### GEORGIA POWER - Submittal for PLANT MCDONOUGH

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

1 Name of legal owner of facility:

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

3 Address of _X__ legal owner or ____ operator:

241 Ralph McGill Blvd NE, Bin 10221 Atlanta, GA 30308 4a Plant 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):

Jack McDonough 4b EIA 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):

710 5 Complete street address of facility (physical location):

5551 South Cobb Drive Smyrna, Georgia, 30080 6 Provide mailing address if different:

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

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

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

sasander@southernco.com 9 Is 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 34 part I, 1-14

### GEORGIA POWER - Submittal for PLANT MCDONOUGH

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

10 Which 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)

_X__ natural gas

_ __ other (specify in question 14 below)

11 Which of the following fossil fuel or other material(s) are permitted 1

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

_X__ coal

_X__ oil (including pet coke)

_X__ natural gas

_X__ other (specify in question 14 below)

12 If coal or solid fuel, as described below, derived from a fossil source is fired, indicate which rank of coal or solid fuel was utilized during the previous 12 months prior to the receipt of this ICR: 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 (% _____)

13 If 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 34 part I, 1-14

### GEORGIA POWER - Submittal for PLANT MCDONOUGH

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

14a If "other" was checked in questions 10 or 11 above indicating that any non-fossil fuel or other material (including, but not limited to, plastics, treated wood, rubber belting or gaskets, whole tires, tire-derived fuel, boiler cleaning solutions, animal wastes, etc.) is either utilized or permitted to be used, please indicate below what materials are combusted in the boiler and in what quantities (specify whether this quantity is on a weight percentage or heat [Btu] basis). Also indicate (yes/no) whether you are permitted 5

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

14b If "other" was checked in questions 10 or 11 above indicating that any non-fossil fuel or other material (including, but not limited to, plastics, treated wood, rubber belting or gaskets, whole tires, tire-derived fuel, boiler cleaning solutions, animal wastes, etc.) is either utilized or permitted to be used, were such material to be classified as "solid waste" under the Resource Conservation and Recovery Act and, thus make the utilizing unit subject to CAA section 129, would you continue to utilize (i.e., use as a fuel) the material? ____ Yes ____ 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"). None in 2009 Synfuel None in 2009

Yes None in 2009

None in 2009 None in 2009 Used Oil Yes Yes 

### Other Material Sawdust Biomass 

### Quantity/year None in 2009 None in 2009 

### Actually burn None in 2009 Yes 

### Permitted to burn

Page 3 of 34 part I, 1-14

### GEORGIA POWER - PLANT MCDONOUGH

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

15 Identification (or designation) of all coal- and oil-fired steam generating units (boilers) (as defined by Clean Air Act section 112(a)(8)) located at this facility. 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

MB1 bituminous CBI CBI 270 247 89.32 87.65 2400 2398 1000 984 1000 988 bituminous coal (100%), distillate oil (100%), natural gas CBI CBI Not applicable 2012

MB2 bituminous CBI CBI 270 247 89.32 88.68 2400 2401 1000 986 1000 989 bituminous coal (100%), distillate oil (100%), natural gas CBI CBI Not applicable 2011

6Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).
7Per fuel burned in the boiler. Report this based on higher heating value (HHV).
8Per fuel burned in the boiler. Report this based on higher heating value (HHV).
9Please indicate if more than one steam reheat cycle is utilized, and, if so, please provide information for both.
10Please indicate if more than one steam reheat cycle is utilized, and, if so, please provide information for both.
11Indicate the fuels utilized for the indicated boiler, and percentages, as indicated in questions 11 - 13.
12The "hours/year operated" would be the average of the actual number of hours the unit operated in 1 year based on the last 3 years of operation.
13This can be treated as CBI and can be submitted through the proper CBI procedure if desired. 

### NOTES: Original Design Fuel

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

Page 4 of 34 part I, 15

### GEORGIA POWER - PLANT MCDONOUGH

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

15 Identification (or designation) of all coal- and oil-fired steam generating units (boilers) (as defined by Clean Air Act section 112(a)(8)) located at this facility. SEE NOTES BELOW for explanations of responses.Boiler ID6Original design fuel (i.e.,coal rank or type of oil)Design heat input,(MMBtu/hr)7Present maximum heatinput, (MMBtu/hr)8MWe Gross capacitysummerMWe Net CapacitysummerOriginal design grossefficiency (%, HHV)Present operating grossefficiency (%, HHV)Design steam pressure(psig)Operating steam pressure(psig)Design steam temperature(oF)Operating steamtemperature (oF)Design steam reheattemperature (oF)9Operating steam reheattemperature (oF)10Fuel11Hours/year operated12Average annual capacityfactor for the past 3 yearsApplicable NSPSEstimated year ofretirement13



### Present Operating Gross Efficiency Based on the most recent actual test of the boiler efficiency, unless no recent boiler efficiency test was available. Where no recent test was available, that status is indicated. Design Steam Pressure Based on the thermal design of the unit as represented on the turbine heat balance sheet. Operating Steam Pressure Represents the average throttle pressure when the unit operated at gross normal full load over a three year period (January 2007 to December 2009). Design Steam Temperature Based on the thermal design of the unit as represented on the turbine heat balance sheet. Operating Steam Temperature Represents the average steam temperature when the unit operated at gross normal full load over a three year period (January 2007 to December 2009). Design Steam Reheat Temperature Based on the thermal design of the unit as represented on the turbine heat balance sheet. Operating Steam Reheat Temperature Represents the average reheat steam temperature when the unit operated at gross normal full load over a three year period (January 2007 to December 2009). Fuel Indicates the fuels burned in the previous calendar year (January to December 2009). Hours/Year Operated Confidential Business Information Annual Average Capacity Factor for the Past 3 Years Confidential Business Information Applicable NSPS Where no NSPS is identified, the unit is not currently subject to any NSPS. Retirement YearGeorgia Power is currently constructing combined-cycle units at the McDonough site. The existing coal units will be retired before the commercial operation date (COD) of the new combinedcycle units. Unit MB2 will be retired before Blocks 4 and 5 COD. Unit MB1 will be retired before Block 6 COD.

Page 5 of 34 part I, 15

### GEORGIA POWER - PLANT MCDONOUGH

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

16 For each boiler noted in Part I, question 15, provide the following information for each current emission control device installed and operating and/or planned (please designate the order of the emission controls - 1 for the first control following the boiler, 2 for the second control following the boiler, etc.): NOTE: SO3 flue gas conditioning systems are operated on an as-needed basis. Boiler ID 14 

### Type 15 

### NOx control 16 

### SO2 control 17 

### PM control 18 

### Other control 19
MB1 tangential-fired (1) low NOX burner + overfire air (2002, replaced existing system) Not applicable (3) cold-side electrostatic precipitator (ESP) (4/1972, replaced original ESP) (2) flue gas conditioning - SO3 injection (10/1993) Not applicable

MB2 tangential-fired (1) low NOX burner + overfire air (2001, replaced existing system) Not applicable (3) cold-side electrostatic precipitator (ESP) (4/1972, replaced original ESP) (2) flue gas conditioning - SO3 injection (10/1993) Not applicable

14Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).
15Examples: tangential-fired; cyclone; wall-fired; circulating fluidized bed (CFB)
16Examples: low-NOx burners; selective catalytic reduction (SCR); selective non-catalytic reduction (SNCR); over-fire air (OFA). Include specific date that control went online or planned operational date for new installation. If this boiler's control configuration utilizes a SCR, please include the type of material from which the catalyst is manufactured and the type of reductant used in with the SCR (e.g., anhydrous ammonia, urea, other). Also, please note if the catalyst is specifically designed to reduce SO3 formation?
17Examples: wet flue gas desulfurization (FGD; any type); dry scrubbing (any type); specify whether calcium- or sodium-based. Include specific date that control went online or planned operational date for new installation.
18Examples: fabric filter; cold-side electrostatic precipitator (ESP); hot-side ESP; cyclone or multiclone; venturi scrubber. Include specific date that control went online or planned operational date for new installation.
19Please indicate systems installed specifically to control any other pollutants (e.g., Hg, SO3, etc.). Examples: activated carbon injection (ACI); Powerspan ECO®; dry sorbent injection or wet ESP for SO3 control; flue gas conditioning to control opacity (e.g., SO3 injection, ammonia, other); additive use for mercury control (e.g., bromine; scrubber additives). Include specific date that control went online or planned operational date for new installation. Also include any pollutants controlled by this technology (e.g., control technology [pollutant controlled]).



### Page 6 of 34 part I, 16

### GEORGIA POWER - PLANT MCDONOUGH

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

17 For each boiler noted in Part I, question 15, provide the company (prime vendor) name and company contact information for each HAP-specific (e.g., mercury, hydrogen chloride) control technology that you have either contracted for, are installing, or have installed for the purpose of participating in a control technology demonstration project 20

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

Name Telephone Address MB1 Not applicable Not applicable Not applicable Not applicable MB2 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 ID 21 

### Company (vendor) name

Page 7 of 34 part I, 17

### GEORGIA POWER - PLANT MCDONOUGH

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

18 For the control technologies identified in Part I, question 17, provide the date of actual start-up of the demonstration (if the control is currently operating), the date of expected or projected start-up, the date the demonstration was completed, the type of HAP control installed (e.g., sorbent and type; pre-combustion boiler chemical additive; combustion boiler chemical additive), the desired HAP emission reduction or rate (if any), and the coal rank(s) 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 ID 22 

### 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 additive 23

### ) Desired HAP

emission reduction (%) or emission rate Coal rank(s) in use

MB1 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable MB2 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 8 of 34 part I, 18

### GEORGIA POWER - PLANT MCDONOUGH

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

19 For each boiler noted in Part I, question 15, provide the company (prime vendor) name and company contact information for each HAP (e.g., mercury, hydrogen chloride, etc.) control technology that you have either contracted for, are installing, or have installed for the purpose of provide a non-demonstration, full-scale operating system.

Name Telephone Address MB1 Not applicable Not applicable Not applicable Not applicable MB2 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 ID 24 

### Company (vendor) name

Page 9 of 34 part I, 19

### GEORGIA POWER - PLANT MCDONOUGH

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

20 For the control technologies identified in Part I, question 19, provide the date of actual start-up (if the control is currently operating), the date of expected or projected start-up, the type of HAP control installed (e.g., sorbent and type; pre-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 ID 25 

### Actual start-up date Expected or projected start-up date Type of control (e.g.,

sorbent and type; chemical additive) 26 

### Guaranteed HAP

emission reduction (%) or emission rate Sorbent or additive

feed rate on which guarantee is based Coal rank(s) upon

which guarantee is based

MB1 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable MB2 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 10 of 34 part I, 20

### GEORGIA POWER - PLANT MCDONOUGH

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

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

PM 28 

### PM 10(29) 

### PM 2.5 (30) 

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

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

MB1 0.24 lb/MMBtu (Title V permit; based on 3-run

stack test using Method 5 of 17; test conducted every 13 months, but may be deferred for 12 months if test results from the previous annual tests are fifty percent or less of the limit) Not applicable Not

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

analysis of coal sample acquired for each operating day and supplier certification statement for No. 2 oil)
5% of potential combustion concentration (95% removal by FGD), effective May 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: 0.24 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).

MB2 0.24 lb/MMBtu (Title V permit; based on 3-run

stack test using Method 5 of 17; test conducted every 13 months, but may be deferred for 12 months if test results from the previous annual tests are fifty percent or less of the limit) Not applicable Not

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

analysis of coal sample acquired for each operating day and supplier certification statement for No. 2 oil)
5% of potential combustion concentration (95% removal by FGD), effective Jan 1, 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: 0.24 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).

27Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).
28If the boiler has separate permitted emission limits for filterable and condensable PM, respectively, please indicate those separate limits. Also include the compliance test method utilized.
29 List the compliance test method utilized.
30List the compliance test method utilized.
31Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, phosphorus, and selenium; indicate permit level for all metal HAP for which a permit level has been developed. 

### Permitted emission limit (indicate type of permit and format of emission limit)
Boiler ID 27



### Page 11 of 34 part I, 21

### GEORGIA POWER - PLANT MCDONOUGH

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

22 For 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.

PM 33 

### PM 10 

### PM 2.5 

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

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

MB1 ESP: 99.0 % collection efficiency filterable

(expired in 1972) Not applicable Not

applicable Not applicable Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable Low Nox burners: 0.40 lb/MMBtu (expired in

1996)

MB2 ESP: 99.0 % collection efficiency filterable

(expired in 1972) Not applicable Not

applicable Not applicable Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable Low Nox burners: 0.23 lb/MMBtu (expired in

2002)



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

_X___ No Please elaborate.

32Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).
33If the boiler has separate guaranteed emission rate for filterable and condensable PM, respectively, please indicate those separate emission rates.
34Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, cobalt, lead, manganese, nickel, phosphorus, and selenium; indicate permit level for all metal HAP for which a permit level has been developed.

### Most recent guaranteed emission rate for each pollutant for which there is a permitted emission limit
Boiler ID 32



### Page 12 of 34 part I, 22-23

### GEORGIA POWER - PLANT MCDONOUGH

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

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

PM 36 

### PM 10 

### PM 2.5 

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

### Hg CO Other organics (specify) MB1 Stack test conducted every 13 months, but may be deferred for 12 months if test results

from the previous annual tests are fifty percent or less of the limit; under the CAM plan, opacity monitored continuously by COMS, excursions (3-hour block averages greater than 40%) reported quarterly.
The facility shall submit 30-day advance notifications of required testing and test reports within 60 days of completion of the testing. All records related to the Title V permit are retained for five years. Not applicable Not

applicable Coal sulfur content monitored through daily coal sampling;

fuel oil sulfur content monitored through vendor certification; exceedances of 3% limit reported quarterly; records retained for 5 years. Effective May 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

MB2 Stack test conducted every 13 months, but may be deferred for 12 months if test results

from the previous annual tests are fifty percent or less of the limit; under the CAM plan, opacity monitored continuously by COMS, excursions (3-hour block averages greater than 40%) reported quarterly.
The facility shall submit 30-day advance notifications of required testing and test reports within 60 days of completion of the testing. All records related to the Title V permit are retained for five years. Not applicable Not

applicable Coal sulfur content monitored through daily coal sampling;

fuel oil sulfur content monitored through vendor certification; exceedances of 3% limit reported quarterly; records retained for 5 years. Effective Jan 1, 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

35Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).
36If the boiler's monitoring, recordkeeping, and reporting requirements require your company to monitoring, keep records, and report filterable and condensable PM separately, please describe the separate actions required.
37Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, phosphorus, and selenium; indicate permit level for all metal HAP for which a permit level has been developed. 

### Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a permitted emission limit
Boiler ID 35



### Page 13 of 34 part I, 24

### GEORGIA POWER - PLANT MCDONOUGH

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

25 For 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]

26 Are any other means of emission control (for any pollutant) employed on any boiler noted in Part I, question 15 (e.g., low-ash coal, coal or oil with low trace constituents, etc.)? Please specify. No.

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



### Page 14 of 34 part I, 25-26

### GEORGIA POWER - PLANT MCDONOUGH

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

PART II: FUEL ANALYSIS AND EMISSION DATA
Fuel Analysis 39



### 1a Plant or facility name from Part I, question 4a:

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

710

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



### Page 15 of 34 part II, 1

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

2 For 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 seam 43 

### % Sulf % Ash Btu/lb 9,614 MB1, MB2 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.22 9.07 13,656 10,029 MB1, MB2 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.27 8.58 13,668

10,568 MB1, MB2 KY PERRY, LETCHER AMBURGY, HAZARD #4, HAZARD TRAIN 0.94 10.36 13,451

10,632 MB1, MB2 KY PERRY, LETCHER AMBURGY, HAZARD #4, HAZARD TRAIN 0.83 8.89 13,771

9,996 MB1, MB2 KY LETCHER LOW SPLINT, HIGH SPLINT, WINIFREDE, HARLAN TRAIN 1.05 12.21 13,281

10,210 MB1, MB2 KY LETCHER LOW SPLINT, HIGH SPLINT, WINIFREDE, HARLAN TRAIN 1 11.64 13,408

10,295 MB1, MB2 KY LETCHER LOW SPLINT, HIGH SPLINT, WINIFREDE, HARLAN TRAIN 0.97 10.8 13,510

10,297 MB1, MB2 KY LETCHER LOW SPLINT, HIGH SPLINT, WINIFREDE, HARLAN TRAIN 1.05 10.53 13,560

10,365 MB1, MB2 KY LETCHER LOW SPLINT, HIGH SPLINT, WINIFREDE, HARLAN TRAIN 1 9.39 13,773 

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

### ID # of boiler(s) firing fuel 41 

### Fuel shipment method

Page 16 of 34 part II, 2

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

2 For 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 seam 43 

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

### ID # of boiler(s) firing fuel 41 

### Fuel shipment method

10,186 MB1, MB2 KY LETCHER LOW SPLINT, HIGH SPLINT, WINIFREDE, HARLAN TRAIN 0.94 10.01 13,557

10,388 MB1, MB2 KY LETCHER LOW SPLINT, HIGH SPLINT, WINIFREDE, HARLAN TRAIN 0.94 10.47 13,574

10,217 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1.05 10.13 13,620

10,200 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.95 10.53 13,537

10,396 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.96 10.5 13,537

10,208 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.96 9.28 13,773

10,174 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1 10.94 13,497

10,178 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.99 11.42 13,360



### Page 17 of 34 part II, 2

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

2 For 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 seam 43 

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

### ID # of boiler(s) firing fuel 41 

### Fuel shipment method

9,878 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1.04 11 13,535

10,227 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1 11.19 13,454

10,331 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.95 11.33 13,457

10,370 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.92 10.19 13,620

10,338 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.96 13.05 13,140

10,361 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1 9.88 13,690

10,383 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1.08 9.47 13,736

10,516 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1.09 9.67 13,652



### Page 18 of 34 part II, 2

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

2 For 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 seam 43 

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

### ID # of boiler(s) firing fuel 41 

### Fuel shipment method

11,090 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1.1 9.63 13,698

10,327 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1.1 9.94 13,682

10,217 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1.1 10.68 13,513

10,349 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1.05 10.02 13,649

10,273 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.98 9.88 13,580

10,336 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1.02 10.1 13,641

10,428 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1.04 10.26 13,520

11,636 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.95 10.13 13,630



### Page 19 of 34 part II, 2

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

2 For 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 seam 43 

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

### ID # of boiler(s) firing fuel 41 

### Fuel shipment method

10,381 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.94 9.9 13,656

10,523 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.93 9.51 13,737

10,350 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1.09 9.56 13,748

10,722 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1.05 9.23 13,771

10,366 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.99 9.28 13,796

10,026 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.97 9.73 13,712

10,090 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.93 10.51 13,536

10,063 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.87 9.85 13,627



### Page 20 of 34 part II, 2

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

2 For 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 seam 43 

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

### ID # of boiler(s) firing fuel 41 

### Fuel shipment method

10,341 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1.03 11.18 13,430

10,313 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.89 9.93 13,597

10,287 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.99 11.42 13,481

10,193 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.97 10.33 13,560

10,395 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.98 9.94 13,669

10,422 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.92 10.98 13,455

10,412 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.95 10.13 13,557

10,262 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.96 10.44 13,578



### Page 21 of 34 part II, 2

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

2 For 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 seam 43 

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

### ID # of boiler(s) firing fuel 41 

### Fuel shipment method

10,315 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.98 9.98 13,682

10,246 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.93 10.83 13,529

10,364 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1.05 10.99 13,556

10,403 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1.06 10.19 13,622

10,411 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1.15 11.62 13,367

10,520 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1.08 10.85 13,444

10,319 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.92 12.02 13,240

10,279 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1.09 10.8 13,535



### Page 22 of 34 part II, 2

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

2 For 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 seam 43 

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

### ID # of boiler(s) firing fuel 41 

### Fuel shipment method

10,407 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.96 10.31 13,495

10,444 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 1 11.78 13,369

10,454 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.98 9.12 13,609

10,003 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.91 11.05 13,482

10,494 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.9 12 13,308

10,284 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.91 11.79 13,371

10,435 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.92 10.82 13,512

10,506 MB1, MB2 KY HARLAN HARLAN, HIGH SPLINT, IMBODE, LOW SPLINT, WINIFREDE TRAIN 0.93 9.52 13,716



### Page 23 of 34 part II, 2

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

2 For 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 seam 43 

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

### ID # of boiler(s) firing fuel 41 

### Fuel shipment method 10,688 MB1, MB2 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.89 12.32 13,245 10,563 MB1, MB2 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.86 10.05 13,539

40EPA recognizes that facilities have (sometimes) several months inventory and that the amount received is not necessarily the same as the amount fired.
41Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).
42If known.
43If known.



### Page 24 of 34 part II, 2

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

3 For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information 44

### , 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

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

4R, Hazard 8, Hazard 7 Train

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

5A, Alma Train

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

4R, Hazard 8, Hazard 7 Train

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

4R, Hazard 8, Hazard 7 Train

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

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

09-418 12,392 1.12 11.36 13,390 ND 111 89 13.9 1.3 9.7 2.1 <0.02 17.3 8.0 8.8 26.4 2.4 KY Harlan Highsplint, Winifrede, Low splint, Lower Harlan, D seam, Kellioki, Imbodden, Owl Train

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

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

### Sample ID # State/ Country County Fuel Shipment Method Nickel, ppm Other trace metal HAP, ppm 45 

### Total Sulfur, % Ash

Content, % Heating Value, Btu/lb Mercury,

ppm Chlorine,

ppm Fluorine,

ppm Coal Seam

Page 25 of 34 part II, 3

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

3 For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information 44

### , 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 Total amount of fuel represented by sample, tons 

### Sample ID # State/ Country County Fuel Shipment Method Nickel, ppm Other trace metal HAP, ppm 45 

### Total Sulfur, % Ash

Content, % Heating Value, Btu/lb Mercury,

ppm Chlorine,

ppm Fluorine,

ppm Coal Seam

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

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

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

#4 rider, Hazard #7, Hazard #8, Hazard #9 Train

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

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

44To the extent that a vendor provides these data or that a facility is required by State or local agency to analyze its fuel for HAP constituents (e.g., Cl, F), and any metallic HAP (e.g., Hg, Pb, As, Se, etc.), EPA wishes the responding facility to provide those fuel analyses results. Otherwise, this 12-month fuel analysis requirement can be bypassed by the respondent.
45Metal HAP includes compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, phosphorus, and selenium.



### Page 26 of 34 part II, 3

### GEORGIA POWER - PLANT MCDONOUGH

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

4 Were 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__)

5 Analyses 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 6 Name and address of laboratory performing analyses:

Georgia Power Environmental Lab (same as above)

Page 27 of 34 part II, 4-6

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

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

Total

Moisture Volatiles Ash Fixed Carbon Carbon Hydrogen Nitrogen Total Sulfur Oxygen Barium Copper Magnesium Sodium Vanadium Zinc Al2O3 Fe2O3 CaO MgO MnO2 P2O5 K2O SiO2 Na2O SO3 TiO2
09-222 6.43 36.45 8.72 54.83 74.25 4.95 1.82 0.89 9.37 92 17.0 0.045 0.035 26.1 14.9 27.2 6.94 1.34 0.819 ND ND 1.93 49.7 0.564 0.835 1.37 09-240 7.39 35.3 9.46 55.23 75.99 4.79 1.72 1.01 7.04 92 16.2 0.051 0.032 26.4 15.8 25.5 7.8 1.54 0.916 ND ND 2.23 54.7 0.532 0.795 1.51 09-206 6.27 36.41 12.5 51.09 74.39 4.94 1.59 1.58 5 132 25.4 0.083 0.041 42.5 32.7 24.7 12.4 1.66 1.04 ND ND 2.35 48.4 0.494 0.938 1.36 09-208 6.52 36.53 10.53 52.94 76.33 4.92 1.65 1.01 5.56 112 19.3 0.073 0.032 28.2 19.2 26.3 8.31 1.78 1.13 ND ND 2.61 52.8 0.512 1.32 1.34 09-404 6.37 34.25 10.64 55.11 77.44 4.83 1.51 0.96 4.6 122 20.9 0.071 0.034 33.5 15.7 27.4 7.05 1.59 0.955 ND ND 2.68 53.7 0.422 0.878 1.43 09-407 6.02 36.85 9.83 53.32 75.27 4.88 1.77 1.82 6.43 102 20.6 0.069 0.016 46.6 20.6 24.6 16.7 3.07 0.895 ND 1.68 ND 44.6 0.203 0.636 1.34 09-418 5.99 34.06 11.36 54.58 75.53 4.88 1.48 1.12 5.63 102 20.7 0.075 0.037 35.9 16.4 26.4 8.43 1.58 1.02 ND ND 2.53 49.3 0.532 1.15 1.52 09-419 6.23 36.36 9.59 54.05 74.33 4.91 1.81 1.33 8.04 82 20.6 0.069 0.015 43.3 26.4 25.7 13.9 2.52 1.18 ND 1.26 2.39 45.3 0.29 0.809 1.37 09-424 6.46 34.53 10.8 54.66 75.06 4.72 1.6 1.06 6.76 81 27.0 0.062 0.030 40.6 17.6 28.3 5.86 1.56 0.979 ND ND 2.37 54 0.453 1.28 1.54 09-432 6.09 35 10.22 54.78 75.13 4.76 1.61 1.24 7.05 92 19.9 0.052 0.036 30.3 17.3 24.4 8.4 1.27 0.791 ND ND 1.98 52.8 0.469 0.888 1.47 09-435 4.86 35.82 8.52 55.65 76.05 4.94 1.87 1.38 7.23 193 18.6 0.058 0.016 37.1 16.9 26 13.8 2.7 1.03 ND 1.35 2.15 44.5 0.314 1.28 1.28 09-442 6.98 36.33 9.79 53.88 75.62 4.89 1.71 1.44 6.55 92 22.8 0.052 0.035 36.1 30.4 24.5 10.5 1.73 0.902 ND ND 2.2 57.8 0.553 0.979 1.53 09-443 6.03 34.1 10.3 55.59 76.39 4.73 1.53 0.9 6.14 81 19.5 0.064 0.033 32.1 14.7 25.8 6 1.92 0.922 ND ND 2.28 55.1 0.463 1.3 1.54 09-445 4.07 36.77 8.45 54.77 76.74 4.91 1.83 1.53 6.55 193 18.2 0.058 0.016 39.9 16.8 24.5 14.5 3.11 1.02 ND 1.45 2.08 46.9 0.308 0.971 1.35 Sample ID # Proximate Analyses, % by wt Ultimate Analyses, % by wt Ash Mineralogy, % by wt Other Trace Metals, ppm, dry basis

Page 28 of 34 part II, 7

### GEORGIA POWER - PLANT MCDONOUGH

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

8a What emission test report(s), parametric monitoring data, and other data or monitoring are available for the boilers noted in Part I, question 15, for tests conducted since January 1, 2005. Please consider reports prepared for all testing and monitoring programs, for all pollutants, including (but not limited to) those required under Title V, compliance with State or local requirements, fulfillment of contractual obligations, U.S. Department of Energy (DOE) programs, etc. (NOTE: EPA is not requesting copies of the test reports or data at this time; however we may request actual copies in the future.) Use additional pages as necessary.

Report 1 Units 1&2 Particulate Emissions Test (February 17, 2005) Report 2 Units 1&2 Particulate Emissions Test (February 21, 2007) Report 3 Units 1&2 Particulate Emissions Test (October 22, 2008)
8b Please indicate the date(s) and types (e.g., stack, fuel, parametric, etc.) of the test(s) and the constituents (including criteria and hazardous air pollutants) sampled for: Report 1 Date: 2/17/2005 Type: stack Constituents: PM Report 2 Date: 2/21/2007 Type: stack Constituents: PM Report 3 Date: 10/22/2008 Type: stack Constituents: PM

8c Do any of these test reports reflect testing at a location upstream of any emission control devices? Yes ____ No _X

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

8d Were 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.

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

___ If yes, please note which reports.

8f Did the unit's control configuration differ from that shown in Part I, question 16, at the time of these test results? Yes ____ No _X

___ If yes, please list the unit's complete control configuration at time of testing in a similar format to Part I, question 16.
8g Do any of these test reports reflect testing at a location before a post combustion SO2 emission control device (e.g., FGD, SDA, Dry Scrubber)? Yes ____ No _X

___ If yes, please note which reports and, in addition to the detailed description of the location of the sampling point(s) (question 8c above), include detail about how much, if any, bypass of unscrubbed flue gas was utilized at at the time of testing (including percentage of total scrubber flue gas flow). Note by diagram where sampling ports were located in relation to the bypass ductwork.

Page 29 of 34 part II, 8

### GEORGIA POWER - PLANT MCDONOUGH

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

9 What 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

10 Are 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

11 Are continuous emissions monitoring system (CEMS) data available (e.g., mercury, continuous opacity monitoring systems) that are not already being provided to the U.S. EPA, 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.

COMS data are available for the last five years or more.

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



### Page 30 of 34 part II, 9-11

### GEORGIA POWER - PLANT MCDONOUGH

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

12 For 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 PM 49 

### SO2 HCl/HF/HCN Metal HAP 50 

### Hg51 

### CO Other organics (specify)
MB1, MB2 

### 2/17/2005 See Attachment 1 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable MB1, MB2 

### 2/21/2007 See Attachment 2 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable MB1, MB2 

### 10/22/2008 See Attachment 3 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

47Provide emission test data for all tests conducted since January 1, 2005. Please indicate test data acquired both before and after any control device. Use additional pages as necessary. EPA may, at some future date, request a copy of one or more emission test reports. Data generated to fulfill both Federal and State requirements must be provided. Note that data generated pursuant to CAA Title V must be maintained and available for 5 years. Also include averaging times and measurement units for all pollutants.
48For each emissions test run the respondent should provide the following process information: Unit Load (MW), Net generation during run (MWh net), Flue gas moisture content (%), Flue gas flow rate (dscfm or Nm 3/hr), Flue gas oxygen content (%, dry), Flue gas carbon dioxide content (%, dry), Flue gas temperature at sampling point ( o F), Flue gas pressure at sampling point (atm), Standard temperature ( o F), 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, PM 10, and PM 2.5 . 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 31 of 34 part II, 12

## ATTACHMENT 1 - McDonough Report 1 Test Results

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

Run 1 Run 2 Run 3 Test Date 2/17/2005 2/17/2005 2/17/2005 Run Start Time 6:20 7:45 09:12 Run End Time 7:30 8:55 10:22 Meter Volume (dacf), Vm: 35.905 35.767 36.764 Sqrt Delta P ("wc): 0.92 0.91 0.93 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.11 29.11 29.11 Delta H ("wc): 1.1 1.1 1.1 Volume in Impingers (mls), VIc: 60.0 59.2 60.8 Static Pressure ("wc), Pg: -1.60 -1.80 -1.70 Stack Pressure ("Hg), Ps: 28.99 28.98 28.99 Stack Temperature (F), Ts: 265 266 265 Meter Coefficient (no units), Y: 0.983 0.983 0.983 Pitot Coefficient (no units) Cp: 0.840 0.840 0.840 Meter OutletTemperature (F), Tm: 67 69 70 Stack Diameter (inches): 312 312 312 Area Stack (sq. ft.), As: 530.93 530.93 530.93 Nozzle Diameter (inches), dp: 0.212 0.212 0.212 Area Nozzle (sq. ft.), An: 0.000245 0.000245 0.000245 Percent CO2 (% dry volume): 11.3 11.4 11.3 Percent O2 (% dry volume): 7.5 7.5 7.6 Percent (N2 + CO) (% dry volume): 81.3 81.1 81.1 Particulate Collected (mg), Mn: 59.5 66.8 59.1

Molec. Wt. Dry

(lb/lb-mole), Md: 30.102 30.129 30.108 Volume Water (scf), Vwstd 2.824 2.787 2.862 Meter Volume (dscf), Vmstd: 34.514 34.212 35.105 Wet Fraction (v/v), Bws: 0.076 0.075 0.075 Molec. Wt. Wet (lb/lb-mole), Ms: 29.187 29.215 29.195 Stack Gas Sampled (acf), Vma: 52.928 52.521 53.839 Ave rages Stack Gas Velocity

(fps), Vs: 61.12 60.55 61.55 61 Volumetric Flowrate (dscfm), Qs: 1,269,702 1,256,448 1,278,436 1,268,195 Volumetric Flowrate (acfm), Qa: 1,947,117 1,928,867 1,960,680 1,945,555 Grainloading (gr/dscf), cs: 0.0266 0.0301 0.0260 0.03 Emission Rate (lb/hour), E: 289.25 324.46 284.41 299.4 Percent Isokinetic Sampling (%), I: 98.42 98.59 99.42 98.81
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 5012.91 4932.92 4991.11 4978.98 Emission Rate (lbs/mmBtu), E: 0.058 0.066 0.057 0.060 Allowable Rate (lb/mmBtu): 0.240 0.240 0.240 0.240 Average Unit 1 Gross Load (MW ) 271 270 271 271 Average Unit 2 Gross Load (MW ) 271 271 270 271 Average Sum Gross Load (MW ) 542 541 541 541 

### Particulate Emission Results Summary

McDonough Unit 1-2

Page 32 of 34 Att. 1

## ATTACHMENT 2 - McDonough Report 2 Test Results

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

Run 1 Run 2 Run 3 Test Date 2/21/2007 2/21/2007 2/21/2007 Run Start Time 8:20 9:50 11:15 Run End Time 9:30 11:00 12:25 Meter Volume (dacf), Vm: 36.05 36.191 37.781 Sqrt Delta P ("wc): 0.89 0.90 0.90 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.00 29.00 29.05 Delta H ("wc): 1.1 1.1 1.1 Volume in Impingers (mls), VIc: 54.6 53.2 54.8 Static Pressure ("wc), Pg: -2.40 -2.40 -2.60 Stack Pressure ("Hg), Ps: 28.82 28.82 28.86 Stack Temperature (F), Ts: 277 279 281 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: 73 75 77 Stack Diameter (inches): 312 312 312 Area Stack (sq. ft.), As: 530.93 530.93 530.93 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): 12.4 12.2 12.2 Percent O2 (% dry volume): 7.1 7.1 7.1 Percent (N2 + CO) (% dry volume): 80.5 80.6 80.7 Particulate Collected (mg), Mn: 40.6 46.9 47.2

Molec. Wt. Dry

(lb/lb-mole), Md: 30.272 30.243 30.231 Volume Water (scf), Vwstd 2.570 2.504 2.579 Meter Volume (dscf), Vmstd: 34.254 34.252 35.681 Wet Fraction (v/v), Bws: 0.070 0.068 0.067 Molec. Wt. Wet (lb/lb-mole), Ms: 29.416 29.409 29.406 Stack Gas Sampled (acf), Vma: 53.331 53.414 55.663 Ave rages Stack Gas Velocity

(fps), Vs: 59.62 60.07 60.64 60 Volumetric Flowrate (dscfm), Qs: 1,219,874 1,227,014 1,238,194 1,228,361 Volumetric Flowrate (acfm), Qa: 1,899,270 1,913,445 1,931,613 1,914,776 Grainloading (gr/dscf), cs: 0.0183 0.0211 0.0204 0.02 Emission Rate (lb/hour), E: 191.16 222.14 216.79 210.0 Percent Isokinetic Sampling (%), I: 99.54 98.96 102.15 100.22
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 4953.45 4958.43 5015.73 4975.87 Emission Rate (lbs/mmBtu), E: 0.04 0.04 0.04 0.042 Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.240 Average Unit 1 Gross Load (MW ) 271 271 271 271 Average Unit 2 Gross Load (MW ) 271 270 270 270 Average Sum Gross Load (MW ) 542 541 541 541 

### Particulate Emission Results Summary

McDonough Unit 1-2

Page 33 of 34 Att. 2

## ATTACHMENT 3 - McDonough Report 3 Test Results

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

Run 1 Run 2 Run 3 Test Date 10/22/2008 10/22/2008 10/22/2008 Run Start Time 9:25 10:55 12:25 Run End Time 10:30 12:05 13:35 Meter Volume (dacf), Vm: 38.708 39.698 39.347 Sqrt Delta P ("wc): 0.91 0.92 0.92 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.38 29.38 29.38 Delta H ("wc): 1.2 1.2 1.2 Volume in Impingers (mls), VIc: 58.7 61.8 60.3 Static Pressure ("wc), Pg: -2.60 -2.50 -2.70 Stack Pressure ("Hg), Ps: 29.19 29.20 29.18 Stack Temperature (F), Ts: 275 281 281 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: 70 74 76 Stack Diameter (inches): 312 312 312 Area Stack (sq. ft.), As: 530.93 530.93 530.93 Nozzle Diameter (inches), dp: 0.217 0.217 0.217 Area Nozzle (sq. ft.), An: 0.000257 0.000257 0.000257 Percent CO2 (% dry volume): 12.1 12.3 12.2 Percent O2 (% dry volume): 6.9 7.1 6.9 Percent (N2 + CO) (% dry volume): 80.9 80.6 80.9 Particulate Collected (mg), Mn: 51.8 46.7 64.1

Molec. Wt. Dry

(lb/lb-mole), Md: 30.219 30.251 30.233 Volume Water (scf), Vwstd 2.763 2.909 2.838 Meter Volume (dscf), Vmstd: 37.909 38.563 38.118 Wet Fraction (v/v), Bws: 0.068 0.070 0.069 Molec. Wt. Wet (lb/lb-mole), Ms: 29.389 29.391 29.386 Stack Gas Sampled (acf), Vma: 58.028 59.611 58.900 Ave rages Stack Gas Velocity

(fps), Vs: 60.28 61.24 61.32 61 Volumetric Flowrate (dscfm), Qs: 1,254,382 1,262,106 1,264,186 1,260,225 Volumetric Flowrate (acfm), Qa: 1,920,139 1,950,991 1,953,424 1,941,518 Grainloading (gr/dscf), cs: 0.0211 0.0187 0.0260 0.02 Emission Rate (lb/hour), E: 226.52 202.27 281.31 236.7 Percent Isokinetic Sampling (%), I: 104.19 105.34 103.95 104.49
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 5142.67 5124.94 5195.23 5154.28 Emission Rate (lbs/mmBtu), E: 0.04 0.04 0.05 0.05 Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.240 Average Unit 1 Gross Load (MW ) 270 271 270 270 Average Unit 2 Gross Load (MW ) 271 271 271 271 Average Sum Gross Load (MW ) 541 541 541 541 

### Particulate Emission Results Summary

McDonough Unit 1-2

Page 34 of 34 Att .3