### GEORGIA POWER - Submittal for PLANT KRAFT

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):

Kraft 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):

733 5 Complete street address of facility (physical location):

Crossgate Road at Savannah River Port Wentworth, Georgia 31407 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 32 part I, 1-14

### GEORGIA POWER - Submittal for PLANT KRAFT

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 ____ 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 

### Not applicable ____ distillate (% _____)

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

Page 2 of 32 part I, 1-14

### GEORGIA POWER - Submittal for PLANT KRAFT

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").

Propane Yes Yes Yes Yes Used Oil None in 2009 None in 2009 None in 2009 None in 2009 None in 2009 None in 2009 None in 2009

None in 2009 

### Permitted to burn Other Material Sawdust Biomass 

### Quantity/year Actually burn

Page 3 of 32 part I, 1-14

### GEORGIA POWER - PLANT KRAFT

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 50 48 88.92 Not available 1450 1421 1000 997 1000 996 bituminous coal (100%), natural gas CBI CBI Not applicable None

planned

2 bituminous CBI CBI 54 50 88.92 Not available 1450 1434 1000 996 1000 995 bituminous coal (100%), natural gas CBI CBI Not applicable None

planned

3 bituminous CBI CBI 107 101 89.44 Not available 1860 1857 1000 1000 1000 996 bituminous coal (100%), natural gas CBI CBI Not applicable None

planned

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

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

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

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

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

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

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

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

### NOTES: Original Design Fuel

Based on the original contract boiler data sheet; only the primary fuel is listed if multiple fuels were included on the data sheet. Design Heat Input Confidential Business Information Present Maximum Heat Input Confidential Business Information MWe Gross Capacity Summer Identifies the gross normal full load. Georgia Power does not change unit capacities season from season. 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 32 part I, 15

### GEORGIA POWER - PLANT KRAFT

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 Year Georgia Power has not committed to actual retirement dates for Plant Kraft Units 1-3. 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 32 part I, 15

### GEORGIA POWER - PLANT KRAFT

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.):

Boiler ID 14 

### Type 15 

### NOx control 16 

### SO2 control 17 

### PM control 18 

### Other control 19
1 tangential-fired Not applicable Not applicable (4) cold-side electrostatic precipitator (ESP) (1978) Not applicable

2 tangential-fired Not applicable Not applicable (4) cold-side electrostatic precipitator (ESP) (1978) Not applicable

3 tangential-fired Not applicable Not applicable (4) cold-side electrostatic precipitator (ESP) (1978) 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 32 part I, 16

### GEORGIA POWER - PLANT KRAFT

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 2 Not applicable Not applicable Not applicable Not applicable 3 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 32 part I, 17

### GEORGIA POWER - PLANT KRAFT

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 2 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable 3 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

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 32 part I, 18

### GEORGIA POWER - PLANT KRAFT

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 2 Not applicable Not applicable Not applicable Not applicable 3 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 32 part I, 19

### GEORGIA POWER - PLANT KRAFT

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 2 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable 3 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

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 32 part I, 20

### GEORGIA POWER - PLANT KRAFT

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 E = 0.7 x (10/R)^0.202, where E equals the allowable particulate emission rate in pounds per million Btu heat input and R equals the heat input in million Btu per hour (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) 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).

2 E = 0.7 x (10/R)^0.202, where E equals the allowable particulate emission rate in pounds per million Btu heat input and R equals the heat input in million Btu per hour (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) 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).

3 E = 0.7 x (10/R)^0.202, where E equals the allowable particulate emission rate in pounds per million Btu heat input and R equals the heat input in million Btu per hour (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) 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).

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 32 part I, 21

### GEORGIA POWER - PLANT KRAFT

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 HAP 34 

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

1 Not applicable Not applicable Not

applicable Not applicable Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable Not applicable



### 2 ESP rebuild: 0.05 lb/MMBtu filterable (expired in 2002) Not applicable Not

applicable Not applicable Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable Not applicable



### 3 ESP rebuild: 0.05 lb/MMBtu filterable (expired in 2002) 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?

_X___ Yes ____ No Please elaborate. Unit 1 ESP was rebuilt in 2001. PM guarantee of 0.05 lb/MMBtu was specified. During final contract negotiations, the requirement for guaranteed emission rates was waived.

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 32 part I, 22-23

### GEORGIA POWER - PLANT KRAFT

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 daily coal sampling;

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

2 Stack test conducted every 13 months, but may be deferred for 12 months if test results from the previous annual tests are fifty percent or less of the limit; under the CAM plan, opacity monitored continuously by COMS, excursions (3-hour block averages greater than 39%) 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. Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable

3 Stack test conducted every 13 months, but may be deferred for 12 months if test results from the previous annual tests are fifty percent or less of the limit; under the CAM plan, opacity monitored continuously by COMS, excursions (3-hour block averages greater than 38%) 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. 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 32 part I, 24

### GEORGIA POWER - PLANT KRAFT

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 32 part I, 25-26

### GEORGIA POWER - PLANT KRAFT

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:

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

733

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



### Page 15 of 32 part II, 1

### GEORGIA POWER - PLANT KRAFT 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 10,809 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 1.02 15.09 13,034 10,033 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.85 12.11 13,499 9,693 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.92 12.14 13,458 10,281 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.95 12.5 13,397 10,127 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.84 12.09 13,417 10,094 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.85 12.24 13,393 10,210 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.9 12.63 13,370 10,053 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.89 11.54 13,532 9,334 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.92 12.38 13,460 9,367 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.9 13.17 13,236 10,211 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.91 11.89 13,401 9,922 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.82 12.86 13,328 10,056 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.87 12.42 13,398 9,881 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.93 11.5 13,559 9,811 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.9 12.23 13,466 10,058 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.9 13.08 13,297 10,010 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.93 12.85 13,329 10,076 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.99 12.93 13,265 10,090 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 1.14 12.81 13,384 10,114 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.88 12.68 13,386 9,941 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.95 13.25 13,190 10,016 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.9 13.1 13,227 9,908 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.93 11 13,616 9,885 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.95 13.2 13,247 

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

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

### Fuel shipment method

Page 16 of 32 part II, 2

### GEORGIA POWER - PLANT KRAFT 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 tons 40 

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

### Fuel shipment method 9,884 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.95 13.49 13,218 9,581 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.89 12.34 13,415 9,964 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.93 13.05 13,234 9,759 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.86 12.59 13,390 9,719 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.87 13.2 13,298 9,802 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.94 12.39 13,337 9,841 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 1 13.68 13,199 9,853 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.95 13.23 13,274 9,809 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.97 13.54 13,194 9,177 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 1.07 12.25 13,457 9,707 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.98 10.51 13,704 8,361 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.93 12.98 13,331 8,803 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 1.08 13.87 13,159 N/A 1, 2, 3 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN N/A N/A N/A

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 17 of 32 part II, 2

### GEORGIA POWER - PLANT KRAFT 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

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

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

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



### Page 18 of 32 part II, 3

### GEORGIA POWER - PLANT KRAFT

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 19 of 32 part II, 4-6

### GEORGIA POWER - PLANT KRAFT

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

09-535 6.75 37.55 9.27 53.18 74.41 4.84 1.6 1.35 8.53 62 21.3 0.045 0.033 35.5 15.3 30.1 11.7 2.59 0.809 ND ND 1.89 48.5 0.545 1.51 1.34 Sample ID # Proximate Analyses, % by wt Ultimate Analyses, % by wt Ash Mineralogy, % by wt Other Trace Metals, ppm, dry basis

Page 20 of 32 part II, 7

### GEORGIA POWER - PLANT KRAFT

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 (September 20, 2005) Report 2 Unit 2 Particulate Emissions Test (September 20, 2006) Report 3 Unit 3 Particulate Emissions Test (September 21, 2006) Report 4 Unit 1 Particulate Emissions Test (September 27, 2007) Report 5 Unit 2 Particulate Emissions Test (August 27, 2008) Report 6 Unit 3 Particulate Emissions Test (August 28, 2008) Report 7 Unit 1 Particulate Emissions Test (September 9, 2009)

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: 9/20/2005 Type: stack Constituents: PM Report 2 Date: 9/20/2006 Type: stack Constituents: PM Report 3 Date: 9/21/2006 Type: stack Constituents: PM Report 4 Date: 9/27/2007 Type: stack Constituents: PM Report 5 Date: 8/27/2008 Type: stack Constituents: PM Report 6 Date: 8/28/2008 Type: stack Constituents: PM Report 7 Date: 9/9/2009 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.

Page 21 of 32 part II, 8

### GEORGIA POWER - PLANT KRAFT

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

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 22 of 32 part II, 8

### GEORGIA POWER - PLANT KRAFT

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.

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 23 of 32 part II, 9-11

### GEORGIA POWER - PLANT KRAFT

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 9/20/2005 See Attachment 1 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable 2 9/20/2006 See Attachment 2 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable 3 9/20/2006 See Attachment 3 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable 1 9/27/2007 See Attachment 4 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable 2 8/27/2008 See Attachment 5 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable 3 8/28/2008 See Attachment 6 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable 1 9/9/2009 See Attachment 7 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 24 of 32 part II, 12

## ATTACHMENT 1 - Kraft Report 1 Test Results

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

Run 1 Run 2 Run 3 Test Date 9/20/2005 9/20/2005 9/20/2005 Run Start Time 10:23 12:15 13:58 Run End Time 11:33 13:23 15:03 Meter Volume (dacf), Vm: 46.12 46.908 47.461 Sqrt Delta P ("wc): 1.25 1.26 1.26 Sam pling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 30.20 30.20 30.21 Delta H ("wc): 1.9 1.9 1.9 Volum e in Im pingers (mls), VIc: 90.0 86.4 87.0 Static Pressure ("wc), Pg: -0.85 -0.82 -0.81 Stack Pressure ("Hg), Ps: 30.14 30.14 30.15 Stack Temperature (F), Ts: 355 355 355 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: 83 87 85 Stack Diameter (inches): 96x64.5 96x64.5 96x64.5 Area Stack (sq. ft.), As: 43.00 43.00 43.00 Nozzle Diam eter (inches), dp: 0.214 0.214 0.214 Area Nozzle (sq. ft.), An: 0.000249 0.000249 0.000249 Percent CO2 (% dry

volum e): 12.3 12.4 12.3 Percent O2 (% dry

volum e): 6.9 6.9 7.0 Percent (N2 + CO) (% dry volum e): 80.8 80.7 80.7 Particulate Collected (mg), Mn: 27.8 27.4 28.1

Molec. W t. Dry

(lb/lb-mole), Md: 30.244 30.260 30.248 Volum e W ater (scf), Vwstd 4.236 4.067 4.095 Meter Volume (dscf), Vmstd: 44.669 45.081 45.828 Wet Fraction (v/v), Bws: 0.087 0.083 0.082 Molec. W t. W et (lb/lb-mole), Ms: 29.183 29.246 29.243 Stack Gas Sampled (acf), Vma: 74.952 75.295 76.478 Averages Stack Gas Velocity

(fps), Vs: 86.64 86.91 87.16 86.90 Volum etric Flowrate (dscfm), Qs: 133,219 134,249 134,743 134,071 Volum etric Flowrate (acfm), Qa: 223,531 224,223 224,861 224,205 Grainloading (gr/dscf), cs: 0.0096 0.0094 0.0094 0.01 Em ission Rate (lb/hour), E: 10.95 10.79 10.91 10.88 Percent Isokinetic Sampling (%), I: 96.72 96.86 98.11 97.23
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 547.47 551.70 549.78 549.65 Emission Rate (lbs/mmBtu), E: 0.02 0.02 0.02 0.02 Allowable Rate (lb/mmBtu): 0.31 0.31 0.31 0.31 Average Unit Gross Load (MW ) 49 49 48 49 

### Particulate Emission Results Summary

Kraft Unit 1

Page 25 of 32 Att. 1

## ATTACHMENT 2 - Kraft Report 2 Test Results

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

Run 1 Run 2 Run 3 Test Date 9/20/2006 9/20/2006 9/20/2006 Run Start Time 8:00 9:50 11:28 Run End Time 9:24 11:10 12:47 Meter Volume (dacf), Vm: 55.638 55.203 58.524 Sqrt Delta P ("wc): 1.21 1.20 1.25 Sam pling Time (min): 70 70 70 Barometric Pressure ("Hg), Pbar: 30.06 30.06 30.06 Delta H ("wc): 1.9 1.9 2.0 Volum e in Im pingers (mls), VIc: 84.2 85.2 87.0 Static Pressure ("wc), Pg: -0.10 -0.20 -0.20 Stack Pressure ("Hg), Ps: 30.05 30.05 30.05 Stack Temperature (F), Ts: 358 358 358 Meter Coefficient (no units), Y: 0.997 0.997 0.997 Pitot Coefficient (no units) Cp: 0.840 0.840 0.840 Meter OutletTemperature (F), Tm: 78 83 88 Stack Diameter (inches): 109.25x64.5 109.25x64.5 109.25x64.5 Area Stack (sq. ft.), As: 48.93 48.93 48.93 Nozzle Diam eter (inches), dp: 0.214 0.214 0.214 Area Nozzle (sq. ft.), An: 0.000250 0.000250 0.000250 Percent CO2 (% dry

volum e): 11.4 11.5 11.6 Percent O2 (% dry

volum e): 7.5 7.6 7.5 Percent (N2 + CO) (% dry volum e): 81.1 81.0 80.9 Particulate Collected (mg), Mn: 50.0 42.0 40.8

Molec. W t. Dry

(lb/lb-mole), Md: 30.125 30.137 30.152 Volum e W ater (scf), Vwstd 3.963 4.010 4.095 Meter Volume (dscf), Vmstd: 54.931 54.035 56.738 Wet Fraction (v/v), Bws: 0.067 0.069 0.067 Molec. W t. W et (lb/lb-mole), Ms: 29.309 29.299 29.334 Stack Gas Sampled (acf), Vma: 90.867 89.586 93.904 Averages Stack Gas Velocity

(fps), Vs: 83.82 82.92 86.27 84 Volum etric Flowrate (dscfm), Qs: 148,778 146,850 153,042 149,556 Volum etric Flowrate (acfm), Qa: 246,109 243,465 253,293 247,623 Grainloading (gr/dscf), cs: 0.0141 0.0120 0.0111 0.01 Em ission Rate (lb/hour), E: 17.92 15.09 14.55 15.9 Percent Isokinetic Sampling (%), I: 103.16 102.81 103.58 103.18
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 583.75 574.75 600.48 586.33 Emission Rate (lbs/mmBtu), E: 0.031 0.026 0.024 0.027 Allowable Rate (lb/mmBtu): 0.308 0.309 0.306 0.308 Average Unit Gross Load (MW ) 51 51 52 51 

### Particulate Emission Results Summary

Kraft Unit 2

Page 26 of 32 Att. 2

## ATTACHMENT 3 - Kraft Report 3 Test Results

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

Run 1 Run 2 Run 3 Test Date 9/21/2006 9/21/2006 9/21/2006 Run Start Time 8:15 10:10 11:50 Run End Time 9:40 11:25 13:06 Meter Volume (dacf), Vm: 38.983 39.575 39.24 Sqrt Delta P ("wc): 1.26 1.27 1.26 Sam pling Time (min): 64.000 64.000 64.000 Barometric Pressure ("Hg), Pbar: 30.190 30.190 30.190 Delta H ("wc): 1.111 1.140 1.124 Volum e in Im pingers (mls), VIc: 76.900 74.200 76.100 Static Pressure ("wc), Pg: -1.100 -1.050 -1.200 Stack Pressure ("Hg), Ps: 30.11 30.11 30.10 Stack Temperature (F), Ts: 255 257 259 Meter Coefficient (no units), Y: 0.997 0.997 0.997 Pitot Coefficient (no units) Cp: 0.840 0.840 0.840 Meter OutletTemperature (F), Tm: 79 87 90 Stack Diameter (inches): 79x79 79x79 79x79 Area Stack (sq. ft.), As: 43.34 43.34 43.34 Nozzle Diam eter (inches), dp: 0.178 0.178 0.178 Area Nozzle (sq. ft.), An: 0.000173 0.000173 0.000173 Percent CO2 (% dry

volum e): 11.4 11.5 11.5 Percent O2 (% dry

volum e): 7.7 7.6 7.6 Percent (N2 + CO) (% dry volum e): 80.9 80.9 80.9 Particulate Collected (mg), Mn: 18.9 18.1 17.7

Molec. W t. Dry

(lb/lb-mole), Md: 30.131 30.143 30.143 Volum e W ater (scf), Vwstd 3.620 3.493 3.582 Meter Volume (dscf), Vmstd: 38.482 38.517 38.012 Wet Fraction (v/v), Bws: 0.086 0.083 0.086 Molec. W t. W et (lb/lb-mole), Ms: 29.088 29.133 29.097 Stack Gas Sampled (acf), Vma: 56.649 56.710 56.315 Averages Stack Gas Velocity

(fps), Vs: 81.62 82.72 82.29 82 Volum etric Flowrate (dscfm), Qs: 144,170 146,105 144,440 144,905 Volum etric Flowrate (acfm), Qa: 212,234 215,111 213,990 213,778 Grainloading (gr/dscf), cs: 0.008 0.007 0.007 0.007 Em ission Rate (lb/hour), E: 9.34 9.08 8.90 9.11 Percent Isokinetic Sampling (%), I: 104.67 103.38 103.20 103.75
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 560.03 571.83 565.32 565.73 Emission Rate (lbs/mmBtu), E: 0.017 0.016 0.016 0.016 Allowable Rate (lb/mmBtu): 0.310 0.309 0.310 0.310 Average Unit Gross Load (MW ) 103 103 103 103 

### Particulate Emission Results Summary

Kraft Unit 3

Page 27 of 32 Att. 3

## ATTACHMENT 4 - Kraft Report 4 Test Results

Performed by : TRC Environmental Corporation, Raleigh, North Carolina

RUN NUMBER M5-1 M5-2 M5-3 RUN DATE 9/27/2007 9/27/2007 9/27/2007 AVERAGE RUN TIME 0745-0856 0940-1045 1125-1230

MEAS URED DA

TA Meter Box Y 1.0013 1.0013 1.0013 1.0013 Avg Delta H, inches H2O 2.073 2.102 2.036 2.070 Barometric Pressure, inches Hg 30.00 30.03 30.00 30.01 Volum e Metered, cubic feet 47.422 47.703 47.139 47.421 Average Meter Temp, deg F 84.2 88.3 95.3 89.25 Static Pressure, inches H2O 0.5 0.5 0.5 0.500 Average Stack Temp, deg F 368.3 370.3 371.7 370.1 Water Collected, mL 102.9 103.6 94.4 100.3 Carbon Dioxide, % 12.613 12.557 12.538 12.569 Oxygen, % 6.507 6.547 6.545 6.533 Nitrogen, % 80.88 80.90 80.92 80.898 Pitot Tube Coefficient 0.84 0.84 0.84 0.84 Avg Sqrt Delta P, (inches H2O) 1/2 1.305 1.309 1.291 1.302 Sam ple Time, min 60.0 60.0 60.0 60.0 Nozzle Diam eter, inches 0.210 0.210 0.210 0.210



### CALCULATED DATA Nozzle Area, square feet 2.405E-04 2.405E-04 2.405E-04 2.405E-04 Standard Meter Volume, ft3 46.412 46.382 45.210 46.001 Standard W ater Vapor Volume, ft3 4.852 4.885 4.451 4.729 Moisture (gravimetrically), % 9.46 9.53 8.96 9.32 Moisture (at saturation), % NA NA NA NA Moisture (actual) 9.46 9.53 8.96 9.32 Dry Mole Fraction 0.905 0.905 0.910 0.907 Molecular W eight-dry, lb/lb-mole 30.28 30.27 30.27 30.27 Molecular W eight-wet, lb/lb-m ole 29.12 29.10 29.17 29.13 Stack Pressure, inches Hg 30.04 30.07 30.04 30.05 Velocity, ft/s 91.19 91.58 90.32 91.03 Stack Area, in 2 6,192.0 6,192.0 6,192.0 6,192.0 Stack Area, ft2 43.00 43.00 43.00 43.00 Percent Excess Air 43.8 44.2 44.2 44.1 Volum etric flow, acfm 235,279 236,288 233,023 234,863 Volum etric flow, dscfm 136,254 136,549 135,151 135,985 Isokinetic Rate, % 101.5 101.2 99.7 100.8 F-factor, DSCF/MMBtu 9780 9780 9780 9780 Approx Heat Input, mmBtu/hr 575.66 575.30 569.49 573.5 

### FILTERABLE PARTICULA TE TEST RESULTS SUMMARY PLANT KRAFT UNIT 1

Page 28 of 32 Att. 4

## ATTACHMENT 4 - Kraft Report 4 Test Results

Performed by : TRC Environmental Corporation, Raleigh, North Carolina

RUN NUMBER M5-1 M5-2 M5-3 RUN DATE 9/27/2007 9/27/2007 9/27/2007 AVERAGE RUN TIME 0745-0856 0940-1045 1125-1230 

### FILTERABLE PARTICULA TE TEST RESULTS SUMMARY PLANT KRAFT UNIT 1

FILTERABLE PARTICULATE EMISSIONS DATA Filterable Particulate Catch, g 0.0184 0.0134 0.0162 Concen., gr/dscf 0.00612 0.00446 0.00553 0.00537 Em ission Rate, lb/hr 7.15 5.22 6.41 6.26 Em ission Rate, lb/MMBtu 0.0124 0.0091 0.0112 0.0109 Gross Load, MW 50 50 50 50



### Page 29 of 32 Att. 4

## ATTACHMENT 5 - Kraft Report 5 Test Results

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

Run 1 Run 2 Run 3 Test Date 8/27/2008 8/27/2008 8/27/2008 Run Start Time 10:25 12:25 14:05 Run End Time 11:55 13:45 15:20 Meter Volume (dacf), Vm: 51.539 54.661 55.921 Sqrt Delta P ("wc): 1.11 1.10 1.13 Sam pling Time (min): 70 70 70 Barometric Pressure ("Hg), Pbar: 29.98 29.98 29.98 Delta H ("wc): 1.6 1.5 1.6 Volum e in Im pingers (mls), VIc: 84.8 88.1 82.2 Static Pressure ("wc), Pg: -0.30 -0.20 -0.20 Stack Pressure ("Hg), Ps: 29.96 29.97 29.97 Stack Temperature (F), Ts: 319 320 320 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: 89 98 99 Stack Diameter (inches): 109.25x64.5 109.25x64.5 109.25x64.5 Area Stack (sq. ft.), As: 48.93 48.93 48.93 Nozzle Diam eter (inches), dp: 0.214 0.214 0.214 Area Nozzle (sq. ft.), An: 0.000250 0.000250 0.000250 Percent CO2 (% dry

volum e): 13.5 13.6 13.5 Percent O2 (% dry

volum e): 6.2 6.2 6.3 Percent (N2 + CO) (% dry volum e): 80.3 80.2 80.2 Particulate Collected (mg), Mn: 88.9 93.9 114.3

Molec. W t. Dry

(lb/lb-mole), Md: 30.412 30.424 30.412 Volum e W ater (scf), Vwstd 3.992 4.147 3.869 Meter Volume (dscf), Vmstd: 49.751 51.860 52.976 Wet Fraction (v/v), Bws: 0.074 0.074 0.068 Molec. W t. W et (lb/lb-mole), Ms: 29.490 29.504 29.567 Stack Gas Sampled (acf), Vma: 79.193 82.592 83.803 Averages Stack Gas Velocity

(fps), Vs: 75.02 74.17 75.94 75 Volum etric Flowrate (dscfm), Qs: 138,372 136,744 140,953 138,690 Volum etric Flowrate (acfm), Qa: 220,259 217,776 222,974 220,336 Grainloading (gr/dscf), cs: 0.0276 0.0279 0.0333 0.03 Em ission Rate (lb/hour), E: 32.71 32.75 40.23 35.2 Percent Isokinetic Sampling (%), I: 100.46 105.96 105.01 103.81
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 598.43 590.06 604.08 597.52 Emission Rate (lbs/mmBtu), E: 0.05 0.06 0.07 0.059 Allowable Rate (lb/mmBtu): 0.31 0.31 0.31 0.306 Average Unit Gross Load (MW ) 53 54 55 54 

### Particulate Emission Results Summary

Kraft Unit 2

Page 30 of 32 Att. 5

## ATTACHMENT 6 - Kraft Report 6 Test Results

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

Run 1 Run 2 Run 3 Test Date 28-Aug-08 28-Aug-08 28-Aug-08 Run Start Time 8:25 10:15 12:18 Run End Time 9:53 11:32 13:38 Meter Volume (dacf), Vm: 38.401 38.196 37.903 Sqrt Delta P ("wc): 1.251 1.248 1.236 Sam pling Time (min): 64 64 64 Barometric Pressure ("Hg), Pbar: 29.99 29.99 29.99 Delta H ("wc): 1.098 1.092 1.076 Volum e in Im pingers (mls), VIc: 57.6 58.2 57.2 Static Pressure ("wc), Pg: 0.850 0.900 0.900 Stack Pressure ("Hg), Ps: 30.053 30.056 30.056 Stack Temperature (F), Ts: 285 286 290 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: 100 110 106 Stack Diameter (inches): 79x79 79x79 79x79 Area Stack (sq. ft.), As: 43.34 43.34 43.34 Nozzle Diam eter (inches), dp: 0.178 0.178 0.178 Area Nozzle (sq. ft.), An: 0.000173 0.000173 0.000173 Percent CO2 (% dry

volum e): 12.1 12.1 12.1 Percent O2 (% dry

volum e): 7.1 7.1 7.2 Percent (N2 + CO) (% dry volum e): 80.8 80.8 80.7 Particulate Collected (mg), Mn: 86.157 85.825 97.175

Molec. W t. Dry

(lb/lb-mole), Md: 30.219 30.225 30.223 Volum e W ater (scf), Vwstd 2.711 2.739 2.692 Meter Volume (dscf), Vmstd: 35.893 35.114 35.032 Wet Fraction (v/v), Bws: 0.070 0.072 0.071 Molec. W t. W et (lb/lb-mole), Ms: 29.361 29.341 29.350 Stack Gas Sampled (acf), Vma: 54.225 53.266 53.330 Averages Stack Gas Velocity

(fps), Vs: 82.544 82.423 81.862 82 Volum etric Flowrate (dscfm), Qs: 142,081 141,291 139,837 141,070 Volum etric Flowrate (acfm), Qa: 214,649 214,334 212,876 213,953 Grainloading (gr/dscf), cs: 0.037 0.038 0.043 0.04 Em ission Rate (lb/hour), E: 45.107 45.674 51.301 47.4 Percent Isokinetic Sampling (%), I: 99.059 97.451 98.236 98.25
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 576.94 572.35 563.72 571.00 Emission Rate (lbs/mmBtu), E: 0.08 0.08 0.09 0.08 Allowable Rate (lb/mmBtu): 0.31 0.31 0.31 0.31 Average Unit Gross Load (MW ) 106 106 106 106 

### Particulate Emission Results Summary

Kraft Unit 3

Page 31 of 32 Att. 6

## ATTACHMENT 7 - Kraft Report 7 Test Results

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

Run 1 Run 2 Run 3 Test Date 9/9/2009 9/9/2009 9/9/2009 Run Start Time 7:30 9:22 10:48 Run End Time 8:41 10:31 11:58 Meter Volume (dacf), Vm: 50.824 53.268 53.122 Sqrt Delta P ("wc): 1.35 1.36 1.37 Sam pling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 30.20 30.20 30.20 Delta H ("wc): 2.2 2.3 2.3 Volum e in Im pingers (mls), VIc: 80.6 79.7 81.5 Static Pressure ("wc), Pg: -0.40 -0.45 -0.40 Stack Pressure ("Hg), Ps: 30.17 30.17 30.17 Stack Temperature (F), Ts: 352 353 353 Meter Coefficient (no units), Y: 0.996 0.996 0.996 Pitot Coefficient (no units) Cp: 0.840 0.840 0.840 Meter OutletTemperature (F), Tm: 82 90 93 Stack Diameter (inches): 77.1588785 77.1588785 77.1588785 Area Stack (sq. ft.), As: 43.00 43.00 43.00 Nozzle Diam eter (inches), dp: 0.214 0.214 0.214 Area Nozzle (sq. ft.), An: 0.000250 0.000250 0.000250 Percent CO2 (% dry

volum e): 11.0 11.1 11.1 Percent O2 (% dry

volum e): 8.1 8.0 8.0 Percent (N2 + CO) (% dry volum e): 80.9 80.9 80.9 Particulate Collected (mg), Mn: 37.8 38.7 37.9

Molec. W t. Dry

(lb/lb-mole), Md: 30.083 30.097 30.101 Volum e W ater (scf), Vwstd 3.794 3.751 3.836 Meter Volume (dscf), Vmstd: 49.987 51.672 51.233 Wet Fraction (v/v), Bws: 0.071 0.068 0.070 Molec. W t. W et (lb/lb-mole), Ms: 29.230 29.279 29.258 Stack Gas Sampled (acf), Vma: 82.030 84.607 84.125 Averages Stack Gas Velocity

(fps), Vs: 93.23 93.87 94.77 94 Volum etric Flowrate (dscfm), Qs: 146,572 147,904 148,909 147,795 Volum etric Flowrate (acfm), Qa: 240,528 242,174 244,507 242,403 Grainloading (gr/dscf), cs: 0.0117 0.0116 0.0114 0.01 Em ission Rate (lb/hour), E: 14.67 14.65 14.58 14.6 Percent Isokinetic Sampling (%), I: 97.69 100.07 98.55 98.77
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 552.15 558.61 563.87 558.21 Emission Rate (lbs/mmBtu), E: 0.03 0.03 0.03 0.03 Allowable Rate (lb/mmBtu): 0.31 0.31 0.31 0.31 Average Unit Gross Load (MW ) 48 48 48 48 

### Particulate Emission Results Summary

Kraft Unit 1

Page 32 of 32 Att. 7