### GEORGIA POWER - Submittal for PLANT MCINTOSH

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):

McIntosh 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):

6124 5 Complete street address of facility (physical location):

981 Old Augusta Road Rincon, Georgia, 31326 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 25 part I, 1-14

### GEORGIA POWER - Submittal for PLANT MCINTOSH

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? ___ coal

__X __ oil (including pet coke)

_ __ natural gas

_ __ other (specify in question 14 below) NOTE: McIntosh Unit 1 was on reserve shutdown during 2009 and thus no coal was burned. One startup on 12/31/2009 involved firing of fuel oil.

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)

_ __ 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 

### See response to Question 10. ____ lignite (% _____) ____ subbituminous (% _____) ____ bituminous (% _____) ____ anthracite (% _____) ____ coal refuse (including gob, culm, and subbituminous-derived coal refuse) (% _____) ____ synfuel (including, but not limited to, briquettes, pellets, or extrusions which are formed by binding materials, or processes that recycle materials) (%_____) (please specify the type or form of synfuel used ___________________________________________) ____ petroleum coke (% _____)

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 25 part I, 1-14

### GEORGIA POWER - Submittal for PLANT MCINTOSH

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. 2 If 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). 3 In 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"). 4 If 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).
5 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 was combusted (e.g., "the permitting agency allowed this fuel to be combusted for special testing and research purposes").



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

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

### Permitted to burn Yes Yes Yes 

### Actually burn

None in 2009 None in 2009 None in 2009



### Page 3 of 25 part I, 1-14

### GEORGIA POWER - PLANT MCINTOSH

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

1 bituminous CBI CBI 165 153 89 89.76 1800 2000 1000 1005 1000 1003 distillate oil (100%) (although the primary fuel for the unit is coal, no coal was fired during 2009 - see response to Part I Question 10) 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

While this unit burned oil for a short period, the contract data sheet indicates that the unit was designed to burn natural gas, oil, and pulverized coal. For the vast majority of the life of the unit, it has burned pulverized coal; thus the responses provided herein are based on the unit's use of pulverized coal. 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. 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.

Page 4 of 25 part I, 15

### GEORGIA POWER - PLANT MCINTOSH

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



### 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 an actual retirement date for Plant McIntosh Unit 1. 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 25 part I, 15

### GEORGIA POWER - PLANT MCINTOSH

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 are installed and available but have not operated since before 1/1/2005. Boiler ID 14 

### Type 15 

### NOx control 16 

### SO2 control 17 

### PM control 18 

### Other control 19 1 wall-fired (1) overfire air (2003) Not applicable (3) cold-side electrostatic precipitator (ESP) (1981) (2) flue gas conditioning - SO3 injection (4/1997) Not applicable

14 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).
15 Examples: tangential-fired; cyclone; wall-fired; circulating fluidized bed (CFB)
16 Examples: 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?
17 Examples: 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. 18 Examples: 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. 19 Please 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 25 part I, 16

### GEORGIA POWER - PLANT MCINTOSH

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 1 Not applicable Not applicable Not applicable Not applicable

20 A 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.
21 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). 

### Company (vendor) contact information Boiler ID 21 

### Company (vendor) name

Page 7 of 25 part I, 17

### GEORGIA POWER - PLANT MCINTOSH

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

1 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

22 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).
23 If additive is used, please indicate injection point.



### Page 8 of 25 part I, 18

### GEORGIA POWER - PLANT MCINTOSH

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 1 Not applicable Not applicable Not applicable Not applicable

24 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). 

### Company (vendor) contact information Boiler ID 24 

### Company (vendor) name

Page 9 of 25 part I, 19

### GEORGIA POWER - PLANT MCINTOSH

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
1 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

25 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).
26 If additive is used, please indicate injection point.



### Page 10 of 25 part I, 20

### GEORGIA POWER - PLANT MCINTOSH

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 HAP 31 

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

1 0.18 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

back-calculation of daily average sulfur content from SO2 CEMS data and supplier certification statement for No. 2 oil) Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable NOx Multi-Unit Plan: Southern Company Phase II

NOx Averaging Plan 0.46 lb/MMBtu annual average over all units (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. 

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



### Page 11 of 25 part I, 21

### GEORGIA POWER - PLANT MCINTOSH

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: NOTE: All guarantees are based on and demonstrated with certain fuel and operating conditions. Guarantees do not well represent 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 HAP 34 

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

1 ESP rebuild: 99.5 % collection efficiency filterable (expired in 1997) Not applicable Not

applicable Not applicable Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable Not applicable



### 23 Was 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 ID 32



### Page 12 of 25 part I, 22-23

### GEORGIA POWER - PLANT MCINTOSH

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 HAP 37 

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

daily average sulfur content of coal using SO2 CEMS; fuel oil sulfur content monitored through vendor certification; exceedances of 3% limit reported quarterly; records retained for 5 years. 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. 

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



### Page 13 of 25 part I, 24

### GEORGIA POWER - PLANT MCINTOSH

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.

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



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

### GEORGIA POWER - PLANT MCINTOSH

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:

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

6124

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



### Page 15 of 25 part II, 1

### GEORGIA POWER - PLANT MCINTOSH 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 County 42 

### Coal seam 43 

### % Sulf % Ash Btu/lb
10,390 1 KY KNOTT, FLOYD 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.52 12.68 12,931
10,172 1 KY KNOTT, FLOYD 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.42 12.02 13,067
9,723 1 KY KNOTT, FLOYD 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.45 11.33 13,187
10,235 1 KY KNOTT, FLOYD 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.35 11.13 13,221
10,113 1 KY KNOTT, FLOYD 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.19 13.46 12,842
10,004 1 KY KNOTT, FLOYD 5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, HAZARD #7 TRAIN 1.31 12.58 13,029

40 EPA recognizes that facilities have (sometimes) several months inventory and that the amount received is not necessarily the same as the amount fired.
41 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).
42 If known.
43 If known. 

### Vendor Analyses Fuel source Amount received, dry basis, short tons 40 

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

### Fuel shipment method

Page 16 of 25 part II, 2

### GEORGIA POWER - PLANT MCINTOSH 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

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

#1, Elkhorn #2, Elkhorn #3, Whitesburg, Hazard #4 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

09-222 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

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

#1, Elkhorn #2, Elkhorn #3, Whitesburg, Hazard #4 Train

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

#1, Elkhorn #2, Elkhorn #3, Whitesburg, Hazard #4 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

44 To 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.
45 Metal HAP includes compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, phosphorus, and selenium. 

### Fuel Shipment Method Total amount of fuel represented by sample, tons 

### Sample ID # State/ Country County Coal Seam Nickel, ppm Other trace metal HAP, ppm 45 

### Total Sulfur, % Ash

Content, % Heating Value, Btu/lb Mercury,

ppm Chlorine,

ppm Fluorine,

ppm

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### GEORGIA POWER - PLANT MCINTOSH

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)

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### GEORGIA POWER - PLANT MCINTOSH

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 K2O SiO2 Na2O SO3 TiO2
09-201 6.97 34.57 13.67 51.75 74.26 4.65 1.37 1.24 4.8 225 21.2 0.118 0.037 32.9 17.1 25.8 10 1.89 1.32 3.11 50.2 0.389 1.47 1.47 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 2.61 52.8 0.512 1.32 1.34 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 1.93 49.7 0.564 0.835 1.37 09-214 5.92 34.69 12.9 52.41 74.42 4.82 1.42 1.41 5.02 174 19.9 0.096 0.031 30.2 13.4 23 10.9 1.59 1.19 2.76 48.6 0.354 1.28 1.21 09-235 5.48 34.35 13.43 52.22 71.09 4.56 1.5 1.22 8.2 194 18.8 0.114 0.040 28.5 19.2 26.2 9.29 1.57 1.42 3.54 50.7 0.464 1.46 1.28 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 2.23 54.7 0.532 0.795 1.51 Sample ID # Proximate Analyses, % by wt Ultimate Analyses, % by wt Ash Mineralogy, % by wt Other Trace Metals, ppm, dry basis

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### GEORGIA POWER - PLANT MCINTOSH

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 Unit 1 Particulate Emissions Test (February 10, 2005) Report 2 Unit 1 Particulate Emissions Test (February 8, 2007)

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: 2/10/2005 Type: stack Constituents: PM Report 2 Date: 2/8/2007 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.

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### GEORGIA POWER - PLANT MCINTOSH

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

8f Did 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.

Boiler ID Type NOx control SO2 control PM control Other control 1 wall-fired (1) overfire air (2) cold-side electrostatic precipitator 

### 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.

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### GEORGIA POWER - PLANT MCINTOSH

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 yes 46 

### , 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.

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 22 of 25 part II, 9-11

### GEORGIA POWER - PLANT MCINTOSH

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 

### Hg 51 

### CO Other organics (specify)

1 2/10/2005 See Attachment 1 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable 1 2/7/2007 See Attachment 2 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable 1 1/20/2010 See Attachment 3 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

47 Provide 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.
48 For 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).
49 If 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 . 50 Metal 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.
51 Please 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 23 of 25 part II, 12

## ATTACHMENT 1 - McIntosh Report 1 Test Results

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

Run 1 Run 2 Run 3 Test Date 2/10/2005 2/10/2005 2/10/2005 Run Start Time 8:45 10:05 11:40 Run End Time 9:40 11:20 12:55 Meter Volume (dacf), Vm: 53.741 55.246 55.865 Sqrt Delta P ("wc): 1.39 1.41 1.42 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.95 29.95 29.95 Delta H ("wc): 2.6 2.6 2.7 Volume in Impingers (mls), VIc: 80.0 81.3 83.2 Static Pressure ("wc), Pg: -2.10 -2.10 -2.20 Stack Pressure ("Hg), Ps: 29.80 29.80 29.79 Stack Temperature (F), Ts: 267 268 268 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: 78 80 81 Stack Diameter (inches): 138 138 138 Area Stack (sq. ft.), As: 103.87 103.87 103.87 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): 12.8 12.7 12.9 Percent O2 (% dry volume): 6.5 6.4 6.5 Percent (N2 + CO) (% dry volume): 80.7 80.9 80.7 Particulate Collected (mg), Mn: 27.6 28.8 32.1

Molec. W t. Dry (lb/lb-mole), Md: 30.308 30.293 30.318 Volume W ater (scf), Vwstd 3.766 3.827 3.916 Meter Volume (dscf), Vmstd: 52.182 53.474 53.977 We t Fraction (v/v), Bws: 0.067 0.067 0.068 Molec. W t. W et (lb/lb-mole), Ms: 29.480 29.472 29.485 Stack Gas Sampled (acf), Vma: 77.355 79.317 80.176 Averages Stack Gas Velocity (fps), Vs: 91.08 91.87 92.61 92 Volumetric Flowrate (dscfm), Qs: 382,904 386,018 388,555 385,825 Volumetric Flowrate (acfm), Qa: 567,624 572,576 577,145 572,448 Grainloading (gr/dscf), cs: 0.0082 0.0083 0.0092 0.01 Emission Rate (lb/hour), E: 26.79 27.54 30.61 28.3 Percent Isokinetic Sampling (%), I: 96.30 97.89 98.17 97.45
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 1618.52 1640.18 1648.11 1635.60 Emission Rate (lbs/mmBtu), E: 0.017 0.017 0.019 0.017 Allowable Rate (lb/mmBtu): 0.180 0.180 0.180 0.180 Average Unit Gross Load (MW ) 165 165 166 165 

### Particulate Emission Results Summary

McIntosh Unit 1

Page 24 of 25 Att. 1

## ATTACHMENT 2 - McIntosh Report 2 Test Results

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

Run 1 Run 2 Run 3 Test Date 2/8/2007 2/8/2007 2/8/2007 Run Start Time 8:00 9:42 11:06 Run End Time 9:20 10:52 12:20 Meter Volume (dacf), Vm: 36.337 37.378 38.75 Sqrt Delta P ("wc): 1.45 1.45 1.45 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 30.06 30.00 30.00 Delta H ("wc): 1.3 1.3 1.3 Volume in Impingers (mls), VIc: 69.8 71.7 70.3 Static Pressure ("wc), Pg: -2.20 -2.30 -2.30 Stack Pressure ("Hg), Ps: 29.90 29.83 29.83 Stack Temperature (F), Ts: 265 269 273 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: 67 71 75 Stack Diameter (inches): 138 138 138 Area Stack (sq. ft.), As: 103.87 103.87 103.87 Nozzle Diameter (inches), dp: 0.174 0.174 0.174 Area Nozzle (sq. ft.), An: 0.000165 0.000165 0.000165 Percent CO2 (% dry volume): 13.4 13.5 13.5 Percent O2 (% dry volume): 6.1 6.2 6.1 Percent (N2 + CO) (% dry volume): 80.5 80.3 80.4 Particulate Collected (mg), Mn: 40.4 33.7 43.1

Molec. W t. Dry (lb/lb-mole), Md: 30.388 30.408 30.404 Volume W ater (scf), Vwstd 3.285 3.375 3.309 Meter Volume (dscf), Vmstd: 36.219 36.870 37.941 We t Fraction (v/v), Bws: 0.083 0.084 0.080 Molec. W t. W et (lb/lb-mole), Ms: 29.358 29.367 29.409 Stack Gas Sampled (acf), Vma: 54.251 55.712 57.443 Averages Stack Gas Velocity (fps), Vs: 94.56 94.99 95.21 95 Volumetric Flowrate (dscfm), Qs: 393,440 391,790 391,911 392,380 Volumetric Flowrate (acfm), Qa: 589,331 592,013 593,360 591,568 Grainloading (gr/dscf), cs: 0.0172 0.0141 0.0175 0.02 Emission Rate (lb/hour), E: 58.00 47.32 58.84 54.7 Percent Isokinetic Sampling (%), I: 96.57 98.72 101.56 98.95
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 1709.25 1690.58 1702.61 1700.81 Emission Rate (lbs/mmBtu), E: 0.034 0.028 0.035 0.032 Allowable Rate (lb/mmBtu): 0.180 0.180 0.180 0.180 Average Unit Gross Load (MW ) 165 166 165 165 

### Particulate Emission Results Summary

Plant McIntosh, Unit 1

Page 25 of 25 Att. 2