### GEORGIA POWER - Submittal for PLANT HAMMOND

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):

Hammond 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):

708 5Complete street address of facility (physical location):

5963 Alabama Highway,SW Rome, Georgia 30165 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 61 part I, 1-14

### GEORGIA POWER - Submittal for PLANT HAMMOND

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

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

_X__ 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 61 part I, 1-14

### GEORGIA POWER - Submittal for PLANT HAMMOND

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

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").



### Other Material Sawdust Biomass

Synfuel Yes 

### Permitted to burn Yes Yes Used Oil Yes 

### Quantity/year

None in 2009 None in 2009 200 tons/year in 2009

None in 2009 

### Actually burn None in 2009

None in 2009 Yes None in 2009



### Page 3 of 61 part I, 1-14

### GEORGIA POWER - PLANT HAMMOND

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 115 107 88.6 87.65 1800 1802 1000 998 1000 1000 bituminous coal (100%), biomass (<1%), distillate oil (100%) CBI CBI Not applicable None

planned

2 bituminous CBI CBI 115 107 88.6 88.28 1800 1800 1000 1000 1000 1000 bituminous coal (100%), distillate oil (100%) CBI CBI Not applicable None

planned

3 bituminous CBI CBI 115 107 88.6 87.65 1800 1806 1000 1000 1000 1000 bituminous coal (100%), distillate oil (100%) CBI CBI Not applicable None

planned

4 bituminous CBI CBI 520 485 89.01 88.71 2400 2403 1000 1000 1000 1000 bituminous coal (100%), distillate oil (100%) CBI CBI Not applicable None

planned

6

### Boiler 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).
7

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

### Per fuel burned in the boiler. Report this based on higher heating value (HHV).
9

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

### Please indicate if more than one steam reheat cycle is utilized, and, if so, please provide information for both.
11

### Indicate the fuels utilized for the indicated boiler, and percentages, as indicated in questions 11 - 13.
12

### The "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.
13

### This 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 61 part I, 15

### GEORGIA POWER - PLANT HAMMOND

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 Hammond 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 61 part I, 15

### GEORGIA POWER - PLANT HAMMOND

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.

SCR catalyst:When making catalyst decisions, the primary goal is to achieve the desired NOx performance, with a secondary goal of minimizing SO3 formation. Boiler ID14 

### Type15 

### NOx control16 

### SO2 control17 

### PM control18 

### Other control19 1 dry bottom wallfired (1) low NOX burner (12/2002)(5) wet flue gas desulfurization (FGD) - 1 vessel for all four units (5/2008), calcium-based. (3) cold-side electrostatic precipitator (ESP) (2/1971) (2) flue gas conditioning - SO3 injection (10/1993) (4) hydrated lime injection - 1 system for all four units (SO3 control, 11/2009)

2 dry bottom wallfired (1) low NOX burner (12/2001)(5) wet flue gas desulfurization (FGD) - 1 vessel for all four units (5/2008), calcium-based. (3) cold-side electrostatic precipitator (ESP) (4/1969) (2) flue gas conditioning - SO3 injection (10/1993) (4) hydrated lime injection - 1 system for all four units (SO3 control, 11/2009)

3 dry bottom wallfired (1) low NOX burner (11/2002)(5) wet flue gas desulfurization (FGD) - 1 vessel for all four units (5/2008), calcium-based. (3) cold-side electrostatic precipitator (ESP) (12/1968) (2) flue gas conditioning - SO3 injection (10/1993) (4) hydrated lime injection - 1 system for all four units (SO3 control, 11/2009)

4 dry bottom wallfired (1) low NOX burner + overfire

air (1991)(2) SCR (5/2002), using titaniavanadia catalyst and anhydrous ammonia reductant; the catalyst is designed to reduce SO3 formation (SEE NOTES). (7) wet flue gas desulfurization (FGD) - 1 vessel for all four units (5/2008), calcium-based. (5) cold-side electrostatic precipitator (ESP) (12/1970, original install) (3) flue gas conditioning - SO3 injection (1990) (6) hydrated lime injection - 1 system for all four units (SO3 control, 11/2009) (4) flue gas conditioning - ammonia (SO3 control, 2005)

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)



### Page 6 of 61 part I, 16

### GEORGIA POWER - PLANT HAMMOND

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.

SCR catalyst:When making catalyst decisions, the primary goal is to achieve the desired NOx performance, with a secondary goal of minimizing SO3 formation. Boiler ID14 

### Type15 

### NOx control16 

### SO2 control17 

### PM control18 

### Other control19

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 61 part I, 16

### GEORGIA POWER - PLANT HAMMOND

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 61 part I, 17

### GEORGIA POWER - PLANT HAMMOND

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 61 part I, 18

### GEORGIA POWER - PLANT HAMMOND

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 61 part I, 19

### GEORGIA POWER - PLANT HAMMOND

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 dateExpected 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 61 part I, 20

### GEORGIA POWER - PLANT HAMMOND

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 one year if test results from the previous annual tests are fifty percent or less of the limit on scrubber stack; once every 5 years or operating 8760 hours, whichever first, on bypass stack) 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, 2012 (State rule, Title V permit revision not complete; based on 30-day rolling average, monitored by CEMS at inlet to scrubber and at scrubber stack during scrubber operations, excluding startup, shutdown, malfunction, and other exemptions) Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable NOx: [0.42 * (Heat Input of Units 1-3) + 0.07

*(Heat Input of Unit 4)]/[Heat Input of Units 1-3 + Heat Input of Unit 4] lb/MMBtu from May 1 through September 30 OR compliance with 5 and 7-plant Nox averages of 0.13 lb/MMBtu and 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 one year if test results from the previous annual tests are fifty percent or less of the limit on scrubber stack; once every 5 years or operating 8760 hours, whichever first, on bypass stack) 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, 2012 (State rule, Title V permit revision not complete; based on 30-day rolling average, monitored by CEMS at inlet to scrubber and at scrubber stack during scrubber operations, excluding startup, shutdown, malfunction, and other exemptions) Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable NOx: [0.42 * (Heat Input of Units 1-3) + 0.07

*(Heat Input of Unit 4)]/[Heat Input of Units 1-3 + Heat Input of Unit 4] lb/MMBtu from May 1 through September 30 OR compliance with 5 and 7-plant Nox averages of 0.13 lb/MMBtu and 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 61 part I, 21

### GEORGIA POWER - PLANT HAMMOND

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



### 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 one year if test results from the previous annual tests are fifty percent or less of the limit on scrubber stack; once every 5 years or operating 8760 hours, whichever first, on bypass stack) 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, 2012 (State rule, Title V permit revision not complete; based on 30-day rolling average, monitored by CEMS at inlet to scrubber and at scrubber stack during scrubber operations, excluding startup, shutdown, malfunction, and other exemptions) Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable NOx: [0.42 * (Heat Input of Units 1-3) + 0.07

*(Heat Input of Unit 4)]/[Heat Input of Units 1-3 + Heat Input of Unit 4] lb/MMBtu from May 1 through September 30 OR compliance with 5 and 7-plant Nox averages of 0.13 lb/MMBtu and 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).

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 one year if test results from the previous annual tests are fifty percent or less of the limit on scrubber stack; once every 5 years or operating 8760 hours, whichever first, on bypass stack) 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, 2012 (State rule, Title V permit revision not complete; based on 30-day rolling average, monitored by CEMS at inlet to scrubber and at scrubber stack during scrubber operations, excluding startup, shutdown, malfunction, and other exemptions) Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable NOx: [0.42 * (Heat Input of Units 1-3) + 0.07

*(Heat Input of Unit 4)]/[Heat Input of Units 1-3 + Heat Input of Unit 4] lb/MMBtu from May 1 through September 30 OR compliance with 5 and 7-plant Nox averages of 0.13 lb/MMBtu and 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).

27

### Boiler 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).
28

### If 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.
29

### List the compliance test method utilized.
30

### List the compliance test method utilized.
31

### Metal 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 61 part I, 21

### GEORGIA POWER - PLANT HAMMOND

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 rebuild: 0.12 lb/MMBtu filterable (expired in 2001) FGD (one vessel for all 4 units): CBI Not applicable Not

applicable FGD: 98% instantaneous removal efficiency to

meet a 95% 30-day rolling average removal efficiency (expired in 2009) Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable Low NOx burners: 0.38 lb/MMBtu (expired in

2003)

2 ESP rebuild: 0.12 lb/MMBtu filterable (expired in 1997) FGD (one vessel for all 4 units): CBI Not applicable Not

applicable FGD: 98% instantaneous removal efficiency to

meet a 95% 30-day rolling average removal efficiency (expired in 2009) Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable Low NOx burners: 0.38 lb/MMBtu (expired in

2002)

3 ESP rebuild: 0.12 lb/MMBtu filterable (expired in 1993) FGD (one vessel for all 4 units): CBI Not applicable Not

applicable FGD: 98% instantaneous removal efficiency to

meet a 95% 30-day rolling average removal efficiency (expired in 2009) Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable Low NOx burners: 0.38 lb/MMBtu (expired in

2003)

4 ESP rebuild: 0.03 lb/MMBtu filterable (expired in 1994) FGD (one vessel for all 4 units): CBI Not applicable Not

applicable FGD: 98% instantaneous removal efficiency to

meet a 95% 30-day rolling average removal efficiency (expired in 2009) Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable Not applicable



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

_X___ No Please elaborate.

32

### Boiler 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).
33

### If the boiler has separate guaranteed emission rate for filterable and condensable PM, respectively, please indicate those separate emission rates.
34

### Metal 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 61 part I, 22-23

### GEORGIA POWER - PLANT HAMMOND

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 Scrubber stack: 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, ESP power level and running of scrubber recycle pumps running monitored continuously, excursions (3-hour block averages) reported quarterly. Bypass stack: Stack test performed within 30 days following 8760 operating hours or every 5 years, whichever comes first; 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 January 1, 2012, SO2 removal by the scrubber will be monitored by inlet and stack SO2 CEMS operated, maintained, and certified using 40 CFR Part 75 procedures. Data from these monitors will provide the SO2 removal percentage on a 30-day rolling average, excluding startup, shutdown, and malfunction. Exceedances of the 5% limit will be reported quarterly; records retained for 5 years (permit revision not yet issued). Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable

2 Scrubber stack: 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, ESP power level and running of scrubber recycle pumps running monitored continuously, excursions (3-hour block averages) reported quarterly. Bypass stack: Stack test performed within 30 days following 8760 operating hours or every 5 years, whichever comes first; 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 January 1, 2012, SO2 removal by the scrubber will be monitored by inlet and stack SO2 CEMS operated, maintained, and certified using 40 CFR Part 75 procedures. Data from these monitors will provide the SO2 removal percentage on a 30-day rolling average, excluding startup, shutdown, and malfunction. Exceedances of the 5% limit will be reported quarterly; records retained for 5 years (permit revision not yet issued). Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable

3 Scrubber stack: 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, ESP power level and running of scrubber recycle pumps running monitored continuously, excursions (3-hour block averages) reported quarterly. Bypass stack: Stack test performed within 30 days following 8760 operating hours or every 5 years, whichever comes first; 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 January 1, 2012, SO2 removal by the scrubber will be monitored by inlet and stack SO2 CEMS operated, maintained, and certified using 40 CFR Part 75 procedures. Data from these monitors will provide the SO2 removal percentage on a 30-day rolling average, excluding startup, shutdown, and malfunction. Exceedances of the 5% limit will be reported quarterly; records retained for 5 years (permit revision not yet issued). Not 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 61 part I, 24

### GEORGIA POWER - PLANT HAMMOND

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 Scrubber stack: 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, ESP power level and running of scrubber recycle pumps running monitored continuously, excursions (3-hour block averages) reported quarterly. Bypass stack: Stack test performed within 30 days following 8760 operating hours or every 5 years, whichever comes first; under the CAM plan, opacity monitored continuously by COMS, excursions (3-hour block averages greater than 37%) 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 January 1, 2012, SO2 removal by the scrubber will be monitored by inlet and stack SO2 CEMS operated, maintained, and certified using 40 CFR Part 75 procedures. Data from these monitors will provide the SO2 removal percentage on a 30-day rolling average, excluding startup, shutdown, and malfunction. Exceedances of the 5% limit will be reported quarterly; records retained for 5 years (permit revision not yet issued). Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable

35

### Boiler 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).
36

### If 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.
37

### Metal 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 61 part I, 24

### GEORGIA POWER - PLANT HAMMOND

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 61 part I, 25-26

### GEORGIA POWER - PLANT HAMMOND

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:

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

708

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



### Page 18 of 61 part II, 1

### GEORGIA POWER - PLANT HAMMOND 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
12,196 1, 2, 3, 4 VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.17 10.93 13,777
12,171 1, 2, 3, 4 VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.03 11.93 13,525
12,076 1, 2, 3, 4 VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.18 11.11 13,741
12,025 1, 2, 3, 4 VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.17 12 13,405
12,100 1, 2, 3, 4 VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.29 11.11 13,557
12,345 1, 2, 3, 4 VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.23 12.16 13,529
12,180 1, 2, 3, 4 VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.18 11.44 13,629
12,247 1, 2, 3, 4 VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.29 12.95 13,283
11,825 1, 2, 3, 4 VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.33 11.86 13,556
12,031 1, 2, 3, 4 VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.37 12.74 13,436
12,063 1, 2, 3, 4 VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.26 13.27 13,304
11,063 1, 2, 3, 4 VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.28 14.56 13,129
11,862 1, 2, 3, 4 VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.27 15.07 13,026
11,930 1, 2, 3, 4 VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.11 13.74 13,185 

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

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

### Fuel shipment method

Page 19 of 61 part II, 2 (coal)

### GEORGIA POWER - PLANT HAMMOND 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 11,818 1, 2, 3, 4 KY MARTIN ALMA TRAIN 1.39 9.06 13,536 11,866 1, 2, 3, 4 KY MARTIN ALMA TRAIN 1.5 8.82 13,522 10,683 1, 2, 3, 4 KY MARTIN ALMA TRAIN 1.47 9.23 13,415 11,971 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 1.05 12.79 13,321 12,000 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.87 12.56 13,404 12,040 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.96 12.04 13,471 12,118 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.96 12.62 13,357 12,146 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 1.04 14.11 13,179 12,138 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 1.01 13.27 13,205 12,101 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.89 12.06 13,442 12,059 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.9 13.32 13,267 12,290 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.99 12.49 13,343 11,787 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.91 12.18 13,469 12,068 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 1.11 12.53 13,391 11,936 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.84 11.68 13,536 12,087 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.99 12.67 13,321 12,115 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.97 11.31 13,623 12,040 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.92 11.96 13,467 11,989 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 1.06 10.96 13,646 12,047 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.99 12.41 13,449 11,443 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.96 12.9 13,352 11,861 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.93 12.08 13,463 12,105 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 1 13.52 13,242 11,850 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.99 12.27 13,409



### Page 20 of 61 part II, 2 (coal)

### GEORGIA POWER - PLANT HAMMOND 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 11,853 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.9 11.72 13,534 11,750 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.92 14.05 13,132 N/A 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN N/A N/A N/A
9,890 1, 2, 3, 4 KY HARLAN, LEE CREECH, DARBY, HARLAN, KELLIOKATRAIN 0.94 11.03 13,249
9,747 1, 2, 3, 4 KY HARLAN, LEE CREECH, DARBY, HARLAN, KELLIOKATRAIN 1.25 14.1 12,851 10,923 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.04 6.16 14,059 11,204 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.04 7.66 13,842 11,133 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.07 7 13,931 11,492 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.04 6.91 13,921 11,424 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.18 7.25 13,903 11,487 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 0.95 8.98 13,527 11,855 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 0.91 7.4 13,759 10,348 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.06 9.35 13,424 11,149 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.07 5.36 14,145 11,140 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.01 8.63 13,562 11,303 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.06 8.68 13,606 10,128 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.07 10.05 13,249 11,033 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.02 7.46 13,744 10,911 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 0.83 8.59 13,557 10,379 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 0.93 11.09 13,129 10,978 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 0.93 10.73 13,343 11,181 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.11 6.58 13,944 10,506 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.04 6.7 13,966



### Page 21 of 61 part II, 2 (coal)

### GEORGIA POWER - PLANT HAMMOND 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 10,298 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.02 7.3 13,896 11,001 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.14 7.1 13,927 11,416 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.08 6.22 14,030 9,823 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 0.98 9.04 13,561 11,530 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.04 7.26 13,874 11,257 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.03 8.89 13,495 11,382 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.29 7.47 13,823 11,241 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.35 11.1 13,316 11,481 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 0.99 6.65 13,985 11,773 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.01 8.71 13,611 10,779 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.2 7.37 13,859 11,178 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.17 8.12 13,749
12,218 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.53 13.34 12,978
11,718 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1 13.15 13,126
11,449 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.3 10.44 13,539
11,323 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.39 10.18 13,577
10,707 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.24 11.92 13,313
12,068 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.59 11.91 13,360
11,876 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.38 13.6 13,024



### Page 22 of 61 part II, 2 (coal)

### GEORGIA POWER - PLANT HAMMOND 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

11,716 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.4 12.01 13,327
11,969 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.98 11.38 13,458
12,024 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.86 13.05 13,182
12,223 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 2.05 13.39 13,116
12,079 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 2.11 13.83 13,089
12,169 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.97 12.84 13,240
12,116 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.76 13.26 13,134
11,946 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.81 11.17 13,369
11,765 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.98 10.31 13,530
12,087 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.77 10.34 13,549
12,229 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.9 12.95 13,109
12,212 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.95 11.28 13,415
12,127 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.99 13.78 13,021
12,282 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.87 12.88 13,223



### Page 23 of 61 part II, 2 (coal)

### GEORGIA POWER - PLANT HAMMOND 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

12,186 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.51 13.29 13,129
11,869 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.84 11.32 13,453
12,245 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.42 12.57 13,215
12,180 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.96 13.31 13,193
12,380 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 2.08 14.1 13,013
11,383 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.78 10.6 13,589
12,093 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.67 12.89 13,177
12,109 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.66 13.03 13,217
11,973 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.68 11.79 13,346
12,088 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORDTRAIN 1.81 11.68 13,240 2,133 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.76 12.3 13,548 1,297 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.78 12.12 13,625 453 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.85 12.44 13,527 430 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.6 12.68 13,340 254 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.24 16.12 12,932 989 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.94 15.75 13,028 762 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.61 17.48 12,790



### Page 24 of 61 part II, 2 (coal)

### GEORGIA POWER - PLANT HAMMOND 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 927 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.87 30.01 10,576 697 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.81 15.9 12,991 521 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.95 11.8 13,669 1,471 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.7 13.81 13,455 714 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.71 12.66 13,549 908 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.2 13.88 13,321 466 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.71 11.99 13,644 1,728 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.65 11.09 13,743 2,587 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.66 12.68 13,492 1,442 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.7 16.16 12,825 1,147 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.6 12.04 13,605 883 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.7 12.74 13,489 1,086 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.65 16.74 12,768 1,485 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.75 12.15 13,574 1,205 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.73 13.46 13,406 1,066 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.71 15.49 13,009 827 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.73 12.59 13,542 843 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.74 11.39 13,739 509 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.56 12.52 13,620 254 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.7 13.09 13,496 257 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.67 10.43 13,911 487 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.63 12.86 13,587 1,472 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.66 12.93 13,540 1,722 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.9 12.73 13,542



### Page 25 of 61 part II, 2 (coal)

### GEORGIA POWER - PLANT HAMMOND 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 1,307 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.81 14.11 13,306 824 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.92 15.37 13,071 1,476 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.92 13.47 13,394 1,516 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.82 13.44 13,409 1,359 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.9 12.84 13,472 1,153 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.98 14.1 13,304 904 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.02 14.64 13,238 839 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.82 15.13 13,136 1,230 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.17 14.13 13,253 977 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.86 13.57 13,347 1,500 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.05 13.46 13,337 1,302 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.73 13.54 13,304 723 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.76 13.52 13,350 960 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.42 14.38 13,119 1,309 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.19 14.57 13,140 667 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.97 14.53 12,992 1,550 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.9 13.79 13,270 744 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.13 19.06 12,319 821 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.18 15.3 13,016 1,458 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.16 17.12 12,721 782 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.07 16.63 12,790 648 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.04 16.49 12,816 834 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.04 16.17 12,854 667 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.22 14.8 13,066



### Page 26 of 61 part II, 2 (coal)

### GEORGIA POWER - PLANT HAMMOND 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 394 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.63 14.61 13,182 1,377 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.89 15.99 12,917 1,055 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.94 18.22 12,517 1,857 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1 14.14 13,209 1,739 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.78 16.78 12,751 944 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.86 15.54 12,943 486 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.86 14.62 13,183 595 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.96 15.93 12,875 1,171 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.95 14.31 13,180 1,764 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.96 15.93 12,875 644 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.84 14.16 13,181 1,858 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.8 14.38 13,212 1,009 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.96 16.78 12,740 375 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.85 12.89 13,470 1,575 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.93 13.64 13,236 1,299 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.46 15.14 13,014 1,697 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.06 13.78 13,254 652 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.02 13.79 13,255 489 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.83 16.78 12,769 1,368 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.84 14.43 13,155 1,416 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.93 15.66 12,926 1,360 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.32 16.23 12,816 1,160 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.81 15.17 13,035 1,432 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.89 14.67 13,143



### Page 27 of 61 part II, 2 (coal)

### GEORGIA POWER - PLANT HAMMOND 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 1,349 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.1 17.18 12,662 1,696 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.42 13.12 13,392 426 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.13 14.47 13,190 351 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.22 14.41 13,142 1,287 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.91 13.92 13,286 418 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.98 14.4 13,206 1,070 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.98 14.38 13,154 891 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.99 13.32 13,335 655 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1 12.98 13,330 994 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.11 12.48 13,454 975 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.17 13.36 13,291 1,003 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.3 15.59 12,938 714 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.04 15.18 13,012 1,000 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.1 16.03 12,866 1,001 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.27 14.44 13,144 902 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.14 13.75 13,253 905 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.95 15.6 12,930 1,208 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.64 12.6 13,553 1,931 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1 13.2 13,451 1,082 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.89 12.85 13,510 1,002 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.79 13.49 13,326 141 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.95 13.34 13,348 923 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.78 14.95 13,130 924 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.78 14 13,262



### Page 28 of 61 part II, 2 (coal)

### GEORGIA POWER - PLANT HAMMOND 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 1,004 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.93 16.31 12,846 1,253 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.77 10.82 13,905 1,289 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.88 11.75 13,791 1,211 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.77 13.47 13,403 851 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.8 13.72 13,361 983 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.74 13.12 13,433 1,065 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.91 14.25 13,239 1,114 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.05 13.66 13,373 912 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.81 15.63 12,954 884 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.82 12.01 13,423 928 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.79 12.01 13,598 935 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.73 12.58 13,502 N/A 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK N/A N/A N/A 867 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.93 13.65 13,267 912 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.91 13.18 13,317 1,054 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.8 12.87 13,438 382 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.72 14.17 13,195 622 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.76 13.21 13,367 1,108 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.71 12.91 13,469 798 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.78 14.34 13,134 878 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.8 13.72 13,300 859 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.84 14.69 13,100 663 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.02 13.67 13,259 1,061 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.91 11.67 13,799



### Page 29 of 61 part II, 2 (coal)

### GEORGIA POWER - PLANT HAMMOND 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 1,056 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.93 14.15 13,277 1,033 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.96 13.96 13,320 646 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.88 12.52 13,499 528 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.84 13.29 13,395 622 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.92 14.73 13,072 667 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.05 15.51 12,938 922 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.86 12.49 13,453 995 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1 13.25 13,328 820 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.89 15.11 13,007 611 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.87 13.6 13,318 1,625 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.87 14.69 13,071 739 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.09 15.77 12,900 665 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.03 16.54 12,790 1,180 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.87 15.18 13,014 567 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.99 15.67 12,936 1,508 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.94 16.47 12,802 827 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.87 14.66 13,152 993 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.03 14.9 13,032 695 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.07 16.16 12,819 806 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.75 13.68 13,406 521 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.72 13.16 13,481 807 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.72 13.27 13,457 1,125 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.72 14.17 13,309 925 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.65 13.3 13,314



### Page 30 of 61 part II, 2 (coal)

### GEORGIA POWER - PLANT HAMMOND 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 1,148 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.64 14.71 13,174 673 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.69 14.02 13,266 1,575 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.62 12.74 13,521 1,697 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.62 12.75 13,520 1,064 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.66 13.13 13,477 1,049 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.67 13.66 13,394 995 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.66 13.2 13,497 1,800 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.71 13.26 13,408 832 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.69 13.28 13,454 426 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.65 13.05 13,482 998 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.63 12.55 13,487 1,111 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.59 13.05 13,501 766 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.82 14.99 13,160 1,211 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.75 13.87 13,335 998 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.68 13.08 13,481 1,174 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.67 12.63 13,534 1,110 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.61 12.5 13,608 1,323 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.75 12.38 13,605 1,347 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.67 12.09 13,662 882 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.72 14.69 13,176 1,035 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.68 13.54 13,392 1,054 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.71 12.68 13,575 1,213 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.68 12.73 13,523 522 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.68 13 13,479



### Page 31 of 61 part II, 2 (coal)

### GEORGIA POWER - PLANT HAMMOND 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 964 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.7 13.26 13,410 1,236 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.72 13.19 13,434 1,454 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.7 13.64 13,348 573 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.7 13.34 13,417 7,889 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 2.14 11.99 13,128 11,978 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.01 9.01 13,487
11,759 1, 2, 3, 4 KY PIKE ALMA, ELKHORN, ELKHORN #2, ELKHORN #3 TRAIN 0.74 11.98 13,246
11,723 1, 2, 3, 4 KY PIKE ALMA, ELKHORN, ELKHORN #2, ELKHORN #3 TRAIN 1.01 11.51 13,419
11,164 1, 2, 3, 4 KY PIKE ALMA, ELKHORN, ELKHORN #2, ELKHORN #3 TRAIN 0.97 10.9 13,536
11,692 1, 2, 3, 4 KY PIKE ALMA, ELKHORN, ELKHORN #2, ELKHORN #3 TRAIN 0.87 11.25 13,441
11,594 1, 2, 3, 4 N/A N/A POND CREEK, TAYLOR, WILLIAMSON TRAIN 0.93 12.59 13,209 11,564 1, 2, 3, 4 KY, WV LESLIE, LOGAN ALMA TRAIN 0.72 9.83 13,467 11,986 1, 2, 3, 4 KY, WV LESLIE, LOGAN ALMA TRAIN 0.74 12.89 13,130 11,730 1, 2, 3, 4 KY, WV LESLIE, LOGAN ALMA TRAIN 0.75 12.22 13,245 10,139 1, 2, 3, 4 KY, WV LESLIE, LOGAN ALMA TRAIN 0.87 12.25 13,245 11,728 1, 2, 3, 4 KY, WV LESLIE, LOGAN ALMA TRAIN 0.91 12.82 13,174 11,898 1, 2, 3, 4 KY, WV LESLIE, LOGAN ALMA TRAIN 1.13 12.84 13,217

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



### Page 32 of 61 part II, 2 (coal)

### GEORGIA POWER - PLANT HAMMOND 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
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 33 of 61 part II, 2 (coal)

### GEORGIA POWER - PLANT HAMMOND

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 30,120 1, 2, 3, 4 Georgia/USA N/A N/A Truck 15,071 1, 2, 3, 4 Georgia/USA N/A N/A Truck 15,063 1, 2, 3, 4 Georgia/USA N/A N/A Truck 7,527 1, 2, 3, 4 Georgia/USA N/A N/A Truck 15,098 1, 2, 3, 4 Georgia/USA N/A N/A Truck 15,043 1, 2, 3, 4 Georgia/USA N/A N/A Truck 45,208 1, 2, 3, 4 Georgia/USA N/A N/A Truck 29,980 1, 2, 3, 4 Georgia/USA N/A N/A Truck 14,971 1, 2, 3, 4 Georgia/USA N/A N/A Truck 14,978 1, 2, 3, 4 Georgia/USA N/A N/A Truck 14,981 1, 2, 3, 4 Georgia/USA N/A N/A Truck 29,990 1, 2, 3, 4 Georgia/USA N/A N/A Truck 14,924 1, 2, 3, 4 Georgia/USA N/A N/A Truck 14,922 1, 2, 3, 4 Georgia/USA N/A N/A Truck 14,874 1, 2, 3, 4 Georgia/USA N/A N/A Truck 22,314 1, 2, 3, 4 Georgia/USA N/A N/A Truck 22,300 1, 2, 3, 4 Georgia/USA N/A N/A Truck 22,271 1, 2, 3, 4 Georgia/USA N/A N/A Truck 29,733 1, 2, 3, 4 Georgia/USA N/A N/A Truck 7,429 1, 2, 3, 4 Georgia/USA N/A N/A Truck 22,215 1, 2, 3, 4 Georgia/USA N/A N/A Truck 22,197 1, 2, 3, 4 Georgia/USA N/A N/A Truck 22,269 1, 2, 3, 4 Georgia/USA N/A N/A Truck 22,285 1, 2, 3, 4 Georgia/USA N/A N/A Truck 14,841 1, 2, 3, 4 Georgia/USA N/A N/A Truck 14,820 1, 2, 3, 4 Georgia/USA N/A N/A Truck 

### FUEL OIL SHIPMENTS Amount received, gallons40 

### ID # of boiler(s)

firing fuel41 

### Fuel source Fuel shipment method

Page 34 of 61 part II, 2 (oil)

### GEORGIA POWER - PLANT HAMMOND

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 14,833 1, 2, 3, 4 Georgia/USA N/A N/A Truck 22,285 1, 2, 3, 4 Georgia/USA N/A N/A Truck 22,271 1, 2, 3, 4 Georgia/USA N/A N/A Truck 29,744 1, 2, 3, 4 Georgia/USA N/A N/A Truck 14,884 1, 2, 3, 4 Georgia/USA N/A N/A Truck 14,880 1, 2, 3, 4 Georgia/USA N/A N/A Truck 22,361 1, 2, 3, 4 Georgia/USA N/A N/A Truck 22,385 1, 2, 3, 4 Georgia/USA N/A N/A Truck 22,346 1, 2, 3, 4 Georgia/USA N/A N/A Truck 22,455 1, 2, 3, 4 Georgia/USA N/A N/A Truck 22,468 1, 2, 3, 4 Georgia/USA N/A N/A Truck 22,483 1, 2, 3, 4 Georgia/USA N/A N/A Truck 22,483 1, 2, 3, 4 Georgia/USA N/A N/A Truck 29,980 1, 2, 3, 4 Georgia/USA N/A N/A Truck 15,031 1, 2, 3, 4 Georgia/USA N/A N/A Truck 22,560 1, 2, 3, 4 Georgia/USA N/A N/A Truck 22,547 1, 2, 3, 4 Georgia/USA N/A N/A Truck 7,538 1, 2, 3, 4 Georgia/USA N/A N/A Truck 30,149 1, 2, 3, 4 Georgia/USA N/A N/A Truck

40EPA recognizes that facilities have (sometimes) several months inventory and that the amount received is not necessarily the same as the amount fired.
41Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).
42If known.



### Page 35 of 61 part II, 2 (oil)

### GEORGIA POWER - PLANT HAMMOND

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
43If known.



### Page 36 of 61 part II, 2 (oil)

### GEORGIA POWER - PLANT HAMMOND 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

09-101 1,275 0.86 16.01 12,962 0.090 1140 92 18.3 1.4 10.9 1.8 <0.02 23.8 8.0 10.3 13.8 1.0AL Jackson Underwood Seam Truck

09-501 12,832 0.99 12.79 13,239 0.070 86 116 14.7 1.2 7.9 2.1 <0.02 19.0 7.8 9.7 41.6 2.3VA Wise (1)Parsons (2) Imboden (3)Taggart (4)Taggert Marker (5)Low Splint C (6) Low splint (7) Low Splint A Train

09-504 11,367 1.23 11.79 13,262 0.070 93 130 10.7 1.3 17.4 1.6 0.13 15.8 6.1 8.1 21.4 2.5VA Wise (1)Morris (2)Cedar Grove (3) Mixed (4)Parsons (5)Taggart (6) #8 Train

09-505 12,229 1.54 10.24 13,258 0.113 2148 69 13.5 1.6 10.6 2.1 0.06 15.8 7.0 9.6 24.2 3.9KY Martin Alma, CoalburgTrain

09-507 12,420 0.91 13.36 13,049 0.073 995 103 12.9 1.0 12.1 2.9 0.03 17.6 8.9 9.1 50.0 3.0KY Pike Broaz, Haddix, Chilton, Middle Whitesburg, Upper/Lower Alma, Haddix, Cedar Grove, Williamson Train

09-103 1,190 0.96 15.38 12,960 0.132 1247 73 16.1 <1 15.0 1.2 <0.02 20.1 6.5 9.2 12.8 1.0AL Jackson Underwood Seam Truck

09-203 10,065 1.45 12.64 13,192 0.116 51 102 10.2 <1 25.6 1.5 0.19 14.2 6.8 6.1 29.3 2.2VA Lee Creech, House Coal Train

09-400 11,412 1.22 7.45 13,789 0.081 1182 82 20.5 <1 7.1 2.4 0.11 12.9 10.5 6.4 10.2 3.4TN ClairborneBraden, Red Ash, Walnut Mountain Train 

### Coal Seam Fuel

Shipment Method Nickel, ppm Other trace metal HAP, ppm45 

### State/ Country County Chlorine, ppm Fluorine,

ppm Total amount of fuel represented by sample, tons 

### Sample ID # Total Sulfur, % Ash

Content, % Heating Value, Btu/lb Mercury,

ppm

Page 37 of 61 part II, 3

### GEORGIA POWER - PLANT HAMMOND 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 Coal Seam Fuel Shipment Method Nickel, ppm Other trace metal HAP, ppm45 

### State/ Country County Chlorine, ppm Fluorine,

ppm Total amount of fuel represented by sample, tons 

### Sample ID # Total Sulfur, % Ash

Content, % Heating Value, Btu/lb Mercury,

ppm

09-401 8,500 2.01 8.93 13,675 0.099 643 74 15.6 <1 15.5 1.9 0.13 13.2 6.4 6.2 14.6 2.9TN ClairborneWalnut Mountain, Windrock, Pee Wee Train

09-510 12,792 1.07 13.2 13,252 0.066 ND 73 14.4 1.5 14.6 2.5 0.04 18.2 8.2 9.7 43.1 2.5VA Wise (1) Low Splint (2) Imboden (3)Taggart (4)Upper Parsons (5)Taggart Marker (6)Lower Parsons Train

09-514 12,661 1.9 12.38 13,317 0.120 126 98 14.0 1.7 39.7 2.6 0.29 15.1 7.9 7.4 37.4 2.6VA Wise Cedar Grove, Morris Ryder Train

09-515 12,746 0.87 11.76 13,275 ND 992 90 15.5 1.1 12.8 2.9 ND 16.2 8.5 7.8 38.4 2.7KY Pike Lower Elkhorn, Elkhorn , Alma, Clintwood Train

09-516 12,427 0.94 14.5 12,864 ND 1178 108 17.1 1.1 16.6 3.2 ND 18.1 10.8 9.5 134.3 2.4KY Pike Chilton, Whitesburg, Upper/Lower Alma, Cedar Grove Train

09-411 10,522 1.63 9.32 13,586 0.115 298 82 16.3 1.6 9.6 2.2 0.12 14.4 6.4 7.9 13.9 3.5TN ClairborneWalnut Mountain, Windrock, Pee Wee Train

09-412 12,474 0.98 9.01 13,460 0.071 1310 98 26.4 1.2 5.0 3.0 0.10 16.9 13.5 9.7 21.9 3.8TN ClairborneBraden, Red Ash, Walnut Mountain Train 09-216 12,723 1.59 9.41 13,416 0.115 2317 60 13.0 1.4 7.9 2.1 0.04 16.0 7.0 9.1 18.9 3.9KY Martin Alma, Taylor Train



### Page 38 of 61 part II, 3

### GEORGIA POWER - PLANT HAMMOND 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 Coal Seam Fuel Shipment Method Nickel, ppm Other trace metal HAP, ppm45 

### State/ Country County Chlorine, ppm Fluorine,

ppm Total amount of fuel represented by sample, tons 

### Sample ID # Total Sulfur, % Ash

Content, % Heating Value, Btu/lb Mercury,

ppm

09-519 12,850 0.9 13.36 13,230 ND 68 119 14.5 1.1 9.7 2.0 ND 19.9 8.0 8.9 49.4 2.5VA Wise (1) Imboden (2)Taggart (3)Lower Parsons (4)Taggart Marker (5)Low Splint (6) Low Splint A (7) Low Splint D (8) Upper Parsons Train

09-521 12,634 0.75 12.11 13,220 ND 1028 100 12.7 1.1 10.1 3.1 ND 16.0 8.1 6.9 24.8 3.4KY Pike Lower Elkhorn, Elkhorn , Alma, Clintwood Train

09-523 12,773 1.63 13.7 13,044 0.157 150 113 15.4 ND 40.8 1.8 0.15 16.6 7.6 7.3 40.6 2.3VA Wise Cedar Grove, High Splint, Morris Ryder, High Splint Marker Train

09-109 1,027 0.67 12.42 13,609 0.022 1181 29 11.6 <1 4.1 1.1 <0.02 17.6 7.3 7.8 12.2 1.0AL Jackson Underwood Seam Truck

09-106 634 1.15 14.68 12,973 0.111 988 ND 18.3 <1 16.3 1.6 0.07 19.0 8.1 11.9 12.6 0.9AL Jackson Underwood Seam Truck

09-527 12,691 0.81 11.8 13,156 ND 1018 80 13.8 1.2 13.7 3.6 0.07 12.0 10.9 8.5 130.1 2.2KY Pike Chilton, Whitesburg, Upper/Lower Alma, Cedar Grove Train

09-231 12,707 1.47 8.58 13,470 0.076 1951 51 17.9 1.2 7.7 2.6 0.06 17.5 9.9 11.0 14.6 4.1KY Martin Alma, Taylor, Stockton Train

09-429 10,084 2 10.27 13,305 0.107 534 92 30.5 1.9 12.0 2.7 0.31 23.9 11.4 13.2 19.0 4.3TN ClairborneWalnut Mountain, Windrock, Pee Wee Train

09-430 11,546 0.94 7.32 13,811 ND 1103 70 28.7 1.1 5.1 3.6 0.11 16.5 14.1 10.2 18.5 3.6TN ClairborneBraden, Red Ash, Walnut Mountain Train



### Page 39 of 61 part II, 3

### GEORGIA POWER - PLANT HAMMOND 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 Coal Seam Fuel Shipment Method Nickel, ppm Other trace metal HAP, ppm45 

### State/ Country County Chlorine, ppm Fluorine,

ppm Total amount of fuel represented by sample, tons 

### Sample ID # Total Sulfur, % Ash

Content, % Heating Value, Btu/lb Mercury,

ppm

09-233 11,610 0.74 12.37 13,164 0.067 1151 76 15.4 1.0 13.3 3.9 0.03 13.8 12.6 7.9 157.6 2.2KY Pike Chilton, Lower Alma, Cedar Grove, #3 Elkhorn Train

09-436 10,210 1.87 9.45 13,497 0.096 392 80 23.1 1.6 11.6 2.1 0.20 18.0 8.8 10.2 14.1 4.1TN ClairborneWalnut Mountain, Windrock, Pee Wee Train

09-437 11,880 1.31 6.61 13,825 0.058 1205 56 22.9 1.2 6.7 2.9 0.10 13.3 12.2 7.9 9.9 3.9TN ClairborneBraden, Red Ash, Walnut Mountain Train

09-529 12,893 1.01 12.13 13,403 ND 155 109 13.5 1.2 7.1 2.2 0.06 20.5 7.8 10.5 26.3 2.8VA Wise (1) Parsons (2)Taggart (3)Low Splint A (4)Dorchester Train

09-530 12,463 0.8 12.06 13,315 0.078 124 47 5.3 ND 0.9 0.3 0.03 3.4 2.5 3.0 13.6 0.9WV Mingo, Logan Coalburg,

Stockton, Alma, Lower Cedar Grove Train

09-532 12,837 1.59 13.08 13,184 0.101 130 91 17.0 1.6 26.8 3.0 0.15 18.1 9.7 9.1 25.9 2.2VA Wise Morris, Cedar Grove, High Splint, ParsonsTrain

09-535 12,753 1.35 9.27 13,431 0.086 1981 103 16.6 1.3 8.0 2.4 ND 16.4 7.9 8.4 14.5 4.1KY Martin Alma, Taylor, Stockton 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 40 of 61 part II, 3

### GEORGIA POWER - PLANT HAMMOND

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 41 of 61 part II, 4-6

### GEORGIA POWER - PLANT HAMMOND

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

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

Total

MoistureVolatiles Ash Fixed Carbon Carbon Hydrogen

### Nitrogen Total Sulfur Oxygen Barium Copper Magnesium

### Sodium Vanadium 

### Zinc Al2O3Fe2O3 CaO MgOMnO2P2O5 K2O SiO2 Na2O SO3 TiO2

09-101 2.75 25.73 16.01 58.26 75.13 4.47 1.37 0.86 2.16 120 17.5 0.117 0.013 43.3 19.6 29.42 5.51 0.95 1.210.014 0.67 3.1657.17 0.11 0.43 1.13 09-501 6.35 32.47 12.79 54.74 75.28 4.65 1.41 0.99 4.88 121 21.1 0.102 0.044 43.2 22.6 27.6 7.960.992 1.25 ND ND 3.05 54.20.5540.561 1.45 09-504 5.84 33.51 11.79 54.7 76.11 4.73 1.48 1.23 4.66 131 19.4 0.077 0.025 29.7 17.1 26.5 9.34 1.220.972 ND0.577 2.73 48.6 0.350.288 1.36 09-505 6.83 37.22 10.24 52.53 76.72 4.88 1.41 1.54 5.2 317 23.5 0.008 0.000 37.3 16.1 26.3 12.7 2.50.876 ND ND 2.2 45.70.523 1.82 1.25 09-507 4.92 31.63 13.36 55.01 75.87 4.63 1.35 0.91 3.88 386 20.0 0.092 0.037 29.4 14.7 24.2 6.890.858 1.11 ND ND 2.78 55.10.3970.715 1.38 09-103 6.77 27.01 15.38 57.61 74.29 4.43 1.37 0.96 3.57 100 13.7 0.109 0.012 38.0 14.5 28.23 6.4 0.79 1.170.013 0.49 3.22 57.62 0.11 0.52 1.23 09-203 5.28 34.06 12.64 53.31 75.25 4.72 1.41 1.45 4.52 152 18.5 0.088 0.027 27.1 15.3 24.6 10.7 1.34 1.13 ND ND 2.5 50.90.3360.658 1.33 09-400 5.42 36.88 7.45 55.68 79.19 4.91 1.83 1.22 5.39 122 21.6 0.063 0.014 31.6 18.9 27.6 11.3 3.44 1.24 ND ND 2.23 49.2 0.36 2.24 1.33 09-401 5.83 36.96 8.93 54.11 77.62 4.92 1.9 2.01 4.63 91 23.9 0.059 0.016 34.8 13.8 22.8 16.7 2.13 0.982 ND ND 2.19 47.50.264 1.1 1.19 09-510 6.98 32.91 13.2 53.89 75.61 4.8 1.4 1.07 3.92 132 22.3 0.109 0.042 39.1 22.4 26.6 9.47 1.34 1.26 ND ND 3.26 53.50.531 0.96 1.34 09-514 4.99 34.16 12.38 53.47 76.24 4.86 1.34 1.9 3.28 172 20.1 0.098 0.025 31.1 21.7 24.1 17.9 1.11 1.17 ND ND 3.13 45.3 0.3220.568 1.02 09-515 5.67 31.26 11.76 56.97 75.97 4.62 1.33 0.87 5.45 417 18.6 0.084 0.047 27.3 15.6 25.2 7.170.964 1.09 ND ND 3.18 550.5620.727 1.26 09-516 5.81 32.04 14.5 53.46 73.4 4.63 1.25 0.94 5.28 386 21.7 0.110 0.038 31.2 21.0 24.4 10.4 1.48 1.24 ND ND 2.92 56.4 0.42 1.17 1.31 09-411 5.82 36.75 9.32 53.92 75.84 4.98 1.77 1.63 6.46 122 26.6 0.063 0.017 35.5 14.7 28.2 11.7 2.56 1.22 ND0.459 2.41 58.50.615 1.21 1.4 09-412 6.19 36.01 9.01 54.99 76.13 4.9 1.63 0.98 7.36 113 28.7 0.081 0.019 45.4 25.6 28.5 7.19 3.26 1.56 ND0.502 2.59 510.349 1.9 1.28 09-216 6.72 38.03 9.41 52.56 72.88 4.8 1.52 1.59 9.79 82 23.2 0.047 0.033 34.8 14.2 27.7 12.7 3.070.839 ND ND 1.86 46.90.546 2.15 1.26 09-519 6.16 32.55 13.36 54.1 75.2 4.82 1.56 0.9 4.16 132 21.5 0.109 0.048 40.3 22.7 26.8 8.44 1.64 1.35 ND ND 3.29 58.40.542 1.25 1.3 09-521 5.15 31.19 12.11 56.71 75.69 4.76 1.56 0.75 5.13 285 18.6 0.086 0.048 28.6 12.6 27.4 6.87 1.13 1.18 ND ND 3.27 57.8 0.540.715 1.35 09-523 5.05 34.22 13.7 52.08 71.4 4.7 1.39 1.63 7.17 183 17.6 0.131 0.026 33.0 25.8 24.8 16.10.949 1.4 ND ND 3.39 470.3020.665 1.1 09-109 2.79 25.19 12.42 62.39 77.79 4.55 1.52 0.67 3.05 80 10.6 0.091 0.011 27.2 19.2 25.47 4.76 0.79 1.210.016 0.31 3.11 62.38 0.12 0.43 1.31 09-106 2.74 27.37 14.68 57.54 72.27 4.43 1.46 1.15 5.6 91 15.4 0.108 0.012 36.7 18.6 28 7.860.879 1.13 ND ND 2.83 52.60.149 ND 1.25 09-527 7.86 32.37 11.8 55.83 74.02 4.43 1.5 0.81 7.44 285 17.6 0.083 0.039 20.4 15.6 24.8 11 1.74 1.33 ND ND 3.03 51.80.507 1.42 1.11 09-231 6.67 38.81 8.58 52.6 74.73 4.82 1.6 1.47 8.8 62 29.3 14.578 0.029 44.2 18.7 30 9.74 2.590.789 ND ND 1.81 47.70.501 2.47 1.21 09-429 6.36 35.29 10.27 54.44 73.63 4.69 1.62 2 7.78 92 45.9 0.085 0.015 61.3 34.8 27.5 11.6 2.72 1.35 ND ND 2.21 45.20.273 2.14 1.41 09-430 5.44 35.86 7.32 56.82 76.71 4.86 1.61 0.94 8.56 82 32.3 0.056 0.029 49.0 22.6 28.5 7.98 3.13 1.46 ND0.441 2.25 48.3 0.376 2.33 1.37 09-233 7.03 31.74 12.37 55.89 73.57 4.52 1.35 0.74 7.46 255 20.5 0.084 0.034 23.3 17.2 23.7 12.7 1.67 1.040.132 ND 2.9 50.10.451 1.27 1.22 09-436 6.32 35.44 9.45 55.11 75 4.78 1.83 1.87 7.06 112 35.2 0.070 0.015 47.6 23.3 28 11.4 2.48 1.25 ND0.477 2.17 48.20.253 2.19 1.38 09-437 6.02 36.44 6.61 56.95 77.61 4.94 1.74 1.31 7.79 71 28.2 0.054 0.015 39.6 20.3 32.3 4.080.9020.651 ND ND 1.54 56.50.173 ND 1.75 09-529 6.24 33.15 12.13 54.71 75.15 4.65 1.44 1.01 5.62 122 24.1 0.092 0.037 41.2 20.5 26.9 6.59 1.2 1.06 ND0.403 2.65 52.40.4350.695 1.51 09-530 6.14 32.04 12.06 55.9 74.64 4.58 1.36 0.8 6.56 317 10.6 0.226 0.082 13.6 14.1 25.3 5.02 0.880.998 ND ND 2.38 56.10.2910.556 1.44 09-532 5.65 33.92 13.08 53.01 73.25 4.71 1.31 1.59 6.06 132 23.5 0.109 0.023 37.5 31.6 27.7 14.2 1.02 1.32 ND ND 3.52 54.40.2920.575 1.21 09-535 6.75 37.55 9.27 53.18 74.41 4.84 1.6 1.35 8.53 62 21.3 0.045 0.033 35.5 15.3 30.1 11.7 2.590.809 ND ND 1.89 48.50.545 1.51 1.34 Sample ID # Proximate Analyses, % by wt Ultimate Analyses, % by wt Ash Mineralogy, % by wt Other Trace Metals, ppm, dry basis

Page 42 of 61 part II, 7

### GEORGIA POWER - PLANT HAMMOND

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 Units 1-3 Particulate Emissions Test (July 13, 2006) Report 2 Unit 4 Particulate Emissions Test (July 13, 2006) Report 3 Units 1-3 Particulate Emissions Test (February 6, 2008) Report 4 Unit 4 Particulate Emissions Test (February 6, 2008 to February 7, 2008) Report 5 Units 1-4 Particulate Emissions Test, FGD Stack (April 22, 2008) Report 6 Units 1-4 CAM Testing, FGD Stack (April 24, 2008) Report 7 Units 4 Low NOx Burners Optimization (April 20, 2009 to April 24, 2009) Report 8 Units 1-4 Scrubber Performance Mercury Test (June 13, 2008 to June 19, 2008) Report 9 Units 1-4 Scrubber Performance SO3 Test (May 29, 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:7/13/2006 Type:stack Constituents:PM Report 2 Date:7/13/2006 Type:stack Constituents:PM Report 3 Date:2/6/2008 Type:stack Constituents:PM Report 4 Date:2/6/2008-2/7/2008 Type:stack Constituents:PM Report 5 Date:4/22/2008 Type:stack Constituents:PM Report 6 Date:4/24/2008 Type:stack Constituents:PM Report 7 Date:4/20/2009-4/24/2009 Type:duct Constituents:CO Report 8 Date:6/13/2008-6/19/2008 Type:duct/stack Constituents:Hg Report 9 Date:5/29/2008 Type:duct/stack Constituents:SO3

Page 43 of 61 part II, 8

### GEORGIA POWER - PLANT HAMMOND

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

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

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.

Boiler ID Type NOx control SO2 control PM control Other control 1 dry bottom wall-fired (1) low NOX burner (2) cold-side electrostatic precipitator 2 dry bottom wall-fired (1) low NOX burner (2) cold-side electrostatic precipitator 3 dry bottom wall-fired (1) low NOX burner (2) cold-side electrostatic precipitator 4 dry bottom wall-fired (1) low NOX burner +

overfire air (2) SCR (3) cold-side electrostatic precipitator



### Page 44 of 61 part II, 8

### GEORGIA POWER - PLANT HAMMOND

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010
The control configuration shown below is representative of the conditions present during Report 4.

Boiler ID Type NOx control SO2 control PM control Other control 4 dry bottom wall-fired (1) low NOX burner +

overfire air (2) cold-side electrostatic precipitator 

### The control configuration shown below is representative of the conditions present during Reports 5, 6, 7, 8, 9.

Boiler ID Type NOx control SO2 control PM control Other control 1 dry bottom wall-fired (1) low NOX burner (3) wet flue gas desulfurization (FGD, 1 vessel for all four units)(2) cold-side electrostatic precipitator

2 dry bottom wall-fired (1) low NOX burner (3) wet flue gas desulfurization (FGD, 1 vessel for all four units)(2) cold-side electrostatic precipitator

3 dry bottom wall-fired (1) low NOX burner (3) wet flue gas desulfurization (FGD, 1 vessel for all four units)(2) cold-side electrostatic precipitator

4 dry bottom wall-fired (1) low NOX burner +

overfire air (2) SCR (4) wet flue gas desulfurization (FGD, 1 vessel for all four units)(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 _X

___No ____ If yes, please note which reports and, in addition to the detailed description of the location of the sampling point(s) (question 8c above), include detail about how much, if any, bypass of unscrubbed flue gas was utilized at 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. Reports 8, 9 include testing at locations before a post combustion SO2 emission control device. No bypass of unscrubbed flue gas was utilized at the time of testing.

Page 45 of 61 part II, 8

### GEORGIA POWER - PLANT HAMMOND

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:

Units 1-4 (common stack/liner, scrubber stack): 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.

46

### Where 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 46 of 61 part II, 9-11

### GEORGIA POWER - PLANT HAMMOND

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, & 3 7/13/2006 See Attachment 1Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable 4 7/13/2006 See Attachment 2Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable 1, 2, & 3 2/6/2008 See Attachment 3Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable 4 2/6/2008 See Attachment 4Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable 1, 2, 3, & 4 4/22/2008 See Attachment 5Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable 1, 2, 3, & 4 4/24/2008 See Attachment 6Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable 4 4/20/2009-4/24/2009 Not applicable Not applicable Not applicable Not applicable Not applicable See Attachment 7Not applicable 1, 2, 3, & 4 6/13/2008-6/19/2008 Not applicable Not applicable Not applicable Not applicable See Attachment 8Not applicable Not applicable

47Provide emission test data for all tests conducted since January 1, 2005. Please indicate test data acquired both before and after any control device. Use additional pages as necessary. EPA may, at some future date, request a copy of one or more emission test reports. Data generated to fulfill both Federal and State requirements must be provided. Note that data generated pursuant to CAA Title V must be maintained and available for 5 years. Also include averaging times and measurement units for all pollutants. 48For each emissions test run the respondent should provide the following process information: Unit Load (MW), Net generation during run (MWh net), Flue gas moisture content (%), Flue gas flow rate (dscfm or Nm3/hr), Flue gas oxygen content (%, dry), Flue gas carbon dioxide content (%, dry), Flue gas temperature at sampling point (oF), Flue gas pressure at sampling point (atm), Standard temperature (oF), Standard pressure (atm).
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 47 of 61 part II, 12

## ATTACHMENT 1 - Hammond Report 1 Test Results

Performed By: Spectrum Systems, Inc., Pensacola, Florida

Run 1 Run 2 Run 3 Test Date 7/13/2006 7/13/2006 7/13/2006 Run Start Time 7:20 9:30 11:15 Run End Time 8:35 10:45 12:30 Meter Volume (dacf), Vm: 39.952 41.701 42.204 Sqrt Delta P ("wc): 0.99 1.00 1.00 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.41 29.41 29.40 Delta H ("wc): 1.3 1.3 1.3 Volume in Impingers (mls), VIc: 62.2 62.9 63.1 Static Pressure ("wc), Pg: -2.10 -1.90 -2.00 Stack Pressure ("Hg), Ps: 29.26 29.27 29.25 Stack Temperature (F), Ts: 286 291 293 Meter Coefficient (no units), Y: 0.997 0.997 0.997 Pitot Coefficient (no units) Cp: 0.840 0.840 0.840 Meter OutletTemperature (F), Tm: 101 106 109 Stack Diameter (inches): 252 252 252 Area Stack (sq. ft.), As: 346.36 346.36 346.36 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): 10.9 10.9 11.0 Percent O2 (% dry volume): 7.7 7.9 7.9 Percent (N2 + CO) (% dry volume): 81.4 81.1 81.1 Particulate Collected (mg), Mn: 86.2 69.3 64.8

Molec. Wt. Dry

(lb/lb-mole), Md: 30.048 30.067 30.071 Volume Water (scf), Vwstd 2.928 2.961 2.970 Meter Volume (dscf), Vmstd: 36.974 38.237 38.449 Wet Fraction (v/v), Bws: 0.073 0.072 0.072 Molec. Wt. Wet (lb/lb-mole), Ms: 29.164 29.199 29.205 Stack Gas Sampled (acf), Vma: 57.670 59.879 60.422 Averages Stack Gas Velocity

(fps), Vs: 66.30 67.14 67.56 67 Volumetric Flowrate (dscfm), Qs: 883,351 891,009 893,438 889,266 Volumetric Flowrate (acfm), Qa: 1,377,791 1,395,298 1,404,048 1,392,379 Grainloading (gr/dscf), cs: 0.0360 0.0279 0.0260 0.03 Emission Rate (lb/hour), E: 272.39 213.43 199.07 228.3 Percent Isokinetic Sampling (%), I: 100.28 102.82 103.10 102.07
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 3414.09 3391.38 3409.37 3404.95 Emission Rate (lbs/mmBtu), E: 0.08 0.06 0.06 0.07 Allowable Rate (lb/mmBtu): 0.240 0.240 0.240 0.240 Average Unit 1 Gross Load (MW) 99 99 99 99 

### Particulate Emission Results Summary

Hammond Units 1-3

Page 48 of 61 Att. 1

## ATTACHMENT 1 - Hammond Report 1 Test Results

Performed By: Spectrum Systems, Inc., Pensacola, Florida

Run 1 Run 2 Run 3 

### Particulate Emission Results Summary

Hammond Units 1-3

Average Unit 2 Gross Load (MW) 105 105 105 105 Average Unit 3 Gross Load (MW) 110 110 110 110 Average Sum Gross Load (MW) 313 314 314 314



### Page 49 of 61 Att. 1

## ATTACHMENT 2 - Hammond Report 2 Test Results

Performed Dy: Spectrum Systems, Inc., Pensacola, Florida

Run 1 Run 2 Run 3 Test Date 7/13/2006 7/13/2006 7/12/2006 Run Start Time 7:20 9:30 11:15 Run End Time 8:35 10:45 12:30 Meter Volume (dacf), Vm: 31.83 34.04 34.314 Sqrt Delta P ("wc): 1.17 1.20 1.18 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.41 29.41 29.40 Delta H ("wc): 0.8 0.9 0.9 Volume in Impingers (mls), VIc: 47.3 52.3 54.0 Static Pressure ("wc), Pg: -2.30 -2.30 -2.40 Stack Pressure ("Hg), Ps: 29.24 29.24 29.22 Stack Temperature (F), Ts: 315 318 323 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: 104 110 110 Stack Diameter (inches): 264 264 264 Area Stack (sq. ft.), As: 380.13 380.13 380.13 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): 12.1 12.2 12.1 Percent O2 (% dry volume): 7.0 6.9 7.0 Percent (N2 + CO) (% dry volume): 80.9 80.9 80.8 Particulate Collected (mg), Mn: 13.2 13.2 14.4

Molec. Wt. Dry

(lb/lb-mole), Md: 30.212 30.224 30.223 Volume Water (scf), Vwstd 2.226 2.462 2.542 Meter Volume (dscf), Vmstd: 29.010 30.737 30.931 Wet Fraction (v/v), Bws: 0.071 0.074 0.076 Molec. Wt. Wet (lb/lb-mole), Ms: 29.342 29.318 29.295 Stack Gas Sampled (acf), Vma: 46.888 50.070 50.811 Averages Stack Gas Velocity

(fps), Vs: 79.96 81.85 80.96 81 Volumetric Flowrate (dscfm), Qs: 1,128,402 1,146,081 1,124,093 1,132,859 Volumetric Flowrate (acfm), Qa: 1,823,822 1,866,946 1,846,563 1,845,777 Grainloading (gr/dscf), cs: 0.0070 0.0066 0.0072 0.01 Emission Rate (lb/hour), E: 67.76 64.96 69.28 67.3 Percent Isokinetic Sampling (%), I: 94.58 98.67 101.23 98.16
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 4593.06 4698.66 4575.52 4622.41 Emission Rate (lbs/mmBtu), E: 0.01 0.01 0.02 0.01 Allowable Rate (lb/mmBtu): 0.240 0.240 0.240 0.240 Average Unit Gross Load (MW) 475 481 482 479 

### Particulate Emission Results Summary

Hammond Unit 4

Page 50 of 61 Att. 2

## ATTACHMENT 3 - Hammond Report 3 Test Results

Performed By: Spectrum Systems, Inc., Pensacola, Florida

Run 1 Run 2 Run 3 Test Date 2/6/2008 2/6/2008 2/7/2008 Run Start Time 11:10 13:05 08:10 Run End Time 12:25 14:20 08:25 Meter Volume (dacf), Vm: 50.728 51.992 50.716 Sqrt Delta P ("wc): 1.01 1.01 1.00 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 28.98 28.98 29.25 Delta H ("wc): 2.2 2.1 2.1 Volume in Impingers (mls), VIc: 64.9 66.3 67.1 Static Pressure ("wc), Pg: -2.40 -2.30 -2.50 Stack Pressure ("Hg), Ps: 28.80 28.81 29.07 Stack Temperature (F), Ts: 278 279 261 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: 99 101 81 Stack Diameter (inches): 252 252 252 Area Stack (sq. ft.), As: 346.36 346.36 346.36 Nozzle Diameter (inches), dp: 0.240 0.240 0.240 Area Nozzle (sq. ft.), An: 0.000314 0.000314 0.000314 Percent CO2 (% dry volume): 11.0 11.1 11.0 Percent O2 (% dry volume): 8.1 7.9 8.0 Percent (N2 + CO) (% dry volume): 80.9 81.0 81.0 Particulate Collected (mg), Mn: 89.8 87.8 96.3

Molec. Wt. Dry

(lb/lb-mole), Md: 30.088 30.088 30.085 Volume Water (scf), Vwstd 3.055 3.121 3.158 Meter Volume (dscf), Vmstd: 46.032 47.006 48.004 Wet Fraction (v/v), Bws: 0.062 0.062 0.062 Molec. Wt. Wet (lb/lb-mole), Ms: 29.336 29.335 29.339 Stack Gas Sampled (acf), Vma: 71.285 72.851 71.941 Averages Stack Gas Velocity

(fps), Vs: 67.69 67.55 65.75 67 Volumetric Flowrate (dscfm), Qs: 908,331 905,724 911,738 908,598 Volumetric Flowrate (acfm), Qa: 1,406,650 1,403,714 1,366,373 1,392,246 Grainloading (gr/dscf), cs: 0.0301 0.0288 0.0309 0.03 Emission Rate (lb/hour), E: 234.36 223.88 241.77 233.3 Percent Isokinetic Sampling (%), I: 93.18 95.42 96.81 95.14
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 3421.76 3447.39 3452.44 3440.53 Emission Rate (lbs/mmBtu), E: 0.07 0.06 0.07 0.068 Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.240 Average Sum Gross Load (MW) 328 328 323 326 

### Particulate Emission Results Summary

Hammond Units 1-3

Page 51 of 61 Att. 3

## ATTACHMENT 4 - Hammond Report 4 Test Results

Performed Dy: Spectrum Systems, Inc., Pensacola, Florida

Run 1 Run 2 Run 3 Test Date 2/6/2008 2/6/2008 2/7/2008 Run Start Time 11:10 13:05 8:10 Run End Time 12:25 14:20 9:25 Meter Volume (dacf), Vm: 45.6 47.735 47.1 Sqrt Delta P ("wc): 1.20 1.22 1.24 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 28.98 28.98 29.25 Delta H ("wc): 1.7 1.8 1.8 Volume in Impingers (mls), VIc: 71.2 71.9 76.9 Static Pressure ("wc), Pg: -2.80 -2.70 -2.70 Stack Pressure ("Hg), Ps: 28.77 28.78 29.05 Stack Temperature (F), Ts: 308 310 287 Meter Coefficient (no units), Y: 0.998 0.998 0.998 Pitot Coefficient (no units) Cp: 0.840 0.840 0.840 Meter OutletTemperature (F), Tm: 90 89 72 Stack Diameter (inches): 264 264 264 Area Stack (sq. ft.), As: 380.13 380.13 380.13 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): 12.0 12.0 12.0 Percent O2 (% dry volume): 7.0 7.0 7.0 Percent (N2 + CO) (% dry volume): 81.0 80.9 81.0 Particulate Collected (mg), Mn: 45.6 45.6 26.7

Molec. Wt. Dry

(lb/lb-mole), Md: 30.204 30.207 30.205 Volume Water (scf), Vwstd 3.351 3.384 3.620 Meter Volume (dscf), Vmstd: 42.514 44.541 45.811 Wet Fraction (v/v), Bws: 0.073 0.071 0.073 Molec. Wt. Wet (lb/lb-mole), Ms: 29.312 29.345 29.312 Stack Gas Sampled (acf), Vma: 69.347 72.633 72.040 Averages Stack Gas Velocity

(fps), Vs: 82.13 83.66 83.26 83 Volumetric Flowrate (dscfm), Qs: 1,148,396 1,170,183 1,207,520 1,175,366 Volumetric Flowrate (acfm), Qa: 1,873,227 1,908,197 1,898,882 1,893,436 Grainloading (gr/dscf), cs: 0.0165 0.0158 0.0090 0.01 Emission Rate (lb/hour), E: 162.73 158.27 93.25 138.1 Percent Isokinetic Sampling (%), I: 97.34 100.09 99.76 99.06
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 4696.92 4763.13 4926.92 4795.65 Emission Rate (lbs/mmBtu), E: 0.03 0.03 0.02 0.029 Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.240 Average Unit Gross Load (MW) 485 486 487 486 

### Particulate Emission Results Summary

Hammond Unit 4

Page 52 of 61 Att. 4

## ATTACHMENT 5 - Hammond Report 5 Test Results

Performed By: Spectrum Systems, Inc., Pensacola, Florida

Run 1 Run 2 Run 3 Test Date 4/22/2008 4/22/2008 4/22/2008 Run Start Time 9:05 10:55 12:25 Run End Time 10:30 12:05 0:00 Meter Volume (dacf), Vm: 43.279 43.485 43.672 Sqrt Delta P ("wc): 0.97 0.98 0.98 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 28.85 28.90 28.90 Delta H ("wc): 1.4 1.4 1.4 Volume in Impingers (mls), VIc: 118.2 116.5 117.6 Static Pressure ("wc), Pg: -0.60 -0.60 -0.70 Stack Pressure ("Hg), Ps: 28.81 28.86 28.85 Stack Temperature (F), Ts: 121 121 121 Meter Coefficient (no units), Y: 0.998 0.998 0.998 Pitot Coefficient (no units) Cp: 0.840 0.840 0.840 Meter OutletTemperature (F), Tm: 85 89 90 Stack Diameter (inches): 396 396 396 Area Stack (sq. ft.), As: 855.30 855.30 855.30 Nozzle Diameter (inches), dp: 0.214 0.214 0.214 Area Nozzle (sq. ft.), An: 0.000249 0.000249 0.000249 Percent CO2 (% dry volume): 10.8 10.9 10.8 Percent O2 (% dry volume): 8.1 8.0 8.2 Percent (N2 + CO) (% dry volume): 81.1 81.1 81.0 Particulate Collected (mg), Mn: 51.1 68.0 32.3

Molec. Wt. Dry

(lb/lb-mole), Md: 30.056 30.064 30.056 Volume Water (scf), Vwstd 5.564 5.484 5.535 Meter Volume (dscf), Vmstd: 40.487 40.466 40.521 Wet Fraction (v/v), Bws: 0.121 0.119 0.120 Molec. Wt. Wet (lb/lb-mole), Ms: 28.599 28.624 28.607 Stack Gas Sampled (acf), Vma: 52.611 52.411 52.516 Averages Stack Gas Velocity

(fps), Vs: 58.42 59.05 59.32 59 Volumetric Flowrate (dscfm), Qs: 2,306,951 2,339,463 2,348,915 2,331,776 Volumetric Flowrate (acfm), Qa: 2,997,742 3,030,075 3,044,274 3,024,030 Grainloading (gr/dscf), cs: 0.0195 0.0259 0.0123 0.02 Emission Rate (lb/hour), E: 385.05 520.25 247.69 384.3 Percent Isokinetic Sampling (%), I: 100.46 99.01 98.75 99.41
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 8690.48 8858.74 8756.63 8768.62 Emission Rate (lbs/mmBtu), E: 0.04 0.06 0.03 0.04 Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.24 Average Unit 1 Gross Load (MW) 114 114 114 114 

### Particulate Emission Results Summary Hammond Units 1-4 FGD

Page 53 of 61 Att. 5

## ATTACHMENT 5 - Hammond Report 5 Test Results

Performed By: Spectrum Systems, Inc., Pensacola, Florida

Run 1 Run 2 Run 3 

### Particulate Emission Results Summary Hammond Units 1-4 FGD

Average Unit 2 Gross Load (MW) 115 115 115 115 Average Unit 3 Gross Load (MW) 115 116 117 116 Average Unit 4 Gross Load (MW) 500 500 500 500 Average Sum Gross Load (MW) 844 845 846 845



### Page 54 of 61 Att. 5

## ATTACHMENT 6 - Hammond Report 6 Test Results

Performed By: Spectrum Systems, Inc., Pensacola, Florida

Run 1 Run 2 Run 3 Test Date 4/24/2008 4/24/2008 4/24/2008 Run Start Time 14:30 16:35 18:40 Run End Time 15:50 18:00 19:50 Meter Volume (dacf), Vm: 43.725 45.122 44.007 Sqrt Delta P ("wc): 0.97 1.00 1.00 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 28.98 28.98 28.98 Delta H ("wc): 1.4 1.4 1.4 Volume in Impingers (mls), VIc: 118.6 121.2 117.6 Static Pressure ("wc), Pg: -0.60 -0.55 -0.50 Stack Pressure ("Hg), Ps: 28.94 28.94 28.94 Stack Temperature (F), Ts: 119 121 121 Meter Coefficient (no units), Y: 0.998 0.998 0.998 Pitot Coefficient (no units) Cp: 0.840 0.840 0.840 Meter OutletTemperature (F), Tm: 92 90 94 Stack Diameter (inches): 396 396 396 Area Stack (sq. ft.), As: 855.30 855.30 855.30 Nozzle Diameter (inches), dp: 0.214 0.214 0.214 Area Nozzle (sq. ft.), An: 0.000250 0.000250 0.000250 Percent CO2 (% dry volume): 11.2 11.3 11.1 Percent O2 (% dry volume): 8.0 8.1 8.1 Percent (N2 + CO) (% dry volume): 80.8 80.7 80.8 Particulate Collected (mg), Mn: 35.0 58.6 71.4

Molec. Wt. Dry

(lb/lb-mole), Md: 30.117 30.125 30.100 Volume Water (scf), Vwstd 5.583 5.705 5.535 Meter Volume (dscf), Vmstd: 40.553 41.993 40.656 Wet Fraction (v/v), Bws: 0.121 0.120 0.120 Molec. Wt. Wet (lb/lb-mole), Ms: 28.651 28.675 28.650 Stack Gas Sampled (acf), Vma: 52.343 54.279 52.574 Averages Stack Gas Velocity

(fps), Vs: 58.46 60.08 60.12 60 Volumetric Flowrate (dscfm), Qs: 2,324,458 2,385,435 2,385,780 2,365,224 Volumetric Flowrate (acfm), Qa: 3,000,222 3,083,378 3,085,124 3,056,241 Grainloading (gr/dscf), cs: 0.0133 0.0215 0.0271 0.02 Emission Rate (lb/hour), E: 265.60 440.32 554.50 420.1 Percent Isokinetic Sampling (%), I: 99.63 100.53 97.32 99.16
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 8801.92 8986.14 8964.09 8917.38 Emission Rate (lbs/mmBtu), E: 0.030 0.049 0.062 0.047 Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.24 Average Unit 1 Gross Load (MW) 115 115 115 115 

### Particulate Emission Results Summary Hammond Units 1-4 FGD CAM

Page 55 of 61 Att. 6

## ATTACHMENT 6 - Hammond Report 6 Test Results

Performed By: Spectrum Systems, Inc., Pensacola, Florida

Run 1 Run 2 Run 3 

### Particulate Emission Results Summary Hammond Units 1-4 FGD CAM

Average Unit 2 Gross Load (MW) 115 115 115 115 Average Unit 3 Gross Load (MW) 116 118 116 117 Average Unit 4 Gross Load (MW) 500 500 500 500 Average Sum Gross Load (MW) 846 848 846 847

Run 1 Run 2 Run 3 Test Date 4/24/2008 4/24/2008 4/24/2008 Run Start Time 7:35 9:25 11:50 Run End Time 8:50 10:40 13:05 Meter Volume (dacf), Vm: 52.048 53.105 54.32 Sqrt Delta P ("wc): 0.62 0.63 0.64 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.02 29.02 29.02 Delta H ("wc): 2.0 2.1 2.2 Volume in Impingers (mls), VIc: 141.2 142.6 148.0 Static Pressure ("wc), Pg: -0.27 -0.30 -0.36 Stack Pressure ("Hg), Ps: 29.00 29.00 28.99 Stack Temperature (F), Ts: 114 115 116 Meter Coefficient (no units), Y: 0.998 0.998 0.998 Pitot Coefficient (no units) Cp: 0.840 0.840 0.840 Meter OutletTemperature (F), Tm: 82 86 89 Stack Diameter (inches): 396 396 396 Area Stack (sq. ft.), As: 855.30 855.30 855.30 Nozzle Diameter (inches), dp: 0.292 0.292 0.292 Area Nozzle (sq. ft.), An: 0.000463 0.000463 0.000463 Percent CO2 (% dry volume): 8.3 8.4 8.2 Percent O2 (% dry volume): 11.2 11.2 11.4 Percent (N2 + CO) (% dry volume): 80.5 80.4 80.4 Particulate Collected (mg), Mn: 49.1 38.3 38.4

Molec. Wt. Dry

(lb/lb-mole), Md: 29.781 29.792 29.773 Volume Water (scf), Vwstd 6.646 6.712 6.966 Meter Volume (dscf), Vmstd: 49.296 50.006 50.847 Wet Fraction (v/v), Bws: 0.119 0.118 0.120 Molec. Wt. Wet (lb/lb-mole), Ms: 28.382 28.397 28.355 Stack Gas Sampled (acf), Vma: 62.754 63.731 65.054 Averages Stack Gas Velocity

(fps), Vs: 37.00 37.93 38.70 38 Volumetric Flowrate (dscfm), Qs: 1,491,368 1,527,488 1,552,367 1,523,741 Volumetric Flowrate (acfm), Qa: 1,898,523 1,946,732 1,986,097 1,943,784 Grainloading (gr/dscf), cs: 0.0154 0.0118 0.0116 0.01 Emission Rate (lb/hour), E: 196.49 154.61 154.99 168.7 Percent Isokinetic Sampling (%), I: 101.74 100.76 100.82 101.11



### Page 56 of 61 Att. 6

## ATTACHMENT 6 - Hammond Report 6 Test Results

Performed By: Spectrum Systems, Inc., Pensacola, Florida

Run 1 Run 2 Run 3 

### Particulate Emission Results Summary Hammond Units 1-4 FGD CAM

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 4246.42 4349.26 4328.97 4308.22 Emission Rate (lbs/mmBtu), E: 0.046 0.036 0.036 0.039 Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.24 Average Unit 1 Gross Load (MW) 115 115 115 115 Average Unit 2 Gross Load (MW) 40 40 41 40 Average Unit 3 Gross Load (MW) 40 40 41 40 Average Unit 4 Gross Load (MW) 180 180 180 180 Average Sum Gross Load (MW) 375 375 377 376



### Page 57 of 61 Att. 6

## ATTACHMENT 7 - Hammond Report 7 Test Results

Start Time End Time Unit Load Avg. Econ. Gas Outlet CO Avg.

Econ. Gas Outlet O2 Avg.

Econ. Gas Outlet CO2 Military Military 

### MW ppm % Dry % Dry
1 Full Load, "As Found", O2 SP @ 3.2%, SOFA in auto at 45% 4/20/2009 13:22 14:10 510 99 3.11 15.41

2 Full Load, "As Found", O2 SP @ 3.2%, SOFA in auto at 45% 4/20/2009 15:31 16:19 510 124 3.07 15.43

5 Full Load, O2 SP 3.8%, SOFA in auto at 50%, burner adjustments 4/21/2009 13:25 14:13 510 152 3.42 15.15

7 Full Load, O2 SP 3.5%, SOFA dampers in manual @ 25%, burner adjustments 4/22/2009 10:48 11:36 510 261 3.55 15.15

8 Full Load, O2 SP 3.4%, SOFA dampers in manual @ 25%, burner adjustments 4/22/2009 15:26 510 284 3.48 15.17

9 Full Load, O2 SP 3.5%, SOFA in auto @ 45%, final sleeve settings 4/23/2009 7:47 8:35 510 314 3.58 15.14

10 Minimum Load, No O2 Bias, SOFA closed at 5% 4/24/2009 8:03 8:51 225 31 5.74 13.11 Hammond Unit 4 LNB Optimization Test Results Summary

Title of Run Description Date



### Page 58 of 61 Att. 7

## ATTACHMENT 8 - Hammond Report 8 Test Results

Hammond Scrubber Performance Hg Test Results

Ontario Hydro Test Results Summary Inlet O2Outlet O2 %, dry %, dry Inlet HgO Inlet Hg+2 Inlet HgT % OxidizedOutlet HgOOutlet Hg+2Outlet HgT% Oxidized

1 6/13/2008 1602-1802 6.8 6.9 0.61 3.16 3.77 83.80% 0.62 0.77 1.39 55.40% 2 6/14/2008 1004-1204 6.8 6.9 0.23 3.99 4.22 94.50% 0.5 0.7 1.2 58.30% 3 6/15/2008 0953-1153 6.8 6.9 0.67 6.14 6.81 90.20% 0.92 0.27 1.19 22.70% 4 6/16/2008 1430-1630 6.8 6.9 0.65 5.9 6.55 90.10% 0.94 0.32 1.26 25.40% 5 6/17/2008 1009-1220 6.8 6.9 0.54 6.19 6.73 92.00% 0.71 0.07 0.78 9.00% 6 6/18/2008 1258-1458 6.8 6.9 0.45 4.99 5.44 91.70% 0.52 0.09 0.61 14.80% 7 6/18/2008 1743-1943 6.8 6.9 0.18 7.99 8.17 97.80% 1.17 0.08 1.25 6.40%

1 6/13/2008 1602-1802 6.8 6.9 0.83 4.3 5.13 83.80% 0.85 1.05 1.9 55.40% 75% 2 6/14/2008 1004-1204 6.8 6.9 0.31 5.43 5.74 94.50% 0.69 0.96 1.64 58.30% 76% 3 6/15/2008 0953-1153 6.8 6.9 0.91 8.35 9.26 90.20% 1.26 0.37 1.63 22.70% 91% 4 6/16/2008 1430-1630 6.8 6.9 0.88 8.03 8.91 90.10% 1.29 0.44 1.73 25.40% 90% 5 6/17/2008 1009-1220 6.8 6.9 0.73 8.42 9.16 92.00% 0.97 0.1 1.07 9.00% 96% 6 6/18/2008 1258-1458 6.8 6.9 0.61 6.79 7.4 91.70% 0.71 0.12 0.84 14.80% 97% 7 6/18/2008 1743-1943 6.8 6.9 0.24 10.87 11.11 97.80% 1.6 0.11 1.71 6.40% 87% 1Based upon guarantee equation – no credit given for elemental mercury removal, elemental re-emission noted in all cases. Absorber Outlet
UN-CORRECTED VALUES (ug/m3, actual O2, dry, 68 oF)

CORRECTED VALUES (ug/Nm3, 3% O2, dry, 0 oC) Hg2+ Removal Efficiency1 Date Time Run Absorber Inlet



### Page 59 of 61 Att. 8

## ATTACHMENT 8 - Hammond Report 8 Test Results

Hammond Scrubber Performance Hg Test Results
EPA Method 30B (Sorbent Trap) Summary Data – Absorber Inlet O2 Regular Trap %, dry Inlet HgOInlet Hg+2 Inlet HgT % Oxidized Inlet HgT

1 6/13/2008 1606-1806 6.8 2.29 1.54 3.85 40.00% 3.85 2 6/14/2008 1000-1200 6.8 2.06 1.9 4 47.50% 4 3 6/15/2008 0950-1150 6.8 na 0.6 na na 9.34 4 6/16/2008 1427-1627 6.8 6.85 3.05 9.93 30.70% 10.5 5 6/17/2008 1008-1208 6.8 3.71 4.34 8.08 53.70% 7.48 6 6/18/2008 1255-1455 6.8 2.45 2.32 4.79 48.40% 4.9 7 6/18/2008 1740-1940 6.8 2.69 2.06 4.77 43.20% 5.15

1 6/13/2008 1606-1806 6.8 3.12 2.09 5.24 40.20% 5.24 2 6/14/2008 1000-1200 6.8 2.8 2.58 5.44 48.00% 5.44 3 6/15/2008 0950-1150 6.8 na 0.82 na na 12.71 4 6/16/2008 1427-1627 6.8 9.32 4.15 13.51 30.80% 14.28 5 6/17/2008 1008-1208 6.8 5.05 5.9 10.99 53.90% 10.18 6 6/18/2008 1255-1455 6.8 3.33 3.16 6.52 48.60% 6.67 7 6/18/2008 1740-1940 6.8 3.66 2.8 6.49 43.40% 7.01 CORRECTED VALUES (ug/Nm3, 3% O2, dry, 0 oC) UN-CORRECTED VALUES (ug/m3, actual O2, dry, 68 oF) Speciated Trap Run Date Time



### Page 60 of 61 Att. 8

## ATTACHMENT 8 - Hammond Report 8 Test Results

Hammond Scrubber Performance Hg Test Results

Continuous Mercury Data – Daily Averages

Hg0 Hg+2 HgT % Hg+2 Hg0 Hg+2 HgT % Hg+2 6/12/2008 0821-2355 1.22 3.47 4.69 74% 1.02 0.07 1.09 6% -0.2 98% 6/13/2008 0003-2356 0.66 3.3 3.96 83% 0.58 0.05 0.63 8% -0.08 98% 6/14/2008 1026-2349 1.06 4.71 5.77 82% 1.27 0.19 1.46 13% 0.21 92% 6/15/2008 0149-2353 0.95 6.16 7.11 87% 1.31 0.14 1.45 10% 0.36 92% 6/16/2008 0908-1732 1.86 7.26 9.12 80% 2.98 0.12 3.1 4% 1.12 83% 6/17/2008 0151-1305 0.8 8.9 9.7 92% 1.12 0.04 1.16 3% 0.32 96% 6/18/2008 0151-1305 0.55 5.37 5.92 91% 0.92 0 0.92 0% 0.37 93% 6/19/2008 0000-1236 0.25 5.43 5.68 96% 0.38 0.05 0.43 12% 0.13 97%
Continuous Mercury Data –Averages Corresponding to Ontario Hydro Run Times

Hg0 Hg+2 HgT % Hg+2 Hg0 Hg+2 HgT % Hg+2 1 6/13/2008 1602-1802 0.91 3.08 3.99 77.20% 0.92 0.08 1 8.00% 0.01 97% 2 6/14/2008 1004-1204 0.66 3.46 4.12 84.00% 0.9 0.14 1.04 13.50% 0.24 89% 3 6/15/2008 0953-1153 1.16 5.5 6.66 82.60% 1.6 0.15 1.75 8.60% 0.44 89% 4 6/16/2008 1430-1630 1.78 7.59 9.37 81.00% 2.98 0.18 3.16 5.70% 1.2 82% 5 6/17/2008 1009-1220 1.41 7.65 9.06 84.40% 2.26 0.01 2.27 0.40% 0.85 89% 6 6/18/2008 1258-1458 0.64 5.42 6.06 89.40% 1.11 0.02 1.13 1.80% 0.47 91% 7 6/18/2008 1743-1943 0.55 5.22 5.77 90.50% 1.11 0.05 1.16 4.30% 0.56 88%Hg0 Reemission Hg+2

Removal - guarantee Hg+2 Removal - guarantee Date Time Inlet (ug/m3 @ 3% O2, 0 C) Outlet (ug/m3 @ 3% O2, 0 C) Hg0 Reemission

Run Date Time Inlet (ug/Nm3 @ 3% O2, dry, 0 C) Outlet (ug/Nm3 @ 3% O2, dry, 0 C)



### Page 61 of 61 Att. 8