### GEORGIA POWER - Submittal for PLANT YATES

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

PART I: GENERAL FACILITY INFORMATION

Process Information

1Name of legal owner of facility:

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

3Address of _X__ legal owner or ____ operator:

241 Ralph McGill Blvd NE, Bin 10221 Atlanta, GA 30308 4aPlant Name (as reported on U.S. DOE/EIA Form-860 (2007), "Annual Electric Generator Report", schedule 2, line 1, page 37, question 1) OR Plant Name (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report", schedule 2, page 1, question 1):

Yates 4bEIA Plant Code (as reported on U.S. DOE/EIA Form-860 (2007), schedule 2, line 1, page 37, question 2) OR Plant ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), schedule 2, page 1, question 2):

728 5Complete street address of facility (physical location):

708 Dyer Road Newnan, Georgia 30263 6Provide mailing address if different:

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

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

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

sasander@southernco.com 9Is this facility considered to be owned or operated by a small entity as defined by the Regulatory Flexibility Act? ____ Yes

_X__ No ____ Don't know

Page 1 of 86 part I, 1-14

### GEORGIA POWER - Submittal for PLANT YATES

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

PART I: GENERAL FACILITY INFORMATION

10Which of the following fossil fuels or other material(s) are fired in any steam generating unit at this facility?

_X__ coal

__X__ oil (including pet coke)

_X__ natural gas

_ __ other (specify in question 14 below)

11Which of the following fossil fuel or other material(s) are permitted1

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

_X__ coal

_X__ oil (including pet coke)

_X__ natural gas

_X__ other (specify in question 14 below)

12If coal or solid fuel, as described below, derived from a fossil source is fired, indicate which rank of coal or solid fuel was utilized during the previous 12 months prior to the receipt of this ICR:2,3 

### ____ lignite (% _____) ____ subbituminous (% _____)

_X___ bituminous (% _100____) ____ anthracite (% _____) ____ coal refuse (including gob, culm, and subbituminous-derived coal refuse) (% _____) ____ synfuel (including, but not limited to, briquettes, pellets, or extrusions which are formed by binding materials, or processes that recycle materials) (%_____) (please specify the type or form of synfuel used ___________________________________________) ____ petroleum coke (% _____)

13If oil is fired, indicate which type of oil was utilized during the previous 12 months prior to the receipt of this ICR:4



### _X___ distillate (% _100____)

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

Page 2 of 86 part I, 1-14

### GEORGIA POWER - Submittal for PLANT YATES

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

PART I: GENERAL FACILITY INFORMATION

14aIf "other" was checked in questions 10 or 11 above indicating that any non-fossil fuel or other material (including, but not limited to, plastics, treated wood, rubber belting or gaskets, whole tires, tire-derived fuel, boiler cleaning solutions, animal wastes, etc.) is either utilized or permitted to be used, please indicate below what materials are combusted in the boiler and in what quantities (specify whether this quantity is on a weight percentage or heat [Btu] basis). Also indicate (yes/no) whether you are permitted5

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

14bIf "other" was checked in questions 10 or 11 above indicating that any non-fossil fuel or other material (including, but not limited to, plastics, treated wood, rubber belting or gaskets, whole tires, tire-derived fuel, boiler cleaning solutions, animal wastes, etc.) is either utilized or permitted to be used, were such material to be classified as "solid waste" under the Resource Conservation and Recovery Act and, thus make the utilizing unit subject to CAA section 129, would you continue to utilize (i.e., use as a fuel) the material? ____ Yes ____ No Explain: Until the regulations are finalized, we cannot determine with certainty whether we would use these other materials or not.

1"Permitted" in this context, refers to the fuels that the permit anticipates will be combusted at the facility.
2If the boiler is fired by a blend of coal ranks, please specify percentage (separately, on both a mass and on a Btu basis) of each coal rank (e.g., 85% subbituminuous/15% bituminous).
3In reference to footnote 1, if necessary, a notation can be added to a utilized fuel type that is not listed in the operating permit noting the reason the fuel type was combusted (e.g., "the permitting agency allowed this fuel to be combusted for special testing and research purposes").
4If the boiler is fired by a blend of fuel oil ranks, please specify percentage (separately, on both a volume and on a Btu basis) of each fuel oil rank (e.g., 85% residual oil/15% distillate).
5If necessary, a notation can be added to a utilized fuel type that is not listed in the operating permit noting the reason the fuel was combusted (e.g., "the permitting agency allowed this fuel to be combusted for special testing and research purposes"). 

### Permitted to burn Other Material Sawdust Biomass Yes Yes 

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

### Actually burn None in 2009 None in 2009

Yes None in 2009

None in 2009 None in 2009 Synfuel Used Oil Yes None in 2009



### Page 3 of 86 part I, 1-14

### GEORGIA POWER - PLANT YATES

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

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

Y1BR bituminous CBI CBI 107 97 88.5 Not available 1250 1250 950 950 Not applicable Not

applicable bituminous coal (100%), distillate

oil (100%), natural gas CBI CBI Not applicable None

planned

Y2BR bituminous CBI CBI 105 98 88.5 Not available 1250 1250 950 950 Not applicable Not

applicable bituminous coal (100%), distillate

oil (100%), natural gas CBI CBI Not applicable None

planned

Y3BR bituminous CBI CBI 105 98 88.5 Not available 1250 1251 950 948 Not applicable Not

applicable bituminous coal (100%), distillate

oil (100%), natural gas CBI CBI Not applicable None

planned

Y4BR bituminous CBI CBI 138 129 88.25 88.4 1800 1813 1000 996 1000 984 bituminous coal (100%), distillate oil (100%), natural gas CBI CBI Not applicable None

planned

Y5BR bituminous CBI CBI 145 135 88.25 89.3 1800 1809 1000 991 1000 1000 bituminous coal (100%), distillate oil (100%), natural gas CBI CBI Not applicable None

planned

Y6BR bituminous CBI CBI 363 347 89.06 88.97 2400 2349 1000 971 1000 998 bituminous coal (100%), distillate oil (100%), natural gas CBI CBI Not applicable None

planned

Y7BR bituminous CBI CBI 361 345 89.06 88.9 2400 2361 1000 980 1000 965 bituminous coal (100%), distillate oil (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.



### Page 4 of 86 part I, 15

### GEORGIA POWER - PLANT YATES

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

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



### 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. 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

Page 5 of 86 part I, 15

### GEORGIA POWER - PLANT YATES

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

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



### 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 Yates Units 1-7. 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 6 of 86 part I, 15

### GEORGIA POWER - PLANT YATES

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

16For each boiler noted in Part I, question 15, provide the following information for each current emission control device installed and operating and/or planned (please designate the order of the emission controls - 1 for the first control following the boiler, 2 for the second control following the boiler, etc.): NOTES: SO3/NH3 flue gas conditioning and lime injection systems are/will be operated on an as-needed basis. Dates for future planned controls listed are subject to change. Boiler ID14 

### Type15 

### NOx control16 

### SO2 control17 

### PM control18 

### Other control19
Y1BR tangential-fired (1) low NOx burners (2005) (4) wet flue gas desulfurization (FGD) (10/1992), calcium based (2) cold-side electrostatic precipitator (ESP) (5/1971) Not applicable

Y2BR tangential-fired Not applicable Not applicable (3) cold-side electrostatic precipitator (ESP) (5/1968) (2) flue gas conditioning - SO3 injection (1994) (1) flue gas conditioning - ammonia (SO3 control, 1996)

Y3BR tangential-fired Not applicable Not applicable (3) cold-side electrostatic precipitator (ESP) (2/1969) (2) flue gas conditioning - SO3 injection (1994) (1) flue gas conditioning - ammonia (SO3 control, 1996)

Y4BR tangential-fired (1) flame attachment nozzle (low-NOX burner tip design) and close-coupled overfire air (5/1995) Not applicable (4) cold-side electrostatic precipitator (ESP) (3/1/1970) (3) flue gas conditioning - SO3 injection (1994) (2) flue gas conditioning - ammonia (SO3 control, 1996)

Y5BR tangential-fired (1) flame attachment nozzle (low-NOX burner tip design) and close-coupled overfire air (4/1994) Not applicable (4) cold-side electrostatic precipitator (ESP) (2/27/1968) (3) flue gas conditioning - SO3 injection (1994) (2) flue gas conditioning - ammonia (SO3 control, 1995)



### Page 7 of 86 part I, 16

### GEORGIA POWER - PLANT YATES

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

16For each boiler noted in Part I, question 15, provide the following information for each current emission control device installed and operating and/or planned (please designate the order of the emission controls - 1 for the first control following the boiler, 2 for the second control following the boiler, etc.): NOTES: SO3/NH3 flue gas conditioning and lime injection systems are/will be operated on an as-needed basis. Dates for future planned controls listed are subject to change. Boiler ID14 

### Type15 

### NOx control16 

### SO2 control17 

### PM control18 

### Other control19
Y6BR tangential-fired (1) low-NOX concentric firing system + separated overfire air (11/1992) (2) SCR (6/1/2015), catalyst not yet purchased (7) wet flue gas desulfurization (FGD) (6/1/2015), calcium based (5) cold-side electrostatic precipitator (ESP) (7/23/1974, original install) (5) hydrated lime injection (SO3 control, 6/1/2015)

Y7BR tangential-fired (1) flame attachment nozzle (low-NOX burner tip design) and separated overfire air (3/1994) (2) SCR (6/1/2015), catalyst not yet purchased (7) wet flue gas desulfurization (FGD) (6/1/2015), calcium based (5) cold-side electrostatic precipitator (ESP) (4/8/1974, original install) (5) hydrated lime injection (SO3 control, 6/1/2015)

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.



### Page 8 of 86 part I, 16

### GEORGIA POWER - PLANT YATES

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

16For each boiler noted in Part I, question 15, provide the following information for each current emission control device installed and operating and/or planned (please designate the order of the emission controls - 1 for the first control following the boiler, 2 for the second control following the boiler, etc.): NOTES: SO3/NH3 flue gas conditioning and lime injection systems are/will be operated on an as-needed basis. Dates for future planned controls listed are subject to change. Boiler ID14 

### Type15 

### NOx control16 

### SO2 control17 

### PM control18 

### Other control19

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 9 of 86 part I, 16

### GEORGIA POWER - PLANT YATES

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

17For each boiler noted in Part I, question 15, provide the company (prime vendor) name and company contact information for each HAP-specific (e.g., mercury, hydrogen chloride) control technology that you have either contracted for, are installing, or have installed for the purpose of participating in a control technology demonstration project20

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

Name Telephone Address Y1BR Not applicable Not applicable Not applicable Not applicable Y2BR Not applicable Not applicable Not applicable Not applicable Y3BR Not applicable Not applicable Not applicable Not applicable Y4BR Not applicable Not applicable Not applicable Not applicable Y5BR Not applicable Not applicable Not applicable Not applicable Y6BR Not applicable Not applicable Not applicable Not applicable Y7BR Not applicable Not applicable Not applicable Not applicable

20A control technology demonstration project is defined as a U.S. Government (e.g., U.S. Department of Energy program) sponsored (in whole or in part) project or mandate (e.g., as a result of a consent decree) that adds a HAP control technology to a facility's unit to demonstrate the technology's HAP removal performance.
21Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8). 

### Company (vendor) contact information Boiler ID21 

### Company (vendor) name

Page 10 of 86 part I, 17

### GEORGIA POWER - PLANT YATES

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

18For the control technologies identified in Part I, question 17, provide the date of actual start-up of the demonstration (if the control is currently operating), the date of expected or projected start-up, the date the demonstration was completed, the type of HAP control installed (e.g., sorbent and type; pre-combustion boiler chemical additive; combustion boiler chemical additive), the desired HAP emission reduction or rate (if any), and the coal rank(s) upon which the demonstration was conducted. Please specify the format of the target HAP emission reduction rate (e.g., lb/MWh, lb/TBtu, percent reduction, etc.). If the format of the target end-point is percent reduction, provide (1) an estimate of what an equivalent emission rate would be (and specify the format of the equivalent emission rate), and (2) the basis for calculating the percent reduction (i.e., where the "inlet" and "outlet" are).

Boiler ID22 

### Demonstration

activity actual startup date Demonstration

activity projected start-up date Demonstration

activity end-date or projected end-date Type of control (e.g.,

sorbent and type; chemical additive23

### ) Desired HAP

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

Y1BR Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Y2BR Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Y3BR Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Y4BR Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Y5BR Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Y6BR Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Y7BR 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 11 of 86 part I, 18

### GEORGIA POWER - PLANT YATES

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

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

Name Telephone Address Y1BR Not applicable Not applicable Not applicable Not applicable Y2BR Not applicable Not applicable Not applicable Not applicable Y3BR Not applicable Not applicable Not applicable Not applicable Y4BR Not applicable Not applicable Not applicable Not applicable Y5BR Not applicable Not applicable Not applicable Not applicable Y6BR Not applicable Not applicable Not applicable Not applicable Y7BR Not applicable Not applicable Not applicable Not applicable

24Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8). 

### Company (vendor) contact information Boiler ID24 

### Company (vendor) name

Page 12 of 86 part I, 19

### GEORGIA POWER - PLANT YATES

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

20For the control technologies identified in Part I, question 19, provide the date of actual start-up (if the control is currently operating), the date of expected or projected start-up, the type of HAP control installed (e.g., sorbent and type; pre-construction boiler chemical additive; combustion of boiler chemical additive), the guaranteed HAP emission reduction or emission rate, the sorbent feed rate upon which the guarantee is based, and the coal rank(s) upon which the guarantee is based. Please specify the format of the guarantee (e.g., lb/MWh, lb/TBtu, percent reduction, etc.). If the format of the guarantee is percent reduction, provide (1) an estimate of what an equivalent emission rate would be (and specify the format of the equivalent emission rate), and (2) the basis for calculating the percent reduction (i.e., where the "inlet" and "outlet" are).

Boiler ID25 

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

sorbent and type; chemical additive)26 

### Guaranteed HAP

emission reduction (%) or emission rate Sorbent or additive

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

which guarantee is based

Y1BR Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Y2BR Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Y3BR Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Y4BR Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Y5BR Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Y6BR Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Y7BR 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 13 of 86 part I, 20

### GEORGIA POWER - PLANT YATES

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

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

PM28 

### PM10(29) 

### PM2.5(30) 

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

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

Y1BR 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 pressure drop across the scrubber) 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)
10% of potential combustion concentration (90% removal by FGD), effective Jan 1, 2010 (State rule, Title V permit revision not complete; based on 30-day rolling average, monitored by CEMS at inlet to scrubber and at scrubber stack during scrubber operations, excluding startup, shutdown, malfunction, and other exemptions) Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable NOx: 0.38 lb/MMBtu from May 1 through

September 30 OR compliance with 5 and 7-plant NOx averages of 0.13 lb/MMBtu and 0.18 lb/MMBtu (Title V permit; based on 30-day rolling averages determined by CEMS)
Southern Company Phase II NOx Averaging Plan limit of 0.46 lb/MMBtu (average of all units) (Phase II NOx Compliance Plan; based on annual average determined by CEMS)



### Y2BR 0.24 lb/MMBtu (Title V permit; based on 3-run

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

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

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

applicable Not

applicable Not

applicable Not

applicable Not

applicable NOx: 0.38 lb/MMBtu from May 1 through

September 30 OR compliance with 5 and 7-plant NOx averages of 0.13 lb/MMBtu and 0.18 lb/MMBtu (Title V permit; based on 30-day rolling averages determined by CEMS)
Southern Company Phase II NOx Averaging Plan limit of 0.46 lb/MMBtu (average of all units) (Phase II NOx Compliance Plan; based on annual average determined by CEMS)


### Y3BR 0.24 lb/MMBtu (Title V permit; based on 3-run

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

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

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

applicable Not

applicable Not

applicable Not

applicable Not

applicable NOx: 0.38 lb/MMBtu from May 1 through

September 30 OR compliance with 5 and 7-plant NOx averages of 0.13 lb/MMBtu and 0.18 lb/MMBtu (Title V permit; based on 30-day rolling averages determined by CEMS)
Southern Company Phase II NOx Averaging Plan limit of 0.46 lb/MMBtu (average of all units) (Phase II NOx Compliance Plan; based on annual average determined by CEMS) 

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



### Page 14 of 86 part I, 21

### GEORGIA POWER - PLANT YATES

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

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

PM28 

### PM10(29) 

### PM2.5(30) 

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

### Hg CO Other organics (specify) Other pollutant (specify) Permitted emission limit (indicate type of permit and format of emission limit)
Boiler ID27



### Y4BR 0.24 lb/MMBtu (Title V permit; based on 3-run

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

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

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

applicable Not

applicable Not

applicable Not

applicable Not

applicable NOx: 0.33 lb/MMBtu from May 1 through

September 30 OR compliance with 5 and 7-plant NOx averages of 0.13 lb/MMBtu and 0.18 lb/MMBtu (Title V permit; based on 30-day rolling averages determined by CEMS)
Southern Company Phase II NOx Averaging Plan limit of 0.46 lb/MMBtu (average of all units) (Phase II NOx Compliance Plan; based on annual average determined by CEMS)


### Y5BR 0.24 lb/MMBtu (Title V permit; based on 3-run

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

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

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

applicable Not

applicable Not

applicable Not

applicable Not

applicable NOx: 0.33 lb/MMBtu from May 1 through

September 30 OR compliance with 5 and 7-plant NOx averages of 0.13 lb/MMBtu and 0.18 lb/MMBtu (Title V permit; based on 30-day rolling averages determined by CEMS)
Southern Company Phase II NOx Averaging Plan limit of 0.46 lb/MMBtu (average of all units) (Phase II NOx Compliance Plan; based on annual average determined by CEMS)


### Y6BR 0.24 lb/MMBtu (Title V permit; based on 3-run

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

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

analysis of coal sample acquired for each operating day and supplier certification statement for No. 2 oil)
5% of potential combustion concentration (95% removal by FGD), effective June 1, 2015 (State rule, Title V permit revision not complete; based on 30-day rolling average, monitored by CEMS at inlet to scrubber and at scrubber stack during scrubber operations, excluding startup, shutdown, malfunction, and other exemptions) Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable NOx: 0.26 lb/MMBtu from May 1 through

September 30 OR compliance with 5 and 7-plant NOx averages of 0.13 lb/MMBtu and 0.18 lb/MMBtu (Title V permit; based on 30-day rolling averages determined by CEMS)
Southern Company Phase II NOx Averaging Plan limit of 0.46 lb/MMBtu (average of all units) (Phase II NOx Compliance Plan; based on annual average determined by CEMS)



### Page 15 of 86 part I, 21

### GEORGIA POWER - PLANT YATES

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

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

PM28 

### PM10(29) 

### PM2.5(30) 

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

### Hg CO Other organics (specify) Other pollutant (specify) Permitted emission limit (indicate type of permit and format of emission limit)
Boiler ID27



### Y7BR 0.24 lb/MMBtu (Title V permit; based on 3-run

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

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

analysis of coal sample acquired for each operating day and supplier certification statement for No. 2 oil)
5% of potential combustion concentration (95% removal by FGD), effective June 1, 2015 (State rule, Title V permit revision not complete; based on 30-day rolling average, monitored by CEMS at inlet to scrubber and at scrubber stack during scrubber operations, excluding startup, shutdown, malfunction, and other exemptions) Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable NOx: 0.26 lb/MMBtu from May 1 through

September 30 OR compliance with 5 and 7-plant NOx averages of 0.13 lb/MMBtu and 0.18 lb/MMBtu (Title V permit; based on 30-day rolling averages determined by CEMS)
Southern Company Phase II NOx Averaging Plan limit of 0.46 lb/MMBtu (average of all units) (Phase II NOx Compliance Plan; based on annual average determined by CEMS)

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



### Page 16 of 86 part I, 21

### GEORGIA POWER - PLANT YATES

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

22For each boiler noted in Part I, question 15, provide the following information: NOTES: All guarantees are based on and demonstrated with certain fuel and operating conditions. Guarantees are not necessarily representative of the long term or day to day variability that may occur with changes in fuel specifications, operating conditions, normal wear and tear of equipment over time, startups, shutdowns, and malfunctions.

PM33 

### PM10 

### PM2.5 

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

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

Y1BR ESP rebuild: 98.0 % collection efficiency filterable (expiration 1997) Not applicable Not

applicable Not applicable Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable Not applicable



### Y2BR ESP rebuild: 98.3 % collection efficiency filterable(expiration in 1997) Not applicable Not

applicable Not applicable Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable Not applicable



### Y3BR ESP rebuild: 98.3 % collection efficiency filterable (expiration in 1995) Not applicable Not

applicable Not applicable Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable Not applicable



### Y4BR ESP rebuild: 98.3 % collection efficiency filterable (expiration in 1996) Not applicable Not

applicable Not applicable Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable Not applicable



### Y5BR ESP rebuild: 98.3 % collection efficiency filterable (expiration 1996) Not applicable Not

applicable Not applicable Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable Not applicable



### Y6BR ESP rebuild: 99.0 % collection efficiency filterable (expiration 1997) Not applicable Not

applicable Not applicable Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable Not applicable



### Y7BR ESP rebuild: 99.0 % collection efficiency filterable (expiration 1997) Not applicable Not

applicable Not applicable Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable Not applicable



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

_X___ No Please elaborate.

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

### Most recent guaranteed emission rate for each pollutant for which there is a permitted emission limit
Boiler ID32



### Page 17 of 86 part I, 22-23

### GEORGIA POWER - PLANT YATES

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

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

PM36 

### PM10 

### PM2.5 

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

### Hg CO Other organics (specify) Y1BR Pressure drop across the scrubber monitored continuously; excursions for pressure drop

less than 10 inches of water reported quarterly; records retained for 5 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. SO2 removal by the scrubber will be monitored by inlet and stack SO2 CEMS operated, maintained, and certified using 40 CFR Part 75 procedures. Data from these monitors will provide the SO2 removal percentage on a 30-day rolling average, excluding startup, shutdown, and malfunction. Exceedances of the 5% limit will be reported quarterly; records retained for 5 years (permit revision not yet issued). Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable



### Y2BR 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 32%) 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



### Y3BR 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 32%) 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



### Y4BR 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 33%) 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 

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



### Page 18 of 86 part I, 24

### GEORGIA POWER - PLANT YATES

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

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

PM36 

### PM10 

### PM2.5 

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

### Hg CO Other organics (specify) Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a permitted emission limit
Boiler ID35



### Y5BR 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 33%) 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



### Y6BR 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 29%) reported quarterly.
The facility shall submit 30-day advance notifications of required testing and test reports within 60 days of completion of the testing. All records related to the Title V permit are retained for five years. Not applicable Not

applicable Coal sulfur content monitored through daily coal sampling;

fuel oil sulfur content monitored through vendor certification; exceedances of 3% limit reported quarterly; records retained for 5 years. Effective June 1, 2015, SO2 removal by the scrubber will be monitored by inlet and stack SO2 CEMS operated, maintained, and certified using 40 CFR Part 75 procedures. Data from these monitors will provide the SO2 removal percentage on a 30-day rolling average, excluding startup, shutdown, and malfunction. Exceedances of the 5% limit will be reported quarterly; records retained for 5 years (permit revision not yet issued). Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable



### Y7BR 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 23%) reported quarterly.
The facility shall submit 30-day advance notifications of required testing and test reports within 60 days of completion of the testing. All records related to the Title V permit are retained for five years. Not applicable Not

applicable Coal sulfur content monitored through daily coal sampling;

fuel oil sulfur content monitored through vendor certification; exceedances of 3% limit reported quarterly; records retained for 5 years. Effective June 1, 2015, SO2 removal by the scrubber will be monitored by inlet and stack SO2 CEMS operated, maintained, and certified using 40 CFR Part 75 procedures. Data from these monitors will provide the SO2 removal percentage on a 30-day rolling average, excluding startup, shutdown, and malfunction. Exceedances of the 5% limit will be reported quarterly; records retained for 5 years (permit revision not yet issued). Not applicable Not

applicable Not

applicable Not

applicable Not

applicable Not

applicable

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



### Page 19 of 86 part I, 24

### GEORGIA POWER - PLANT YATES

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

25For the control technologies identified in Part I, questions 17 and 19, provide the cost information requested.38



### Facility Name/Unit No.: Not applicable Retrofit to existing boiler? Not applicable Installation on a new boiler? Not applicable Total Capital Investment:

- $ Total Annual Operating and Maintenance Costs:

- $ (Include base year for operating costs [e.g., 2006]

26Are any other means of emission control (for any pollutant) employed on any boiler noted in Part I, question 15 (e.g., low-ash coal, coal or oil with low trace constituents, etc.)? Please specify. Units 1-7 have the ability to inject a limited amount of natural gas as needed to meet permit limits for NOx emissions during the ozone season.

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



### Page 20 of 86 part I, 25-26

### GEORGIA POWER - PLANT YATES

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

PART II: FUEL ANALYSIS AND EMISSION DATA

Fuel Analysis39



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

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

728

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



### Page 21 of 86 part II, 1

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

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

### % Sulf % Ash Btu/lb

12,182 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.24 13.34 13,217

11,831 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 0.84 12.56 13,193

12,150 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.34 13.8 13,253

11,101 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 0.97 12.75 13,422

12,144Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.08 12.18 13,456

12,205 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.33 12.98 13,358

12,218 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.12 12.81 13,397

11,884Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.05 12.45 13,527 

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

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

### Fuel source Fuel shipment method

Page 22 of 86 part II, 2 (coal)

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

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

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

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

### Fuel source Fuel shipment method

12,091 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.11 11.64 13,566

12,069 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.31 12.82 13,434

12,229 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.11 11.32 13,578

12,125 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1 11.88 13,561

12,231 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.29 11.77 13,637

11,956 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.13 11.67 13,571

12,076 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.24 11.44 13,633

11,928 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 0.98 11.71 13,579



### Page 23 of 86 part II, 2 (coal)

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

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

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

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

### Fuel source Fuel shipment method

11,734Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.33 12.32 13,422

12,105 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.33 12.26 13,490

12,206 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.42 12.57 13,361

12,121 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.08 13.75 13,175

12,140 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE EDWARDS, JAWBONE, NORTON, RAVEN, SPLASHDAM TRAIN 1.42 12.54 13,389

7,013 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.31 12.99 13,024

6,958 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.33 13.09 13,034

7,066 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.32 12.92 13,053



### Page 24 of 86 part II, 2 (coal)

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

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

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

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

### Fuel source Fuel shipment method

7,030 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.34 13.2 13,002

7,014 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.36 13.01 13,037

7,023 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.29 12.51 13,115

7,048 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.33 12.62 13,097

6,962 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.33 12.35 13,118

6,999 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.35 12.45 13,134

7,198 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.32 12.81 13,018

7,166 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.54 13.45 12,928



### Page 25 of 86 part II, 2 (coal)

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

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

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

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

### Fuel source Fuel shipment method

7,001 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.43 12.26 13,135

7,046 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.56 12.48 13,099

6,853 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.2 13.81 12,914

6,778 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.44 13.11 13,030

7,006 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.4 13.14 13,041

7,026 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.25 12.4 13,148

6,944 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.43 12.3 13,139

7,077 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.39 13.69 12,896



### Page 26 of 86 part II, 2 (coal)

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

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

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

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

### Fuel source Fuel shipment method

7,102 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.35 13.21 12,994

7,012 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.36 13.1 13,022

7,035 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.11 12.47 13,069

7,017 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.14 11.91 13,160

6,998 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.23 12.05 13,124

7,035 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.34 13.38 12,957

7,026 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.22 12.53 13,101

6,881 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.3 12.82 13,052



### Page 27 of 86 part II, 2 (coal)

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

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

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

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

### Fuel source Fuel shipment method

7,039 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.15 12.35 13,137

6,949 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.33 12.29 13,110

7,021 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.22 13.34 12,947

6,985 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.25 12.69 13,086

7,123 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.14 13.06 13,013

6,944 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.18 12.64 13,076

6,957 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.12 13.03 13,068

7,189 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.13 12.74 13,109



### Page 28 of 86 part II, 2 (coal)

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

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

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

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

### Fuel source Fuel shipment method

7,029 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.16 13.39 12,989

6,891 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.33 12.88 13,063

7,003 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.33 13.55 12,992

7,065 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.22 14.16 12,842

6,889 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.19 12.35 13,181

7,087 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.18 12.96 12,933

6,917 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.29 12.32 12,997

6,879 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.16 12.52 13,071



### Page 29 of 86 part II, 2 (coal)

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

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

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

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

### Fuel source Fuel shipment method

6,806 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.16 13.48 12,988

6,920 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.05 13.7 12,911

6,909 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.21 13.17 13,004

6,926 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR AL FAYETTE, TUSCALOOSA PRATT TRAIN 2.25 12.52 13,131

9,923 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR COLOMBIA N/A GRAN MADRE TRAIN 0.48 5.89 13,124

10,006 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR COLOMBIA N/A GRAN MADRE TRAIN 0.51 6.07 13,107

9,974 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR COLOMBIA N/A GRAN MADRE TRAIN 0.53 5.47 13,236

11,377 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY MARTIN ALMA TRAIN 1.57 9.65 13,394



### Page 30 of 86 part II, 2 (coal)

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

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

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

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

### Fuel source Fuel shipment method

12,028 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.95 12.11 13,457

11,694Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 1.12 14.8 13,003

12,084Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 1.09 12.4 13,370

12,033 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.9 12.31 13,447

12,031 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.91 13.31 13,250

11,960 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.89 10.96 13,637

11,969 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.87 12.56 13,376

12,013 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.9 12.32 13,432



### Page 31 of 86 part II, 2 (coal)

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

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

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

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

### Fuel source Fuel shipment method

12,031 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.85 11.47 13,539

12,111 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.87 13.01 13,289

12,082 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 1.06 13.02 13,273

12,096 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.95 13.69 13,185

12,057 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.92 13.02 13,320

11,991 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.98 11.84 13,478

12,063 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.91 13.4 13,270

10,379 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY, VA HARLAN, LEE CREECH, DARBY, HARLAN, KELLIOKA TRAIN 0.87 12.24 13,236



### Page 32 of 86 part II, 2 (coal)

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

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

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

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

### Fuel source Fuel shipment method

10,454Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY, VA HARLAN, LEE CREECH, DARBY, HARLAN, KELLIOKA TRAIN 1.1 11.02 13,403

11,305 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.15 9.84 13,376

11,568 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 0.89 6.88 13,905

11,695 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.01 8.99 13,566

10,282 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.08 10.25 13,254

11,010 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.17 9.34 13,507

10,951 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.12 8.03 13,670

10,987 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.05 7.93 13,777



### Page 33 of 86 part II, 2 (coal)

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

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

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

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

### Fuel source Fuel shipment method

11,735 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.68 12.1 13,295

10,578 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.86 11.19 13,497

11,423 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.4 12.94 13,257

12,093 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.9 13.3 13,142

12,024Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.92 12.32 13,297

12,100 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 2.03 12.53 13,302

8,418 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.95 9.99 13,487

8,285 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.62 10.06 13,457



### Page 34 of 86 part II, 2 (coal)

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

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

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

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

### Fuel source Fuel shipment method

7,247 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 2.03 9.18 13,369

7,645 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 2.05 10.37 13,365

7,733 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 2.37 11.02 13,317

7,729 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 2.37 10.73 13,301

7,748 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 2.41 10.69 13,378

7,930 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.71 10.26 13,437

7,988 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 2.02 8.53 13,665

8,796 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 2.03 11.04 13,246



### Page 35 of 86 part II, 2 (coal)

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

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

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

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

### Fuel source Fuel shipment method

10,204Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 2.32 10.11 13,409

11,596 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.1 8.31 13,610

9,740 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.68 10.74 13,346

9,669 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.49 11.68 13,141

9,675 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.48 9.05 13,539

9,979 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.68 6.87 14,015

9,725 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.52 9.92 13,365

9,929 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.59 8.82 13,644



### Page 36 of 86 part II, 2 (coal)

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

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

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

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

### Fuel source Fuel shipment method

9,824 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.82 8.33 13,644

10,046 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.84 9.34 13,548

9,393 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.8 9.1 13,570

9,832 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.43 11.61 13,185

10,051 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.65 11.05 13,220

9,645 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.43 10.79 13,340

9,826 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.3 10.65 13,284

9,792 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.51 11.81 13,039



### Page 37 of 86 part II, 2 (coal)

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

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

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

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

### Fuel source Fuel shipment method

9,778 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.45 10.76 13,256

9,822 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.45 10.76 13,267

9,738 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.23 9.37 13,534

9,446 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.56 10.15 13,324

10,453 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.21 8.29 13,680

9,787 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.67 10.03 13,367

9,366 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.58 9.49 13,489

9,723 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.47 10.77 13,283



### Page 38 of 86 part II, 2 (coal)

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

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

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

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

### Fuel source Fuel shipment method

9,969 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.29 11 13,224

9,793 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.81 8.68 13,598

9,905 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.48 9.35 13,481

9,658 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.48 10.2 13,346

9,732 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.55 9.45 13,462

9,760 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.44 9.67 13,475

9,892 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.5 10.18 13,402

9,434 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.33 11.35 13,249



### Page 39 of 86 part II, 2 (coal)

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

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

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

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

### Fuel source Fuel shipment method

10,972 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 0.91 6.09 14,061

9,681 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.64 9.99 13,416

9,758 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.27 10.59 13,184

10,908 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.17 6.95 13,903

9,614 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.1 7.42 13,952

11,811 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY PIKE ALMA TRAIN 1.32 8.97 13,413

11,850 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY PIKE ALMA TRAIN 1.76 9.24 13,397

11,850 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY PIKE ALMA, ELKHORN, ELKHORN #2, ELKHORN #3 TRAIN 0.75 10.02 13,658



### Page 40 of 86 part II, 2 (coal)

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

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

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

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

### Fuel source Fuel shipment method

11,907 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY PIKE ALMA, ELKHORN, ELKHORN #2, ELKHORN #3 TRAIN 0.97 12.4 13,098

11,879 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY PIKE ALMA, ELKHORN, ELKHORN #2, ELKHORN #3 TRAIN 0.78 11.8 13,315

12,044Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY PIKE ALMA, ELKHORN, ELKHORN #2, ELKHORN #3 TRAIN 0.82 11.99 13,241

11,668 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY PIKE ALMA, ELKHORN, ELKHORN #2, ELKHORN #3 TRAIN 0.72 9.62 13,518

11,936 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY PIKE ALMA, ELKHORN, ELKHORN #2, ELKHORN #3 TRAIN 0.84 10.75 13,636

11,989 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY PIKE ALMA, ELKHORN, ELKHORN #2, ELKHORN #3 TRAIN 0.88 12.34 13,306

12,028 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY PIKE ALMA, ELKHORN, ELKHORN #2, ELKHORN #3 TRAIN 0.81 10.9 13,496

11,984Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY PIKE ALMA, ELKHORN, ELKHORN #2, ELKHORN #3 TRAIN 0.79 12.28 13,301



### Page 41 of 86 part II, 2 (coal)

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

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

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

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

### Fuel source Fuel shipment method

12,075 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY PIKE ALMA, ELKHORN, ELKHORN #2, ELKHORN #3 TRAIN 0.98 11.14 13,430

11,935 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY PIKE ALMA, ELKHORN, ELKHORN #2, ELKHORN #3 TRAIN 0.75 12.21 13,296

12,056 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY PIKE ALMA, ELKHORN, ELKHORN #2, ELKHORN #3 TRAIN 1.01 9.9 13,735

N/AY1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY PIKE ALMA, ELKHORN, ELKHORN #2, ELKHORN #3 TRAIN N/A N/A N/A

11,581 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY PIKE POND CREEK, TAYLOR, WILLIAMSON TRAIN 0.87 13.2 13,019

11,640 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY PIKE POND CREEK, TAYLOR, WILLIAMSON TRAIN 0.79 13.21 13,085

11,601 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY PIKE POND CREEK, TAYLOR, WILLIAMSON TRAIN 0.84 13.51 12,956

11,668 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY PIKE POND CREEK, TAYLOR, WILLIAMSON TRAIN 0.85 12.8 13,191



### Page 42 of 86 part II, 2 (coal)

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

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

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

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

### Fuel source Fuel shipment method

10,938 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY, WV LESLIE, LOGAN ALMA TRAIN 0.78 13.06 13,076

12,194Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY, WV LESLIE, LOGAN ALMA TRAIN 0.66 10.45 13,503

10,058 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY, WV LESLIE, LOGAN ALMA TRAIN 0.81 12.3 13,183

10,379 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY, WV LESLIE, LOGAN ALMA TRAIN 0.79 11.98 13,340

11,703 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY, WV LESLIE, LOGAN ALMA TRAIN 0.81 12.27 13,311

10,579 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY, WV LESLIE, LOGAN ALMA TRAIN 0.83 11.68 13,413

11,962 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY, WV LESLIE, LOGAN ALMA TRAIN 0.77 12.02 13,367

11,968 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY, WV LESLIE, LOGAN ALMA TRAIN 1.02 10.4 13,624



### Page 43 of 86 part II, 2 (coal)

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

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary): NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B. State/Country County42 

### Coal seam43 

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

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

### Fuel source Fuel shipment method

11,017 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY MARTIN POND CREEK TRAIN 0.94 9.84 13,371

11,871 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY MARTIN POND CREEK TRAIN 1.01 5.92 14,066

10,944Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY MARTIN POND CREEK TRAIN 0.92 10.53 13,205

11,132 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR, Y6BR, Y7BR KY MARTIN POND CREEK TRAIN 0.99 10.36 13,138

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



### Page 44 of 86 part II, 2 (coal)

### GEORGIA POWER - PLANT YATES

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

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary):

State/Country County42 

### Coal seam43 7,627 Y6BR, Y7BR Georgia/USA N/A N/A Truck 15,215 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR Georgia/USA N/A N/A Truck 7,520 Y6BR, Y7BR Georgia/USA N/A N/A Truck 7,630 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR Georgia/USA N/A N/A Truck 7,620 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR Georgia/USA N/A N/A Truck 15,265 Y6BR, Y7BR Georgia/USA N/A N/A Truck 15,250 Y6BR, Y7BR Georgia/USA N/A N/A Truck 7,680 Y6BR, Y7BR Georgia/USA N/A N/A Truck 15,263 Y6BR, Y7BR Georgia/USA N/A N/A Truck 7,626 Y6BR, Y7BR Georgia/USA N/A N/A Truck 7,635 Y6BR, Y7BR Georgia/USA N/A N/A Truck 7,636 Y6BR, Y7BR Georgia/USA N/A N/A Truck 7,638 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR Georgia/USA N/A N/A Truck 7,639 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR Georgia/USA N/A N/A Truck 7,647 Y6BR, Y7BR Georgia/USA N/A N/A Truck 15,188 Y6BR, Y7BR Georgia/USA N/A N/A Truck 15,208 Y6BR, Y7BR Georgia/USA N/A N/A Truck 7,606 Y6BR, Y7BR Georgia/USA N/A N/A Truck 7,610 Y6BR, Y7BR Georgia/USA N/A N/A Truck 7,603 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR Georgia/USA N/A N/A Truck 7,591 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR Georgia/USA N/A N/A Truck 7,591 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR Georgia/USA N/A N/A Truck 15,136 Y6BR, Y7BR Georgia/USA N/A N/A Truck 7,557 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR Georgia/USA N/A N/A Truck 

### FUEL OIL SHIPMENTS Amount received, gallons40 

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

### Fuel source Fuel shipment method

Page 45 of 86 part II, 2 (oil)

### GEORGIA POWER - PLANT YATES

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

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary):

State/Country County42 

### Coal seam43 

### FUEL OIL SHIPMENTS Amount received, gallons40 

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

### Fuel source Fuel shipment method 7,549 Y6BR, Y7BR Georgia/USA N/A N/A Truck 7,557 Y6BR, Y7BR Georgia/USA N/A N/A Truck 7,558 Y6BR, Y7BR Georgia/USA N/A N/A Truck 7,533 Y6BR, Y7BR Georgia/USA N/A N/A Truck 7,534 Y6BR, Y7BR Georgia/USA N/A N/A Truck 7,554 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR Georgia/USA N/A N/A Truck 7,521 Y6BR, Y7BR Georgia/USA N/A N/A Truck 22,551 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR Georgia/USA N/A N/A Truck 7,520 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR Georgia/USA N/A N/A Truck 7,522 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR Georgia/USA N/A N/A Truck 7,537 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR Georgia/USA N/A N/A Truck 7,543 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR Georgia/USA N/A N/A Truck 7,562 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR Georgia/USA N/A N/A Truck 30,273 Y6BR, Y7BR Georgia/USA N/A N/A Truck 7,579 Y6BR, Y7BR Georgia/USA N/A N/A Truck 15,146 Y6BR, Y7BR Georgia/USA N/A N/A Truck 7,572 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR Georgia/USA N/A N/A Truck 22,765 Y6BR, Y7BR Georgia/USA N/A N/A Truck 7,585 Y1BR, Y2BR, Y3BR, Y4BR, Y5BR Georgia/USA N/A N/A Truck 7,624 Y6BR, Y7BR Georgia/USA N/A N/A Truck

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



### Page 46 of 86 part II, 2 (oil)

### GEORGIA POWER - PLANT YATES

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

2For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicated N/A if not available; use additional pages, as necessary):

State/Country County42 

### Coal seam43 

### FUEL OIL SHIPMENTS Amount received, gallons40 

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

### Fuel source Fuel shipment method

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 47 of 86 part II, 2 (oil)

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

3For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information44

### , as available (dry basis) (indicate N/A if not available): NOTES: "ND" indicates results are non detect. All results presented on a dry basis. Georgia Power collects this information on select coal shipments on a quarterly basis, but does not have this information available on a shipment by shipment basis. The information Georgia Power provides in this question cannot be linked to the information in Part II, Question 2 because the information comes from two separate databases. Thus the information provided in this question represents only a very small portion of our actual shipments.

Antimony Arsenic Beryllium Cadmium Chromium 

### Cobalt Lead Manganese 

### Selenium

09-500 12,831 1.11 12.61 13,387 0.080 385 121 12.3 1.2 18.4 2.0 0.04 18.6 7.0 8.9 27.8 2.1KY, VA KY - Harlan VA - Buchanan, Dickenson, Wise Clintwood 28.82%,

Blair 9.16%, Eagle 10.89%, Norton 15.19%, L. Banner 5.15%, Tiller 6.27%, Bolling 6.06%, Blue Gem 0.91%, Aily 6.81%, Banner 6.55%, Jawbone 4.19% Train

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

09-504 11,367 1.23 11.79 13,262 0.070 93 130 10.7 1.3 17.4 1.6 0.13 15.8 6.1 8.1 21.4 2.5VA Wise (1)Morris (2)Cedar Grove (3) Mixed (4)Parsons (5)Taggart (6)#8 Train 09-505 12,229 1.54 10.24 13,258 0.113 2148 69 13.5 1.6 10.6 2.1 0.06 15.8 7.0 9.6 24.2 3.9KY Martin Alma, Coalburg Train

09-507 12,420 0.91 13.36 13,049 0.073 995 103 12.9 1.0 12.1 2.9 0.03 17.6 8.9 9.1 50.0 3.0KY Pike Broaz, Haddix, Chilton, Middle Whitesburg, Upper/Lower Alma, Haddix, Cedar Grove, Williamson Train 09-623 7,557 2.3 13.06 13,035 0.151 151 44 18.3 1.5 13.8 1.7 <0.02 25.6 9.4 6.7 33.8 2.2AL Fayette Pratt Train

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

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

09-401 8,500 2.01 8.93 13,675 0.099 643 74 15.6 <1 15.5 1.9 0.13 13.2 6.4 6.2 14.6 2.9TN Clairborne Walnut Mountain, Windrock, Pee Wee Train Total amount of fuel represented by sample, tons 

### Sample ID # State/ Country County Fuel Shipment Method Nickel, ppm Other trace metal HAP, ppm45 

### Total Sulfur, % Ash

Content, % Heating Value, Btu/lb Mercury,

ppm Chlorine,

ppm Fluorine,

ppm Coal Seam

Page 48 of 86 part II, 3

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

3For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information44

### , as available (dry basis) (indicate N/A if not available): NOTES: "ND" indicates results are non detect. All results presented on a dry basis. Georgia Power collects this information on select coal shipments on a quarterly basis, but does not have this information available on a shipment by shipment basis. The information Georgia Power provides in this question cannot be linked to the information in Part II, Question 2 because the information comes from two separate databases. Thus the information provided in this question represents only a very small portion of our actual shipments.

Antimony Arsenic Beryllium Cadmium Chromium 

### Cobalt Lead Manganese 

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

### Sample ID # State/ Country County Fuel Shipment Method Nickel, ppm Other trace metal HAP, ppm45 

### Total Sulfur, % Ash

Content, % Heating Value, Btu/lb Mercury,

ppm Chlorine,

ppm Fluorine,

ppm Coal Seam

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

09-517 12,882 1.18 13.47 13,283 0.081 654 108 11.5 1.4 22.5 2.0 0.14 16.0 7.0 8.3 60.1 1.9VA Buchanan, Dickenson and Wise Blair 26.61%,

Clintwoood 20.34%, Raven 18.16%, Aily 12.22%, Eagle 11.99%, L. Banner 5.69%, Banner 4.99% Train

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

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

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

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

09-412 12,474 0.98 9.01 13,460 0.071 1310 98 26.4 1.2 5.0 3.0 0.10 16.9 13.5 9.7 21.9 3.8TN Clairborne Braden, Red Ash, Walnut Mountain Train 09-216 12,723 1.59 9.41 13,416 0.115 2317 60 13.0 1.4 7.9 2.1 0.04 16.0 7.0 9.1 18.9 3.9KY Martin Alma, Taylor Train 09-217 12,700 0.95 9.81 13,351 ND 1563 59 21.5 1.3 4.5 2.8 ND 22.5 12.0 10.0 6.2 4.7WV Wayne Coalburg Train 09-641 7,575 2.39 13.06 12,996 0.182 133 68 16.9 1.7 15.2 1.3 0.09 20.9 8.5 9.5 33.7 2.2AL Fayette Pratt Train



### Page 49 of 86 part II, 3

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

3For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information44

### , as available (dry basis) (indicate N/A if not available): NOTES: "ND" indicates results are non detect. All results presented on a dry basis. Georgia Power collects this information on select coal shipments on a quarterly basis, but does not have this information available on a shipment by shipment basis. The information Georgia Power provides in this question cannot be linked to the information in Part II, Question 2 because the information comes from two separate databases. Thus the information provided in this question represents only a very small portion of our actual shipments.

Antimony Arsenic Beryllium Cadmium Chromium 

### Cobalt Lead Manganese 

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

### Sample ID # State/ Country County Fuel Shipment Method Nickel, ppm Other trace metal HAP, ppm45 

### Total Sulfur, % Ash

Content, % Heating Value, Btu/lb Mercury,

ppm Chlorine,

ppm Fluorine,

ppm Coal Seam

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

09-520 12,855 1.28 9.91 13,626 ND 464 89 12.5 1.3 21.0 2.0 0.08 16.8 7.5 7.5 62.5 2.1VA Buchanan, Dickenson and Wise Clintwoood

34.89%, Norton 26.08% Blair 14.43% Aily 6.83%, Jawbone 5.33% Eagle 4.99 (7) Cedar Grove 3.10% (8) Bolling 2.96% (9) Raven 1.38% Train

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

09-523 12,773 1.63 13.7 13,044 0.157 150 113 15.4 ND 40.8 1.8 0.15 16.6 7.6 7.3 40.6 2.3VA Wise Cedar Grove, High Splint, Morris Ryder, High Splint Marker Train 09-110 7,812 2.16 12.63 13,082 0.122 165 35 18.4 1.4 15.6 1.4 0.10 24.9 9.6 11.0 36.2 2.3AL Fayette Pratt Train 09-226 11,981 0.98 10.72 13,199 ND 1129 65 22.0 1.5 3.8 2.8 ND 22.4 11.8 10.3 6.4 4.7WV Wayne Coalburg Train

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

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

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

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

### Page 50 of 86 part II, 3

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

3For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information44

### , as available (dry basis) (indicate N/A if not available): NOTES: "ND" indicates results are non detect. All results presented on a dry basis. Georgia Power collects this information on select coal shipments on a quarterly basis, but does not have this information available on a shipment by shipment basis. The information Georgia Power provides in this question cannot be linked to the information in Part II, Question 2 because the information comes from two separate databases. Thus the information provided in this question represents only a very small portion of our actual shipments.

Antimony Arsenic Beryllium Cadmium Chromium 

### Cobalt Lead Manganese 

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

### Sample ID # State/ Country County Fuel Shipment Method Nickel, ppm Other trace metal HAP, ppm45 

### Total Sulfur, % Ash

Content, % Heating Value, Btu/lb Mercury,

ppm Chlorine,

ppm Fluorine,

ppm Coal Seam

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

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

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

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

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

Stockton, Alma, Lower Cedar GroveTrain 09-241 12,019 0.89 11.46 13,096 ND 1180 72 23.0 1.7 4.0 3.1 ND 27.4 13.3 11.1 9.8 4.8WV Wayne Coalburg Train

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

09-534 12,889 1.07 13.4 13,260 0.060 426 59 14.1 <1 18.0 1.9 0.17 17.3 7.9 6.8 39.1 2.7VA Buchanan, Dickenson and Wise Bolling 24.88%,

Clintwoood 19.15%, Aily 15.35%, Blair 14.42% L. Banner 13.23%, Raven 4.52% Eagle 4.02%, U. Banner 3.44%, Taggart 0.98% Train

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

09-239 12,757 0.89 11.8 13,371 ND 1048 88 15.5 1.3 10.5 3.4 ND 18.5 10.4 8.7 24.6 3.1KY Pike Lower Elkhorn, Elkhorn , Alma, Clintwood Train

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

### Page 51 of 86 part II, 3

### GEORGIA POWER - PLANT YATES

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

4Were the data provided in Part II, question 3 above, acquired pursuant to:

__X__ permit requirements (for coal) ____ contractual obligations ____ standard operational procedures

__X__ other (please specify _at the discretion of the plant and to support other projects__)

5Analyses provided in Part II, question 3 above, supplied by ____ Fuel supplier (name and address)

__X__ Other (name and address)

Georgia Power Environmental Lab 5131 Maner Road, Smyrna GA 30080 6Name and address of laboratory performing analyses:

Georgia Power Environmental Lab (same as above)

Page 52 of 86 part II, 4-6

### GEORGIA POWER - PLANT YATES

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

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

Total

Moisture 

### Volatiles Ash Fixed Carbon Carbon Hydrogen 

### Nitrogen Total Sulfur Oxygen Barium Copper Magnesium 

### Sodium Vanadium 

### Zinc Al2O3 Fe2O3 

### CaO MgO MnO2 P2O5 K2O SiO2 Na2O SO3 TiO2
09-500 4.94 30.41 12.61 56.98 76.22 4.6 1.52 1.11 3.94 181 20.6 0.087 0.033 36.2 16.0 25.7 9.28 1.7 1.03 ND 0.491 2.2 50.2 0.434 1.28 1.55 09-501 6.35 32.47 12.79 54.74 75.28 4.65 1.41 0.99 4.88 121 21.1 0.102 0.044 43.2 22.6 27.6 7.96 0.992 1.25 ND ND 3.05 54.2 0.554 0.561 1.45 09-504 5.84 33.51 11.79 54.7 76.11 4.73 1.48 1.23 4.66 131 19.4 0.077 0.025 29.7 17.1 26.5 9.34 1.22 0.972 ND 0.577 2.73 48.6 0.35 0.288 1.36 09-505 6.83 37.22 10.24 52.53 76.72 4.88 1.41 1.54 5.2 317 23.5 0.008 0.000 37.3 16.1 26.3 12.7 2.5 0.876 ND ND 2.2 45.7 0.523 1.82 1.25 09-507 4.92 31.63 13.36 55.01 75.87 4.63 1.35 0.91 3.88 386 20.0 0.092 0.037 29.4 14.7 24.2 6.89 0.858 1.11 ND ND 2.78 55.1 0.397 0.715 1.38 09-623 7.14 34.92 13.06 52.02 73.1 4.92 1.92 2.3 4.7 220 35.3 0.102 0.044 55.8 26.9 26.08 14.67 4.31 1.3 0.041 0.68 2.38 43.07 0.46 5.31 1.34 09-203 5.28 34.06 12.64 53.31 75.25 4.72 1.41 1.45 4.52 152 18.5 0.088 0.027 27.1 15.3 24.6 10.7 1.34 1.13 ND ND 2.5 50.9 0.336 0.658 1.33 09-400 5.42 36.88 7.45 55.68 79.19 4.91 1.83 1.22 5.39 122 21.6 0.063 0.014 31.6 18.9 27.6 11.3 3.44 1.24 ND ND 2.23 49.2 0.36 2.24 1.33 09-401 5.83 36.96 8.93 54.11 77.62 4.92 1.9 2.01 4.63 91 23.9 0.059 0.016 34.8 13.8 22.8 16.7 2.13 0.982 ND ND 2.19 47.5 0.264 1.1 1.19 09-510 6.98 32.91 13.2 53.89 75.61 4.8 1.4 1.07 3.92 132 22.3 0.109 0.042 39.1 22.4 26.6 9.47 1.34 1.26 ND ND 3.26 53.5 0.531 0.96 1.34 09-517 5.05 28.35 13.47 58.17 75.07 4.5 1.45 1.18 4.33 172 23.8 0.101 0.036 30.8 19.1 24.1 10.4 1.71 1.12 ND ND 2.77 54.7 0.412 1.19 1.21 09-514 4.99 34.16 12.38 53.47 76.24 4.86 1.34 1.9 3.28 172 20.1 0.098 0.025 31.1 21.7 24.1 17.9 1.11 1.17 ND ND 3.13 45.3 0.322 0.568 1.02 09-515 5.67 31.26 11.76 56.97 75.97 4.62 1.33 0.87 5.45 417 18.6 0.084 0.047 27.3 15.6 25.2 7.17 0.964 1.09 ND ND 3.18 55 0.562 0.727 1.26 09-516 5.81 32.04 14.5 53.46 73.4 4.63 1.25 0.94 5.28 386 21.7 0.110 0.038 31.2 21.0 24.4 10.4 1.48 1.24 ND ND 2.92 56.4 0.42 1.17 1.31 09-411 5.82 36.75 9.32 53.92 75.84 4.98 1.77 1.63 6.46 122 26.6 0.063 0.017 35.5 14.7 28.2 11.7 2.56 1.22 ND 0.459 2.41 58.5 0.615 1.21 1.4 09-412 6.19 36.01 9.01 54.99 76.13 4.9 1.63 0.98 7.36 113 28.7 0.081 0.019 45.4 25.6 28.5 7.19 3.26 1.56 ND 0.502 2.59 51 0.349 1.9 1.28 09-216 6.72 38.03 9.41 52.56 72.88 4.8 1.52 1.59 9.79 82 23.2 0.047 0.033 34.8 14.2 27.7 12.7 3.07 0.839 ND ND 1.86 46.9 0.546 2.15 1.26 09-217 6.04 36.73 9.81 53.45 73.44 4.77 1.47 0.95 9.57 31 20.8 0.038 0.023 43.1 21.9 32.7 5.17 1.15 0.612 ND ND 1.89 52.7 0.375 0.386 1.28 09-641 6.91 34.91 13.06 52.03 73.1 4.78 1.1 2.39 5.57 220 32.1 0.099 0.039 51.0 22.2 25.07 14.91 5.41 1.26 0.041 0.64 2.38 42.44 0.41 5.79 1.24 09-519 6.16 32.55 13.36 54.1 75.2 4.82 1.56 0.9 4.16 132 21.5 0.109 0.048 40.3 22.7 26.8 8.44 1.64 1.35 ND ND 3.29 58.4 0.542 1.25 1.3 09-520 4.92 35.57 9.91 54.52 77.95 4.74 1.69 1.28 4.43 172 20.4 0.075 0.034 31.0 17.7 25.8 12.5 1.78 1.09 ND ND 2.43 58 0.509 1.28 1.42 09-521 5.15 31.19 12.11 56.71 75.69 4.76 1.56 0.75 5.13 285 18.6 0.086 0.048 28.6 12.6 27.4 6.87 1.13 1.18 ND ND 3.27 57.8 0.54 0.715 1.35 09-523 5.05 34.22 13.7 52.08 71.4 4.7 1.39 1.63 7.17 183 17.6 0.131 0.026 33.0 25.8 24.8 16.1 0.949 1.4 ND ND 3.39 47 0.302 0.665 1.1 09-110 6.66 34.78 12.63 52.59 72.71 4.97 1.8 2.16 5.73 230 36.6 0.101 0.042 59.8 42.3 26.37 14.37 4.18 1.32 0.045 0.81 2.34 43.59 0.45 4.76 1.37 09-226 6.43 36.29 10.72 52.99 74.53 4.93 1.59 0.98 7.25 41 21.0 0.042 0.026 45.6 27.4 32.4 4.36 0.883 0.64 ND ND 2.1 56.5 0.37 0.272 1.29 09-527 7.86 32.37 11.8 55.83 74.02 4.43 1.5 0.81 7.44 285 17.6 0.083 0.039 20.4 15.6 24.8 11 1.74 1.33 ND ND 3.03 51.8 0.507 1.42 1.11 09-231 6.67 38.81 8.58 52.6 74.73 4.82 1.6 1.47 8.8 62 29.3 14.578 0.029 44.2 18.7 30 9.74 2.59 0.789 ND ND 1.81 47.7 0.501 2.47 1.21 09-429 6.36 35.29 10.27 54.44 73.63 4.69 1.62 2 7.78 92 45.9 0.085 0.015 61.3 34.8 27.5 11.6 2.72 1.35 ND ND 2.21 45.2 0.273 2.14 1.41 09-430 5.44 35.86 7.32 56.82 76.71 4.86 1.61 0.94 8.56 82 32.3 0.056 0.029 49.0 22.6 28.5 7.98 3.13 1.46 ND 0.441 2.25 48.3 0.376 2.33 1.37 09-233 7.03 31.74 12.37 55.89 73.57 4.52 1.35 0.74 7.46 255 20.5 0.084 0.034 23.3 17.2 23.7 12.7 1.67 1.04 0.132 ND 2.9 50.1 0.451 1.27 1.22 09-436 6.32 35.44 9.45 55.11 75 4.78 1.83 1.87 7.06 112 35.2 0.070 0.015 47.6 23.3 28 11.4 2.48 1.25 ND 0.477 2.17 48.2 0.253 2.19 1.38 09-437 6.02 36.44 6.61 56.95 77.61 4.94 1.74 1.31 7.79 71 28.2 0.054 0.015 39.6 20.3 32.3 4.08 0.902 0.651 ND ND 1.54 56.5 0.173 ND 1.75 09-529 6.24 33.15 12.13 54.71 75.15 4.65 1.44 1.01 5.62 122 24.1 0.092 0.037 41.2 20.5 26.9 6.59 1.2 1.06 ND 0.403 2.65 52.4 0.435 0.695 1.51 09-530 6.14 32.04 12.06 55.9 74.64 4.58 1.36 0.8 6.56 317 10.6 0.226 0.082 13.6 14.1 25.3 5.02 0.88 0.998 ND ND 2.38 56.1 0.291 0.556 1.44 09-241 7.18 35.8 11.46 52.75 73.15 4.74 1.45 0.89 8.31 31 22.7 0.052 0.026 48.8 23.3 28.5 3.76 0.833 0.679 ND ND 1.97 52.9 0.325 0.353 1.24 09-532 5.65 33.92 13.08 53.01 73.25 4.71 1.31 1.59 6.06 132 23.5 0.109 0.023 37.5 31.6 27.7 14.2 1.02 1.32 ND ND 3.52 54.4 0.292 0.575 1.21 Sample ID # Proximate Analyses, % by wt Ultimate Analyses, % by wt Ash Mineralogy, % by wt Other Trace Metals, ppm, dry basis

Page 53 of 86 part II, 7

### GEORGIA POWER - PLANT YATES

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

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

Total

Moisture 

### Volatiles Ash Fixed Carbon Carbon Hydrogen 

### Nitrogen Total Sulfur Oxygen Barium Copper Magnesium 

### Sodium Vanadium 

### Zinc Al2O3 Fe2O3 

### CaO MgO MnO2 P2O5 K2O SiO2 Na2O SO3 TiO2 Sample ID # Proximate Analyses, % by wt Ultimate Analyses, % by wt Ash Mineralogy, % by wt Other Trace Metals, ppm, dry basis

09-534 5.91 28.73 13.4 57.87 71.07 4.35 1.49 1.07 8.62 162 17.8 0.087 0.033 29.8 22.0 27.5 9.14 2.04 1.11 ND 0.353 2.64 58.4 0.431 1.09 1.78 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 09-239 6.42 31.36 11.8 56.85 74.7 4.56 1.5 0.89 6.56 315 21.4 0.080 0.043 33.1 13.0 30.3 5.64 1.14 1.15 ND ND 2.9 51 0.57 1.08 1.4

Page 54 of 86 part II, 7

### GEORGIA POWER - PLANT YATES

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

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

Report 1 Units 2&3 Particulate Emissions Test (March 1, 2005) Report 2 Units 4&5 Particulate Emissions Test (March 2, 2005) Report 3 Unit 6 Particulate Emissions Test (April 27, 2005) Report 4 Unit 7 Particulate Emissions Test (April 27, 2005) Report 5 Units 2&3 Particulate Emissions Test (February 28, 2007) Report 6 Units 4&5 Particulate Emissions Test (February 28, 2007) Report 7 Unit 6 Particulate Emissions Test (February 28, 2007) Report 8 Unit 7 Particulate Emissions Test (February 28, 2007) Report 9 Units 2&3 Particulate Emissions Test (February 25, 2009) Report 10Units 4&5 Particulate Emissions Test (February 25, 2009) Report 11 Unit 6 Particulate Emissions Test (February 24, 2009) Report 12 Unit 7 Particulate Emissions Test (February 24, 2009) Report 13 Unit 6 SCR Baseline (September 12, 2008 to October 2, 2008) Report 14Unit 6 Sorbent Injection Mercury Study (February 28, 2005 to March 22, 2005) Report 15 DRAFT Unit 1 Boiler Chemical Addition Mercury Study (October 31, 2007 to November 7, 2007) Report 16 Unit 1 Sorbent Injection for Small ESP Mercury Control (January 2005) Report 17 Unit 1 Field Testing of a Wet FGD Additive for Enhanced Mercury Control (May 15, 2007 to September 27, 2007) Report 18 Unit 1 Multi-Method Mercury Speciation Testing (March 15, 2006 to March 21, 2006) Report 19 Unit 1 SO3 Testing (March to August 2008) Report 20Unit 1 SO3 Testing (October 2009) Report 21 Unit 1 ACI into FGD (November 2009 to December 2009) Report 22 Unit 1 Lime Injection into FGD (February 2006) Report 23 Unit 1 Lime Injection into FGD (February 2007)

Page 55 of 86 part II, 8

### GEORGIA POWER - PLANT YATES

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

8bPlease indicate the date(s) and types (e.g., stack, fuel, parametric, etc.) of the test(s) and the constituents (including criteria and hazardous air pollutants) sampled for: Report 1 Date:3/1/2005 Type:stack Constituents:PM Report 2 Date:3/2/2005 Type:stack Constituents:PM Report 3 Date:4/27/2005 Type:stack Constituents:PM Report 4 Date:4/27/2005 Type:stack Constituents:PM Report 5 Date:2/28/2007 Type:stack Constituents:PM Report 6 Date:2/28/2007 Type:stack Constituents:PM Report 7 Date:2/28/2007 Type:stack Constituents:PM Report 8 Date:2/28/2007 Type:stack Constituents:PM Report 9 Date:2/25/2009 Type:stack Constituents:PM Report 10 Date:2/25/2009 Type:stack Constituents:PM Report 11 Date:2/24/2009 Type:stack Constituents:PM Report 12 Date:2/24/2009 Type:stack Constituents:PM Report 13 Date:9/12/2008-10/2/2008 Type:duct Constituents:CO Report 14 Date:2/28/2005-3/22/2005 Type:duct/stack Constituents:Hg Report 15 Date:10/31/2007-11/7/2007 Type:duct/stack Constituents:Hg Report 16 Date:Jan 2005 Type:duct/stack Constituents:HCl, HF

Report 17 Date:5/15/2007-5/30/2007 8/28/2007-9/27/2007 Type:duct/stack Constituents:Hg Report 18 Date:3/15/2006-3/21/2006 Type:duct/stack Constituents:Hg, HCl, SO3 Report 19 Date:Mar 2008-Aug 2008 Type:duct/stack Constituents:SO3 Report 20 Date:Oct 2009 Type:duct/stack Constituents:SO3 Report 21 Date:Nov 2009-Dec 2009 Type:stack Constituents:PM Report 22 Date:Feb 2006 Type:duct/stack Constituents:SO3 Report 23 Date:Feb 2007 Type:duct/stack Constituents:SO3

Page 56 of 86 part II, 8

### GEORGIA POWER - PLANT YATES

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

8cDo any of these test reports reflect testing at a location upstream of any emission control devices? Yes _X

___No ____ If yes, please note which reports and provide a detailed description of the location of the emissions sampling point(s). Although Report 13 reflects testing at the economizer outlet (upstream of all post-combustion control devices), there are no control devices downstream designed to reduce CO. Reports 15, 16, 17, 18, 19, 20, 22, 23 reflect testing upstream of the scrubber, at the inlet duct.

8dWere any of these test reports conducted when use of other material(s) or non-fossil fuels were fired in the boiler? Yes ____ No _X

___ If yes, please not which reports and identify the other material(s) or non-fossil fuels used.

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

___ If yes, please note which reports.

8fDid the unit's control configuration differ from that shown in Part I, question 16, at the time of these test results? Yes _X

___No ____ If yes, please list the unit's complete control configuration at time of testing in a similar format to Part I, question 16.

Page 57 of 86 part II, 8

### GEORGIA POWER - PLANT YATES

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010
The control configuration shown below is representative of the conditions present during Reports 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 21.

Boiler ID Type NOx control SO2 control PM control Other control Y1BR tangentialfired (1) low NOx burners (3) wet flue gas desulfurization (FGD) (2) cold-side electrostatic precipitator

Y2BR tangentialfired (3) cold-side electrostatic precipitator (2) flue gas conditioning (SO3 injection) (1) flue gas conditioning (ammonia)

Y3BR tangentialfired (3) cold-side electrostatic precipitator (2) flue gas conditioning (SO3 injection) (1) flue gas conditioning (ammonia)

Y4BR tangentialfired (1) flame attachment

nozzle (low-NOX burnertip design) and closecoupled overfire air (4) cold-side electrostatic precipitator (3) flue gas conditioning (SO3 injection) (2) flue gas conditioning (ammonia)

Y5BR tangentialfired (1) flame attachment

nozzle (low-NOX burnertip design) and closecoupled overfire air (4) cold-side electrostatic precipitator (3) flue gas conditioning (SO3 injection) (2) flue gas conditioning (ammonia)

Y6BR tangentialfired (1) low-NOX concentric

firing system + separated overfire air (5) cold-side electrostatic precipitator

Y7BR tangentialfired (1) flame attachment

nozzle (low-NOX burner tip design) and separated overfire air (5) cold-side electrostatic precipitator



### Page 58 of 86 part II, 8

### GEORGIA POWER - PLANT YATES

EGU HAPs ICR, OMB Control No. 2060-0631 April 5, 2010
The control configuration shown below is representative of the conditions present during Reports 19, 20, 22, 23.

Boiler ID Type NOx control SO2 control PM control Other control Y1BR tangentialfired (1) low NOx burners (3) wet flue gas desulfurization (FGD) (2) cold-side electrostatic precipitator (3) lime injection (temporary system installed and operated for research & development purposes only)



### 8gDo any of these test reports reflect testing at a location upstream of a post combustion SO2 emission control device (e.g., FGD, SDA, Dry Scrubber)? Yes _X

___No ____ If yes, please note which reports and, in addition to the detailed description of the location of the sampling point(s) (question 8c above), include detail about how much, if any, bypass of unscrubbed flue gas was utilized at at the time of testing (including percentage of total scrubber flue gas flow). Note by diagram where sampling ports were located in relation to the bypass ductwork. Reports 15, 16, 17, 18, 19, 20, 22, 23 include testing at locations before a post combustion SO2 emission control device. No bypass of unscrubbed flue gas was utilized at the time of testing.

Page 59 of 86 part II, 8

### GEORGIA POWER - PLANT YATES

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

9What type of deviation reporting is required for violations of permit requirements?

Specified deviations are reported quarterly. Emissions exceeding a standard for a period of 4 hours or more are reported within 7 days. Other deviations are reported semiannually. Note: Not all reported deviations are considered violations of permit requirements

10Are deviation reports available for malfunctions or other periods of noncompliance with permit terms and conditions? Yes _X

__ No ____ If yes, please note which reports.

Deviation reports including periods of malfuncation are available where required in quarterly monitor breakdown reports and excess emissions, exdeedances, and excursion reports. Note: A malfunction is not necessarily a period of noncompliance with permit terms and conditions. Not all reported deviations are considered violations of permit requirements

11Are continuous emissions monitoring system (CEMS) data available (e.g., mercury, continuous opacity monitoring systems) that are not already being provided to the U.S. EPA, even if from short-term testing? Yes _X

__ No ____ If yes46

### , please note for which pollutants CEMS data are available and the period of time (both total period and calendar period) for which the data are available. If CEM data are being provided to EPA, please note to which Office the data are being provided.

Mercury CEMS data not available for this facility, however some mercury CEMS data are provided in reports in response to Part II Question 12 of this ICR for reference. These data are collected for research purposes and do not necessarily follow any specific QA/QC guidelines.
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 60 of 86 part II, 9-11

### GEORGIA POWER - PLANT YATES

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

12For each boiler noted in Part I, question 15, provide the following information: NOTE: Net generation data not available in test reports. Other parameters may or may not be available depending on the test report.

Date of test PM49 

### SO2 HCl/HF/HCN Metal HAP50 

### Hg51 

### CO Other organics (specify)
Y2BR & Y3BR 3/1/2005 See Attachment 1 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Y4BR & Y5BR 3/2/2005 See Attachment 2 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Y6BR 4/27/2005 See Attachment 3 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Y7BR 4/27/2005 See Attachment 4 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Y2BR & Y3BR 2/28/2007 See Attachment 5 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Y4BR & Y5BR 2/28/2007 See Attachment 6 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Y6BR 2/28/2007 See Attachment 7 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Y7BR 2/28/2007 See Attachment 8 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Y2BR & Y3BR 2/25/2009 See Attachment 9 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Y4BR & Y5BR 2/25/2009 See Attachment 10Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Y6BR 2/24/2009 See Attachment 11Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Y7BR 2/24/2009 See Attachment 12Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

Y6BR 9/12/2008-

10/2/2008 Not applicable Not applicable Not applicable Not applicable Not applicable See Attachment 13Not applicable

Y6BR 2/28/2005-

3/22/2005 Not applicable Not applicable Not applicable Not applicable See Attachment 14Not applicable Not applicable

Y1BR 10/31/2007-

11/7/2007 Not applicable Not applicable Not applicable Not applicable See Attachment 15Not applicable Not applicable Y1BR Jan 2005 Not applicable Not applicable See Attachment 16 Not applicable Not applicable Not applicable Not applicable

Y1BR 5/15/2007-

9/27/2007 Not applicable Not applicable Not applicable Not applicable See Attachment 17Not applicable Not applicable 

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



### Page 61 of 86 part II, 12

### GEORGIA POWER - PLANT YATES

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

12For each boiler noted in Part I, question 15, provide the following information: NOTE: Net generation data not available in test reports. Other parameters may or may not be available depending on the test report.

Date of test PM49 

### SO2 HCl/HF/HCN Metal HAP50 

### Hg51 

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

Y1BR 3/15/2006-

3/21/2006 Not applicable Not applicable See Attachment 18 Not applicable See Attachment 18Not applicable Not applicable

Y1BR Nov 2009-Dec

2009 Final data not yet

available 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 Nm3/hr), Flue gas oxygen content (%, dry), Flue gas carbon dioxide content (%, dry), Flue gas temperature at sampling point (oF), Flue gas pressure at sampling point (atm), Standard temperature (oF), Standard pressure (atm).
49If emission testing recorded the emissions of filterable and condensable PM, separately, please include those separate emission results. Also, please include separate emission results for total PM, PM10, and PM2.5. 50Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, phosphorus, and selenium; indicate emission level for all metal HAP for which an emission test has been conducted.
51Please provide separate results for total Hg, elemental Hg, oxidized Hg, and particulate Hg, as available. If the emissions testing recorded the amount of unburned carbon in fly ash (as reflected by the "Loss of Ignition" [L.O.I]) at the time of any Hg testing, please include these data.



### Page 62 of 86 part II, 12

## ATTACHMENT 1 - Yates Report 1 Test Results

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

Run 1 Run 2 Run 3 Test Date 3/1/2005 3/1/2005 3/1/2005 Run Start Time 8:15 9:45 11:15 Run End Time 9:20 10:55 12:25 Meter Volume (dacf), Vm: 41.29 42.335 41.707 Sqrt Delta P ("wc): 1.02 1.03 1.01 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 28.92 29.22 29.20 Delta H ("wc): 1.4 1.5 1.4 Volume in Impingers (mls), VIc: 58.0 64.1 63.0 Static Pressure ("wc), Pg: -1.50 -1.50 -1.60 Stack Pressure ("Hg), Ps: 28.81 29.11 29.08 Stack Temperature (F), Ts: 245 248 249 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: 59 65 67 Stack Diameter (inches): 197 197 197 Area Stack (sq. ft.), As: 211.67 211.67 211.67 Nozzle Diameter (inches), dp: 0.214 0.214 0.214 Area Nozzle (sq. ft.), An: 0.000249 0.000249 0.000249 Percent CO2 (% dry volume): 11.6 11.5 11.6 Percent O2 (% dry volume): 7.1 7.3 7.2 Percent (N2 + CO) (% dry volume): 81.3 81.2 81.2 Particulate Collected (mg), Mn: 130.5 98.8 115.5

Molec. Wt. Dry

(lb/lb-mole), Md: 30.140 30.132 30.144 Volume Water (scf), Vwstd 2.730 3.017 2.965 Meter Volume (dscf), Vmstd: 40.029 41.034 40.209 Wet Fraction (v/v), Bws: 0.064 0.068 0.069 Molec. Wt. Wet (lb/lb-mole), Ms: 29.365 29.301 29.310 Stack Gas Sampled (acf), Vma: 59.321 60.706 59.616 Averages Stack Gas Velocity

(fps), Vs: 66.56 67.07 66.23 67 Volumetric Flowrate (dscfm), Qs: 570,451 575,779 567,321 571,183 Volumetric Flowrate (acfm), Qa: 845,386 851,807 841,147 846,113 Grainloading (gr/dscf), cs: 0.0503 0.0372 0.0443 0.04 Emission Rate (lb/hour), E: 245.87 183.35 215.62 214.9 Percent Isokinetic Sampling (%), I: 99.64 101.19 100.64 100.49
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 2310.81 2298.59 2281.47 2296.95 Emission Rate (lbs/mmBtu), E: 0.106 0.080 0.095 0.094 Allowable Rate (lb/mmBtu): 0.240 0.240 0.240 0.240 Average Unit Gross Load (MW) 204 204 204 204 

### Particulate Emission Results Summary

Plant Yates Units 2-3

Page 63 of 86 Att. 1

## ATTACHMENT 2 - Yates Report 2 Test Results

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

Run 1 Run 2 Run 3 Test Date 3/2/2005 3/2/2005 3/2/2005 Run Start Time 8:15 9:45 11:15 Run End Time 9:25 10:55 12:25 Meter Volume (dacf), Vm: 58.825 59.502 60.585 Sqrt Delta P ("wc): 1.52 1.52 1.54 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.20 29.22 29.20 Delta H ("wc): 3.0 3.0 3.1 Volume in Impingers (mls), VIc: 96.6 100.1 100.7 Static Pressure ("wc), Pg: -2.70 -3.20 -3.00 Stack Pressure ("Hg), Ps: 29.00 28.98 28.98 Stack Temperature (F), Ts: 283 285 287 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: 55 60 65 Stack Diameter (inches): 174.96 174.96 174.96 Area Stack (sq. ft.), As: 166.96 166.96 166.96 Nozzle Diameter (inches), dp: 0.214 0.214 0.214 Area Nozzle (sq. ft.), An: 0.000249 0.000249 0.000249 Percent CO2 (% dry volume): 0.0 0.0 0.0 Percent O2 (% dry volume): 0.0 0.0 0.0 Percent (N2 + CO) (% dry volume): 100.0 100.0 100.0 Particulate Collected (mg), Mn: 121.9 121.9 132.0

Molec. Wt. Dry

(lb/lb-mole), Md: 28.000 28.000 28.000 Volume Water (scf), Vwstd 4.547 4.712 4.740 Meter Volume (dscf), Vmstd: 58.231 58.389 58.921 Wet Fraction (v/v), Bws: 0.072 0.075 0.074 Molec. Wt. Wet (lb/lb-mole), Ms: 27.276 27.253 27.255 Stack Gas Sampled (acf), Vma: 91.139 91.959 93.000 Averages Stack Gas Velocity

(fps), Vs: 105.47 106.27 107.54 106 Volumetric Flowrate (dscfm), Qs: 675,049 675,925 682,544 677,839 Volumetric Flowrate (acfm), Qa: 1,056,537 1,064,534 1,077,309 1,066,127 Grainloading (gr/dscf), cs: 0.0323 0.0322 0.0346 0.03 Emission Rate (lb/hour), E: 186.87 186.60 202.20 191.9 Percent Isokinetic Sampling (%), I: 96.61 96.75 96.68 96.68
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 4141.41 4146.78 4187.38 4158.52 Emission Rate (lbs/mmBtu), E: 0.045 0.045 0.048 0.046 Allowable Rate (lb/mmBtu): 0.240 0.240 0.240 0.240 Average Unit Gross Load (MW) 282 282 282 282 

### Particulate Emission Results Summary

Plant Yates Units 4-5

Page 64 of 86 Att. 2

## ATTACHMENT 3 - Yates Report 3 Test Results

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

Run 1 Run 2 Run 3 Test Date 4/27/2005 4/27/2005 4/27/2005 Run Start Time 8:00 9:55 11:40 Run End Time 9:25 11:10 12:50 Meter Volume (dacf), Vm: 37.455 39.265 40.262 Sqrt Delta P ("wc): 1.44 1.46 1.46 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.01 29.01 29.01 Delta H ("wc): 1.4 1.4 1.4 Volume in Impingers (mls), VIc: 46.0 47.0 45.5 Static Pressure ("wc), Pg: -2.50 -2.70 -2.40 Stack Pressure ("Hg), Ps: 28.83 28.81 28.83 Stack Temperature (F), Ts: 249 258 261 Meter Coefficient (no units), Y: 0.985 0.985 0.985 Pitot Coefficient (no units) Cp: 0.840 0.840 0.840 Meter OutletTemperature (F), Tm: 73 79 83 Stack Diameter (inches): 209.53 209.53 209.53 Area Stack (sq. ft.), As: 239.45 239.45 239.45 Nozzle Diameter (inches), dp: 0.172 0.172 0.172 Area Nozzle (sq. ft.), An: 0.000162 0.000162 0.000162 Percent CO2 (% dry volume): 12.5 12.6 12.5 Percent O2 (% dry volume): 7.0 6.8 6.9 Percent (N2 + CO) (% dry volume): 80.5 80.6 80.6 Particulate Collected (mg), Mn: 12.3 18.6 20.2

Molec. Wt. Dry

(lb/lb-mole), Md: 30.285 30.289 30.276 Volume Water (scf), Vwstd 2.165 2.212 2.142 Meter Volume (dscf), Vmstd: 35.518 36.829 37.508 Wet Fraction (v/v), Bws: 0.057 0.057 0.054 Molec. Wt. Wet (lb/lb-mole), Ms: 29.579 29.593 29.613 Stack Gas Sampled (acf), Vma: 52.515 55.133 56.177 Averages Stack Gas Velocity

(fps), Vs: 94.36 96.19 96.15 96 Volumetric Flowrate (dscfm), Qs: 916,924 923,152 922,324 920,800 Volumetric Flowrate (acfm), Qa: 1,355,716 1,381,956 1,381,382 1,373,018 Grainloading (gr/dscf), cs: 0.0053 0.0078 0.0083 0.01 Emission Rate (lb/hour), E: 41.87 61.70 65.57 56.4 Percent Isokinetic Sampling (%), I: 95.59 98.45 100.36 98.13
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 3741.23 3811.80 3790.33 3781.12 Emission Rate (lbs/mmBtu), E: 0.011 0.016 0.017 0.015 Allowable Rate (lb/mmBtu): 0.240 0.240 0.240 0.240 Average Unit Gross Load (MW) 359 361 360 360 

### Particulate Emission Results Summary

Yates Unit 6

Page 65 of 86 Att. 3

## ATTACHMENT 4 - Yates Report 4 Test Results

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

Run 1 Run 2 Run 3 Test Date 4/27/2005 4/27/2005 4/27/2005 Run Start Time 8:00 9:55 11:40 Run End Time 9:25 11:10 12:50 Meter Volume (dacf), Vm: 40.748 41.472 41.249 Sqrt Delta P ("wc): 1.45 1.44 1.46 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.01 29.01 29.01 Delta H ("wc): 1.4 1.4 1.4 Volume in Impingers (mls), VIc: 54.4 54.1 52.8 Static Pressure ("wc), Pg: -2.70 -2.60 -2.60 Stack Pressure ("Hg), Ps: 28.81 28.82 28.82 Stack Temperature (F), Ts: 255 262 266 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: 72 75 80 Stack Diameter (inches): 209.53 209.53 209.53 Area Stack (sq. ft.), As: 239.45 239.45 239.45 Nozzle Diameter (inches), dp: 0.176 0.176 0.176 Area Nozzle (sq. ft.), An: 0.000168 0.000168 0.000168 Percent CO2 (% dry volume): 12.6 12.7 12.6 Percent O2 (% dry volume): 6.8 6.9 6.8 Percent (N2 + CO) (% dry volume): 80.6 80.4 80.6 Particulate Collected (mg), Mn: 15.2 15.2 16.0

Molec. Wt. Dry

(lb/lb-mole), Md: 30.288 30.304 30.289 Volume Water (scf), Vwstd 2.561 2.546 2.485 Meter Volume (dscf), Vmstd: 38.672 39.103 38.542 Wet Fraction (v/v), Bws: 0.062 0.061 0.061 Molec. Wt. Wet (lb/lb-mole), Ms: 29.525 29.552 29.545 Stack Gas Sampled (acf), Vma: 57.984 59.129 58.535 Averages Stack Gas Velocity

(fps), Vs: 95.28 95.30 96.59 96 Volumetric Flowrate (dscfm), Qs: 912,980 905,498 913,793 910,757 Volumetric Flowrate (acfm), Qa: 1,368,906 1,369,227 1,387,794 1,375,309 Grainloading (gr/dscf), cs: 0.0061 0.0060 0.0064 0.01 Emission Rate (lb/hour), E: 47.56 46.65 50.31 48.2 Percent Isokinetic Sampling (%), I: 100.41 102.37 99.98 100.92
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 3778.73 3712.33 3773.16 3754.74 Emission Rate (lbs/mmBtu), E: 0.013 0.013 0.013 0.013 Allowable Rate (lb/mmBtu): 0.240 0.240 0.240 0.240 Average Unit Gross Load (MW) 353 354 351 353 

### Particulate Emission Results Summary

Yates Unit 7

Page 66 of 86 Att. 4

## ATTACHMENT 5 - Yates Report 5 Test Results

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

Run 1 Run 2 Run 3 Test Date 2/28/2007 2/28/2007 2/28/2007 Run Start Time 9:15 11:10 12:40 Run End Time 10:30 12:20 13:50 Meter Volume (dacf), Vm: 42.721 43.269 43.568 Sqrt Delta P ("wc): 1.06 1.07 1.07 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.10 29.10 29.10 Delta H ("wc): 1.6 1.6 1.6 Volume in Impingers (mls), VIc: 55.6 55.5 56.2 Static Pressure ("wc), Pg: -2.10 -2.20 -2.20 Stack Pressure ("Hg), Ps: 28.95 28.94 28.94 Stack Temperature (F), Ts: 255 263 267 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: 64 73 79 Stack Diameter (inches): 197 197 197 Area Stack (sq. ft.), As: 211.67 211.67 211.67 Nozzle Diameter (inches), dp: 0.214 0.214 0.214 Area Nozzle (sq. ft.), An: 0.000249 0.000249 0.000249 Percent CO2 (% dry volume): 11.8 11.8 11.8 Percent O2 (% dry volume): 7.8 7.9 7.9 Percent (N2 + CO) (% dry volume): 80.5 80.4 80.2 Particulate Collected (mg), Mn: 80.6 63.2 59.6

Molec. Wt. Dry

(lb/lb-mole), Md: 30.193 30.197 30.211 Volume Water (scf), Vwstd 2.617 2.612 2.645 Meter Volume (dscf), Vmstd: 41.435 41.271 41.148 Wet Fraction (v/v), Bws: 0.059 0.060 0.060 Molec. Wt. Wet (lb/lb-mole), Ms: 29.469 29.471 29.473 Stack Gas Sampled (acf), Vma: 61.626 62.129 62.301 Averages Stack Gas Velocity

(fps), Vs: 69.91 70.92 71.08 71 Volumetric Flowrate (dscfm), Qs: 596,982 598,274 596,258 597,171 Volumetric Flowrate (acfm), Qa: 887,888 900,637 902,785 897,103 Grainloading (gr/dscf), cs: 0.0300 0.0236 0.0223 0.03 Emission Rate (lb/hour), E: 153.56 121.23 114.19 129.7 Percent Isokinetic Sampling (%), I: 98.32 97.72 97.76 97.93
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 2301.45 2288.87 2269.49 2286.61 Emission Rate (lbs/mmBtu), E: 0.07 0.05 0.05 0.06 Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.240 Average Unit Gross Load (MW) 208 208 208 208 

### Particulate Emission Results Summary

Yates Unit 2-3

Page 67 of 86 Att. 5

## ATTACHMENT 6 - Yates Report 6 Test Results

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

Run 1 Run 2 Run 3 Test Date 2/28/2007 2/28/2007 2/28/2007 Run Start Time 9:15 11:10 12:40 Run End Time 10:30 12:20 13:50 Meter Volume (dacf), Vm: 44.52 42.975 43.28 Sqrt Delta P ("wc): 1.57 1.55 1.56 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.10 29.10 29.10 Delta H ("wc): 1.6 1.6 1.6 Volume in Impingers (mls), VIc: 65.1 62.9 63.5 Static Pressure ("wc), Pg: -2.00 -2.10 -1.90 Stack Pressure ("Hg), Ps: 28.95 28.95 28.96 Stack Temperature (F), Ts: 284 290 292 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: 60 72 77 Stack Diameter (inches): 175 175 175 Area Stack (sq. ft.), As: 167.03 167.03 167.03 Nozzle Diameter (inches), dp: 0.178 0.178 0.178 Area Nozzle (sq. ft.), An: 0.000173 0.000173 0.000173 Percent CO2 (% dry volume): 13.2 12.9 13.0 Percent O2 (% dry volume): 6.4 6.5 6.5 Percent (N2 + CO) (% dry volume): 80.4 80.6 80.4 Particulate Collected (mg), Mn: 49.2 65.7 56.8

Molec. Wt. Dry

(lb/lb-mole), Md: 30.364 30.328 30.347 Volume Water (scf), Vwstd 3.064 2.961 2.989 Meter Volume (dscf), Vmstd: 44.004 41.503 41.399 Wet Fraction (v/v), Bws: 0.065 0.067 0.067 Molec. Wt. Wet (lb/lb-mole), Ms: 29.559 29.507 29.515 Stack Gas Sampled (acf), Vma: 68.508 65.248 65.336 Averages Stack Gas Velocity

(fps), Vs: 104.88 104.51 104.86 105 Volumetric Flowrate (dscfm), Qs: 675,162 666,254 665,903 669,106 Volumetric Flowrate (acfm), Qa: 1,051,131 1,047,446 1,050,928 1,049,835 Grainloading (gr/dscf), cs: 0.0173 0.0244 0.0212 0.02 Emission Rate (lb/hour), E: 99.84 139.58 120.91 120.1 Percent Isokinetic Sampling (%), I: 105.06 100.42 100.22 101.90
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 2867.10 2822.75 2808.23 2832.69 Emission Rate (lbs/mmBtu), E: 0.03 0.05 0.04 0.04 Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.24 Average Unit Gross Load (MW) 282 280 280 281 

### Particulate Emission Results Summary

Yates Unit 4-5

Page 68 of 86 Att. 6

## ATTACHMENT 7 - Yates Report 7 Test Results

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

Run 1 Run 2 Run 3 Test Date 2/28/2007 2/28/2007 2/28/2007 Run Start Time 15:45 17:15 18:45 Run End Time 16:55 18:25 20:00 Meter Volume (dacf), Vm: 40.73 40.78 41.529 Sqrt Delta P ("wc): 1.44 1.45 1.45 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.00 29.00 28.98 Delta H ("wc): 1.3 1.4 1.4 Volume in Impingers (mls), VIc: 52.8 53.3 54.1 Static Pressure ("wc), Pg: -2.20 -2.10 -2.00 Stack Pressure ("Hg), Ps: 28.84 28.85 28.83 Stack Temperature (F), Ts: 268 269 268 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 81 78 Stack Diameter (inches): 195.96 195.96 195.96 Area Stack (sq. ft.), As: 209.44 209.44 209.44 Nozzle Diameter (inches), dp: 0.178 0.178 0.178 Area Nozzle (sq. ft.), An: 0.000172 0.000172 0.000172 Percent CO2 (% dry volume): 12.2 12.2 12.3 Percent O2 (% dry volume): 6.2 6.2 6.1 Percent (N2 + CO) (% dry volume): 81.6 81.6 81.6 Particulate Collected (mg), Mn: 17.4 19.1 20.0

Molec. Wt. Dry

(lb/lb-mole), Md: 30.199 30.201 30.207 Volume Water (scf), Vwstd 2.485 2.509 2.546 Meter Volume (dscf), Vmstd: 38.675 38.563 39.457 Wet Fraction (v/v), Bws: 0.060 0.061 0.061 Molec. Wt. Wet (lb/lb-mole), Ms: 29.462 29.456 29.467 Stack Gas Sampled (acf), Vma: 58.881 58.812 60.070 Averages Stack Gas Velocity

(fps), Vs: 95.69 96.15 96.04 96 Volumetric Flowrate (dscfm), Qs: 789,816 792,265 792,753 791,611 Volumetric Flowrate (acfm), Qa: 1,202,442 1,208,286 1,206,898 1,205,876 Grainloading (gr/dscf), cs: 0.0069 0.0076 0.0078 0.01 Emission Rate (lb/hour), E: 46.89 51.83 53.25 50.7 Percent Isokinetic Sampling (%), I: 99.35 98.75 100.98 99.69
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 3415.80 3410.89 3444.02 3423.57 Emission Rate (lbs/mmBtu), E: 0.01 0.02 0.02 0.01 Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.24 Average Unit Gross Load (MW) 361 363 364 363 

### Particulate Emission Results Summary

Yates Unit 6

Page 69 of 86 Att. 7

## ATTACHMENT 8 - Yates Report 8 Test Results

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

Run 1 Run 2 Run 3 Test Date 2/28/2007 2/28/2007 2/28/2007 Run Start Time 15:45 17:15 18:45 Run End Time 16:55 18:25 20:00 Meter Volume (dacf), Vm: 41.019 40.872 39.197 Sqrt Delta P ("wc): 1.49 1.47 1.45 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.00 29.00 29.98 Delta H ("wc): 1.4 1.4 1.4 Volume in Impingers (mls), VIc: 55.7 56.1 56.3 Static Pressure ("wc), Pg: -2.30 -2.20 -2.20 Stack Pressure ("Hg), Ps: 28.83 28.84 29.82 Stack Temperature (F), Ts: 274 275 272 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: 79 80 77 Stack Diameter (inches): 195.96 195.96 195.96 Area Stack (sq. ft.), As: 209.44 209.44 209.44 Nozzle Diameter (inches), dp: 0.178 0.178 0.178 Area Nozzle (sq. ft.), An: 0.000173 0.000173 0.000173 Percent CO2 (% dry volume): 12.2 12.3 12.2 Percent O2 (% dry volume): 6.0 5.9 6.0 Percent (N2 + CO) (% dry volume): 81.8 81.8 81.8 Particulate Collected (mg), Mn: 40.3 40.3 30.3

Molec. Wt. Dry

(lb/lb-mole), Md: 30.196 30.204 30.197 Volume Water (scf), Vwstd 2.622 2.641 2.650 Meter Volume (dscf), Vmstd: 38.598 38.382 38.225 Wet Fraction (v/v), Bws: 0.064 0.064 0.065 Molec. Wt. Wet (lb/lb-mole), Ms: 29.420 29.418 29.407 Stack Gas Sampled (acf), Vma: 59.474 59.240 56.829 Averages Stack Gas Velocity

(fps), Vs: 99.57 98.11 95.21 98 Volumetric Flowrate (dscfm), Qs: 812,047 798,822 804,774 805,214 Volumetric Flowrate (acfm), Qa: 1,251,230 1,232,944 1,196,448 1,226,874 Grainloading (gr/dscf), cs: 0.0161 0.0162 0.0122 0.01 Emission Rate (lb/hour), E: 112.20 111.00 84.27 102.5 Percent Isokinetic Sampling (%), I: 96.07 97.12 96.01 96.40
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 3559.62 3517.28 3519.87 3532.26 Emission Rate (lbs/mmBtu), E: 0.03 0.03 0.02 0.03 Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.24 Average Unit Gross Load (MW) 363 361 362 362 

### Particulate Emission Results Summary

Yates Unit 7

Page 70 of 86 Att. 8

## ATTACHMENT 9 - Yates Report 9 Test Results

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

Run 1 Run 2 Run 3 Test Date 2/25/2009 2/25/2009 2/25/2009 Run Start Time 10:05 11:50 13:25 Run End Time 11:20 13:05 14:35 Meter Volume (dacf), Vm: 38.582 39.446 39.89 Sqrt Delta P ("wc): 0.98 1.00 1.01 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.32 29.32 29.33 Delta H ("wc): 1.4 1.4 1.4 Volume in Impingers (mls), VIc: 51.7 52.7 54.9 Static Pressure ("wc), Pg: -1.50 -1.40 -1.40 Stack Pressure ("Hg), Ps: 29.21 29.22 29.23 Stack Temperature (F), Ts: 265 265 265 Meter Coefficient (no units), Y: 0.985 0.985 0.985 Pitot Coefficient (no units) Cp: 0.840 0.840 0.840 Meter OutletTemperature (F), Tm: 63 66 69 Stack Diameter (inches): 197.04 197.04 197.04 Area Stack (sq. ft.), As: 211.76 211.76 211.76 Nozzle Diameter (inches), dp: 0.210 0.210 0.210 Area Nozzle (sq. ft.), An: 0.000241 0.000241 0.000241 Percent CO2 (% dry volume): 11.2 11.3 11.3 Percent O2 (% dry volume): 7.8 7.9 8.0 Percent (N2 + CO) (% dry volume): 81.0 80.8 80.7 Particulate Collected (mg), Mn: 109.0 110.3 103.1

Molec. Wt. Dry

(lb/lb-mole), Md: 30.100 30.120 30.132 Volume Water (scf), Vwstd 2.434 2.481 2.584 Meter Volume (dscf), Vmstd: 37.683 38.318 38.578 Wet Fraction (v/v), Bws: 0.061 0.061 0.063 Molec. Wt. Wet (lb/lb-mole), Ms: 29.366 29.383 29.370 Stack Gas Sampled (acf), Vma: 56.423 57.335 57.834 Averages Stack Gas Velocity

(fps), Vs: 64.91 66.03 66.64 66 Volumetric Flowrate (dscfm), Qs: 550,822 560,641 564,771 558,745 Volumetric Flowrate (acfm), Qa: 824,761 838,893 846,665 836,773 Grainloading (gr/dscf), cs: 0.0446 0.0444 0.0412 0.04 Emission Rate (lb/hour), E: 210.73 213.53 199.61 208.0 Percent Isokinetic Sampling (%), I: 100.44 100.35 100.29 100.36
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 2112.72 2133.92 2144.12 2130.26 Emission Rate (lbs/mmBtu), E: 0.10 0.10 0.09 0.10 Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.24 Average Unit 2 Gross Load (MW) 105 105 105 105 Average Unit 3 Gross Load (MW) 105 105 105 105 Average Sum Gross Load (MW) 110 110 110 110 

### Particulate Emission Results Summary

Plant Yates Units 2-3

Page 71 of 86 Att. 9

## ATTACHMENT 10 - Yates Report 10 Test Results

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

Run 1 Run 2 Run 3 Test Date 2/25/2009 2/25/2009 2/25/2009 Run Start Time 10:05 11:50 13:25 Run End Time 11:20 13:05 14:35 Meter Volume (dacf), Vm: 40.46 41.287 40.957 Sqrt Delta P ("wc): 1.54 1.54 1.53 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.32 29.32 29.33 Delta H ("wc): 1.4 1.4 1.4 Volume in Impingers (mls), VIc: 54.8 58.0 57.8 Static Pressure ("wc), Pg: -3.10 -3.20 -3.10 Stack Pressure ("Hg), Ps: 29.09 29.08 29.10 Stack Temperature (F), Ts: 295 296 296 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: 64 67 70 Stack Diameter (inches): 167.03 167.03 167.03 Area Stack (sq. ft.), As: 152.17 152.17 152.17 Nozzle Diameter (inches), dp: 0.176 0.176 0.176 Area Nozzle (sq. ft.), An: 0.000169 0.000169 0.000169 Percent CO2 (% dry volume): 11.8 11.8 11.9 Percent O2 (% dry volume): 7.1 7.0 7.0 Percent (N2 + CO) (% dry volume): 81.1 81.2 81.1 Particulate Collected (mg), Mn: 81.1 88.7 71.9

Molec. Wt. Dry

(lb/lb-mole), Md: 30.177 30.163 30.179 Volume Water (scf), Vwstd 2.579 2.730 2.721 Meter Volume (dscf), Vmstd: 39.937 40.470 39.978 Wet Fraction (v/v), Bws: 0.061 0.063 0.064 Molec. Wt. Wet (lb/lb-mole), Ms: 29.439 29.394 29.403 Stack Gas Sampled (acf), Vma: 62.525 63.617 62.876 Averages Stack Gas Velocity

(fps), Vs: 103.77 103.92 103.19 104 Volumetric Flowrate (dscfm), Qs: 605,145 603,544 599,024 602,571 Volumetric Flowrate (acfm), Qa: 947,417 948,745 942,121 946,094 Grainloading (gr/dscf), cs: 0.0313 0.0338 0.0277 0.03 Emission Rate (lb/hour), E: 162.55 175.04 142.41 160.0 Percent Isokinetic Sampling (%), I: 99.13 100.72 100.25 100.03
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 2451.35 2462.58 2444.13 2452.69 Emission Rate (lbs/mmBtu), E: 0.07 0.07 0.06 0.07 Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.24 Average Unit 4 Gross Load (MW) 138 138 138 138 Average Unit 5 Gross Load (MW) 145 145 145 145 Average Sum Gross Load (MW) 283 283 283 283 

### Particulate Emission Results Summary

Plant Yates Units 4-5

Page 72 of 86 Att. 10

## ATTACHMENT 11 - Yates Report 11 Test Results

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

Run 1 Run 2 Run 3 Test Date 2/24/2009 2/24/2009 2/24/2009 Run Start Time 14:00 15:50 17:20 Run End Time 15:25 17:05 18:30 Meter Volume (dacf), Vm: 41.809 40.325 40.862 Sqrt Delta P ("wc): 1.43 1.45 1.43 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.22 29.22 29.22 Delta H ("wc): 1.3 1.4 1.3 Volume in Impingers (mls), VIc: 72.8 67.7 68.1 Static Pressure ("wc), Pg: -2.60 -2.80 -2.80 Stack Pressure ("Hg), Ps: 29.03 29.01 29.01 Stack Temperature (F), Ts: 260 261 263 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: 61 66 69 Stack Diameter (inches): 209.53 209.53 209.53 Area Stack (sq. ft.), As: 239.45 239.45 239.45 Nozzle Diameter (inches), dp: 0.176 0.176 0.176 Area Nozzle (sq. ft.), An: 0.000169 0.000169 0.000169 Percent CO2 (% dry volume): 13.1 13.1 13.1 Percent O2 (% dry volume): 5.4 5.4 5.3 Percent (N2 + CO) (% dry volume): 81.5 81.5 81.5 Particulate Collected (mg), Mn: 22.9 41.2 37.1

Molec. Wt. Dry

(lb/lb-mole), Md: 30.313 30.317 30.315 Volume Water (scf), Vwstd 3.427 3.187 3.205 Meter Volume (dscf), Vmstd: 41.345 39.489 39.795 Wet Fraction (v/v), Bws: 0.077 0.075 0.075 Molec. Wt. Wet (lb/lb-mole), Ms: 29.371 29.398 29.397 Stack Gas Sampled (acf), Vma: 62.897 60.116 60.692 Averages Stack Gas Velocity

(fps), Vs: 94.22 95.61 94.78 95 Volumetric Flowrate (dscfm), Qs: 889,842 902,355 892,833 895,010 Volumetric Flowrate (acfm), Qa: 1,353,702 1,373,679 1,361,667 1,363,016 Grainloading (gr/dscf), cs: 0.0086 0.0161 0.0144 0.01 Emission Rate (lb/hour), E: 65.30 124.48 110.12 100.0 Percent Isokinetic Sampling (%), I: 109.83 103.44 105.36 106.21
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 4039.95 4105.59 4079.73 4075.09 Emission Rate (lbs/mmBtu), E: 0.02 0.03 0.03 0.02 Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.24 Average Unit Gross Load (MW) 363 363 363 363 

### Particulate Emission Results Summary

Yates Unit 6

Page 73 of 86 Att. 11

## ATTACHMENT 12 - Yates Report 12 Test Results

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

Run 1 Run 2 Run 3 Test Date 2/24/2009 2/24/2009 2-24=09 Run Start Time 14:00 15:50 17:20 Run End Time 15:25 17:05 18:30 Meter Volume (dacf), Vm: 40.082 38.579 39.572 Sqrt Delta P ("wc): 1.43 1.43 1.44 Sampling Time (min): 60 60 60 Barometric Pressure ("Hg), Pbar: 29.22 29.22 29.22 Delta H ("wc): 1.3 1.3 1.3 Volume in Impingers (mls), VIc: 59.0 56.8 57.7 Static Pressure ("wc), Pg: -2.60 -2.70 -2.70 Stack Pressure ("Hg), Ps: 29.03 29.02 29.02 Stack Temperature (F), Ts: 259 262 264 Meter Coefficient (no units), Y: 0.985 0.985 0.985 Pitot Coefficient (no units) Cp: 0.840 0.840 0.840 Meter OutletTemperature (F), Tm: 68 71 76 Stack Diameter (inches): 209.53 209.53 209.53 Area Stack (sq. ft.), As: 239.45 239.45 239.45 Nozzle Diameter (inches), dp: 0.176 0.176 0.176 Area Nozzle (sq. ft.), An: 0.000169 0.000169 0.000169 Percent CO2 (% dry volume): 13.0 13.0 13.1 Percent O2 (% dry volume): 5.3 5.4 5.5 Percent (N2 + CO) (% dry volume): 81.7 81.6 81.5 Particulate Collected (mg), Mn: 54.8 68.9 54.8

Molec. Wt. Dry

(lb/lb-mole), Md: 30.292 30.296 30.309 Volume Water (scf), Vwstd 2.777 2.674 2.716 Meter Volume (dscf), Vmstd: 38.650 36.981 37.631 Wet Fraction (v/v), Bws: 0.067 0.067 0.067 Molec. Wt. Wet (lb/lb-mole), Ms: 29.468 29.467 29.481 Stack Gas Sampled (acf), Vma: 58.124 55.884 56.997 Averages Stack Gas Velocity

(fps), Vs: 94.17 94.19 94.88 94 Volumetric Flowrate (dscfm), Qs: 899,604 895,476 899,949 898,343 Volumetric Flowrate (acfm), Qa: 1,352,892 1,353,205 1,363,107 1,356,401 Grainloading (gr/dscf), cs: 0.0219 0.0288 0.0225 0.02 Emission Rate (lb/hour), E: 168.82 220.69 173.20 187.6 Percent Isokinetic Sampling (%), I: 101.55 97.62 98.84 99.33
F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780 Heat Input (mmBtu/hour): 4119.48 4074.29 4077.03 4090.26 Emission Rate (lbs/mmBtu), E: 0.04 0.05 0.04 0.05 Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.24 Average Unit Gross Load (MW) 365 364 363 364 

### Particulate Emission Results Summary

Yates Unit 7

Page 74 of 86 Att. 12

## ATTACHMENT 13 - Yates Report 13 Test Results

Start Time End

Time Unit Load Avg. Econ. Gas Outlet CO Avg. Econ. Gas Outlet O2 Avg. Econ. Gas Outlet CO2 Avg. Econ.

Gas Outlet Temp Military Military 

### MW ppm % Dry % Dry Deg F
2 Baseline 1 9/12/2008 9:36 10:03 362 90 3.35 15.37 666 3 Baseline 3 9/25/2008 8:05 8:41 366 64 4.31 14.73 670 4 Baseline 4 9/25/2008 11:45 12:21 364 72 4.3 14.66 672 5 Baseline 5 9/26/2008 7:25 8:01 361 128 3.43 15.32 665 6 Opt - 1 9/26/2008 9:40 10:16 361 77 3.17 15.58 666 7 Opt - 2 9/29/2008 11:29 12:05 362 67 3.93 14.91 670 8 Opt - 2 9/29/2008 14:06 14:42 365 32 4.51 14.37 675 9 Daily Baseline 9/30/2008 7:18 7:54 364 42 4.06 14.86 665 10 High NOx 9/30/2008 9:49 10:25 361 20 3.82 15.07 667 11 Low O2 9/30/2008 11:37 12:13 362 54 3.16 15.58 661 12 High O2 9/30/2008 14:12 14:48 363 69 4.36 14.48 670 13 Daily Baseline 10/1/2008 8:20 8:56 362 31 3.67 15.25 663 14 Increase Tilts 10/1/2008 9:42 10:18 368 38 3.6 15.37 667 15 Decrease Tilts 10/1/2008 11:21 11:57 361 33 3.62 15.33 661 16 VWO 10/1/2008 13:14 13:50 371 62 3.66 15.25 670 17 Temp vs. Load; E Mill off 10/1/2008 21:28 22:04 285 9 3.45 15.39 607 18 Mid Load; D&E Mills off 10/1/2008 23:18 23:54 238 8 3.62 15.26 573 19 Low Load; D&E Mills off 10/2/2008 0:40 1:16 201 15 3.85 15.04 544 20 Low Low Load; D&E Mills

off 10/2/2008 1:59 2:35 160 9 4.07 14.87 510

SCR Baseline Test Results Summary

Yates Unit 6

Title of Run Description Date



### Page 75 of 86 Att. 13

## ATTACHMENT 14 - Yates Report 14 Test Results

Unit 6 Sorbent Injection Mercury Study (February 28, 2005 to March 22, 2005)
Table 8. Snap Shot Results from Constant Rate Injection Test at 6 lb/MMacf Injection. ESP Inlet Hg ESP Outlet Hg Mercury Date Point (μg/dNm^3, 3% O2) (μg/dNm^3, 3% O2) Capture 3/11/2005 15:45 11.4 (SCEM) 2.9 (SCEM) 75% 3/12/2005 9:20 (SCEM) 4.4 (SCEM) 66% 3/19/2005 14:00 11.2 (TE) 3.2 (STM) 71% 3/19/2005 14:00 11.2 (COAL) 3.2 (STM) 71% 3/19/2005 22:00 17.4 (TE) 2.1 (STM) 88% SCEM Value obtained by semi-continuous emission monitor TE Value obtained by Thermo Electron, corrected to dry conditions STM Value obtained by sorbent trap method COAL Value obtained by coal analysis
Table 9. STM Results for the Constant Rate Injection Test, ESP A Outlet, 6 lb/MMacf Result Date Run (μg/Nm^3, 3% O2) 3/19/2005 1A 3.28 3/19/2005 1B 3.14 3/19/2005 2A 2.03 3/19/2005 2B 2.15 3/20/2005 3A 0.38 3/20/2005 3B 0.37 3/20/2005 4A 0.82 3/20/2005 4B 0.9 3/21/2005 5A 1.69 3/21/2005 5B 1.85 3/21/2005 6A 1.5 3/21/2005 6B 1.59

Table 15 Baseline Condition Method 17 Particulate Measurement Results Date 3/2/2005 Run 1 Run 2 Run 3 Unit Load MW 360 360 360

gr/dscf 0.0394 0.038 0.038 lb/MMBtu 0.0853 0.0817 0.0604 gr/dscf 0.0385 lb/MMBtu 0.0758
Table 16 Maximum Injection Condition Method 17 Particulate Measurement Results Date 3/8/2005 Run 1 Run 2 Run 3 Unit Load MW 360 360* 360

gr/dscf 0.0328 0.025 0.0237 lb/MMBtu 0.071 0.0544 0.052 gr/dscf 0.0272 lb/MMBtu 0.0592 * Unit load started to decrease near the end of the test. PM Emissions

Average

PM Emissions

Average

Page 76 of 86 Att. 14

## ATTACHMENT 15 - Yates Report 15 Test Results

DRAFT Unit 1 Boiler Chemical Addition Mercury Study (October 31, 2007 to November 7, 2007)

Table 4. Calcium Chloride Injection Testing Outline



### 6-Nov 886 240-550 91-113 36.6
Table 10. Comparison of Ontario Hydro and SCEM Results at ESP Outlet

BL 1-Nov 9:45 11:45 9.6 3.7 61 9.3 4.3 54 -3% 14% BL 1-Nov 12:15 14:15 9.4 3.7 61 7.9 4.3 46 -18% 15% BL 1-Nov 14:40 16:40 10.3 4.3 58 11 4.1 63 7% -6% Br (370) 3-Nov 13:30 15:30 7.9 2 74 1 0.7 37 -153% -102% Br (370) 3-Nov 16:10 18:10 8 2 75 0.3 0.4 -43 -186% -132% Br (100) 4-Nov 13:45 15:15 7.8 2.9 63 2.5 0.6 77 -102% -133% Br (100) 4-Nov 15:45 17:15 7.5 2.8 63 3.2 1.9 40 -81% -39% Cl (240-550) 6-Nov 15:45 17:45 9.2 3 67 4 2.2 46 -79% -33% * BL = baseline (no bromide injection); Br = calcium bromide injection at ppm Br in coal dry basis, stated in parentheses; Cl = calcium chloride injection at ppm Cl in coal dry basis, stated in parentheses. Total Hg Elem. Hg OH Results – ESP Outlet %RD Elem. Hg (μg/Nm3) %Oxid. Total Hg (μg/Nm3) %Oxid. 

### Date in 2007 Measured Coal Conc. (ppm Cl, dry) Actual

CaCl2 

### Injection rate (ppm Cl in coal, dry) Theoretical Gas Conc. (ppmv Cl, dry 3% O2

### ) Measured

Gas Conc. (ppmv HCl, dry 3% O2

### )Condition* Date in 2007 Start Time End Time Elem. Hg (μg/Nm3) SCEM Results - ESP Outlet Total Hg (μg/Nm3)



### Page 77 of 86 Att. 15

## ATTACHMENT 15 - Yates Report 15 Test Results

Table 11. Comparison of Sorbent Tube, OH and SCEM Results at ESP Outlet ST OH URS SCEM

0 1-Nov 9:45 11:45 10.1 9.6 9.3 -5.1 -7.7 0 1-Nov 12:25 14:25 9.9 9.4 8.2 -5.5 -18.8 0 1-Nov 14:40 16:40 10 10.3 11 2.7 9.4 370 3-Nov 13:30 15:30 7.8 7.9 1 1.1 -152.6 370 3-Nov 16:10 18:10 7.9 8 0.3 1.4 -186.9

Table 12. Comparison of Ontario Hydro and Thermo CEM Results at ESP Outlet

BL 1-Nov 9:45 11:45 9.6 3.7 61 9.8 5.3 46 2% 34% BL 1-Nov 12:15 14:15 9.4 3.7 61 9.6 5.1 48 5% 34% BL 1-Nov 14:40 16:40 10.3 4.3 58 11 6.1 45 7% 35% Br (370) 3-Nov 13:30 15:30 7.9 2 74 7.3 0.8 89 -8% -89% Br (370) 3-Nov 16:10 18:10 8 2 75 10.9 2 82 31% -3% Br (100) 4-Nov 13:45 15:15 7.8 2.9 63 10.6 2.2 79 31% -27% Br (100) 4-Nov 15:45 17:15 7.5 2.8 63 6.7 3.5 48 -11% 23% Cl (240-550) 6-Nov 15:45 17:45 9.2 3 67 9.1 2.2 75 -2% -30% * BL = baseline (no bromide injection); Br = calcium bromide injection at ppm Br in coal, stated in parentheses; Cl = calcium chloride injection at ppm Cl in coal, stated in parentheses. Thermo CEM Results-ESP Outlet OH Results – ESP Outlet %RSD Total Hg (μg/Nm3) Elem. Hg

(μg/Nm3) %Oxid. Total Hg (μg/Nm3) Elem. Hg

(μg/Nm3) %Oxid. Total Hg Elem. HgCondition* Date in 2007 Start Time End Time Br Injection Rate (ppm in coal) Date in

2007 Start Time End Time Between OH and ST Between SCEM and ST % RSD Total Hg (μg/dNm3 at 3% O2) Total Hg

(μg/dNm3at 3% O2) Total Hg

(μg/dNm3at 3% O2)



### Page 78 of 86 Att. 15

## ATTACHMENT 15 - Yates Report 15 Test Results

Table 13. Comparison of Sorbent Tube and Thermo CEM Results at JBR Outlet ST Thermo CEM % RSD

BL 4-Nov 9:12 10:42 5.3 2.4 -75 BL 4-Nov 11:15 12:45 5.9 2.8 -71 Br (100) 4-Nov 13:45 15:15 4.5 2.8 -47 BL 5-Nov 8:07 9:37 5.3 1.8 -99 BL 5-Nov 10:06 11:36 6.3 3 -71 Br (260) 5-Nov 15:20 16:50 4.8 3.4 -34 BL 6-Nov 8:00 9:30 5.5 2.9 -62 BL 6-Nov 9:53 11:23 4.1 2.4 -52 Cl (240-550) 6-Nov 14:15 15:15 4 2 -67 Cl (240-550) 6-Nov 15:45 17:45 3.8 2 -62 BL 7-Nov 7:52 9:22 4 1.8 -76 BL 7-Nov 9:43 11:13 4.2 1.8 -80 Br (220) 7-Nov 11:45 14:45 3.3 2.6 -24 * BL = baseline (no bromide injection); Br = calcium bromide injection at ppm Br in coal dry basis, stated in parentheses; Cl = calcium chloride injection at ppm Cl in coal dry basis, stated in parentheses. Total Hg (μg/dNm3 at 3% O2) Total Hg

(μg/dNm3at 3% O2) Between

CEM and ST Condition

* Date in

2007 Start Time End Time



### Page 79 of 86 Att. 15

## ATTACHMENT 15 - Yates Report 15 Test Results

Table 14. Total and Oxidized Flue Gas Mercury Concentrations (dry, at 3% O2) Measured by SCEM during Baseline Conditions

Ave. Tot. Hg Ave. Elem

Hg Ave. Tot. Hg Ave. Elem Hg Ave. Tot. Hg Ave. Elem

Hg (μg/Nm3) (μg/Nm3) (μg/Nm3) (μg/Nm3) (μg/Nm3) (μg/Nm3) 1-Nov 8:52 20:47 10.2 3.7 64 10.5 7.6 28 8.3 4.2 50 2-Nov 7:47 13:23 12.1 6.7 45 10.1 7.1 30 6.5 3.3 49 3-Nov 8:08 12:56 11.7 6.9 41 9.2 4.5 51 6.3 3.9 38 4-Nov 7:06 13:14

- 9.2*

- 11.5 6.4 44 7.8 2.2 72 5-Nov 8:19 12:37 12.8 7 45 8.5 6 29 7.1 3.5 51 6-Nov 8:18 12:30 8.9 6.1 31 10.5 5.4 49 4.3 2.8 35 7-Nov 7:50 11:13 10.3 7 32 8.2 4.1 50 8.2 4.6 44 11/1-11/7 11 6.2 43 9.8 6.1 38 7.7 3.6 53 *Note values were not used in average for 11/1 through 11/7. End Time %Hg Oxid. %Hg Oxid. %Hg Oxid. AH Inlet AH Outlet ESP Outlet

Date in Nov. 2007 Start Time



### Page 80 of 86 Att. 15

## ATTACHMENT 15 - Yates Report 15 Test Results

Table 15. Mercury Measurements Across the JBR Scrubber at Baseline. 

### ST Thermo CEM

8:52 20:47 8.3 4.2 no data no data no data 4.6 9:45 11:45 9.3 4.3 9.6 3.7 no data 4.3 12:15 14:15 7.8 4.3 9.4 3.6 no data 4.8 14:40 16:40 11 4 10.3 4.3 no data 4.8 2-Nov 7:47 13:23 6.5 3.3 no data no data no data 4.4 3-Nov 8:08 12:56 6.3 3.9 no data no data no data 3.8

7:06 13:14 7.8 2.2 no data no data no data 2.5 9:12 10:42 no data no data no data no data 5.2 2.6 11:15 12:45 7.8 no data no data no data 5.9 2.9 8:19 12:37 7.1 3.5 no data no data no data 2.7 8:07 9:37 no data 2.8 no data no data 5.3 1.9 10:06 11:36 7.1 4.1 no data no data 6.3 3.1 8:18 12:30 4.3 2.8 no data no data no data 2.5 8:00 9:30 no data 3.2 no data no data 5.5 2.9 9:53 11:23 4.3 2.6 no data no data 4.1 2.6 7:50 11:13 8.2 4.6 no data no data no data 1.8 7:52 9:22 no data 4.2 no data no data 4 1.8 9:43 11:13 8.2 4.6 no data no data 4.2 2.2 7-Nov ESP Outlet Hg° JBR

Outlet HgT Date Start Time JBR Outlet HgT 1-Nov

4-Nov

5-Nov

6-Nov End Time ESP Outlet HgT ESP Outlet

Hg° ESP Outlet

HgT 

### URS SCEM OH

Page 81 of 86 Att. 15

## ATTACHMENT 16 - Yates Report 16 Test Results

Unit 1 Sorbent Injection for Small ESP Mercury Control (January 2005)

Table 3-19. Unit 1- Method 26A Data at ESP Outlet for Baseline Characterization Tests Carbon Injection Rate HCl HF (lb/hr) (ppmv) (ppmv) Baseline 25.71 12.73

Table 3-19. Unit 1- Method 26A Data at ESP Outlet for Baseline Characterization Tests Carbon Injection Rate HCl HF (lb/hr) (ppmv) (ppmv) 143 18.71 13.31 200 17.95 12.02

All concentrations corrected to 3% O2.

Page 82 of 86 Att. 16

## ATTACHMENT 17 - Yates Report 17 Test Results

Unit 1 Field Testing of a Wet FGD Additive for Enhanced Mercury Control (May 15, 2007 to Sept 27, 2007)
Table 39. JBR Mercury Removal Data, by SCEM and CEM during the May 2007 TMT-15 Additive Portion of the Test Program

Total Hg Hgo 

### 5/15/2007 6:00-17:00 0 (baseline) 5.7 1.5 2.4 26 57 (assumed 23 5/18/2007 8:00-16:00 20 7.6 2.1 3.2 28 57 (assumed 21 5/24/2007 6:00-20:00 40 7.4 1.7 3.2 23 36 (assumed 53 5/29/2007 4:00-14:00 40 3.9 1.1 4.7 29 -8.2 (assumed 112
Table 40. Results of Ontario Hydro Measurements During TMT-15 Test at Yates Unit 1 (mean values for three Ontario Hydro runs +/- 95% confidence interval about the mean)

JBR Inlet Stack JBR Inlet Stack * Stack ** 3.6 +/- 0.6 4.6 +/- 0.2 4.7 +/- 0.7 8.9 +/- 2.9 7.5 +/- 0.9 3.4 +/- 0.7 0.2 +/- 0.1 4.8 +/- 0.2 0.7 +/- 0.2 0.5 +/- 0.1 7.0 +/- 0.4 4.8 +/- 0.2 9.5 +/- 0.5 9.6 +/- 3.1 8.0 +/- 0.9 52 +/- 9 49 +/- 5

95% +/- 2% 87% +/- 5% 89% +/- 1% 1.0 +/- 0.7 4.2 +/- 2.7 3.0 +/- 1.9 29% +/- 17% 88% +/- 59% 60% +/- 34% 31% +/- 6% -1% +/- 31% 15% +/- 16% * Results including apparent outlier value for one of three runs ** Results for two runs, excluding apparent outlier value for one of three runs Overall Hg Removal across Absorber, % Hg+2,μg/Nm^3 @ 3%O2 Total Hg,μg/Nm^3 @ 3%O2 Mercury Oxidation at JBR Inlet, % Hg+2 Removal across Absorber, %

Hgo

### Re-emissions, % of JBR inlet Hg+2 Hgo

### Re-emissions across Absorber,μg/Nm^3

Hgo


### ,μg/Nm^3 @ 3%O2 Hg Oxidation at Inlet, % Total Hg

Removal by FGD, % Hg+2

Capture by FGD, % Hgo

### Reemission, % of inlet Hg+2

Condition Baseline 5/15/2007 With TMT-15 @ 40 mL/ton coal 5/24/2007 Date Time Averaged TMT-15 Dose Rate, mL/ton of coal fired JBR Inlet Hg,μg/Nm^3 @ 3%O2 JBR Outlet

Total Hg, μg/Nm^3 @3% O2

Page 83 of 86 Att. 17

## ATTACHMENT 17 - Yates Report 17 Test Results

Table 45. JBR Mercury Removal Data, by SCEM and CEM during the August and September 2007 Nalco 8034 Additive Portion of the Test Program

Total Hg Hgo 

### Total Hg Hgo 

### 8/28/2007 10:00-21:00 0 4.6 2.4 2.9 2.8 53 36 94 18 9/8/2007 6:00-16:00 875 3.8 2.0 3.5 4.0 51 9 132 113 9/18/2007 6:00-20:00 525 5.7 1.5 3.1 2.4 27 46 84 22 9/26/2007 11:00-21:00 525 6.4 2.2 3.8 3.6 35 41 96 33
Table 46. Results of Ontario Hydro Measurements During Nalco 8034 Test at Yates Unit 1 (mean values for three Ontario Hydro runs +/- 95% confidence interval about the mean)

JBR Inlet Stack JBR Inlet * Stack * 3.7 +/- 0.9 4.2 +/- 1.1 4.5 +/- 0.3 5.0 +/- 0.3 2.9 +/- 0.3 < 0.3 3.4 +/- 0.3 < 0.5 6.6 +/- 1.2 4.2 +/- 1.1 8.0 +/- 0.1 5.0 +/- 0.3 56 +/- 4 56 +/- 5

>90% >86% 0.5 +/- 0.9 0.5 +/- 0.1 18% +/- 32% 15% +/- 1% 36% +/- 13% 38% +/- 4% * Results for two runs, excluding apparent outlier value for one of three runs Hgo

### Re-emissions, % of JBR inlet Hg+2 Overall Hg Removal across Absorber, % JBR Outlet Total Hg, μg/Nm^3 @3% O2

With Nalco 8034 @ 525 g/g FGD Inlet Hg+2

9/18/2007

Hgo


### ,μg/Nm^3 @ 3%O2 Hg+2,μg/Nm^3 @ 3%O2 Total Hg,μg/Nm^3 @ 3%O2 Mercury Oxidation at JBR Inlet, % Hg+2 Removal across Absorber, % Hgo

### Re-emissions across Absorber,μg/Nm^3 Total Hg Removal by FGD, % Hg+2

Removal by FGD, % Hgo

### Reemission, %

Condition Baseline 8/28/2007 JBR Inlet Hg,μg/Nm^3 @ 3%O2 Date Time Averaged Nalco 8034, g/g FGD Inlet Hg +2 Hg Oxidation at Inlet, %

Page 84 of 86 Att. 17

## ATTACHMENT 18 - Yates Report 18 Test Results

Unit 1 Multi-Method Mercury Speciation Testing (March 15, 2006 to March 21, 2006)
Table 1-2 Mercury overviews at FGD Inlet OHM SCEM Drift from OHM SCEM Drift from Appendix K Drift from Hg(0) Hg(0) OHM Hg(T) Hg(T) OHM Hg(T) OHM Date Condition μg/Nm^3 μg/Nm^3 % μg/Nm^3 μg/Nm^3 % μg/Nm^3 %

High load 6.05 6.10 0.4% 14.03 11.35 10.5% 11.60 9.5% High load 6.20 6.20 0.0% 12.77 10.80 8.3% 3/16/2006 Low load 2.32 2.61 5.8% 8.26 8.50 1.4% 7.98 1.7%

Low load 2.38 2.78 7.8% 8.86 9.19 1.8% Low load 2.40 3.03 11.6% 9.60 9.54 0.3% High load 3.41 3.98 7.7% 8.05 6.32 12.0% 9.28 4.5% High load 4.17 5.00 9.1% 9.79 7.96 10.3% High load 5.48 5.81 2.9% 12.65 11.37 5.3% High load 3.74 4.45 8.7% 8.87 9.16 1.6% 7.73 1.8% High load 3.15 4.06 12.6% 7.39 8.56 7.3% High load 3.53 4.05 6.9% 7.78 8.77 6.0% High load 4.96 4.26 7.6% 9.62 9.87 1.3% 8.82 2.8% High load 4.65 4.89 2.5% 9.36 9.88 2.7% High load 4.67 4.51 1.8% 8.98 9.85 4.6% 3/15/2006

3/17/2006

3/18/2006

3/20/2006

3/21/2006

Page 85 of 86 Att. 18

## ATTACHMENT 18 - Yates Report 18 Test Results

Table 1-3 Mercury overviews at FGD Inlet OHM SCEM Drift from OHM SCEM Drift from Appendix K Drift from Hg(0) Hg(0) OHM Hg(T) Hg(T) OHM Hg(T) OHM Date Condition μg/Nm^3 μg/Nm^3 % μg/Nm^3 μg/Nm^3 % μg/Nm^3 %

High load 4.17 4.94 8.5% 4.75 6.09 12.4% 4.47 3.0% High load 4.13 4.59 5.3% 4.96 5.42 4.4% 3/16/2006 Low load 1.97 2.40 9.8% 2.77 2.98 3.7% 2.06 14.7%

Low load 2.06 2.40 7.6% 3.16 2.77 6.6% Low load 2.04 2.64 12.7% 2.36 2.88 9.9% High load 3.25 2.78 7.8% 3.50 3.40 1.4% 4.23 0.7% High load 3.78 3.33 6.4% 3.93 3.15 11.0% High load 4.80 3.44 16.4% 5.08 3.81 14.3% High load 3.84 4.16 4.0% 4.17 3.81 4.5% 3.47 9.2% High load 3.40 3.96 7.6% 3.67 3.92 3.3% High load 3.85 4.22 4.6% 4.01 4.04 0.4% High load 4.36 4.00 4.4% 4.64 4.56 0.9% 4.36 2.1% High load 4.29 4.45 1.8% 4.50 4.65 1.6% High load 4.33 4.04 3.5% 4.51 4.17 3.9%

Table 1-8 HCl measurement at the stack HCl Time Date mg/NM^3 13:15-15:20 3/16/2006 1.06 14:20-16:20 3/17/2006 0.57 0.82 13:15-15:20 3/16/2006 0.65 14:20-16:20 3/17/2006 0.35 0.50 Average 3/15/2006

3/17/2006

3/18/2006

3/20/2006

3/21/2006

Average

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