 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.42 8.49 13,737 10,844 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.51 8.52 13,799 10,517 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.86 8.39 13,815 10,626 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.28 9.34 13,669 10,667 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.35 8.87 13,751



### Page 40 of 67 part II, 2 (coal)

### GEORGIA POWER - PLANT BRANCH

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 10,567 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.44 7.82 13,879 10,429 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.46 8.33 13,845 10,264 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.46 8.35 13,769 10,563 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.52 7.81 13,846 10,510 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.38 8.67 13,724 10,549 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.49 8.31 13,769 10,500 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.48 9.52 13,577 10,505 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.44 8.42 13,782 1,021 1, 2, 3, 4 KY MARTIN MULTIPLE TRAIN 1.92 13.37 12,800

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 41 of 67 part II, 2 (coal)

### GEORGIA POWER - PLANT BRANCH

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):

State/Country County42 

### Coal seam43 7,492 1, 2 Georgia/USA N/A N/A Truck 7,491 3, 4 Georgia/USA N/A N/A Truck 7,515 1, 2 Georgia/USA N/A N/A Truck 7,515 3, 4 Georgia/USA N/A N/A Truck 7,553 1, 2 Georgia/USA N/A N/A Truck 7,556 3, 4 Georgia/USA N/A N/A Truck 7,523 3, 4 Georgia/USA N/A N/A Truck 15,017 1, 2 Georgia/USA N/A N/A Truck 15,010 3, 4 Georgia/USA N/A N/A Truck 15,047 3, 4 Georgia/USA N/A N/A Truck 15,010 1, 2 Georgia/USA N/A N/A Truck 7,507 3, 4 Georgia/USA N/A N/A Truck 22,589 1, 2 Georgia/USA N/A N/A Truck 14,981 1, 2 Georgia/USA N/A N/A Truck 14,997 1, 2 Georgia/USA N/A N/A Truck 7,498 3, 4 Georgia/USA N/A N/A Truck 7,488 1, 2 Georgia/USA N/A N/A Truck 7,485 3, 4 Georgia/USA N/A N/A Truck 7,503 1, 2 Georgia/USA N/A N/A Truck 22,432 1, 2 Georgia/USA N/A N/A Truck 7,470 3, 4 Georgia/USA N/A N/A Truck 14,914 1, 2 Georgia/USA N/A N/A Truck 14,929 3, 4 Georgia/USA N/A N/A Truck 29,890 1, 2 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 42 of 67 part II, 2 (oil)

### GEORGIA POWER - PLANT BRANCH

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):

State/Country County42 

### Coal seam43 

### FUEL OIL SHIPMENTS Amount received, gallons40 

### ID # of boiler(s)

firing fuel41 

### Fuel source Fuel shipment method 7,479 1, 2 Georgia/USA N/A N/A Truck 7,449 3, 4 Georgia/USA N/A N/A Truck 14,904 1, 2 Georgia/USA N/A N/A Truck 14,899 3, 4 Georgia/USA N/A N/A Truck 7,436 1, 2 Georgia/USA N/A N/A Truck 14,882 3, 4 Georgia/USA N/A N/A Truck 14,867 1, 2 Georgia/USA N/A N/A Truck 7,421 3, 4 Georgia/USA N/A N/A Truck 7,424 1, 2 Georgia/USA N/A N/A Truck 14,868 1, 2 Georgia/USA N/A N/A Truck 7,426 3, 4 Georgia/USA N/A N/A Truck 7,455 1, 2 Georgia/USA N/A N/A Truck 7,420 3, 4 Georgia/USA N/A N/A Truck 7,447 1, 2 Georgia/USA N/A N/A Truck 7,416 3, 4 Georgia/USA N/A N/A Truck 14,839 1, 2 Georgia/USA N/A N/A Truck 14,828 1, 2 Georgia/USA N/A N/A Truck 7,433 3, 4 Georgia/USA N/A N/A Truck 14,874 1, 2 Georgia/USA N/A N/A Truck 44,746 3, 4 Georgia/USA N/A N/A Truck 7,485 1, 2 Georgia/USA N/A N/A Truck 14,882 1, 2 Georgia/USA N/A N/A Truck 7,562 3, 4 Georgia/USA N/A N/A Truck 7,544 1, 2 Georgia/USA N/A N/A Truck



### Page 43 of 67 part II, 2 (oil)

### GEORGIA POWER - PLANT BRANCH

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):

State/Country County42 

### Coal seam43 

### FUEL OIL SHIPMENTS Amount received, gallons40 

### ID # of boiler(s)

firing fuel41 

### Fuel source Fuel shipment method 7,518 3, 4 Georgia/USA N/A N/A Truck 45,399 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 44 of 67 part II, 2 (oil)

### GEORGIA POWER - PLANT BRANCH 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 Cadmium Chromium 

### Cobalt Lead Manganese 

### Selenium

09-201 10,500 1.24 13.67 12,758 0.142 1166 109 13.4 1.3 15.8 2.9 0.07 18.6 7.2 10.0 53.4 3.0KY Floyd, Knott Hazard 8, Elkhorn #1, Elkhorn #2, Elkhorn #3, Whitesburg, Hazard #4 Train

09-206 11,001 1.58 12.5 13,153 0.117 1252 87 16.0 1.8 23.0 3.4 0.14 17.4 7.6 11.5 32.9 2.0KY Harlan, Leslie Hazard 4,

Hazard 4R, Hazard 8, Hazard 7 Train

09-207 11,309 1.32 13.23 12,872 0.089 588 97 14.3 1.2 9.1 2.3 0.03 21.0 8.1 9.2 15.1 3.8KY Perry, Breathitt Hazard #8,

Hazard #7 Train

09-208 22,300 1.01 10.53 13,482 0.056 1301 71 12.3 1.1 6.8 2.5 0.04 14.6 6.9 8.8 31.4 2.8KY Perry, Letcher Hazard 4,

Hazard 4R, Hazard 8, Hazard 7 Train

09-404 11,324 0.96 10.64 13,265 ND 95 64 12.0 1.2 7.2 2.0 0.05 16.7 7.0 8.4 21.8 2.8KY Harlan Highsplint, Winifrede, Low splint, Lower Harlan, D seam, Kellioki, Imbodden, Owl Train

09-406 11,090 0.85 11.16 13,267 ND 1278 52 12.8 <1 6.8 2.7 ND 14.7 7.4 6.2 12.5 3.2KY Perry Hazard #4, Amburgey, Hazard #8 Train

09-407 10,438 1.82 9.83 12,383 0.072 115 79 11.3 <1 16.6 1.6 0.10 16.7 4.8 8.9 50.9 2.9KY Bell Garmeda Seam, Buckeye Springs Seam, Stray Seam Train

09-209 11,230 1.51 8.93 13,727 0.081 1619 62 14.9 1.2 11.6 2.7 0.08 11.9 7.8 7.1 20.7 3.4KY Pike Elkhorn #3, Millard Train

09-222 11,142 0.89 8.72 13,685 ND ND 59 10.3 1.0 3.8 3.1 0.02 11.6 6.1 7.8 17.5 2.3kY Perry, Letcher Hazard 4,

Hazard 4R, Hazard 8, Hazard 7 Train



### Fuel Shipment Method Nickel, ppm Other trace metal HAP, ppm45 Total amount of fuel represented by sample, tons 

### Coal Seam Sample ID # State/ Country County Total Sulfur, % Ash

Content, % Heating Value, Btu/lb Mercury,

ppm Chlorine,

ppm Fluorine,

ppm

Page 45 of 67 part II, 3

### GEORGIA POWER - PLANT BRANCH 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 Cadmium Chromium 

### Cobalt Lead Manganese 

### Selenium Fuel Shipment Method Nickel, ppm Other trace metal HAP, ppm45 Total amount of fuel represented by sample, tons 

### Coal Seam Sample ID # State/ Country County Total Sulfur, % Ash

Content, % Heating Value, Btu/lb Mercury,

ppm Chlorine,

ppm Fluorine,

ppm

09-420 11,327 1.33 12.34 12,926 0.100 637 93 14.5 1.1 10.4 2.6 ND 20.6 8.9 7.6 16.6 3.6KY Perry Hazard 5A, Hazard#7, Hazard #8, Hazard #9 Train

09-422 12,662 0.77 10.97 13,368 ND 1373 79 13.0 <1 6.2 2.4 ND 16.2 7.8 6.3 12.4 3.2KY Perry Hazard #4, Amburgey, Hazard #8 Train

09-418 12,392 1.12 11.36 13,390 ND 111 89 13.9 1.3 9.7 2.1 ND 17.3 8.0 8.8 26.4 2.4KY Harlan Highsplint, Winifrede, Low splint, Lower Harlan, D seam, Kellioki, Imbodden, Owl Train

09-419 9,865 1.33 9.59 13,450 0.080 102 149 18.2 1.3 18.7 1.8 0.12 17.6 7.5 8.3 43.6 2.7KY Bell Garmeda Seam, Buckeye Springs Seam, Stray Seam Train

09-214 10,500 1.41 12.9 12,896 0.082 1360 102 11.9 1.2 19.3 2.7 0.06 16.5 7.1 8.5 32.2 3.0KY Floyd, Knott Hazard 8, Elkhorn #1, Elkhorn #2, Elkhorn #3, Whitesburg, Hazard #4 Train

09-218 11,336 1.44 7.97 13,885 0.077 ND 54 13.4 1.2 11.1 2.5 0.12 11.7 7.0 6.9 20.9 3.4KY Pike Elkhorn #3, Millard Train

09-224 11,255 0.89 10.78 13,329 ND 1324 71 10.3 1.0 3.8 3.1 0.02 11.6 6.1 7.8 17.5 2.3KY Perry Amburgy, Hazard 8, Hazard 7, Hazard 5A Train

09-225 10,998 1.47 8.13 13,831 ND 1669 56 14.2 1.3 11.2 2.2 0.06 12.3 7.7 6.2 20.8 3.4KY Pike Elkhorn #3, Millard Train

09-423 11,403 1.34 11.99 13,000 0.071 609 87 16.0 <1 11.6 2.9 0.05 21.1 10.7 10.8 18.5 3.7KY Perry Hazard 5A, Hazard#7, Hazard #8, Hazard #9 Train



### Page 46 of 67 part II, 3

### GEORGIA POWER - PLANT BRANCH 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 Cadmium Chromium 

### Cobalt Lead Manganese 

### Selenium Fuel Shipment Method Nickel, ppm Other trace metal HAP, ppm45 Total amount of fuel represented by sample, tons 

### Coal Seam Sample ID # State/ Country County Total Sulfur, % Ash

Content, % Heating Value, Btu/lb Mercury,

ppm Chlorine,

ppm Fluorine,

ppm

09-424 11,170 1.06 10.8 13,433 ND 111 84 18.0 1.0 6.7 2.5 0.07 19.6 10.5 12.0 30.3 2.5KY Harlan Highsplint, Winifrede, Low splint, Lower Harlan, D seam, Kellioki, Imbodden, Owl Train

09-432 12,905 1.24 10.22 13,490 ND 1262 66 12.4 <1 9.4 2.4 0.04 15.4 7.0 10.3 23.0 2.4KY Perry Hazard #4, Alma, Hazard #8, Hazard #9, Hazard #10 Train

09-435 12,885 1.38 8.52 13,711 0.060 109 120 11.5 <1 14.2 1.4 0.11 14.3 5.6 7.1 0.1 2.8KY Bell Garmeda Seam, Buckeye Springs Seam, Stray Seam Train

09-235 10,772 1.22 13.43 12,920 ND 1202 112 11.9 <1 12.8 1.8 0.07 16.6 6.9 7.9 32.6 2.9KY Floyd, Knott Hazard 8, Elkhorn #1, Elkhorn #2, Elkhorn #3, Whitesburg, Hazard #4 Train

09-237 11,038 1.02 10.17 13,539 ND 1333 67 14.1 1.0 7.1 2.8 ND 16.7 9.3 7.5 13.6 3.3KY Perry Amburgy, Hazard 8, Hazard 7, Hazard 5A Train

09-441 11,536 1.58 11.78 13,077 0.092 697 74 14.1 <1 8.4 2.3 0.03 20.1 7.1 8.3 10.8 4.0KY Perry Hazard 5A, Hazard#7, Hazard #8, Hazard #9 Train

09-240 12,908 1.01 9.46 13,576 ND 1501 133 11.7 1.0 5.7 2.5 0.05 14.0 7.0 8.2 19.5 2.5KY Perry, Letcher Hazard 4,

Hazard 5A, Alma Train

09-442 12,855 1.44 9.79 13,612 0.058 1437 79 13.7 1.7 21.0 3.6 0.14 14.1 7.2 10.4 29.1 1.9KY Harlan, Bell Hazard #4, Hazard #4 rider, Hazard #7, Hazard #8, Hazard #9 Train



### Page 47 of 67 part II, 3

### GEORGIA POWER - PLANT BRANCH 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 Cadmium Chromium 

### Cobalt Lead Manganese 

### Selenium Fuel Shipment Method Nickel, ppm Other trace metal HAP, ppm45 Total amount of fuel represented by sample, tons 

### Coal Seam Sample ID # State/ Country County Total Sulfur, % Ash

Content, % Heating Value, Btu/lb Mercury,

ppm Chlorine,

ppm Fluorine,

ppm

09-443 12,664 0.9 10.3 13,598 ND 105 60 12.4 1.0 4.7 2.1 0.03 16.7 7.9 9.1 23.4 2.8KY Harlan Highsplint, Winifrede, Low splint, Lower Harlan, D seam, Kellioki, Imbodden, Owl Train

09-445 12,890 1.53 8.45 13,778 0.076 61 56 11.1 <1 12.5 1.4 0.08 14.3 5.8 7.6 37.5 2.8KY Bell Garmeda Seam, Buckeye Springs Seam, Stray Seam 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.



### Page 48 of 67 part II, 3

### GEORGIA POWER - PLANT BRANCH

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)

Page 49 of 67 part II, 4-6

### GEORGIA POWER - PLANT BRANCH

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

Moisture 

### Volatiles Ash Fixed Carbon Carbon Hydrogen 

### Nitrogen Total Sulfur Oxygen Barium Copper Magnesium 

### Sodium Vanadium 

### Zinc Al2O3 Fe2O3 

### CaO MgO P2O5 K2O SiO2 Na2O SO3 TiO2
09-201 6.97 34.57 13.67 51.75 74.26 4.65 1.37 1.24 4.8 225 21.2 0.118 0.037 32.9 17.1 25.8 10 1.89 1.32 ND 3.11 50.2 0.389 1.47 1.47 09-206 6.27 36.41 12.5 51.09 74.39 4.94 1.59 1.58 5 132 25.4 0.083 0.041 42.5 32.7 24.7 12.4 1.66 1.04 ND 2.35 48.4 0.494 0.938 1.36 09-207 5.78 35.9 13.23 50.88 72.61 4.76 1.45 1.32 6.64 163 20.4 0.063 0.016 37.5 13.1 28.9 7.92 1.14 0.75 ND 2.13 52.5 0.214 0.524 1.4 09-208 6.52 36.53 10.53 52.94 76.33 4.92 1.65 1.01 5.56 112 19.3 0.073 0.032 28.2 19.2 26.3 8.31 1.78 1.13 ND 2.61 52.8 0.512 1.32 1.34 09-404 6.37 34.25 10.64 55.11 77.44 4.83 1.51 0.96 4.6 122 20.9 0.071 0.034 33.5 15.7 27.4 7.05 1.59 0.955 ND 2.68 53.7 0.422 0.878 1.43 09-406 4.82 34.97 11.16 53.88 76.49 4.79 1.56 0.85 5.15 112 17.4 0.055 0.028 26.1 9.6 26.3 5.4 1.25 0.785 ND 2.23 56 0.37 0.633 1.45 09-407 6.02 36.85 9.83 53.32 75.27 4.88 1.77 1.82 6.43 102 20.6 0.069 0.016 46.6 20.6 24.6 16.7 3.07 0.895 1.68 ND 44.6 0.203 0.636 1.34 09-209 6.45 37.34 8.93 53.73 76.98 5.08 1.24 1.51 6.26 143 23.5 0.057 0.030 33.3 17.1 25.3 14.4 2.6 1.09 ND 2.32 43.8 0.545 2.03 1.31 09-222 6.43 36.45 8.72 54.83 74.25 4.95 1.82 0.89 9.37 92 17.0 0.045 0.035 26.1 14.9 27.2 6.94 1.34 0.819 ND 1.93 49.7 0.564 0.835 1.37 09-420 7.31 36.44 12.34 51.22 69.95 4.65 1.47 1.33 10.26 154 18.1 0.063 0.016 34.5 16.5 25.1 9.16 1.48 0.916 ND 2.08 50.5 0.216 0.803 1.36 09-422 4.89 35.09 10.97 53.94 73.33 4.8 1.57 0.77 8.56 102 15.3 0.056 0.024 26.1 9.5 27.4 5.1 1.23 0.903 ND 2.11 54 0.391 0.639 1.52 09-418 5.99 34.06 11.36 54.58 75.53 4.88 1.48 1.12 5.63 102 20.7 0.075 0.037 35.9 16.4 26.4 8.43 1.58 1.02 ND 2.53 49.3 0.532 1.15 1.52 09-419 6.23 36.36 9.59 54.05 74.33 4.91 1.81 1.33 8.04 82 20.6 0.069 0.015 43.3 26.4 25.7 13.9 2.52 1.18 1.26 2.39 45.3 0.29 0.809 1.37 09-214 5.92 34.69 12.9 52.41 74.42 4.82 1.42 1.41 5.02 174 19.9 0.096 0.031 30.2 13.4 23 10.9 1.59 1.19 ND 2.76 48.6 0.354 1.28 1.21 09-218 6.69 36.94 7.97 55.1 77.68 5.02 1.53 1.44 6.36 112 23.8 0.053 0.030 30.7 14.4 26.2 12.7 2.48 1.04 ND 2.47 47.5 0.559 2.06 1.14 09-224 5.12 35.23 10.78 53.99 74.91 4.9 1.74 0.89 6.77 92 17.0 0.045 0.035 26.1 14.9 28.3 6.71 1.62 0.962 ND 2.09 61.7 0.49 1.13 1.42 09-225 5.15 37.79 8.13 54.09 77.75 5.12 1.77 1.47 5.76 122 22.8 0.054 0.031 31.1 16.2 24.8 15.1 2.84 1.07 ND 2.24 49 0.585 2.34 1.13 09-423 6.5 35.5 11.99 52.51 72.73 4.6 1.55 1.34 7.78 143 24.2 0.055 0.014 38.3 15.3 29.7 7.94 1.24 0.773 ND 1.99 55.4 0.211 0.884 1.53 09-424 6.46 34.53 10.8 54.66 75.06 4.72 1.6 1.06 6.76 81 27.0 0.062 0.030 40.6 17.6 28.3 5.86 1.56 0.979 ND 2.37 54 0.453 1.28 1.54 09-432 6.09 35 10.22 54.78 75.13 4.76 1.61 1.24 7.05 92 19.9 0.052 0.036 30.3 17.3 24.4 8.4 1.27 0.791 ND 1.98 52.8 0.469 0.888 1.47 09-435 4.86 35.82 8.52 55.65 76.05 4.94 1.87 1.38 7.23 193 18.6 0.058 0.016 37.1 16.9 26 13.8 2.7 1.03 1.35 2.15 44.5 0.314 1.28 1.28 09-235 5.48 34.35 13.43 52.22 71.09 4.56 1.5 1.22 8.2 194 18.8 0.114 0.040 28.5 19.2 26.2 9.29 1.57 1.42 ND 3.54 50.7 0.464 1.46 1.28 09-237 5.52 34.93 10.17 54.89 74.91 4.79 1.59 1.02 7.52 81 18.4 0.053 0.024 30.3 19.6 30.7 4.89 1.22 0.825 ND 1.77 54.7 0.347 0.911 1.4 09-441 7.66 36.36 11.78 51.85 72.24 4.72 1.44 1.58 8.25 103 17.2 0.054 0.012 32.6 12.2 30.1 9.25 1 0.763 ND 1.97 53.7 0.229 0.528 1.63 09-240 7.39 35.3 9.46 55.23 75.99 4.79 1.72 1.01 7.04 92 16.2 0.051 0.032 26.4 15.8 25.5 7.8 1.54 0.916 ND 2.23 54.7 0.532 0.795 1.51 09-442 6.98 36.33 9.79 53.88 75.62 4.89 1.71 1.44 6.55 92 22.8 0.052 0.035 36.1 30.4 24.5 10.5 1.73 0.902 ND 2.2 57.8 0.553 0.979 1.53 09-443 6.03 34.1 10.3 55.59 76.39 4.73 1.53 0.9 6.14 81 19.5 0.064 0.033 32.1 14.7 25.8 6 1.92 0.922 ND 2.28 55.1 0.463 1.3 1.54 09-445 4.07 36.77 8.45 54.77 76.74 4.91 1.83 1.53 6.55 193 18.2 0.058 0.016 39.9 16.8 24.5 14.5 3.11 1.02 1.45 2.08 46.9 0.308 0.971 1.35 Sample ID # Proximate Analyses, % by wt Ultimate Analyses, % by wt Ash Mineralogy, % by wt Other Trace Metals, ppm, dry basis

Page 50 of 67 part II, 7GEORGIA POWER - PLANT BRANCH

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 1 Unit 1&2 Particulate Emissions Test (June 15, 2005) Report 2 Unit 3&4 Particulate Emissions Test (May 24, 2006) Report 3 Unit 1&2 Particulate Emissions Test (May 24, 2007) Report 4 Unit 3&4 Particulate Emissions Test (May 22, 2008) Report 5 Unit 1&2 Particulate Emissions Test (June 11, 2009) Report 6 Unit 1 Boiler Optimization (September 10, 2007 to November 1, 2007) Report 7 Unit 2 Boiler Optimization (February 27, 2008) Report 8 Unit 3 Boiler Optimization (November 13, 2007) Report 9 Unit 4 Boiler Optimization (May 7, 2008 to May 8, 2008)

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:6/15/2005 Type:stack Constituents:PM Report 2 Date:5/24/2006 Type:stack Constituents:PM Report 3 Date:5/24/2007 Type:stack Constituents:PM Report 4 Date:5/22/2008 Type:stack Constituents:PM Report 5 Date:6/11/2009 Type:stack Constituents:PM Report 6 Date:9/10/2007 - 11/1/2007 Type:duct Constituents:CO Report 7 Date:2/27/2008 Type:duct Constituents:CO Report 8 Date:11/13/2007 Type:duct Constituents:CO Report 9 Date:5/7/2008-5/8/2008 Type:duct Constituents:CO

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). Reports 6, 7, 8, 9 reflect testing at the economizer outlet (upstream of all post-combustion control devices). Note that there are no control devices downstream designed to reduce CO.

Page 51 of 67 part II, 8GEORGIA POWER - PLANT BRANCH

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

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.

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.

Boiler ID Type NOx control SO2 control PM control Other control 1 cell burner (1) low NOx burner (4) cold-side electrostatic precipitator 2 dry bottom wall-fired (1) low NOx burner (4) cold-side electrostatic precipitator 3 cell burner (1) low NOx burner (3) cold-side electrostatic precipitator 4 cell burner (1) low NOx burner (3) cold-side electrostatic precipitator
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 52 of 67 part II, 8

### GEORGIA POWER - PLANT BRANCH

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 available for the following periods of time:

Unit 3&4 (common stack/liner): 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 53 of 67 part II, 9-11

### GEORGIA POWER - PLANT BRANCH 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/HCN Metal HAP50 

### Hg51 

### CO Other organics (specify)

1&2 6/15/2005 See Attachment 1 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable 3&4 5/24/2006 See Attachment 2 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable 1&2 5/24/2007 See Attachment 3 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable 3&4 5/22/2008 See Attachment 4 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable 1&2 6/11/2009 See Attachment 5 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable 1 9/10/2007 - 11/1/2007 Not applicable Not applicable Not applicable Not applicable Not applicable See Attachment 6 Not applicable 2 2/27/2008 Not applicable Not applicable Not applicable Not applicable Not applicable See Attachment 7 Not applicable 3 11/13/2007 Not applicable Not applicable Not applicable Not applicable Not applicable See Attachment 8 Not applicable 4 5/7/2008-5/8/2008 Not applicable Not applicable Not applicable Not applicable Not applicable See Attachment 9 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).
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. 

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



### Page 54 of 67 part II, 12

## ATTACHMENT 1 - Branch Report 1 Test Results

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

Run 1 Run 2 Run 3 Test Date 6/15/2005 6/15/2005 6/15/2005 Run Start Time 8:30 10:11 11:55 Run End Time 9:45 11:30 13:12 Meter Volume (dacf), Vm: 36.279 36.556 36.252 Sqrt Delta P ("wc): 1.25 1.25 1.25 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.65 29.65 29.65 Delta H ("wc): 1.0 1.0 1.0 Volume in Impingers (mls), VIc: 64.1 64.5 64.8 Static Pressure ("wc), Pg: -3.10 -3.20 -3.00 Stack Pressure ("Hg), Ps: 29.42 29.41 29.43 Stack Temperature (F), Ts: 289 290 295 Meter Coefficient (no units), Y: 0.983 0.983 0.983 Pitot Coefficient (no units) Cp: 0.840 0.840 0.840 Meter OutletTemperature (F), Tm: 94 99 101 Stack Diameter (inches): 270 270 270 Area Stack (sq. ft.), As: 397.61 397.61 397.61 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): 12.0 12.1 12.2 Percent O2 (% dry

volume): 6.8 6.6 6.8 Percent (N2 + CO) (% dry volume): 81.2 81.3 81.0 Particulate Collected (mg), Mn: 24.5 20.6 21.4

Molec. Wt. Dry

(lb/lb-mole), Md: 30.192 30.200 30.220 Volume Water (scf), Vwstd 3.017 3.036 3.050 Meter Volume (dscf), Vmstd: 33.728 33.719 33.313 Wet Fraction (v/v), Bws: 0.082 0.083 0.084 Molec. Wt. Wet (lb/lb-mole), Ms: 29.191 29.192 29.195 Stack Gas Sampled (acf), Vma: 52.990 53.118 52.845 Averages Stack Gas Velocity

(fps), Vs: 84.07 83.97 84.42 84.15 Volumetric Flowrate (dscfm), Qs: 1,276,562 1,271,619 1,269,619 1,272,600 Volumetric Flowrate (acfm), Qa: 2,005,593 2,003,178 2,014,051 2,007,607 Grainloading (gr/dscf), cs: 0.0112 0.0094 0.0099 0.01 Emission Rate (lb/hour), E: 122.89 102.75 107.67 111.10 Percent Isokinetic Sampling (%), I: 103.70 104.08 102.98 103.59
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 5283.57 5337.76 5254.83 5292.05 

### Particulate Emission Results Summary Plant Branch, Units 1&2

Page 55 of 67 Att. 1

## ATTACHMENT 1 - Branch Report 1 Test Results

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

Run 1 Run 2 Run 3 

### Particulate Emission Results Summary Plant Branch, Units 1&2

Emission Rate (lbs/mmBtu), E: 0.02 0.02 0.02 0.02 Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.240 Average Unit 1 Gross Load (MW) 266 266 267 266 Average Unit 2 Gross Load (MW) 332 332 332 332 Average Sum Gross Load (MW) 598 598 598 598



### Page 56 of 67 Att. 1

## ATTACHMENT 2 - Branch Report 2 Test Results

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

Run 1 Run 2 Run 3 Test Date 5/24/2006 5/24/2006 5/24/2006 Run Start Time 10:30 11:55 13:20 Run End Time 11:38 13:03 14:28 Meter Volume (dacf), Vm: 37.849 39.055 40.088 Sqrt Delta P ("wc): 1.35 1.36 1.37 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.45 29.42 29.42 Delta H ("wc): 1.2 1.2 1.2 Volume in Impingers (mls), VIc: 48.5 50.1 50.2 Static Pressure ("wc), Pg: -3.00 -3.10 -3.00 Stack Pressure ("Hg), Ps: 29.23 29.19 29.20 Stack Temperature (F), Ts: 274 276 277 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: 97 102 104 Stack Diameter (inches): 348 348 348 Area Stack (sq. ft.), As: 660.52 660.52 660.52 Nozzle Diameter (inches), dp: 0.178 0.178 0.178 Area Nozzle (sq. ft.), An: 0.000172 0.000172 0.000172 Percent CO2 (% dry

volume): 11.9 11.9 12.0 Percent O2 (% dry

volume): 7.3 7.4 7.4 Percent (N2 + CO) (% dry volume): 80.9 80.7 80.7 Particulate Collected (mg), Mn: 98.7 82.1 82.3

Molec. Wt. Dry

(lb/lb-mole), Md: 30.189 30.204 30.209 Volume Water (scf), Vwstd 2.283 2.358 2.363 Meter Volume (dscf), Vmstd: 34.993 35.768 36.572 Wet Fraction (v/v), Bws: 0.061 0.062 0.061 Molec. Wt. Wet (lb/lb-mole), Ms: 29.443 29.449 29.468 Stack Gas Sampled (acf), Vma: 53.008 54.464 55.707 Averages Stack Gas Velocity

(fps), Vs: 89.50 90.14 91.00 90 Volumetric Flowrate (dscfm), Qs: 2,341,684 2,346,079 2,367,751 2,351,838 Volumetric Flowrate (acfm), Qa: 3,547,176 3,572,427 3,606,574 3,575,392 Grainloading (gr/dscf), cs: 0.0435 0.0354 0.0347 0.04 Emission Rate (lb/hour), E: 873.89 712.31 704.45 763.5 Percent Isokinetic Sampling (%), I: 95.53 97.46 98.74 97.24
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 9371.23 9319.95 9406.04 9365.74 

### Particulate Emission Results Summary Plant Branch, Units 3&4

Page 57 of 67 Att. 2

## ATTACHMENT 2 - Branch Report 2 Test Results

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

Run 1 Run 2 Run 3 

### Particulate Emission Results Summary Plant Branch, Units 3&4

Emission Rate (lbs/mmBtu), E: 0.09 0.08 0.07 0.08 Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.240 Average Unit 3 Gross Load (MW) 517 517 516 517 Average Unit 4 Gross Load (MW) 517 517 516 517 Average Sum Gross Load (MW) 1033 1033 1033 1033



### Page 58 of 67 Att. 2

## ATTACHMENT 3 - Branch Report 3 Test Results

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

Run 1 Run 2 Run 3 Test Date 5/24/2007 5/24/2007 5/24/2007 Run Start Time 8:20 9:50 11:10 Run End Time 9:35 11:00 12:15 Meter Volume (dacf), Vm: 34.053 35.565 35.903 Sqrt Delta P ("wc): 1.26 1.27 1.28 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.70 29.70 29.70 Delta H ("wc): 1.0 1.0 1.0 Volume in Impingers (mls), VIc: 51.2 52.8 54.3 Static Pressure ("wc), Pg: -2.90 -3.00 -2.90 Stack Pressure ("Hg), Ps: 29.49 29.48 29.49 Stack Temperature (F), Ts: 271 275 277 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: 86 92 95 Stack Diameter (inches): 270 270 270 Area Stack (sq. ft.), As: 397.61 397.61 397.61 Nozzle Diameter (inches), dp: 0.178 0.178 0.178 Area Nozzle (sq. ft.), An: 0.000172 0.000172 0.000172 Percent CO2 (% dry

volume): 12.6 12.5 12.6 Percent O2 (% dry

volume): 6.4 6.6 6.5 Percent (N2 + CO) (% dry volume): 80.9 80.9 80.9 Particulate Collected (mg), Mn: 28.5 27.8 28.0

Molec. Wt. Dry

(lb/lb-mole), Md: 30.279 30.259 30.276 Volume Water (scf), Vwstd 2.410 2.485 2.556 Meter Volume (dscf), Vmstd: 32.325 33.427 33.530 Wet Fraction (v/v), Bws: 0.069 0.069 0.071 Molec. Wt. Wet (lb/lb-mole), Ms: 29.427 29.410 29.407 Stack Gas Sampled (acf), Vma: 48.773 50.756 51.122 Averages Stack Gas Velocity

(fps), Vs: 83.29 84.24 84.57 84.15 Volumetric Flowrate (dscfm), Qs: 1,316,837 1,323,527 1,323,208 1,272,600 Volumetric Flowrate (acfm), Qa: 1,986,921 2,009,659 2,017,429 2,007,607 Grainloading (gr/dscf), cs: 0.0136 0.0128 0.0129 0.01 Emission Rate (lb/hour), E: 153.46 145.75 146.23 111.10 Percent Isokinetic Sampling (%), I: 94.46 97.19 97.51 103.59
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 5591.99 5555.65 5593.15 5292.05 

### Particulate Emission Results Summary Plant Branch, Units 1&2

Page 59 of 67 Att. 3

## ATTACHMENT 3 - Branch Report 3 Test Results

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

Run 1 Run 2 Run 3 

### Particulate Emission Results Summary Plant Branch, Units 1&2

Emission Rate (lbs/mmBtu), E: 0.03 0.03 0.03 0.03 Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.240 Average Unit 1 Gross Load (MW) 267 267 267 267 Average Unit 2 Gross Load (MW) 331 331 331 331 Average Sum Gross Load (MW) 598 598 598 598



### Page 60 of 67 Att. 3

## ATTACHMENT 4 - Branch Report 4 Test Results

Performed by: TRC Environmental Corporation, Raleigh, North Carolina

RUN NUMBER U3/4-M17-1 U3/4-M17-2 U3/4-M17-3 RUN DATE 5/22/2008 5/22/2008 5/22/2008 AVERAGE RUN TIME 0720-0829 0852-1002 1021-1128

MEASURED DA

TA Static Pressure, inches H2O -2.60 -2.80 -2.80 -2.73 Average Stack Temp, deg F 271 276 279 276 Carbon Dioxide, % 12.2 12.3 12.0 12.2 Oxygen, % 6.9 6.8 7.2 7.0 Nitrogen, % 80.9 80.9 80.8 80.9 Sample Time, min 60.0 60.0 60.0 60.0



### CALCULATED DATA Stack Pressure, inches Hg 28.84 28.82 28.82 28.83 Moisture (gravimetrically), % 6.7 6.4 6.9 6.7 Velocity, ft/s 91.5 91.7 92.6 92.0 Stack Area, ft2 660.52 660.52 660.52 660.52 Volumetric flow, acfm 3,625,006 3,635,821 3,671,760 3,644,196 Volumetric flow, dscfm 2,351,215 2,349,409 2,352,507 2,351,043 Isokinetic Rate, % 95.9 96.6 98.1 96.9 F-factor, DSCF/MMBtu 9780.0 9780.0 9780.0 9780.0



### FILTERABLE PARTICULATE EMISSIONS DATA Filterable Catch, g 0.0469 0.0402 0.0468 0.0446 Probe wash Catch, g 0.0015 0.0020 0.0021 0.0019 Total Filterable Particulate Catch, g 0.0484 0.0422 0.0489 0.0465 Concen., mg/dscm 36.4 31.5 36.0 34.6 Concen., mg/actual m3 23.6 20.4 23.0 22.4 Concen., gr/dscf 0.01591 0.01378 0.01571 0.01514 Concen., gr/dscf@8% Oxygen 0.0147 0.0126 0.0148 0.0140 Emission Rate, lb/hr 320.713 277.599 316.849 305.054 Emission Rate, lb/MMBtu 0.0332 0.0285 0.0335 0.0317 Unit 3 Gross Load, MW 511 511 511 511 Unit 4 Gross Load, MW 517 517 517 517 SumGross Load, MW 

### 1028 1028 1028 1028 

### FILTERABLE PARTICULA TE TEST RESULTS SUMMARY PLANT Branch UNIT 3/4 STACK

Page 61 of 67 Att. 4

## ATTACHMENT 5 - Branch Report 5 Test Results

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

Run 1 Run 2 Run 3 Test Date 6/11/2009 6/11/2009 6/11/2009 Run Start Time 11:10 12:40 14:05 Run End Time 12:25 13:50 15:20 Meter Volume (dacf), Vm: 48.881 48.975 48.969 Sqrt Delta P ("wc): 1.20 1.21 1.20 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.30 29.30 29.30 Delta H ("wc): 1.9 1.9 1.9 Volume in Impingers (mls), VIc: 74.5 74.3 71.3 Static Pressure ("wc), Pg: -2.50 -2.40 -2.40 Stack Pressure ("Hg), Ps: 29.12 29.12 29.12 Stack Temperature (F), Ts: 281 284 284 Meter Coefficient (no units), Y: 0.966 0.966 0.966 Pitot Coefficient (no units) Cp: 0.840 0.840 0.840 Meter OutletTemperature (F), Tm: 92 96 97 Stack Diameter (inches): 270 270 270 Area Stack (sq. ft.), As: 397.61 397.61 397.61 Nozzle Diameter (inches), dp: 0.210 0.210 0.210 Area Nozzle (sq. ft.), An: 0.000241 0.000241 0.000241 Percent CO2 (% dry

volume): 11.0 11.1 11.2 Percent O2 (% dry

volume): 7.5 7.6 7.5 Percent (N2 + CO) (% dry volume): 81.5 81.3 81.3 Particulate Collected (mg), Mn: 34.4 36.6 40.5

Molec. Wt. Dry

(lb/lb-mole), Md: 30.065 30.085 30.093 Volume Water (scf), Vwstd 3.507 3.497 3.356 Meter Volume (dscf), Vmstd: 44.404 44.218 44.127 Wet Fraction (v/v), Bws: 0.073 0.073 0.071 Molec. Wt. Wet (lb/lb-mole), Ms: 29.182 29.200 29.239 Stack Gas Sampled (acf), Vma: 69.094 69.035 68.761 Averages Stack Gas Velocity

(fps), Vs: 80.43 81.04 80.53 81 Volumetric Flowrate (dscfm), Qs: 1,233,185 1,238,317 1,232,910 1,234,804 Volumetric Flowrate (acfm), Qa: 1,918,892 1,933,321 1,921,181 1,924,464 Grainloading (gr/dscf), cs: 0.0119 0.0128 0.0142 0.01 Emission Rate (lb/hour), E: 126.20 135.65 149.60 137.1 Percent Isokinetic Sampling (%), I: 99.27 98.44 98.67 98.79
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 4850.64 4834.48 4837.50 4840.87 

### Particulate Emission Results Summary

Branch Units 1-2

Page 62 of 67 Att. 5

## ATTACHMENT 5 - Branch Report 5 Test Results

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

Run 1 Run 2 Run 3 

### Particulate Emission Results Summary

Branch Units 1-2

Emission Rate (lbs/mmBtu), E: 0.03 0.03 0.03 0.03 Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.240 Average Unit 1 Gross Load (MW) 233 234 233 233 Average Unit 2 Gross Load (MW) 293 293 293 293 Average Sum Gross Load (MW) 526 527 526 526



### Page 63 of 67 Att. 5

## ATTACHMENT 6 - Branch Report 6 Test Results

Title of Run Description Date Start Time End

Time Test Load Avg. Econ. Gas Outlet CO Avg. Econ. Gas Outlet O2 Avg. Econ. Gas Outlet CO2 Avg. AH Gas Inlet Temp.

Military Military 

### MW ppm % Dry % Dry Deg F Test 1 0 9/10/2007 13:46 14:22 267 27.31 4.73 14.04 613 Test 2 Reduced O2 -0.5% 9/11/2007 7:12 7:48 267 119 4.43 14.49 604

Test 3 Reduced O2 -0.5% / Biased air to Rear Burners 9/11/2007 9:00 9:36 267 111 4.35 14.52 605

Test 4 Reduced O2 -0.5% / Biased air to Rear Burners 9/11/2007 11:57 12:33 267 115 4.32 14.48 606 Test 5 Abnormal Firing Conditions 9/12/2007 14:23 14:59 267 135 4.36 14.26 578 Test 6 Reduced O2 9/13/2007 9:05 9:41 267 490 4.2 14.6 608

Test 7 Reduced O2 - PA flow Adj. 9/13/2007 11:49 12:25 267 156 4.32 14.44 611 Test 8 Baseline 10/24/2007 13:54 14:30 267 36 4.56 14.28 604 Test 9 Baseline 10/29/2007 12:27 13:03 267 36 4.9 13.95 606 Test 10B3 B1 C1 Dmp 60% 10/29/2007 14:37 15:13 267 90 4.44 14.26 605 Test 11Baseline 10/30/2007 6:43 7:19 267 36 4.91 14.09 605 Test 12Reduced B Mill PA Bias 10/30/2007 6:43 7:19 267 22 4.94 14.03 601 Test 13Mill at 54 klb/hr 10/31/2007 11:17 11:53 267 114 4.46 14.22 603 Test 14Bias Removed 11/1/2007 7:48 8:24 267 109 4.77 14.15 602 Test 15O2 SP 4.28% 11/1/2007 9:47 10:23 267 28 5.33 13.42 605 Test 16O2 SP 4.28% 11/1/2007 12:21 12:57 267 79.49 4.82 14 606 Test 17O2 SP 4.28% 11/1/2007 13:39 14:15 267 73.73 4.77 14.02 605 Boiler Optimization Test Results Summary

Branch Unit 1

Page 64 of 67 Att. 6

## ATTACHMENT 7 - Branch Report 7 Test Results

Title of Run Description Date Start Time End Time Test Load Avg. Econ. Gas Outlet CO Avg. Econ. Gas Outlet O2 Avg. Econ. Gas Outlet CO2 

### Military Military MW ppm % Dry % Dry Test 01 Baseline 2/27/2008 14:26 15:39 320 49 4.26 14.55 Test 02 Baseline 2/27/2008 11:02 11:47 320 77 4.26 14.61 Test 03 Baseline 2/27/2008 13:00 13:45 320 73 4.3 14.54 Test 04 Baseline 2/27/2008 6:32 7:17 320 62 4.31 14.65 Test 05 Baseline 2/27/2008 9:48 10:33 320 42 4.31 14.7 Test 06 Baseline 2/27/2008 11:53 12:38 320 23 4.44 14.56 Boiler Optimization Test Results Summary

Branch Unit 2

Page 65 of 67 Att. 7

## ATTACHMENT 8 - Branch Report 8 Test Results

Title of Run Description Date Start Time End Time Test Load Avg. 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 Test 1 Baseline 11/13/2007 8:38 9:41 511 29 4.16 14.65 529

Test 2 Confirmation 11/13/2007 11:32 12:25 513 18 4.51 14.22 557 Boiler Optimization Test Results Summary

Branch Unit 3

Page 66 of 67 Att. 8

## ATTACHMENT 9 - Branch Report 9 Test Results

Title of Run Description Date Start Time End Time Test Load Avg. 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 Test 1 Baseline 5/7/2008 7:06 8:10 518 5 4.24 14.63 584 Test 2 Opt - 1 5/7/2008 9:38 10:41 518 10 3.71 15.11 580 Test 3 Opt - 2 5/7/2008 12:39 13:42 518 10 3.77 15.04 580 Test 4 Opt - 2 5/8/2008 12:50 13:53 518 8 4.08 14.47 581 Boiler Optimization Test Results Summary

Branch Unit 4

Page 67 of 67 Att. 9