GEORGIA POWER - Submittal for PLANT SCHERER

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

April 5, 2010

PART I: GENERAL FACILITY INFORMATION

Process Information

1 Name of legal owner of facility:

Georgia Power, Oglethorpe Power Corporation (OPC), Florida Power & Light (FP&L), Municipal Electric Authority of 

Georgia (MEAG), Gulf Power, Jacksonville Electric Authority (JEA), and Dalton Utilities (DU).

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

Georgia Power

3 Address of ____ legal owner or _X___ operator:

241 Ralph McGill Blvd NE, Bin 10221

Atlanta, GA 30308

4a Plant Name (as reported on U.S. DOE/EIA Form-860 (2007), "Annual Electric Generator Report", schedule 2, line 1, page 37, question 1)

OR Plant Name (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report", schedule 2, page 1, question 1):

Scherer

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

DOE/EIA Form EIA-923 (2008), schedule 2, page 1, question 2):

6257

5 Complete street address of facility (physical location):

10986 Highway 87

Juliette, Georgia 31046

6 Provide mailing address if different:

241 Ralph McGill Blvd NE, Bin 10221

Atlanta, GA 30308

7 Name and title of contact(s) able to answer technical questions about the completed survey:

Sarah Markham, Engineer II

8 Contact(s) telephone number(s):

(205) 257-6780

and e-mail address(es):

sasander@southernco.com

9 Is this facility considered to be owned or operated by a small entity as defined by the Regulatory Flexibility Act? 

____ Yes _X__ No ____ Don't know

Page 1 of 93 part I, 1-14
GEORGIA POWER - Submittal for PLANT SCHERER

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

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

_X__ coal __X__ oil (including pet coke) ___ natural gas

___ other (specify in question 14 below)

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

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

_X__ coal _X__ oil (including pet coke) ___ natural gas

_X__ other (specify in question 14 below)

12 If coal or solid fuel, as described below, derived from a fossil source is fired, indicate which rank of coal or solid fuel was utilized

during the previous 12 months prior to the receipt of this ICR:2,3

____ lignite (% _____) _X___ subbituminous (% _100____)

____ bituminous (% _____) ____ anthracite (% _____)

____ coal refuse (including gob, culm, and subbituminous-derived coal refuse) (% _____)

____ synfuel (including, but not limited to, briquettes, pellets, or extrusions which are formed by binding materials, or processes

 that recycle materials) (%_____)

 (please specify the type or form of synfuel used ___________________________________________)

____ petroleum coke (% _____)

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

_X___ distillate (% _100____)

____ other (specify __________) (% _____)

____ residual or bunker C (% _____)

Page 2 of 93 part I, 1-14
GEORGIA POWER - Submittal for PLANT SCHERER

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

14a If "other" was checked in questions 10 or 11 above indicating that any non-fossil fuel or other material (including, but not limited to, 

plastics, treated wood, rubber belting or gaskets, whole tires, tire-derived fuel, boiler cleaning solutions, animal wastes, etc.) is 

either utilized or permitted to be used, please indicate below what materials are combusted in the boiler and in what quantities

(specify whether this quantity is on a weight percentage or heat [Btu] basis). Also indicate (yes/no) whether you are permitted5 to 

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

14b If "other" was checked in questions 10 or 11 above indicating that any non-fossil fuel or other material (including, but not limited to,

plastics, treated wood, rubber belting or gaskets, whole tires, tire-derived fuel, boiler cleaning solutions, animal wastes, etc.) is 

either utilized or permitted to be used, were such material to be classified as "solid waste" under the Resource Conservation and 

Recovery Act and, thus make the utilizing unit subject to CAA section 129, would you continue to utilize (i.e., use as a fuel) the 

material? ____ Yes ____ No

Explain:

Until the regulations are finalized, we cannot determine with certainty whether we would use these other materials.

1

 "Permitted" in this context, refers to the fuels that the permit anticipates will be combusted at the facility.

2

 If the boiler is fired by a blend of coal ranks, please specify percentage (separately, on both a mass and on a Btu basis) of each coal rank

(e.g., 85% subbituminuous/15% bituminous).

3

 In reference to footnote 1, if necessary, a notation can be added to a utilized fuel type that is not listed in the operating permit noting 

the reason the fuel type was combusted (e.g., "the permitting agency allowed this fuel to be combusted for special testing and research

purposes").

4

 If the boiler is fired by a blend of fuel oil ranks, please specify percentage (separately, on both a volume and on a Btu basis) of each

fuel oil rank (e.g., 85% residual oil/15% distillate).

5

 If necessary, a notation can be added to a utilized fuel type that is not listed in the operating permit noting the reason the fuel was

combusted (e.g., "the permitting agency allowed this fuel to be combusted for special testing and research purposes").

None in 2009

None in 2009

None in 2009

Actually burn Quantity/year

None in 2009 None in 2009

None in 2009

Other Material

Sawdust

Biomass

Permitted to burn

Yes

Yes

Synfuel Yes None in 2009

Used Oil Yes None in 2009

Page 3 of 93 part I, 1-14
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

located at this facility.

SEE NOTES BELOW for explanations of responses. Boiler ID

6

coal rank or type of oil)

Original design fuel (i.e., 

Design heat input, 

(MMBtu/hr)

7

Present maximum heat 

input, (MMBtu/hr)

8

MWe Gross capacity

summer

MWe Net Capacity

summer

Original design gross 

efficiency (%, HHV)

Present operating gross 

efficiency (%, HHV)

Design steam pressure 

(psig)

Operating steam pressure 

(psig)

Design steam temperature 

(

oF)

temperature (

Operating steam 

oF)

Design steam reheat 

temperature (

oF)

9

Operating steam reheat 

temperature (

oF)10

Fuel11

Hours/year operated12

Average annual capacity 

factor for the past 3 years

Applicable NSPS

Estimated year of 

retirement13

1 subbituminousCBI CBI 870 820 87.1 84.6 2400 2404 1000 967 1000 998 sub-bituminous coal (100%), 

distillate oil (100%)

CBI CBI Subpart D None 

planned

2 subbituminousCBI CBI 870 820 87.1 87.6 2400 2396 1000 989 1000 1002 sub-bituminous coal (100%), 

distillate oil (100%)

CBI CBI Subpart D None 

planned

3 bituminous CBI CBI 880 839 89.3 86.0 2400 2391 1000 1000 1000 999 sub-bituminous coal (100%), 

distillate oil (100%)

CBI CBI Subpart D None 

planned

4 bituminous CBI CBI 880 839 89.3 86.2 2400 2398 1000 996 1000 1003 sub-bituminous coal (100%), 

distillate oil (100%)

CBI CBI Subpart D None 

planned

6

 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, 

[for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW])

OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).

7

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

8

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

9

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

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

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

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

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

NOTES: Original Design Fuel

Based on the original contract boiler data sheet; only the primary fuel is listed if multiple fuels were included on the data sheet. 

Design Heat Input

Confidential Business Information

Present Maximum Heat Input

Confidential Business Information

MWe Gross Capacity Summer

Identifies the gross normal full load. Georgia Power does not change unit capacities season from season. 

MWe Net Capacity Summer

Identifies the net normal full load; taken directly from the 2010 installed and authorized document. Georgia Power does not change unit capacities from season to season. 

Original Design Gross Efficiency

Taken directly from the original contract boiler data sheet.

Page 4 of 93 part I, 15
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

located at this facility.

SEE NOTES BELOW for explanations of responses. Boiler ID

6

coal rank or type of oil)

Original design fuel (i.e., 

Design heat input, 

(MMBtu/hr)

7

Present maximum heat 

input, (MMBtu/hr)

8

MWe Gross capacity

summer

MWe Net Capacity

summer

Original design gross 

efficiency (%, HHV)

Present operating gross 

efficiency (%, HHV)

Design steam pressure 

(psig)

Operating steam pressure 

(psig)

Design steam temperature 

(

oF)

temperature (

Operating steam 

oF)

Design steam reheat 

temperature (

oF)

9

Operating steam reheat 

temperature (

oF)10

Fuel11

Hours/year operated12

Average annual capacity 

factor for the past 3 years

Applicable NSPS

Estimated year of 

retirement13

Present Operating Gross Efficiency 

Based on the most recent actual test of the boiler efficiency, unless no recent boiler efficiency test was available. Where no recent test was available, that status is indicated. 

Design Steam Pressure

Based on the thermal design of the unit as represented on the turbine heat balance sheet. 

Operating Steam Pressure

Represents the average throttle pressure when the unit operated at gross normal full load over a three year period (January 2007 to December 2009). 

Design Steam Temperature

Based on the thermal design of the unit as represented on the turbine heat balance sheet. 

Operating Steam Temperature 

Represents the average steam temperature when the unit operated at gross normal full load over a three year period (January 2007 to December 2009). 

Design Steam Reheat Temperature 

Based on the thermal design of the unit as represented on the turbine heat balance sheet. 

Operating Steam Reheat Temperature

Represents the average reheat steam temperature when the unit operated at gross normal full load over a three year period (January 2007 to December 2009). 

Fuel

Indicates the fuels burned in the previous calendar year (January to December 2009). 

Hours/Year Operated

Confidential Business Information

Annual Average Capacity Factor for the Past 3 Years

Confidential Business Information

Applicable NSPS

Where no NSPS is identified, the unit is not currently subject to any NSPS.

Retirement Year

Georgia Power and Plant Scherer co-owners have not committed to actual retirement dates for Units 1-4. Georgia Power continually evaluates retirement scenarios with respect to its generating units for a variety 

of planning purposes, taking into account a wide range of variables. While the company assumes financial "retirement dates" for accounting purposes, for example, for depreciation schedules or for FERC or 

Public Service Commission uses, these dates are not indicative of the unit's actual retirement date.

Page 5 of 93 part I, 15
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

16 For each boiler noted in Part I, question 15, provide the following information for each current emission control device installed

and operating and/or planned (please designate the order of the emission controls - 1 for the first control following the boiler, 2

for the second control following the boiler, etc.):

NOTES: SO3 flue gas conditioning systems are operated on an as-needed basis.

Dates for future planned controls listed are subject to change.

Operation of planned SCRs required during ozone season only.

Boiler ID14 Type15 NOx control16 SO2 control17 PM control18 Other control19

1 tangential-fired (1) overfire air (3/2001)

(2) SCR (5/2014), catalyst not 

yet purchased

(6) wet flue gas 

desulfurization (FGD) 

(4/2014), calcium-based

(4) cold-side electrostatic 

precipitator (ESP) (3/1982, hotside ESP original install; 

conversion to cold-side 

5/2003)

(3) flue gas conditioning - SO3 

injection (5/2003)

(5) baghouse with activated 

carbon injection (mercury 

control, 12/2009 initial 

startup, 2/2010 commercial 

operation)

2 tangential-fired (1) overfire air (1/2002)

(2) SCR (6/2013), catalyst not 

yet purchased

(6) wet flue gas 

desulfurization (FGD) 

(8/2013), calcium-based.

(4) cold-side electrostatic 

precipitator (ESP) (2/1984, hotside ESP original install; 

conversion to cold-side 

12/2003)

(3) flue gas conditioning - SO3 

injection (12/2003)

(5) baghouse with activated 

carbon injection (mercury 

control, 4/2009 initial startup, 

6/2009 commercial operation)

3 tangential-fired (1) overfire air (12/2001)

(2) SCR (5/2011), catalyst not 

yet purchased

(5) wet flue gas 

desulfurization (FGD) 

(4/2011), calcium-based.

(3) cold-side electrostatic 

precipitator (ESP) (1/1987, 

original install)

(5) baghouse with activated 

carbon injection (mercury 

control, 12/2008 initial 

startup, 2/2009 commercial 

operation)

4 tangential-fired (1) overfire air (11/2002)

(2) SCR (5/2012), catalyst not 

yet purchased

(5) wet flue gas 

desulfurization (FGD) 

(8/2012), calcium-based.

(3) cold-side electrostatic 

precipitator (ESP) (2/1989, 

original install)

(5) baghouse with activated 

carbon injection (mercury 

control, 4/2010 initial startup, 

6/2010 commercial operation)

Page 6 of 93 part I, 16
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

16 For each boiler noted in Part I, question 15, provide the following information for each current emission control device installed

and operating and/or planned (please designate the order of the emission controls - 1 for the first control following the boiler, 2

for the second control following the boiler, etc.):

NOTES: SO3 flue gas conditioning systems are operated on an as-needed basis.

Dates for future planned controls listed are subject to change.

Operation of planned SCRs required during ozone season only.

Boiler ID14 Type15 NOx control16 SO2 control17 PM control18 Other control19

14 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, 

[for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW])

OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).

15 Examples: tangential-fired; cyclone; wall-fired; circulating fluidized bed (CFB)

16 Examples: low-NOx burners; selective catalytic reduction (SCR); selective non-catalytic reduction (SNCR); over-fire air (OFA). Include

specific date that control went online or planned operational date for new installation. If this boiler's control configuration utilizes a SCR,

please include the type of material from which the catalyst is manufactured and the type of reductant used in with the SCR (e.g., anhydrous

ammonia, urea, other). Also, please note if the catalyst is specifically designed to reduce SO3 formation?

17 Examples: wet flue gas desulfurization (FGD; any type); dry scrubbing (any type); specify whether calcium- or sodium-based. Include 

specific date that control went online or planned operational date for new installation. 

18 Examples: fabric filter; cold-side electrostatic precipitator (ESP); hot-side ESP; cyclone or multiclone; venturi scrubber. Include specific

date that control went online or planned operational date for new installation. January 1, 2009 - December 31, 2009

19 Please indicate systems installed specifically to control any other pollutants (e.g., Hg, SO3, etc.). Examples: activated carbon injection (ACI);

Powerspan ECO®; dry sorbent injection or wet ESP for SO3 control; flue gas conditioning to control opacity (e.g., SO3 injection, ammonia, other);

additive use for mercury control (e.g., bromine; scrubber additives). Include specific date that control went online or planned operational date for 

new installation. Also include any pollutants controlled by this technology (e.g., control technology [pollutant controlled]).

Page 7 of 93 part I, 16
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

17 For each boiler noted in Part I, question 15, provide the company (prime vendor) name and company contact information for each

HAP-specific (e.g., mercury, hydrogen chloride) control technology that you have either contracted for, are installing, or have installed

for the purpose of participating in a control technology demonstration project20 (e.g., U.S. Department of Energy program, consent decree,

etc.).

Name Telephone Address

1 Not applicable Not applicable Not applicable Not applicable

2 Not applicable Not applicable Not applicable Not applicable

3 Not applicable Not applicable Not applicable Not applicable

4 Not applicable Not applicable Not applicable Not applicable

20 A control technology demonstration project is defined as a U.S. Government (e.g., U.S. Department of Energy program) sponsored

(in whole or in part) project or mandate (e.g., as a result of a consent decree) that adds a HAP control technology to a facility's unit to

demonstrate the technology's HAP removal performance.

21 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, 

[for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW])

OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).

Company (vendor) contact information

Boiler ID21 Company (vendor) name

Page 8 of 93 part I, 17
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

18 For the control technologies identified in Part I, question 17, provide the date of actual start-up of the demonstration (if the control

is currently operating), the date of expected or projected start-up, the date the demonstration was completed, the type of HAP

control installed (e.g., sorbent and type; pre-combustion boiler chemical additive; combustion boiler chemical additive), the desired

HAP emission reduction or rate (if any), and the coal rank(s) upon which the demonstration was conducted. Please specify the format 

of the target HAP emission reduction rate (e.g., lb/MWh, lb/TBtu, percent reduction, etc.). If the format of the target end-point is

percent reduction, provide (1) an estimate of what an equivalent emission rate would be (and specify the format of the equivalent

emission rate), and (2) the basis for calculating the percent reduction (i.e., where the "inlet" and "outlet" are).

Boiler ID22

Demonstration 

activity actual startup date

Demonstration 

activity projected 

start-up date

Demonstration 

activity end-date or 

projected end-date

Type of control (e.g., 

sorbent and type; 

chemical additive23)

Desired HAP 

emission reduction 

(%) or emission rate

Coal rank(s) in use

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

2 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

3 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

4 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

22 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, 

[for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW])

OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).

23 If additive is used, please indicate injection point.

Page 9 of 93 part I, 18
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

19 For each boiler noted in Part I, question 15, provide the company (prime vendor) name and company contact information for each

HAP (e.g., mercury, hydrogen chloride, etc.) control technology that you have either contracted for, are installing, or have installed

for the purpose of provide a non-demonstration, full-scale operating system.

Name Telephone Address

1 Siemens Energy, Inc (formerly 

Wheelabrator)

Daniel S. Chobirko, PMP 412-562-7306 501 Grant Street, Pittsburgh, PA 15219-4429

2 Siemens Energy, Inc (formerly 

Wheelabrator)

Daniel S. Chobirko, PMP 412-562-7306 501 Grant Street, Pittsburgh, PA 15219-4429

3 Siemens Energy, Inc (formerly 

Wheelabrator)

Daniel S. Chobirko, PMP 412-562-7306 501 Grant Street, Pittsburgh, PA 15219-4429

4 Siemens Energy, Inc (formerly 

Wheelabrator)

Daniel S. Chobirko, PMP 412-562-7306 501 Grant Street, Pittsburgh, PA 15219-4429

24 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, 

[for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW])

OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).

Company (vendor) contact information

Boiler ID24 Company (vendor) name

Page 10 of 93 part I, 19
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

20 For the control technologies identified in Part I, question 19, provide the date of actual start-up (if the control is currently operating), the

date of expected or projected start-up, the type of HAP control installed (e.g., sorbent and type; pre-construction boiler chemical additive;

combustion of boiler chemical additive), the guaranteed HAP emission reduction or emission rate, the sorbent feed rate upon which the 

guarantee is based, and the coal rank(s) upon which the guarantee is based. Please specify the format of the guarantee (e.g., lb/MWh,

lb/TBtu, percent reduction, etc.). If the format of the guarantee is percent reduction, provide (1) an estimate of what an equivalent emission

rate would be (and specify the format of the equivalent emission rate), and (2) the basis for calculating the percent reduction (i.e., where the

"inlet" and "outlet" are).

NOTE: 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.

Boiler ID25 Actual startup date

Expected or 

projected 

start-up 

date

Type of control (e.g., 

sorbent and type; 

chemical additive)26

Guaranteed HAP emission reduction 

(%) or emission rate

Sorbent or additive feed 

rate on which 

guarantee is based

Coal rank(s) 

upon which 

guarantee is 

based

1 12/7/2009 

(first gas)

Not 

applicable

baghouse with activated 

carbon injection upstream 

of the baghouse, 

downstream of the ESP

CBI CBI CBI

2 4/27/2009 

(first gas)

Not 

applicable

baghouse with activated 

carbon injection upstream 

of the baghouse, 

downstream of the ESP

CBI CBI CBI

3 12/08/2008 

(first gas)

Not 

applicable

baghouse with activated 

carbon injection upstream 

of the baghouse, 

downstream of the ESP

CBI CBI CBI

Page 11 of 93 part I, 20
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

20 For the control technologies identified in Part I, question 19, provide the date of actual start-up (if the control is currently operating), the

date of expected or projected start-up, the type of HAP control installed (e.g., sorbent and type; pre-construction boiler chemical additive;

combustion of boiler chemical additive), the guaranteed HAP emission reduction or emission rate, the sorbent feed rate upon which the 

guarantee is based, and the coal rank(s) upon which the guarantee is based. Please specify the format of the guarantee (e.g., lb/MWh,

lb/TBtu, percent reduction, etc.). If the format of the guarantee is percent reduction, provide (1) an estimate of what an equivalent emission

rate would be (and specify the format of the equivalent emission rate), and (2) the basis for calculating the percent reduction (i.e., where the

"inlet" and "outlet" are).

NOTE: 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.

Boiler ID25 Actual startup 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

4 Not 

applicable

4/2010 (first 

gas)

baghouse with activated 

carbon injection upstream 

of the baghouse, 

downstream of the ESP

CBI CBI CBI

25 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, 

[for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW])

OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).

26 If additive is used, please indicate injection point.

Page 12 of 93 part I, 20
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

PM28 PM10

(29) PM2.5(30) SO2

HCl 

and/or HF HCN

Metal 

HAP31 Hg CO

Other 

organics 

(specify)

Other pollutant (specify)

1 0.10 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

1.2 lb/MMBtu (Title V permit; based on 30-day 

rolling average, monitored by coal sulfur and 

heat content analysis and calculation)

5% of potential combustion concentration (95% 

removal by FGD), effective Jan 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: 0.7 lb/MMBtu (Title V permit; based on 3-

hour average determined by CEMS)

0.20 lb/MMBtu from May 1 through September 

30 OR compliance with 7-plant NOx average of 

0.18 lb/MMBtu and Scherer site-average of 0.17 

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)

2 0.10 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

1.2 lb/MMBtu (Title V permit; based on 30-day 

rolling average, monitored by coal sulfur and 

heat content analysis and calculation)

5% of potential combustion concentration (95% 

removal by FGD), effective Jan 1, 2014 (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: 0.7 lb/MMBtu (Title V permit; based on 3-

hour average determined by CEMS)

0.17 lb/MMBtu from May 1 through September 

30 OR compliance with 7-plant NOx average of 

0.18 lb/MMBtu and Scherer site-average of 0.17 

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)

3 0.10 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

1.2 lb/MMBtu (Title V permit; based on 30-day 

rolling average, monitored by coal sulfur and 

heat content analysis and calculation)

5% of potential combustion concentration (95% 

removal by FGD), effective Jan 1, 2012 (State 

rule, Title V permit revision not complete; based 

on 30-day rolling average, monitored by CEMS 

at inlet to scrubber and at scrubber stack during 

scrubber operations, excluding startup, 

shutdown, malfunction, and other exemptions)

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

NOx: 0.7 lb/MMBtu (Title V permit; based on 3-

hour average determined by CEMS)

0.15 lb/MMBtu from May 1 through September 

30 OR compliance with 7-plant NOx average of 

0.18 lb/MMBtu and Scherer site-average of 0.17 

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 13 of 93 part I, 21
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

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

4 0.10 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

1.2 lb/MMBtu (Title V permit; based on 30-day 

rolling average, monitored by coal sulfur and 

heat content analysis and calculation)

5% of potential combustion concentration (95% 

removal by FGD), effective Jan 1, 2013 (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: 0.7 lb/MMBtu (Title V permit; based on 3-

hour average determined by CEMS)

0.16 lb/MMBtu from May 1 through September 

30 OR compliance with 7-plant NOx average of 

0.18 lb/MMBtu and Scherer site-average of 0.17 

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)

27 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, 

[for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW])

OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).

28 If the boiler has separate permitted emission limits for filterable and condensable PM, respectively, please indicate those separate limits. 

Also include the compliance test method utilized.

29 List the compliance test method utilized.

30 List the compliance test method utilized.

31 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, phosphorus, and selenium;

indicate permit level for all metal HAP for which a permit level has been developed.

Page 14 of 93 part I, 21
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

NOTE: All guarantees are based on and demonstrated with certain fuel and operating conditions. Guarantees are not necessarily representative of the long term or day to day

variability that may occur with changes in fuel specifications, operating conditions, normal wear and tear of equipment over time, startups, shutdowns, and malfunctions.

PM33 PM10 PM2.5 SO2

HCl 

and/or HF HCN

Metal 

HAP34 Hg CO

Other 

organics 

(specify)

Other pollutant (specify)

1 ESP: 99.97 % collection efficiency filterable 

(expired in 1982)

Baghouse: CBI

FGD: CBI

Not 

applicable

Not 

applicable

FGD: 98% instantaneous removal efficiency to 

meet a 95% 30-day rolling average removal 

efficiency (not yet demonstrated, expires 18-

months after startup)

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not applicable

2 ESP: 99.97 % collection efficiency filterable 

(expired in 1984)

Baghouse: CBI

FGD: CBI

Not 

applicable

Not 

applicable

FGD: 98% instantaneous removal efficiency to 

meet a 95% 30-day rolling average removal 

efficiency (not yet demonstrated, expires 18-

months after startup)

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Overfire Air NOx: 0.23 (expired in 2003)

3 ESP: 97.75 % collection efficiency filterable 

(expired in 1987)

Baghouse: CBI

FGD: CBI

Not 

applicable

Not 

applicable

FGD: 98% instantaneous removal efficiency to 

meet a 95% 30-day rolling average removal 

efficiency (not yet demonstrated, expires 18-

months after startup)

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Overfire Air NOx: 0.13 (expired in 2002)

4 ESP: 97.75 % collection efficiency filterable 

(expired in 1989)

Baghouse: CBI

FGD: CBI

Not 

applicable

Not 

applicable

FGD: 98% instantaneous removal efficiency to 

meet a 95% 30-day rolling average removal 

efficiency (not yet demonstrated, expires 18-

months after startup)

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Overfire Air NOx: 0.13 (expired in 2003)

23 Was any other guarantee level sought or offered? ____ Yes _X___ No

Please elaborate.

32 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, 

[for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW])

OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).

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

34 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, cobalt, lead, manganese, nickel, phosphorus, and selenium; 

indicate permit level for all metal HAP for which a permit level has been developed.

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

Boiler ID32

Page 15 of 93 part I, 22-23
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

PM36 PM10 PM2.5 SO2

HCl 

and/or HF HCN

Metal 

HAP37 Hg CO

Other 

organics 

(specify)

1 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 20%) 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 1.2 lb/MMBtu 30-day rolling 

average limit reported quarterly; records retained for 5 

years.

Effective Jan 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

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

from the previous annual tests are fifty percent or less of the limit; under the CAM plan, 

opacity monitored continuously by COMS, excursions (3-hour block averages greater 

than 20%) 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 1.2 lb/MMBtu 30-day rolling 

average limit reported quarterly; records retained for 5 

years.

Effective Jan 1, 2014, SO2 removal by the scrubber will be 

monitored by inlet and stack SO2 CEMS operated, 

maintained, and certified using 40 CFR Part 75 procedures. 

Data from these monitors will provide the SO2 removal 

percentage on a 30-day rolling average, excluding startup, 

shutdown, and malfunction. Exceedances of the 5% limit 

will be reported quarterly; records retained for 5 years 

(permit revision not yet issued).

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

3 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 20%) 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 1.2 lb/MMBtu 30-day rolling 

average limit reported quarterly; records retained for 5 

years.

Effective Jan 1, 2012, SO2 removal by the scrubber will be 

monitored by inlet and stack SO2 CEMS operated, 

maintained, and certified using 40 CFR Part 75 procedures. 

Data from these monitors will provide the SO2 removal 

percentage on a 30-day rolling average, excluding startup, 

shutdown, and malfunction. Exceedances of the 5% limit 

will be reported quarterly; records retained for 5 years 

(permit revision not yet issued).

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

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

Boiler ID35

Page 16 of 93 part I, 24
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

PM36 PM10 PM2.5 SO2

HCl 

and/or HF HCN

Metal 

HAP37 Hg CO

Other 

organics 

(specify)

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

Boiler ID35

4 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 20%) 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 1.2 lb/MMBtu 30-day rolling 

average limit reported quarterly; records retained for 5 

years.

Effective Jan 1, 2013, SO2 removal by the scrubber will be 

monitored by inlet and stack SO2 CEMS operated, 

maintained, and certified using 40 CFR Part 75 procedures. 

Data from these monitors will provide the SO2 removal 

percentage on a 30-day rolling average, excluding startup, 

shutdown, and malfunction. Exceedances of the 5% limit 

will be reported quarterly; records retained for 5 years 

(permit revision not yet issued).

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

35 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, 

[for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW])

OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).

36 If the boiler's monitoring, recordkeeping, and reporting requirements require your company to monitoring, keep records, and report filterable

and condensable PM separately, please describe the separate actions required.

37 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, phosphorus, and selenium;

indicate permit level for all metal HAP for which a permit level has been developed.

Page 17 of 93 part I, 24
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

Facility Name/Unit No.: Scherer Unit 1

Retrofit to existing boiler? Yes

Installation on a new boiler? No

Total Capital Investment: CBI

Total Annual Operating and Maintenance Costs: CBI (Include base year for operating costs [e.g., 2006]

Facility Name/Unit No.: Scherer Unit 2

Retrofit to existing boiler? Yes

Installation on a new boiler? No

Total Capital Investment: CBI

Total Annual Operating and Maintenance Costs: CBI (Include base year for operating costs [e.g., 2006]

Facility Name/Unit No.: Scherer Unit 3

Retrofit to existing boiler? Yes

Installation on a new boiler? No

Total Capital Investment: CBI

Total Annual Operating and Maintenance Costs: CBI (Include base year for operating costs [e.g., 2006]

Facility Name/Unit No.: Scherer Unit 4

Retrofit to existing boiler? Yes

Installation on a new boiler? No

Total Capital Investment: CBI

Total Annual Operating and Maintenance Costs: CBI (Include base year for operating costs [e.g., 2006]

26 Are any other means of emission control (for any pollutant) employed on any boiler noted in Part I, question 15 (e.g., low-ash coal,

coal or oil with low trace constituents, etc.)? Please specify.

PRB coal for reduction of NOx and SO2.

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

Page 18 of 93 part I, 25-26
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

PART II: FUEL ANALYSIS AND EMISSION DATA

Fuel Analysis39

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

Scherer

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

6257

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

Page 19 of 93 part II, 1
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

10,240 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 5.94 11,980

10,288 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 6.47 11,920

10,078 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 6.19 11,958

10,302 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 5.83 12,027

10,183 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 5.82 12,031

10,272 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.42 5.9 12,024

10,311 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.41 5.93 12,011

10,241 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.43 6.19 11,984

10,277 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.49 7.09 11,854

10,212 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.45 7.33 11,853

10,258 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.6 6.74 11,898

10,094 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.53 6.74 11,951

10,183 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.57 6.54 11,970

10,219 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.59 6.72 11,956

10,248 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.43 6.32 11,903

10,189 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.52 6.38 12,001

9,854 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.47 6.06 11,918

10,354 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.38 6.06 12,097

10,346 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.49 7.56 11,875

10,184 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.42 6.24 11,945

10,273 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.49 6.36 11,990

10,219 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.44 6.52 11,780

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

Page 20 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,163 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.51 6.32 11,979

10,263 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.51 6.34 11,950

9,577 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.5 6.18 11,953

9,659 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.54 6.41 11,976

9,533 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.51 6.35 11,956

10,186 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.52 6.89 11,923

10,305 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.4 6.41 11,975

10,233 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.45 6.31 11,985

10,192 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.58 6.55 11,967

10,212 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.57 6.48 11,991

10,242 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.52 6.4 11,991

10,344 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.38 6.23 11,964

10,350 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.39 6.31 11,918

10,380 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.54 6.48 11,940

10,149 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.47 6.34 11,976

10,287 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.53 6.75 11,947

10,462 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.59 6.74 11,920

10,312 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.54 6.76 11,870

10,205 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.47 6.94 11,936

10,387 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.62 7.05 11,872

10,311 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.46 6.46 11,868

10,234 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.51 6.37 11,939

Page 21 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,243 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.46 6.08 11,960

10,221 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.49 6.18 11,975

10,379 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.55 6.84 11,858

10,340 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.56 6.65 11,892

10,429 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.61 6.76 11,881

10,211 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.5 6.16 11,948

10,173 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.49 6.45 11,912

10,355 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.44 6.89 11,841

10,406 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.58 6.62 11,915

10,369 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.5 6.16 11,916

10,172 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.53 6.22 11,897

10,209 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.6 6.81 11,882

10,393 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.48 6.1 11,952

10,309 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.55 6.4 12,031

10,167 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.61 7.14 12,042

10,252 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.53 6.56 11,961

10,364 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.47 6.42 12,040

10,431 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.62 7.01 11,923

10,065 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.61 6.6 11,978

10,448 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.5 7.73 11,732

10,213 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.63 6.44 11,826

10,230 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.31 5.79 12,026

Page 22 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,278 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.51 6.57 11,955

10,186 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.52 6.48 11,970

10,233 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.37 5.77 12,022

10,329 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.46 6.02 12,016

10,337 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.54 6.17 11,981

10,295 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.48 6.1 12,032

10,155 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.52 7.33 11,833

10,202 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.52 6.84 11,907

10,275 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.49 6.59 11,936

10,419 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.56 7.33 11,862

10,240 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.55 6.61 11,972

10,174 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.33 4.91 12,137

10,385 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.6 7.29 11,870

10,392 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.52 6.53 11,902

10,070 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.43 6.43 11,907

10,177 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.57 6.94 11,912

9,975 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.49 6.33 11,876

10,396 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.5 6.41 11,953

9,204 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.31 5.61 11,969

10,370 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.49 6.48 11,981

10,308 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.5 6.52 11,995

10,233 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.45 6.56 11,930

Page 23 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,594 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.51 6.43 11,891

10,180 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.51 7.36 11,975

10,284 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.4 6.39 11,950

10,405 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.36 6.3 11,908

10,235 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.49 6.32 11,985

10,203 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.52 6.4 11,998

10,361 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.51 6.51 11,940

10,213 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.64 7.04 11,916

10,397 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.55 6.81 11,964

10,243 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.56 6.67 11,968

10,157 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.51 6.89 12,049

10,321 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.57 6.66 11,900

9,836 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.47 6.35 11,911

10,350 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.42 6.48 11,906

10,227 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.56 6.59 11,916

10,423 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.56 6.72 11,910

10,364 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.41 6.13 11,898

10,273 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.55 7.18 12,038

10,349 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.45 6.3 11,944

10,177 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.54 6.51 11,945

10,279 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.5 6.43 11,987

10,144 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.42 6.54 11,937

Page 24 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,323 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.59 6.62 11,936

10,296 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.61 6.55 11,919

10,253 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.58 6.91 12,041

10,376 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.47 6.68 11,838

10,380 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.54 6.46 11,931

10,216 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.52 6.27 11,964

10,424 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.55 6.3 11,914

10,353 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.53 6.44 11,933

10,314 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.48 6.16 12,017

10,221 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.56 7.21 12,024

10,169 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.48 6.38 12,083

10,304 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.58 6.93 11,931

10,625 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.59 6.81 11,838

10,210 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.47 6.75 11,966

10,460 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.45 6.37 11,965

10,419 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.53 6.71 11,879

10,372 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.59 6.57 11,921

10,383 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.52 6.48 11,985

10,344 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.5 6.47 11,988

10,167 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.52 6.59 11,996

10,561 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.51 6.48 11,875

10,116 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.45 6.57 12,022

Page 25 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,392 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.53 6.82 11,994

10,268 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 6.15 12,001

10,446 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.44 6.61 11,926

10,176 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.35 6.32 12,005

10,298 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 6.82 11,919

10,046 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 4.93 12,212

10,181 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.27 11,774

10,256 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.44 6.3 11,901

10,233 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 5.89 12,042

10,336 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 6.21 12,010

10,284 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.32 11,939

10,168 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 6.26 11,928

10,297 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.45 11,971

10,198 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 6.13 11,966

10,170 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.24 11,934

10,212 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.44 6.2 11,967

10,158 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.29 6.05 12,040

10,177 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.57 6.67 11,804

10,314 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 6.02 11,990

9,339 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.22 5.68 12,045

10,209 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 6.05 11,977

10,185 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.23 5.63 12,095

Page 26 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,239 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.27 5.64 11,970

10,318 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.27 5.71 12,057

10,115 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.26 6.24 11,971

10,136 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.21 5.94 11,998

10,347 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 6.29 11,929

10,199 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.24 6.01 11,988

10,270 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.23 11,969

10,293 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.44 6.68 11,858

10,337 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.28 6.08 11,975

10,233 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 6.56 11,885

10,278 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.31 5.74 11,990

10,289 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 5.8 12,016

10,339 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.46 6.14 11,963

10,241 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.17 11,938

10,308 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.49 6.86 11,810

10,277 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.49 7.21 11,750

10,231 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 5.91 12,040

10,367 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 6.11 11,943

10,260 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.64 11,922

10,236 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 6.5 11,883

10,312 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 5.82 12,000

10,218 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.45 6.62 11,855

Page 27 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,260 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.44 6.82 11,928

10,219 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.28 11,980

10,182 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.52 5.56 12,233

10,590 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.51 11,966

10,662 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.63 12,111

10,399 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.17 11,976

10,460 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 5.91 11,994

10,656 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 6.12 12,002

10,536 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.17 12,023

10,542 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.43 12,063

10,631 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 6.48 11,957

10,642 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.21 11,925

10,543 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.79 12,098

10,644 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.06 12,058

10,541 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.8 12,025

10,407 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 5.95 12,032

10,564 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 5.88 12,053

10,788 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.65 11,898

10,183 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.92 12,025

10,461 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.2 6.02 12,006

10,477 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 5.88 12,041

10,674 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 6.16 12,039

Page 28 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,550 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.33 6.45 11,889

10,580 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 5.19 12,083

10,717 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.02 12,005

10,448 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.07 11,961

10,379 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.2 5.72 11,942

10,605 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 5.83 12,005

10,780 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.6 12,084

10,668 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 5.36 12,062

10,602 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.58 12,074

10,564 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.31 11,912

10,570 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 5.74 11,949

10,512 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 5.85 11,895

10,640 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 6.16 11,927

10,603 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 5.94 11,967

10,581 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 5.99 11,916

10,708 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.65 12,090

10,659 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.24 11,919

10,429 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.63 11,930

10,533 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.34 5.84 11,994

10,625 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.22 5.51 12,133

10,711 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.96 12,063

10,618 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 5.57 12,063

Page 29 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,524 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.83 12,083

10,604 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 6.2 11,943

10,721 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.4 12,062

10,533 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 5.59 12,025

10,541 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.03 12,045

10,549 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 5.72 12,094

10,660 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.21 6.09 12,015

10,610 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.1 12,027

10,626 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.12 12,083

10,524 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.05 12,059

10,234 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.5 11,914

10,340 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.48 11,919

10,288 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.49 6.63 11,923

10,350 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.44 11,967

10,317 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.23 11,985

10,249 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 5.01 12,082

10,161 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 6.17 11,996

10,309 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 6.16 11,985

10,214 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.53 7.66 11,797

10,263 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 6.02 12,040

10,309 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.21 11,979

10,265 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.09 12,000

Page 30 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,098 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.35 6.6 11,908

10,333 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 6.17 11,987

10,165 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.26 11,989

10,373 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.37 11,957

10,099 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.28 5.47 12,168

10,121 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 6.42 12,091

10,212 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 5.75 12,086

9,929 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.47 11,911

10,243 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.45 7.7 11,791

10,053 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 6.04 11,896

10,199 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.7 11,896

10,408 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.35 6.34 11,996

10,313 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.46 6.32 11,810

10,198 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.21 12,007

10,371 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.5 6.91 11,863

10,361 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.49 6.48 11,949

10,262 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.46 6.34 11,893

10,326 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 6.04 12,062

10,270 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.56 6.33 11,956

10,192 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.55 7.01 11,901

10,336 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 5.85 12,011

10,241 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.66 11,941

Page 31 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,313 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.48 6.08 11,933

10,177 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.01 11,993

10,378 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.1 11,989

10,331 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.44 6.69 11,928

10,228 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.45 6.59 11,890

10,158 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.12 11,946

10,297 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.21 11,997

10,384 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 5.96 12,026

10,191 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.31 5.82 12,034

10,171 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 6.02 12,023

10,164 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 5.6 12,048

10,317 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.37 6.19 11,913

10,102 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.31 6.06 11,823

10,088 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.29 5.77 11,855

10,250 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.28 5.36 12,060

10,160 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.29 5.67 12,055

10,242 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 5.79 12,009

10,252 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 6.49 11,883

9,922 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 6.07 12,004

10,194 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 6.35 11,959

10,180 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.44 11,984

10,221 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.25 11,967

Page 32 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,163 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 5.55 12,053

10,001 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.51 6.72 11,863

10,069 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.35 5.55 12,047

10,068 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 5.55 12,020

10,138 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.35 5.45 12,004

10,157 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.26 5.48 12,080

10,179 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.29 6.05 12,010

10,355 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 5.9 11,966

10,261 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.35 6.1 11,989

10,447 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.35 5.83 12,020

10,153 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.28 5.5 12,097

10,287 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.28 5.88 11,996

10,281 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.22 5.45 12,100

10,188 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.24 6.16 12,004

10,195 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 5.63 12,050

10,182 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 5.7 12,013

10,266 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.01 11,935

10,287 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.31 7.01 11,830

10,249 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 6.78 11,870

10,216 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.24 6.1 11,860

10,178 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 6.01 12,020

10,112 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.23 6.2 11,985

Page 33 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,222 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.24 6.11 11,997

10,282 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.57 11,879

10,272 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.37 6.32 11,883

10,190 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.29 6.63 11,886

10,283 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 5.92 11,980

10,252 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.35 6.55 11,884

10,097 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.28 6.11 11,989

10,181 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.28 5.88 12,004

10,280 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.25 6.11 11,974

10,241 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 6.28 11,923

10,251 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.31 6.56 11,907

10,199 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.27 5.85 11,918

10,109 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.23 6.06 12,001

10,211 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.25 5.92 11,989

10,292 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 6.41 11,917

10,154 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.16 11,965

10,227 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 6.2 11,964

10,112 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 6.06 11,968

10,319 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 6.74 11,778

10,286 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.37 6.31 11,947

10,287 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.76 11,875

10,330 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.25 6.38 11,929

Page 34 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,305 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.28 5.95 11,961

10,297 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.28 6.11 11,928

10,189 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.37 6.15 11,927

10,173 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.13 11,933

10,250 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.56 11,861

10,237 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.5 7.27 11,997

10,301 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.35 6.33 11,922

10,174 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 6.07 12,007

10,391 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 6.31 11,878

9,780 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 6.19 11,987

10,264 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 5.81 12,010

10,365 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 6.04 11,995

10,260 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 6.33 11,816

10,228 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 5.88 12,020

10,255 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.1 11,988

10,272 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.1 11,963

10,238 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.29 5.88 11,996

10,314 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 5.64 12,001

10,213 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.32 11,958

10,179 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.07 11,960

10,202 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.47 6.21 11,967

10,307 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.53 6.53 11,829

Page 35 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,268 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.5 6.46 11,874

10,273 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 5.81 11,967

10,465 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 6.31 11,939

10,220 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.29 6.72 11,753

10,302 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 5.77 12,047

10,195 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 6.3 11,948

10,211 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 5.97 11,985

10,191 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 5.99 11,978

10,241 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 6.36 11,942

10,232 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.37 6.1 11,969

10,267 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 5.88 11,991

10,123 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 5.75 12,059

10,253 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.29 5.93 11,998

10,345 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.45 6.23 11,978

10,178 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 6.31 11,886

10,295 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.51 6.66 11,849

10,186 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.85 11,822

10,163 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 6.15 11,949

10,202 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.44 5.96 11,982

10,167 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.48 6.24 11,950

10,201 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.5 6.35 11,884

10,059 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 5.55 12,051

Page 36 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,240 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.08 11,985

9,973 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.29 11,988

10,264 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.65 11,879

10,308 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 6.2 12,019

10,288 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.44 6.27 11,940

10,322 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.49 6.68 11,931

10,390 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.51 6.96 11,655

10,324 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.52 6.61 11,877

10,212 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 5.77 12,035

10,243 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 5.71 11,995

10,276 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.44 6.25 11,959

10,285 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.44 6.13 11,957

10,172 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 6 12,023

10,121 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 5.98 12,074

10,281 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.46 6.97 11,934

10,176 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.28 5.79 12,066

10,208 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.9 11,919

10,217 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 5.65 11,990

10,221 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 5.75 12,024

10,274 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.14 11,998

10,374 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.17 11,860

10,080 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 5.99 12,014

Page 37 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,262 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 5.92 12,038

10,306 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.41 11,921

10,220 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.44 6.11 12,009

10,121 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.31 5.88 12,086

10,252 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6 12,086

10,201 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.15 12,053

10,165 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.25 5.82 12,111

10,232 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.27 5.65 12,142

10,214 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 5.82 12,104

10,286 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.22 5.78 12,093

10,230 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.24 5.46 12,114

10,213 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 5.78 12,043

10,189 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.24 5.83 12,092

10,233 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.24 5.66 12,104

10,127 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 6.44 11,982

10,215 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.24 6.57 12,023

10,293 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.27 5.66 12,132

10,259 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.2 5.47 12,153

10,375 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.47 6.55 11,931

10,287 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 6.77 11,933

10,417 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.73 11,929

10,260 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 6.35 11,936

Page 38 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,388 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.48 6.44 11,966

10,178 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.45 11,969

10,381 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 6.03 12,032

10,279 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.27 6.36 11,951

10,245 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.28 5.82 12,037

10,291 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 6.85 11,929

10,293 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 6.25 12,018

10,174 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 6.12 12,072

10,365 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.47 6.59 11,978

10,223 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 6.26 12,044

10,291 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.46 6.59 11,965

10,306 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.22 12,030

10,244 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.19 12,019

10,266 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 6.26 12,007

10,143 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 6.3 12,030

10,104 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.35 6.32 12,002

10,354 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.35 6.04 12,040

10,357 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.37 6.42 11,983

10,357 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.84 11,952

10,329 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.37 6.32 11,979

10,386 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.35 11,957

10,303 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.45 6.66 12,026

Page 39 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,437 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.45 6.7 12,062

10,465 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.5 7.18 11,925

10,316 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.47 6.7 12,007

10,329 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.47 6.91 12,007

10,423 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.42 6.47 12,088

10,409 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.41 5.94 12,099

10,357 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.46 6.62 12,002

10,241 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.45 7.21 11,827

10,283 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.49 6.97 11,922

10,237 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.45 6.36 12,000

10,296 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.48 6.95 11,956

10,302 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.53 7.21 11,974

10,348 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.46 6.7 11,890

10,238 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.52 7.23 11,952

11,066 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.52 7.15 11,932

9,741 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.49 6.6 12,014

10,352 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.46 7.61 11,895

10,231 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.46 6.64 12,025

10,327 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.44 7.27 11,931

10,350 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.48 6.73 11,978

10,343 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.4 6.32 12,024

10,425 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.45 6.27 12,064

Page 40 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,031 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.44 6.25 12,024

10,311 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.53 7.4 11,886

10,363 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.4 7.22 11,916

10,366 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.47 6.65 11,931

10,251 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.48 6.43 12,058

10,262 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.48 6.54 12,012

10,268 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.54 6.51 12,081

10,298 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.38 5.65 12,221

10,297 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.44 7.48 11,874

10,314 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.41 6.81 12,043

10,223 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.43 6.93 12,007

10,292 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.44 6.52 12,036

9,966 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.49 7.24 11,826

10,163 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.57 7.34 11,809

10,261 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.49 7.06 11,839

10,214 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.45 7.55 11,756

10,256 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.52 7.91 11,756

10,136 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.47 7.06 11,823

10,101 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.46 7.08 11,838

10,217 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.47 7.33 11,783

10,113 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.48 7.36 11,861

10,703 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.46 7.01 11,877

Page 41 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,208 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.49 7.61 11,820

10,141 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.42 6.93 11,881

10,280 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.4 6.68 11,945

10,229 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.48 6.8 11,855

10,059 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.35 6.4 11,962

10,131 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.42 6.87 11,865

10,150 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.5 7.05 11,804

10,129 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.47 7.17 11,784

10,162 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.51 6.94 11,825

10,184 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.43 7.19 11,763

10,297 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.55 7.41 11,770

10,320 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.44 6.86 11,877

10,198 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.53 7.59 11,719

10,162 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.53 7.13 11,790

10,130 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.43 7.11 11,741

10,234 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.43 6.94 11,828

10,151 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.41 7.18 11,885

10,061 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.33 6.23 11,931

10,149 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.4 7.37 11,733

10,172 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.48 7.24 11,767

10,242 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.38 7.52 11,757

10,209 1, 2, 3, 4 WY CAMPBELL ROLAND, SMITH TRAIN 0.46 6.27 11,881

Page 42 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,418 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.32 6.77 11,951

10,805 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.3 6.57 11,983

10,846 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.27 7.05 11,909

10,823 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.28 6.72 11,944

10,863 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.28 6.97 11,895

10,877 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.28 7.21 11,890

10,812 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.29 6.51 11,954

10,877 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.31 7.45 11,831

10,818 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.46 6.6 11,954

10,804 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 6.69 11,998

11,068 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 6.54 12,017

10,860 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 8.2 11,731

10,892 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 6.32 11,981

11,015 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.41 6.22 12,008

10,756 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.4 6.09 12,021

10,947 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 6.46 12,003

10,961 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 8.02 11,820

10,894 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 7.84 11,899

10,924 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 6.94 11,988

10,929 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 7.03 11,890

11,105 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.31 8.27 11,670

10,855 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 6.92 11,867

Page 43 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,979 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.23 7.37 11,887

10,981 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.28 7.77 11,831

10,733 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.29 7.63 11,845

11,032 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.24 6.63 11,991

10,890 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.26 7.33 11,858

10,757 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.31 6.58 11,931

10,743 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.3 6.78 11,912

10,652 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 6.05 12,020

11,011 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 6.17 11,982

10,973 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 7.28 11,846

10,825 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 5.95 11,998

10,990 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 6.08 12,014

10,912 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 7.49 11,847

10,328 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 6.72 11,890

10,854 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.27 6.31 12,021

10,894 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.27 6.25 12,039

10,977 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 7.33 11,826

10,886 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.32 6.44 11,951

11,028 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.29 6.12 12,055

10,828 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.3 6.44 12,003

10,848 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.25 6.21 12,103

10,794 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.27 7.62 11,903

Page 44 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,862 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.32 6.94 11,889

10,951 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.32 6.72 11,909

10,900 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.26 6.75 11,962

10,704 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.25 6.53 11,944

11,003 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 6.21 11,966

10,912 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 6.54 11,915

10,769 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 7.65 11,788

10,966 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 7.38 11,841

10,966 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.29 7.17 11,900

10,867 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.3 8.05 11,755

10,985 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.33 7.84 11,796

11,020 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.3 7.74 11,743

10,831 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.33 6.4 11,932

10,923 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.39 5.9 12,010

10,925 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.39 6.06 11,986

10,797 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 6.76 11,936

10,922 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.41 8.08 11,751

10,885 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.33 7.69 11,794

10,871 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.26 6.28 12,012

10,842 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.22 6.42 12,000

10,916 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 6.16 11,941

10,872 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.29 7.32 11,838

Page 45 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,840 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.3 7.85 11,806

10,920 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.3 6.2 11,989

10,972 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.32 6.96 11,830

10,962 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 7.66 11,765

10,954 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.33 6.46 11,911

10,949 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 6.61 11,892

10,930 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.4 6.92 11,924

10,933 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.4 6.12 11,964

10,852 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 6.55 11,996

10,955 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 7.6 11,851

11,001 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.52 7.09 11,819

11,036 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.39 9.19 11,601

10,927 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.42 8.17 11,730

10,844 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 7.05 11,896

10,895 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.33 6.32 11,970

11,024 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 8.01 11,729

10,815 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.24 7 11,963

10,982 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.3 7.64 11,857

10,931 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.31 7.64 11,824

11,035 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 6.67 11,965

11,066 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.42 7.23 11,897

10,888 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.31 6.23 12,051

Page 46 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,583 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.26 6.92 11,979

10,908 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.32 6.45 12,047

10,961 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 7.25 11,938

N/A 1, 2, 3, 4 WY CONVERSE CANYON TRAIN N/A N/A N/A

10,901 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 6.29 11,998

10,894 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 6.49 12,030

10,839 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 6.15 12,102

10,545 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.75 12,058

10,611 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.33 6.19 11,949

10,725 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.22 11,992

10,623 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.04 12,081

10,507 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.45 12,107

10,593 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.62 11,961

10,763 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.33 6.12 11,930

10,615 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.61 11,954

10,409 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 5.89 12,100

10,569 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 5.78 12,034

10,497 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.91 11,910

10,589 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.31 11,971

10,373 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 4.65 12,110

10,463 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 5.09 12,101

10,434 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.16 11,852

Page 47 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,644 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.26 11,963

10,595 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 4.72 12,186

10,390 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 6.24 11,964

10,569 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.5 11,905

10,607 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.71 11,881

10,659 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.35 11,896

10,641 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.31 12,006

10,637 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.06 12,016

10,697 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.25 11,991

10,667 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.23 11,998

10,740 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 5.72 12,112

10,630 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.7 12,068

10,796 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 5.26 12,187

10,733 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.87 12,014

10,644 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.96 12,064

10,473 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.12 12,019

10,599 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 6.04 12,028

10,653 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 6.68 11,840

10,569 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.12 12,016

10,604 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.33 5.84 12,005

10,015 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 5.83 12,022

10,765 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 6.13 12,030

Page 48 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,553 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 5.85 11,936

10,644 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.22 5.82 12,009

10,655 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.33 6.27 11,927

10,522 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.22 5.8 12,008

10,549 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.88 11,884

10,687 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.91 11,856

10,655 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.18 11,907

10,557 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.24 11,960

10,637 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.98 11,975

10,742 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.51 11,888

10,722 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 5.94 11,948

10,571 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 5.92 11,913

10,537 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 5.96 11,988

10,419 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 5.92 12,024

10,535 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.84 11,910

10,543 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.2 6.1 12,016

10,636 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 6.07 12,003

10,615 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.22 6.03 11,995

10,509 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.33 6.28 11,899

10,516 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.71 12,002

10,552 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.5 11,948

10,588 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.33 5.6 12,031

Page 49 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,621 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6 11,980

10,542 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 5.69 12,060

10,655 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.28 11,958

10,643 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.26 11,977

10,614 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 5.72 12,013

10,565 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.98 12,002

10,514 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.51 11,887

10,461 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.7 11,987

10,731 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 5.66 12,008

10,634 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 5.96 12,011

10,685 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 5.9 12,022

10,781 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 6.22 11,922

10,529 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.22 6.18 11,931

10,619 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.2 11,943

10,619 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 7.03 11,903

10,010 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.05 12,013

10,562 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.13 11,951

10,560 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.18 6.06 11,985

10,561 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.03 11,983

10,606 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.94 11,959

10,699 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.33 6.46 11,918

10,687 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.55 11,888

Page 50 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,530 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.4 11,908

10,679 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.91 12,011

10,694 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 5.65 12,095

10,659 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.99 11,979

10,551 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 5.45 12,104

10,711 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.25 12,037

10,381 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.33 11,973

10,489 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.14 11,949

10,619 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.24 11,990

10,511 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.2 6.14 12,025

10,593 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 5.57 12,042

10,566 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.94 12,071

10,669 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.36 5.84 12,032

10,670 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.32 11,995

10,571 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 5.55 12,095

10,685 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.02 11,984

10,641 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.6 11,878

10,541 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.82 12,013

10,557 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.35 5.92 11,983

10,495 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 5.76 12,064

10,290 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.22 5.87 11,923

10,530 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.21 6.14 12,001

Page 51 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

N/A 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN N/A N/A N/A

10,602 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.12 12,032

10,434 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.16 12,034

10,564 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 5.72 12,079

N/A 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN N/A N/A N/A

10,514 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 5.78 12,105

10,349 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 6.35 11,981

10,701 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 7.1 11,896

10,294 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.46 6.62 11,952

10,237 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 6.24 11,990

10,317 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 6.38 11,970

10,277 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.23 11,955

10,269 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 6.49 11,973

10,295 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.47 11,972

10,188 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 6.25 11,967

10,261 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 6 12,105

10,248 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.88 11,939

10,189 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.2 11,972

10,269 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.49 6.82 11,860

10,273 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.56 6.86 11,880

10,381 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 5.56 12,130

10,283 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.31 5.46 12,125

Page 52 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,333 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 6.74 12,047

10,288 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 6.36 11,962

10,331 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.35 6.25 11,952

10,360 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.26 11,943

10,392 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 6.37 11,995

10,154 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.27 6.05 11,993

10,152 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 6.33 11,936

10,206 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.37 6.2 11,970

10,254 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.37 5.91 12,038

10,007 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 5.88 12,054

10,226 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.45 6.68 11,873

10,142 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 5.76 12,019

10,085 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 5.95 11,954

10,283 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 5.97 11,962

10,140 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.23 5.77 12,017

10,214 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.23 5.34 12,090

10,242 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 5.88 12,035

10,221 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.13 11,942

10,179 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.24 5.85 12,027

10,231 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 7.69 11,743

10,214 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.28 5.81 12,067

10,230 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.22 6.01 11,984

Page 53 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,241 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 7 11,935

10,162 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.24 6.11 11,997

10,223 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.31 6.3 11,892

10,202 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.25 5.86 11,924

10,206 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 6.02 11,988

10,221 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.35 6.05 11,978

10,345 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.54 11,906

10,230 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.37 6.59 11,921

10,244 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 6 11,934

10,220 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.31 6.4 11,923

10,315 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.64 11,881

10,318 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 6.33 11,936

10,289 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 6.26 11,919

10,341 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 5.9 11,939

10,297 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 5.98 11,905

10,328 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 5.85 11,981

10,228 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.07 11,927

10,260 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.5 6.84 11,831

10,242 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.47 6.55 11,831

10,156 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.31 5.9 12,020

10,323 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.37 6.78 11,872

10,269 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 6.42 11,949

Page 54 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,274 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 6.42 11,942

10,260 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.36 5.98 11,971

10,161 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.29 6.04 12,008

10,283 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.11 11,933

10,211 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.47 6.84 11,744

10,275 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 5.77 12,017

10,205 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 5.93 11,999

10,357 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.43 6.33 11,920

10,357 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.32 11,933

10,287 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.47 6.25 11,941

10,300 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 7.3 11,788

10,252 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.44 6.9 11,905

10,210 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.44 6.2 11,998

10,204 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.42 5.93 12,076

10,208 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.25 5.6 12,124

10,194 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.26 5.84 12,079

10,227 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.27 5.75 12,119

10,318 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.33 6.09 12,026

10,213 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.4 6.44 11,982

10,247 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.22 5.67 12,153

10,198 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.34 6.91 11,909

10,301 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.01 11,992

Page 55 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,311 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.07 11,980

10,284 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.37 6.07 12,014

10,284 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.39 6.32 12,010

10,351 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.38 6.61 11,968

10,225 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.3 6.13 12,003

10,093 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.41 6.69 11,964

10,338 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.51 6.37 11,984

10,147 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.55 7.5 11,881

10,236 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.49 7.71 11,915

10,068 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.52 7.58 11,889

10,266 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.44 6.74 12,010

10,117 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.45 7.15 11,977

10,351 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.33 6.68 12,042

10,274 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.46 7.31 11,911

10,087 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.44 8.03 11,810

10,307 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.45 8.17 11,800

9,399 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.47 7.03 11,928

10,188 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.4 7.16 12,106

10,169 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.38 8.51 11,879

10,384 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.39 8.34 11,819

10,335 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.4 7.6 11,848

10,309 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.39 7.71 11,817

Page 56 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,318 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.32 6.64 11,856

10,308 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.38 6.79 11,935

10,414 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.4 6.3 12,040

10,300 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.39 6.55 11,962

10,211 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.42 7.44 11,852

10,290 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.52 7.32 11,920

10,237 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.4 6.63 12,033

10,408 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.47 9.17 11,642

10,114 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.38 7.27 11,815

10,269 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.45 7.6 11,824

10,109 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.47 8.1 11,769

10,289 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.49 7.58 11,911

10,268 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.44 7.35 11,923

10,175 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.53 7.68 11,914

10,311 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.38 8.14 11,834

10,374 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.36 7.91 11,855

10,169 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.39 6.99 11,987

10,281 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.4 7.61 11,903

10,393 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.52 7.37 11,973

10,185 1, 2, 3, 4 WY CAMPBELL ANDERSON, CANYON TRAIN 0.32 6.01 11,947

10,689 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.19 11,987

10,643 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.87 12,045

Page 57 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,460 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.33 6.48 11,898

10,355 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 6.04 12,035

10,381 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.94 12,048

10,404 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.02 11,960

10,453 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.22 11,972

10,641 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.76 11,943

10,484 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 6.62 11,884

10,502 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.2 11,963

10,708 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.72 11,882

10,620 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.27 11,920

10,572 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 5.93 11,958

10,571 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.35 11,866

10,388 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.2 5.91 11,969

10,369 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.23 11,892

10,525 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.96 11,987

10,503 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 6.51 11,940

10,546 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.1 11,977

10,390 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 6.16 11,938

10,768 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.36 5.59 12,025

10,019 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.78 11,953

10,539 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 6.23 11,933

10,419 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.02 11,917

Page 58 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,560 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.13 11,986

10,639 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.22 5.96 11,948

10,662 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.12 11,956

10,483 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.14 11,933

10,733 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.36 11,973

10,527 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.83 12,044

10,471 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.98 12,036

10,604 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 5.89 12,089

10,322 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.18 12,007

10,607 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.03 12,044

10,595 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 5.68 12,076

10,537 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.31 11,927

10,440 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.2 11,939

10,352 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.05 11,960

10,608 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.08 11,994

10,658 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.21 5.6 12,084

N/A 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN N/A N/A N/A

10,341 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.31 11,937

10,468 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.35 11,999

10,230 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.09 11,927

10,719 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.67 12,092

10,778 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.22 5.85 12,098

Page 59 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,367 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.21 11,985

10,663 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 5.33 12,152

10,442 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.1 12,012

9,679 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 5.82 12,026

10,518 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.81 12,060

10,451 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.95 11,998

10,649 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 7.34 11,772

10,416 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.89 11,962

10,548 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.77 12,016

10,486 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 5.89 11,997

10,526 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.28 11,925

10,614 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.98 11,930

10,580 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 5.75 11,941

10,465 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.21 6 11,942

10,470 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.82 12,011

8,622 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 6.33 11,956

10,673 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.19 12,011

10,690 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.38 11,986

10,670 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.63 12,042

10,691 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.66 11,987

10,688 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 5.94 12,028

10,559 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 5.82 12,021

Page 60 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,604 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.03 11,934

10,428 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.35 11,874

10,534 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 6.3 11,901

10,635 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.21 6.02 11,977

10,501 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.02 11,854

10,465 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 6.4 11,873

10,606 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.34 6.01 12,054

10,680 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 5.53 12,084

10,689 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 6.03 12,011

10,421 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.11 12,025

10,587 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.7 12,007

10,820 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 5.89 12,034

10,538 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.23 5.54 12,071

10,387 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.56 11,938

10,548 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.11 12,012

10,393 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.97 12,042

10,401 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.06 12,051

10,494 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.45 12,022

10,362 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 6.56 11,898

10,447 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.49 11,957

10,560 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.3 7.23 11,858

10,130 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.48 7.88 11,938

Page 61 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual shipments may not have originated 

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot guarantee that what was

shipped in the preceding 12 calendar months is what was burned in the preceding 12 calendar months.

D.B. D.B. D.B.

State/Country County42 Coal seam43 % Sulf % Ash Btu/lb

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

10,194 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.43 7.41 11,879

10,357 1, 2, 3, 4 WY CAMPBELL WYODAC TRAIN 0.37 8.55 11,768

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

amount fired.

41 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, 

[for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW])

OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).

42 If known.

43 If known.

Page 62 of 93 part II, 2 (coal)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: 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.

State/Country County42 Coal seam43

45,219 1, 2, 3, 4 Georgia/USA N/A N/A Truck

30,200 1, 2, 3, 4 Georgia/USA N/A N/A Truck

15,042 1, 2, 3, 4 Georgia/USA N/A N/A Truck

45,149 1, 2, 3, 4 Georgia/USA N/A N/A Truck

45,021 1, 2, 3, 4 Georgia/USA N/A N/A Truck

45,013 1, 2, 3, 4 Georgia/USA N/A N/A Truck

44,895 1, 2, 3, 4 Georgia/USA N/A N/A Truck

44,901 1, 2, 3, 4 Georgia/USA N/A N/A Truck

44,861 1, 2, 3, 4 Georgia/USA N/A N/A Truck

44,828 1, 2, 3, 4 Georgia/USA N/A N/A Truck

44,778 1, 2, 3, 4 Georgia/USA N/A N/A Truck

37,267 1, 2, 3, 4 Georgia/USA N/A N/A Truck

7,452 1, 2, 3, 4 Georgia/USA N/A N/A Truck

44,617 1, 2, 3, 4 Georgia/USA N/A N/A Truck

66,811 1, 2, 3, 4 Georgia/USA N/A N/A Truck

44,504 1, 2, 3, 4 Georgia/USA N/A N/A Truck

22,284 1, 2, 3, 4 Georgia/USA N/A N/A Truck

44,538 1, 2, 3, 4 Georgia/USA N/A N/A Truck

44,532 1, 2, 3, 4 Georgia/USA N/A N/A Truck

37,106 1, 2, 3, 4 Georgia/USA N/A N/A Truck

7,425 1, 2, 3, 4 Georgia/USA N/A N/A Truck

22,324 1, 2, 3, 4 Georgia/USA N/A N/A Truck

37,159 1, 2, 3, 4 Georgia/USA N/A N/A Truck

FUEL OIL SHIPMENTS

Amount received, 

gallons40

ID # of boiler(s) 

firing fuel41

Fuel source Fuel shipment 

method

Page 63 of 93 Part II, 2 (oil)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

as available (indicated N/A if not available; use additional pages, as necessary):

NOTE: 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.

State/Country County42 Coal seam43

FUEL OIL SHIPMENTS

Amount received, 

gallons40

ID # of boiler(s) 

firing fuel41

Fuel source Fuel shipment 

method

37,163 1, 2, 3, 4 Georgia/USA N/A N/A Truck

37,270 1, 2, 3, 4 Georgia/USA N/A N/A Truck

44,721 1, 2, 3, 4 Georgia/USA N/A N/A Truck

37,249 1, 2, 3, 4 Georgia/USA N/A N/A Truck

29,815 1, 2, 3, 4 Georgia/USA N/A N/A Truck

44,707 1, 2, 3, 4 Georgia/USA N/A N/A Truck

44,919 1, 2, 3, 4 Georgia/USA N/A N/A Truck

44,855 1, 2, 3, 4 Georgia/USA N/A N/A Truck

45,154 1, 2, 3, 4 Georgia/USA N/A N/A Truck

44,937 1, 2, 3, 4 Georgia/USA N/A N/A Truck

44,933 1, 2, 3, 4 Georgia/USA N/A N/A Truck

45,140 1, 2, 3, 4 Georgia/USA N/A N/A Truck

45,129 1, 2, 3, 4 Georgia/USA N/A N/A Truck

22,593 1, 2, 3, 4 Georgia/USA N/A N/A Truck

37,505 1, 2, 3, 4 Georgia/USA N/A N/A Truck

45,115 1, 2, 3, 4 Georgia/USA N/A N/A Truck

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

amount fired.

41 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), "Annual Electric Generating Report," schedule 6, part A, line 1, page 53, 

[for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW])

OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).

42 If known.

43 If known.

Page 64 of 93 Part II, 2 (oil)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

09-313 14,629 0.32 6.91 11,971 0.082 43 48 4.1 <1 0.3 0.3 <0.02 3.5 3.0 2.4 5.7 0.5 WY Campbell Wyodak Train

09-300 14,441 0.53 7.06 11,920 0.115 64 64 4.5 <1 1.6 0.4 0.08 4.4 2.5 3.3 13.5 0.8 WY Campbell Wyodak Train

09-301 14,169 0.43 6.78 11,925 0.054 55 56 4.7 <1 1.1 0.2 0.05 2.6 1.9 2.4 18.4 0.7 WY Campbell Wyodak Train

09-302 14,519 0.28 6 11,962 0.065 60 67 3.0 <1 0.5 0.4 0.05 3.9 2.5 3.1 8.5 0.6 WY Campbell Wyodak Train

09-305 14,629 0.34 6.26 12,038 0.058 60 60 3.4 <1 0.4 0.3 0.05 3.4 2.8 2.5 9.4 0.6 WY Campbell, Converse Wyodak Train

09-307 14,709 0.44 6.52 12,075 0.091 79 56 3.9 <1 0.7 0.4 0.06 4.0 2.6 3.1 8.6 1.0 WY Campbell Wyodak Train

09-309 14,658 0.57 9.22 11,569 0.123 70 81 5.5 <1 2.2 0.5 0.07 8.1 2.6 5.5 13.2 0.9 WY Campbell Wyodak Train

09-310 14,617 0.5 8.15 11,630 0.092 64 67 5.1 <1 1.5 0.4 0.07 6.4 2.8 3.9 17.2 0.9 WY Campbell Wyodak Train

09-312 14,588 0.28 5.95 12,055 ND ND 32 3.5 ND 0.3 0.3 ND 3.1 2.9 2.4 6.7 0.7 WY Campbell Wyodak Train

09-314 14,588 0.29 5.94 12,083 ND ND 32 3.9 ND 1.4 0.3 ND 1.9 2.0 2.2 5.3 0.8 WY Campbell Wyodak Train

09-316 14,836 0.42 6.14 11,935 ND 69 44 4.0 <1 0.8 0.4 ND 2.7 2.4 2.5 12.6 0.9 WY Campbell Wyodak Train

09-317 14,589 0.41 6.73 11,946 ND ND ND 4.1 ND 0.6 0.1 0.05 4.3 2.4 2.2 9.7 0.9 WY Campbell Wyodak Train

09-325 16,045 0.27 6.5 12,079 0.079 37 48 2.8 <1 0.5 0.4 <0.02 2.9 2.5 2.2 5.6 0.7 WY Campbell Wyodak Train

09-327 16,001 0.37 7.14 11,968 0.076 37 33 4.6 <1 0.8 0.3 <0.02 3.4 3.3 2.9 4.7 0.6 WY Campbell, Converse Wyodak Train

09-321 14,657 0.46 7.44 11,918 0.125 ND 63 5.7 ND 1.4 0.4 0.01 7.0 3.0 4.0 11.6 1.0 WY Campbell Wyodak Train

09-322 14,465 0.44 6.53 11,864 ND ND 63 5.1 ND 1.2 2.9 ND 3.0 2.0 2.5 15.5 0.7 WY Campbell Wyodak Train

09-328 14,637 0.41 6.25 11,932 ND 72 60 4.0 ND 1.1 0.4 ND 2.9 2.2 2.4 13.5 0.8 WY Campbell Wyodak Train

09-329 13,820 0.49 6.33 11,891 ND ND 49 4.2 ND 1.1 0.2 ND 2.1 2.0 2.0 5.3 0.7 WY Campbell Wyodak Train

09-330 14,599 0.62 7.43 11,746 0.135 62 56 14.0 ND 1.4 0.4 0.01 4.3 2.7 2.4 13.0 0.7 WY Campbell Wyodak Train

09-331 14,252 0.46 6.69 11,959 ND 62 60 4.4 ND 1.1 0.4 0.02 4.0 2.9 2.7 8.2 0.9 WY Campbell Wyodak Train

09-332 14,627 0.54 7.43 11,860 ND 60 56 4.8 ND 1.0 0.2 0.07 4.8 2.6 3.3 17.9 0.9 WY Campbell Wyodak Train

09-341 14,561 0.49 7.44 11,954 0.069 85 61 6.5 ND 1.9 0.4 ND 6.7 3.5 3.9 9.7 1.1 WY Campbell Wyodak Train

09-342 14,583 0.57 6.41 12,013 0.071 95 51 5.3 ND 1.4 0.3 ND 3.1 2.8 2.4 16.0 0.9 WY Campbell Wyodak Train

09-343 14,718 0.37 6.36 11,990 ND 88 62 3.7 ND 0.5 0.4 ND 3.3 3.3 2.9 6.8 0.6 WY Campbell Wyodak Train

09-346 14,344 0.46 6.12 12,056 ND 94 50 4.7 ND 1.6 0.3 ND 2.5 2.4 2.3 6.8 0.8 WY Campbell Wyodak Train

09-347 14,688 0.41 7.17 11,923 ND ND 49 2.9 ND 0.5 0.2 ND 3.2 2.7 2.9 12.3 0.5 WY Campbell Wyodak Train

09-348 14,647 0.51 6.56 12,040 0.115 82 51 5.2 ND 1.3 0.4 0.05 4.3 2.9 2.8 8.5 0.9 WY Campbell Wyodak Train

09-349 14,594 0.45 7.2 11,869 ND 105 88 15.5 1.3 10.5 3.4 ND 18.5 10.4 8.7 24.6 3.1 WY Campbell Wyodak Train

44 To the extent that a vendor provides these data or that a facility is required by State or local agency to analyze its fuel for HAP constituents (e.g., Cl, F), 

and any metallic HAP (e.g., Hg, Pb, As, Se, etc.), EPA wishes the responding facility to provide those fuel analyses results. Otherwise, this 12-month fuel

analysis requirement can be bypassed by the respondent.

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

Fuel 

Shipment 

Method

Total amount 

of fuel 

represented by 

Sample ID 

#

State/

Country

County Coal Seam Nickel, 

ppm

Other trace metal HAP, ppm45

Total 

Sulfur, %

Ash 

Content, 

%

Heating 

Value, 

Btu/lb

Mercury, 

ppm

Chlorine, 

ppm

Fluorine, 

ppm

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April 5, 2010

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

__X__ permit requirements (for coal)

____ contractual obligations

____ standard operational procedures

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

5 Analyses provided in Part II, question 3 above, supplied by

____ Fuel supplier (name and address)

__X__ Other (name and address)

Georgia Power Environmental Lab

5131 Maner Road, Smyrna GA 30080

6 Name and address of laboratory performing analyses:

Georgia Power Environmental Lab (same as above)
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

7 In addition to the analyses required in Part II, question 3 above, for samples for which analyses of chlorine and/or any of the HAP metals were 

conducted, please provide copies of any analyses conducted over the preceding 12 calendar months for (a) complete proximate and ultimate 

analyses, (b) additional trace metals, and (c) the mineralogy of the ash that are readily available for the oil(s) or coal(s) listed in Part II, question

2 above. The Agency is requesting these data only as they may already be available; no additional sampling or analyses are required to provide

these data.

Total 

Moisture

Volatiles Ash Fixed 

Carbon

Carbon Hydrogen Nitrogen Total 

Sulfur

Oxygen Barium Copper Magnesium Sodium Vanadium Zinc Al2O3 Fe2O3 CaO MgO MnO2 P2O5 K2O SiO2 Na2O SO3 TiO2

09-313 26.08 43.52 6.91 49.57 70.56 4.77 1.03 0.32 16.41 390 9.8 0.211 0.063 12.2 19.1 15.71 5.76 20.61 5.06 0.013 1.23 0.53 36.25 1.23 11.55 1.07

09-300 29.35 46.13 7.06 46.81 69.06 4.47 0.83 0.53 18.06 363 12.3 0.257 0.080 16.1 8.7 14.8 4.1 17.3 5.25 ND 0.577 ND 32.3 1.45 16.9 1.01

09-301 31.61 45.88 6.78 47.34 71.09 4.55 1.18 0.43 15.97 349 7.3 0.247 0.076 9.3 9.7 12 4.4 20.9 4.67 ND 0.881 ND 29.5 1.08 21.1 0.675

09-302 26.54 44.79 6 49.21 69.39 4.45 0.86 0.28 19.03 361 11.0 0.206 0.083 13.5 6.9 15 4.54 18.2 4.24 ND 1.29 ND 35.6 1.28 15.1 1.11

09-305 26.91 45.12 6.26 48.62 72.4 4.45 1.16 0.34 15.39 302 10.6 0.217 0.078 12.9 15.0 14.3 5.75 18.3 4.62 ND 0.6 ND 32.3 1.24 15.2 1.01

09-307 30.85 45.28 6.52 48.21 70.73 4.53 1.03 0.44 16.76 329 14.3 0.173 0.068 15.7 5.1 12.5 4.06 19.5 3.71 ND 0.781 ND 26.2 1.07 22.9 1.25

09-309 30.9 44.87 9.22 45.9 66.88 4.35 0.95 0.57 18.03 350 12.5 0.244 0.090 20.5 11.4 15.4 4.39 13.5 3.67 ND 0.437 ND 41.6 1.09 12.9 0.777

09-310 30.38 45.68 8.15 46.16 68.85 4.55 0.98 0.5 16.96 366 16.4 0.191 0.076 20.5 9.0 15.4 3.77 15.9 3.61 ND 0.641 ND 35.7 1.18 16.2 1.14

09-312 28.27 44.91 5.95 49.14 70.27 4.6 0.99 0.28 17.9 346 11.3 0.198 0.074 11.9 9.0 15.4 5.33 21.8 5.17 ND 1.29 ND 35.2 1.53 12.4 1.35

09-314 30.84 45.73 5.94 48.32 70.56 4.46 0.95 0.29 17.79 356 7.3 0.245 0.085 7.4 10.9 11.9 5.1 22.3 5.58 ND 0.954 ND 30.9 1.44 17.3 0.908

09-316 30.41 45.53 6.14 48.34 68.16 4.49 0.92 0.42 19.9 381 9.5 0.247 0.077 11.5 6.3 12.3 3.86 19.3 5.18 ND 0.595 ND 29.5 1.35 21.1 0.894

09-317 30.48 45.28 6.73 47.99 72.24 4.82 1 0.41 14.8 340 12.9 0.182 0.070 15.8 4.2 14.5 4 15.8 3.71 ND 0.666 ND 32.5 1.27 17.6 1.22

09-325 27.29 43.79 6.5 49.71 69.81 4.79 0.65 0.27 17.98 340 10.3 0.189 0.074 11.2 7.4 17.12 5.07 20.27 4.83 0.014 1.11 0.4 35.15 1.53 12.51 1.13

09-327 26.57 42.74 7.14 50.12 69.41 4.73 0.98 0.37 17.37 380 9.5 0.208 0.057 10.8 12.5 16.55 4.88 19.32 4.83 0.01 1.26 0.42 34.62 1.08 14.81 0.97

09-321 29.84 46.28 7.44 46.29 68.82 4.6 0.83 0.46 17.85 361 16.8 0.184 0.072 23.1 7.3 16.6 3.99 17.5 3.31 ND 0.846 ND 33.7 1.2 15.4 1.2

09-322 31.43 45.62 6.53 47.84 69.24 5.42 0.79 0.44 18.48 322 8.7 0.231 0.087 11.4 11.9 13.4 5.64 22 4.8 ND ND ND 30.3 1.65 17 0.945

09-328 28.63 46.69 6.25 47.06 68.82 4.53 1.05 0.41 18.94 375 11.2 0.272 0.099 13.2 6.7 15.8 4.45 23.2 6.02 ND 0.618 ND 30.6 1.49 22.4 1.16

09-329 29.63 46.18 6.33 47.25 64.98 4.36 1.06 0.49 22.77 281 8.2 0.219 0.069 8.8 11.9 12.3 4.81 21.7 5.15 ND 0.551 ND 30.9 1.2 20.9 0.951

09-330 28.8 46.56 7.43 46.01 67.77 4.44 0.96 0.62 18.79 372 12.3 0.243 0.073 14.5 15.5 14.3 5.19 18.6 4.37 ND ND ND 34.8 1.27 20.1 1.08

09-331 29.34 46.38 6.69 46.94 68.34 4.49 1.12 0.46 18.9 337 15.2 0.184 0.069 16.5 7.4 14.9 4.52 19.6 3.73 ND 0.874 ND 35.1 1.2 17.8 1.07

09-332 30.37 46.11 7.43 46.47 67.5 4.66 1.14 0.54 18.73 337 15.2 0.192 0.057 19.7 6.6 14.5 4.21 19.2 3.66 ND 0.916 ND 30 0.927 17.7 1.17

09-341 30.84 45.09 7.44 47.47 68.33 4.44 1.13 0.49 18.17 348 17.1 0.166 0.071 21.9 8.7 18 4.5 19.8 3.45 ND 0.779 ND 33.5 1.31 11.4 1.28

09-342 30.44 45.41 6.41 48.19 68.68 4.57 1.1 0.57 18.67 389 10.5 0.253 0.094 13.5 8.4 14.5 4.95 22.7 5.94 ND 0.634 ND 28.9 1.94 15.4 1.03

09-343 28.18 44.34 6.36 49.31 68.87 4.53 1.09 0.37 18.77 375 11.1 0.209 0.071 12.9 8.9 15.3 4.7 20.4 4.96 ND 1.22 ND 33.6 1.55 9.47 1.13

09-346 31.12 45.62 6.12 48.26 68.52 4.49 1.04 0.46 19.37 315 9.6 0.246 0.089 11.2 10.7 13.3 5.44 23.1 5.91 ND 0.547 ND 30.2 1.91 13.2 1.04

09-347 26.57 43.07 7.17 49.76 68.26 4.45 1.1 0.41 18.61 479 9.7 0.219 0.069 12.2 6.4 12.8 4.53 18.7 4.39 ND 1.29 ND 37.9 1.28 11.2 1.01

09-348 30.74 46.12 6.56 47.33 68.6 4.62 0.95 0.51 18.76 342 15.6 0.188 0.084 16.2 7.2 14.9 4.44 20.9 4.11 ND 0.763 ND 29.3 1.4 14.3 1.26

09-349 31.25 45.14 7.2 47.65 68.42 4.27 0.88 0.45 18.77 315 21.4 0.080 0.043 33.1 13.0 12.9 4.89 19.3 4.43 ND 0.536 ND 32.5 1.38 12.9 1.1

Sample ID #

Proximate Analyses, % by wt Ultimate Analyses, % by wt Other Trace Metals, ppm, dry basis Ash Mineralogy, % by wt

Page 67 of 93 part II, 7
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April 5, 2010

8a What emission test report(s), parametric monitoring data, and other data or monitoring are available for the boilers noted in Part I,

question 15, for tests conducted since January 1, 2005. Please consider reports prepared for all testing and monitoring programs, for

all pollutants, including (but not limited to) those required under Title V, compliance with State or local requirements, fulfillment of

contractual obligations, U.S. Department of Energy (DOE) programs, etc. (NOTE: EPA is not requesting copies of the test reports or data

at this time; however we may request actual copies in the future.) Use additional pages as necessary.

Report 1 Unit 4 Particulate Emissions Test (April 12, 2006)

Report 2 Unit 3 Particulate Emissions Test (April 13, 2006)

Report 3 Unit 1 Particulate Emissions Test (June 15, 2006)

Report 4 Unit 2 Particulate Emissions Test (June 15, 2006)

Report 5 Unit 3 Particulate Emissions Test (February 19, 2008)

Report 6 Unit 4 Particulate Emissions Test (February 20, 2008)

Report 7 Unit 1 Particulate Emissions Test (June 3, 2008 to June 4, 2008)

Report 8 Unit 2 Particulate Emissions Test (June 5, 2008)

Report 9 Unit 1 Boiler Optimization (September 20, 2007 to September 25, 2007)

Report 10 Unit 2 Economizer Performance (August 25, 2009 to August 26, 2009)

Report 11 Unit 3 Economizer Performance (March 3, 2009)

Report 12 Unit 4 SCR Baseline (October 24, 2006 to October 31, 2006)

Report 13 Unit 2 Baghouse Performance (May 28, 2009 to June 1, 2009)

Report 14 Unit 3 Baghouse Performance (January 28, 2009 to January 29, 2009)

8b Please indicate the date(s) and types (e.g., stack, fuel, parametric, etc.) of the test(s) and the constituents (including criteria and hazardous

air pollutants) sampled for:

Report 1 Date: 4/12/2006 Type: stack Constituents: PM

Report 2 Date: 4/13/2006 Type: stack Constituents: PM

Report 3 Date: 6/15/2006 Type: stack Constituents: PM

Report 4 Date: 6/15/2006 Type: stack Constituents: PM

Report 5 Date: 2/19/2008 Type: stack Constituents: PM

Report 6 Date: 2/20/2008 Type: stack Constituents: PM

Report 7 Date: 6/3/2008-6/4/2008 Type: stack Constituents: PM

Report 8 Date: 6/5/2008 Type: stack Constituents: PM

Page 68 of 93 part II, 8
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Report 9 Date: 9/20/2007-9/25/2007 Type: duct Constituents: CO

Report 10 Date: 8/25/2009-8/26/2009 Type: duct Constituents: CO

Report 11 Date: 3/3/2009 Type: duct Constituents: CO

Report 12 Date: 10/24/2006-10/31/2006 Type: duct Constituents: CO

Report 13 Date: 5/28/2009-6/1/2009 Type: duct/stack Constituents: PM, Hg

Report 14 Date: 1/28/2009-1/29/2009 Type: duct/stack Constituents: PM, Hg

8c Do 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 Reports 9, 10, 11, 12 reflect testing at the economizer outlet (upstream of all post-combustion control devices), there are

no control devices downstream designed to reduce CO.

Reports 13, 14 reflect testing upstream of the baghouse (downstream of the ESP).

8d Were any of these test reports conducted when use of other material(s) or non-fossil fuels were fired in the boiler?

Yes ____ No _X___ If yes, please not which reports and identify the other material(s) or non-fossil fuels used.

8e Do any of these test reports reflect testing during periods of startup, shutdown, and malfunction?

Yes ____ No _X___ If yes, please note which reports.

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

Yes _X___ No ____ If yes, please list the unit's complete control configuration at time of testing in a similar format to Part I, question 16.

The control configuration shown below is representative of the conditions present during Reports 1, 2, 3, 4, 5, 6, 7, 8, 9, 12.

Boiler ID Type NOx control SO2 control PM control Other control

1 tangentialfired

(1) overfire air (3) cold-side 

electrostatic 

precipitator

(2) flue gas 

conditioning (SO3 

injection)

2 tangentialfired

(1) overfire air (3) cold-side 

electrostatic 

precipitator

(2) flue gas 

conditioning (SO3 

injection)

3 tangentialfired

(1) overfire air (2) cold-side 

electrostatic 

precipitator

4 tangentialfired

(1) overfire air (2) cold-side 

electrostatic 

precipitator

Page 70 of 93 part II, 8
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EGU HAPs ICR, OMB Control No. 2060-0631

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The control configuration shown below is representative of the conditions present during Report 10, 11, 13, 14.

Boiler ID Type NOx control SO2 control PM control Other control

2 tangentialfired

(1) overfire air (3) cold-side 

electrostatic 

precipitator

(4) baghouse with 

activated carbon 

injection

3 tangentialfired

(1) overfire air (3) cold-side 

electrostatic 

precipitator

(3) baghouse with 

activated carbon 

injection

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

Yes ____ No _X___ If yes, please note which reports and, in addition to the detailed description of the location of the sampling point(s)

(question 8c above), include detail about how much, if any, bypass of unscrubbed flue gas was utilized at at the time of testing (including

percentage of total scrubber flue gas flow). Note by diagram where sampling ports were located in relation to the bypass ductwork.

Page 71 of 93 part II, 8
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9 What type of deviation reporting is required for violations of permit requirements?

Specified deviations are reported quarterly. Emissions exceeding a standard for 

a period of 4 hours or more are reported within 7 days. 

Other deviations are reported semiannually.

Note: Not all reported deviations are considered violations of permit requirements

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

Yes _X__ No ____ If yes, please note which reports.

Deviation reports including periods of malfuncation are available where required in quarterly monitor 

breakdown reports and excess emissions, exdeedances, and excursion reports.

Note: A malfunction is not necessarily a period of noncompliance with permit terms and conditions. 

Not all reported deviations are considered violations of permit requirements

11 Are continuous emissions monitoring system (CEMS) data available (e.g., mercury, continuous opacity monitoring systems) that are not

already being provided to the U.S. EPA, even if from short-term testing?

Yes _X__ No ____ If yes46, please note for which pollutants CEMS data are available and the period of time (both total period and calendar

period) for which the data are available. If CEM data are being provided to EPA, please note to which Office the data are being provided.

Mercury CEMS data are operating for the following periods of time:

Unit 3: January 1, 2009 - December 31, 2009

EPA requested in Footnote 46 to Part II, Question 11 that facilities submit available mercury CEMS data that follow recognized 

QA/QC procedures. While EPA did not make the submittal mandatory, Georgia Power wishes to provide available mercury 

CEMS data in a separate submittal to assist the rulemaking process. Georgia Power has installed and operated monitors on 

certain units that, as closely as possible, follow the QA/QC procedures as written under the vacated Clean Air Mercury Rule 

("CAMR"). However, Georgia Power does not regularly submit reports to a regulatory agency on an ongoing basis. Thus, 

Georgia Power will require additional time to review and prepare the data for submittal to EPA. Georgia Power plans to submit 

this data by May 3, 2010.

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

46 Where units are monitored by CEMs (either following CAMR, State, or NIST QA/QC procedures), and where data are available, EPA requests

that this CEM data by submitted by the respondent. The respondent should also mark the periods of start up, shut down and malfunction events 

(SSM) in the data sets.

Page 72 of 93 part II, 9-11
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12 For each boiler noted in Part I, question 15, provide the following information:

NOTE: Net generation data not available in test reports. Other parameters may or may not be available depending on the test report.

Date of test PM49 SO2 HCl/HF/HCN Metal HAP50 Hg51 CO

Other organics 

(specify)

4 4/12/2006 See Attachment 1 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

3 4/13/2006 See Attachment 2 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

1 6/15/2006 See Attachment 3 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

2 6/15/2006 See Attachment 4 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

3 2/19/2008 See Attachment 5 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

4 2/20/2008 See Attachment 6 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

1 6/3/2008-6/4/2008 See Attachment 7 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

2 6/5/2008 See Attachment 8 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

3 1/5/2010 See Attachment 9 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

4 1/5/2010 See Attachment 10 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

1 9/20/2007-9/25/2007 Not applicable Not applicable Not applicable Not applicable Not applicable See Attachment 11 Not applicable

2 8/25/2009-8/26/2009 Not applicable Not applicable Not applicable Not applicable Not applicable See Attachment 12 Not applicable

3 3/3/2009 Not applicable Not applicable Not applicable Not applicable Not applicable See Attachment 13 Not applicable

4 10/24/2006-10/31/2006 Not applicable Not applicable Not applicable Not applicable Not applicable See Attachment 14 Not applicable

2 5/28/2009-6/1/2009 See Attachment 15 Not applicable Not applicable Not applicable See Attachment 15 Not applicable Not applicable

3 1/28/2009-1/29/2009 See Attachment 16 Not applicable Not applicable Not applicable See Attachment 16 Not applicable Not applicable

47 Provide emission test data for all tests conducted since January 1, 2005. Please indicate test data acquired both before and after

any control device. Use additional pages as necessary. EPA may, at some future date, request a copy of one or more emission test reports.

Data generated to fulfill both Federal and State requirements must be provided. Note that data generated pursuant to CAA Title V

must be maintained and available for 5 years. Also include averaging times and measurement units for all pollutants.

48 For each emissions test run the respondent should provide the following process information: Unit Load (MW), Net generation during run (MWh net),

Flue gas moisture content (%), Flue gas flow rate (dscfm or 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).

Boiler ID

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

Page 73 of 93 part II, 12
GEORGIA POWER - PLANT SCHERER

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

NOTE: Net generation data not available in test reports. Other parameters may or may not be available depending on the test report.

Date of test PM49 SO2 HCl/HF/HCN Metal HAP50 Hg51 CO

Other organics 

(specify)

Boiler ID

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

49 If emission testing recorded the emissions of filterable and condensable PM, separately, please include those separate emission results. 

Also, please include separate emission results for total PM, PM10, and PM2.5.

50 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, phosphorus, and selenium;

indicate emission level for all metal HAP for which an emission test has been conducted.

51 Please provide separate results for total Hg, elemental Hg, oxidized Hg, and particulate Hg, as available. If the emissions testing recorded

the amount of unburned carbon in fly ash (as reflected by the "Loss of Ignition" [L.O.I]) at the time of any Hg testing, please include these data.

Page 74 of 93 part II, 12
ATTACHMENT 1 - Scherer Report 1 Test Results

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

Run 1 Run 2 Run 3

Test Date 4/12/2006 4/12/2006 4/12/2006

Run Start Time 7:50 10:00 12:15

Run End Time 9:10 11:20 13:35

Meter Volume (dacf), Vm: 37.158 37.699 37.218

Sqrt Delta P ("wc): 1.38 1.40 1.40

Sampling Time (min): 60 60 60

Barometric Pressure ("Hg), Pbar: 29.68 29.70 29.72

Delta H ("wc): 1.1 1.1 1.1

Volume in Impingers (mls), VIc: 93.4 94.8 94.1

Static Pressure ("wc), Pg: -4.00 -3.90 -4.10

Stack Pressure ("Hg), Ps: 29.39 29.41 29.42

Stack Temperature (F), Ts: 311 325 333

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 85 89

Stack Diameter (inches): 324 324 324

Area Stack (sq. ft.), As: 572.56 572.56 572.56

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 13.0 13.2

Percent O2 (% dry volume): 6.0 6.0 6.2

Percent (N2 + CO) (% dry volume): 80.8 81.0 80.6

Particulate Collected (mg), Mn: 19.4 18.5 24.5

Molec. Wt. Dry (lb/lb-mole), Md: 30.343 30.320 30.355

Volume Water (scf), Vwstd 4.396 4.462 4.429

Meter Volume (dscf), Vmstd: 36.104 36.215 35.551

Wet Fraction (v/v), Bws: 0.109 0.110 0.111

Molec. Wt. Wet (lb/lb-mole), Ms: 29.003 28.968 28.986

Stack Gas Sampled (acf), Vma: 60.188 61.479 61.050 Averages

Stack Gas Velocity (fps), Vs: 94.09 96.41 96.66 96

Volumetric Flowrate (dscfm), Qs: 1,938,974 1,950,945 1,933,744 1,941,221

Volumetric Flowrate (acfm), Qa: 3,232,443 3,311,971 3,320,753 3,288,389

Grainloading (gr/dscf), cs: 0.0083 0.0079 0.0106 0.01

Emission Rate (lb/hour), E: 137.97 131.46 176.34 148.6

Percent Isokinetic Sampling (%), I: 104.94 104.62 103.61 104.39

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780

Heat Input (mmBtu/hour): 8461.58 8532.92 8344.15 8446.22

Emission Rate (lbs/mmBtu), E: 0.02 0.02 0.02 0.02

Allowable Rate (lb/mmBtu): 0.10 0.10 0.10 0.10

Average Unit Gross Load (MW) 862 867 873 867

Particulate Emission Results Summary

Scherer Unit 4

Page 75 of 93 Att. 1
ATTACHMENT 2 - Scherer Report 2 Test Results

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

Run 1 Run 2 Run 3

Test Date 4/13/2006 4/13/2006 4/13/2006

Run Start Time 7:00 9:10 11:10

Run End Time 8:35 10:35 12:30

Meter Volume (dacf), Vm: 37.343 37.476 36.972

Sqrt Delta P ("wc): 1.39 1.41 1.40

Sampling Time (min): 60 60 60

Barometric Pressure ("Hg), Pbar: 29.75 29.75 29.77

Delta H ("wc): 1.1 1.1 1.1

Volume in Impingers (mls), VIc: 94.6 96.9 93.6

Static Pressure ("wc), Pg: -3.80 -4.00 -3.90

Stack Pressure ("Hg), Ps: 29.47 29.46 29.48

Stack Temperature (F), Ts: 294 314 322

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 86 92

Stack Diameter (inches): 324 324 324

Area Stack (sq. ft.), As: 572.56 572.56 572.56

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): 12.9 12.8 12.9

Percent O2 (% dry volume): 6.2 6.3 6.1

Percent (N2 + CO) (% dry volume): 80.9 80.9 81.0

Particulate Collected (mg), Mn: 21.2 21.2 18.0

Molec. Wt. Dry (lb/lb-mole), Md: 30.312 30.304 30.308

Volume Water (scf), Vwstd 4.453 4.561 4.406

Meter Volume (dscf), Vmstd: 36.380 36.004 35.149

Wet Fraction (v/v), Bws: 0.109 0.112 0.111

Molec. Wt. Wet (lb/lb-mole), Ms: 28.969 28.921 28.937

Stack Gas Sampled (acf), Vma: 59.212 60.396 59.444 Averages

Stack Gas Velocity (fps), Vs: 94.03 96.38 96.40 96

Volumetric Flowrate (dscfm), Qs: 1,984,538 1,973,798 1,958,126 1,972,154

Volumetric Flowrate (acfm), Qa: 3,230,078 3,310,959 3,311,613 3,284,217

Grainloading (gr/dscf), cs: 0.0090 0.0091 0.0079 0.01

Emission Rate (lb/hour), E: 153.07 153.82 132.79 146.6

Percent Isokinetic Sampling (%), I: 103.32 102.81 101.17 102.43

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780

Heat Input (mmBtu/hour): 8563.33 8478.37 8506.84 8516.18

Emission Rate (lbs/mmBtu), E: 0.02 0.02 0.02 0.02

Allowable Rate (lb/mmBtu): 0.10 0.10 0.10 0.10

Average Unit Gross Load (MW) 873 875 875 874

Particulate Emission Results Summary

Scherer Unit 3

Page 76 of 93 Att. 2
ATTACHMENT 3 - Scherer Report 3 Test Results

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

Run 1 Run 2 Run 3

Test Date 6/15/2006 6/15/2006 6/15/2006

Run Start Time 7:00 9:15 10:50

Run End Time 8:30 10:25 12:00

Meter Volume (dacf), Vm: 38.814 37.85 37.759

Sqrt Delta P ("wc): 1.48 1.46 1.46

Sampling Time (min): 60 60 60

Barometric Pressure ("Hg), Pbar: 29.10 29.10 29.10

Delta H ("wc): 1.2 1.2 1.2

Volume in Impingers (mls), VIc: 84.8 79.8 80.8

Static Pressure ("wc), Pg: -3.90 -3.80 -4.00

Stack Pressure ("Hg), Ps: 28.81 28.82 28.81

Stack Temperature (F), Ts: 351 358 364

Meter Coefficient (no units), Y: 0.989 0.989 0.989

Pitot Coefficient (no units) Cp: 0.840 0.840 0.840

Meter OutletTemperature (F), Tm: 100 104 109

Stack Diameter (inches): 324 324 324

Area Stack (sq. ft.), As: 572.56 572.56 572.56

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): 12.2 12.4 12.4

Percent O2 (% dry volume): 6.9 6.8 7.0

Percent (N2 + CO) (% dry volume): 80.9 80.8 80.6

Particulate Collected (mg), Mn: 11.1 9.4 19.7

Molec. Wt. Dry (lb/lb-mole), Md: 30.232 30.251 30.268

Volume Water (scf), Vwstd 3.992 3.756 3.803

Meter Volume (dscf), Vmstd: 35.303 34.186 33.820

Wet Fraction (v/v), Bws: 0.102 0.099 0.101

Molec. Wt. Wet (lb/lb-mole), Ms: 28.989 29.038 29.028

Stack Gas Sampled (acf), Vma: 62.641 61.018 60.985 Averages

Stack Gas Velocity (fps), Vs: 104.70 103.67 104.30 104

Volumetric Flowrate (dscfm), Qs: 2,027,017 1,995,353 1,987,054 2,003,141

Volumetric Flowrate (acfm), Qa: 3,596,763 3,561,452 3,583,163 3,580,460

Grainloading (gr/dscf), cs: 0.0049 0.0043 0.0090 0.01

Emission Rate (lb/hour), E: 84.38 72.74 152.93 103.4

Percent Isokinetic Sampling (%), I: 98.72 97.11 96.47 97.43

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780

Heat Input (mmBtu/hour): 8349.96 8258.57 8127.01 8245.18

Emission Rate (lbs/mmBtu), E: 0.01 0.01 0.02 0.01

Allowable Rate (lb/mmBtu): 0.100 0.100 0.100 0.100

Average Unit Gross Load (MW) 852 851 851 851

Particulate Emission Results Summary

Scherer Unit 1

Page 77 of 93 Att. 3
ATTACHMENT 4 - Scherer Report 4 Test Results

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

Run 1 Run 2 Run 3

Test Date 6/15/2006 6/15/2006 6/15/2006

Run Start Time 7:00 9:15 10:50

Run End Time 8:30 10:25 12:00

Meter Volume (dacf), Vm: 41.08 41.05 41.328

Sqrt Delta P ("wc): 1.58 1.56 1.55

Sampling Time (min): 60 60 60

Barometric Pressure ("Hg), Pbar: 29.10 29.10 29.10

Delta H ("wc): 1.4 1.3 1.3

Volume in Impingers (mls), VIc: 86.2 87.8 85.3

Static Pressure ("wc), Pg: -4.20 -4.00 -3.90

Stack Pressure ("Hg), Ps: 28.79 28.81 28.81

Stack Temperature (F), Ts: 364 364 360

Meter Coefficient (no units), Y: 0.997 0.997 0.99

Pitot Coefficient (no units) Cp: 0.840 0.840 0.840

Meter OutletTemperature (F), Tm: 99 103 107

Stack Diameter (inches): 324 324 324

Area Stack (sq. ft.), As: 572.56 572.56 572.56

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): 11.9 12.0 11.8

Percent O2 (% dry volume): 7.2 7.3 7.4

Percent (N2 + CO) (% dry volume): 80.8 80.8 80.8

Particulate Collected (mg), Mn: 18.3 18.3 18.6

Molec. Wt. Dry (lb/lb-mole), Md: 30.199 30.205 30.189

Volume Water (scf), Vwstd 4.057 4.133 4.015

Meter Volume (dscf), Vmstd: 37.730 37.476 37.196

Wet Fraction (v/v), Bws: 0.097 0.099 0.097

Molec. Wt. Wet (lb/lb-mole), Ms: 29.014 28.993 29.002

Stack Gas Sampled (acf), Vma: 67.729 67.459 66.453 Averages

Stack Gas Velocity (fps), Vs: 112.68 111.41 110.34 111

Volumetric Flowrate (dscfm), Qs: 2,156,342 2,126,166 2,121,599 2,134,702

Volumetric Flowrate (acfm), Qa: 3,870,872 3,827,283 3,790,417 3,829,524

Grainloading (gr/dscf), cs: 0.0075 0.0075 0.0077 0.01

Emission Rate (lb/hour), E: 138.28 137.27 140.29 138.6

Percent Isokinetic Sampling (%), I: 98.61 99.34 98.81 98.92

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780

Heat Input (mmBtu/hour): 8650.60 8508.74 8407.43 8522.26

Emission Rate (lbs/mmBtu), E: 0.02 0.02 0.02 0.02

Allowable Rate (lb/mmBtu): 0.100 0.100 0.100 0.100

Average Unit Gross Load (MW) 870 865 865 867

Particulate Emission Results Summary

Scherer Unit 2

Page 78 of 93 Att. 4
ATTACHMENT 5 - Scherer Report 5 Test Results

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

Run 1 Run 2 Run 3

Test Date 2/19/2008 2/19/2008 2/19/2008

Run Start Time 8:00 10:15 12:00

Run End Time 9:30 11:35 13:20

Meter Volume (dacf), Vm: 34.588 34.956 34.485

Sqrt Delta P ("wc): 1.34 1.33 1.33

Sampling Time (min): 60 60 60

Barometric Pressure ("Hg), Pbar: 29.40 29.41 29.42

Delta H ("wc): 1.0 1.0 1.0

Volume in Impingers (mls), VIc: 75.8 74.1 73.1

Static Pressure ("wc), Pg: -3.80 -3.90 -3.90

Stack Pressure ("Hg), Ps: 29.12 29.12 29.13

Stack Temperature (F), Ts: 311 315 317

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: 84 91 95

Stack Diameter (inches): 324 324 324

Area Stack (sq. ft.), As: 572.56 572.56 572.56

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): 14.0 13.9 14.0

Percent O2 (% dry volume): 5.3 5.3 5.2

Percent (N2 + CO) (% dry volume): 80.8 80.8 80.8

Particulate Collected (mg), Mn: 21.5 16.9 17.8

Molec. Wt. Dry (lb/lb-mole), Md: 30.445 30.435 30.453

Volume Water (scf), Vwstd 3.568 3.488 3.441

Meter Volume (dscf), Vmstd: 32.606 32.569 31.883

Wet Fraction (v/v), Bws: 0.099 0.097 0.097

Molec. Wt. Wet (lb/lb-mole), Ms: 29.218 29.232 29.240

Stack Gas Sampled (acf), Vma: 54.272 54.349 53.370 Averages

Stack Gas Velocity (fps), Vs: 91.42 91.16 91.46 91

Volumetric Flowrate (dscfm), Qs: 1,886,792 1,876,628 1,877,073 1,880,164

Volumetric Flowrate (acfm), Qa: 3,140,539 3,131,589 3,142,022 3,138,050

Grainloading (gr/dscf), cs: 0.0102 0.0080 0.0086 0.01

Emission Rate (lb/hour), E: 164.62 128.94 138.91 144.2

Percent Isokinetic Sampling (%), I: 97.67 98.09 96.00 97.26

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780

Heat Input (mmBtu/hour): 8658.48 8611.84 8650.61 8,640.31

Emission Rate (lbs/mmBtu), E: 0.02 0.01 0.02 0.02

Allowable Rate (lb/mmBtu): 0.10 0.10 0.10 0.10

Average Unit Gross Load (MW) 879 880 880 880

Particulate Emission Results Summary

Scherer Unit 3

Page 79 of 93 Att. 5
ATTACHMENT 6 - Scherer Report 6 Test Results

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

Run 1 Run 2 Run 3

Test Date 2/20/2008 2/20/2008 2/20/2008

Run Start Time 10:00 11:40 13:20

Run End Time 11:15 12:55 14:45

Meter Volume (dacf), Vm: 34.175 34.672 35.497

Sqrt Delta P ("wc): 1.35 1.35 1.36

Sampling Time (min): 60 60 60

Barometric Pressure ("Hg), Pbar: 29.40 29.40 29.41

Delta H ("wc): 1.0 1.0 1.0

Volume in Impingers (mls), VIc: 79.1 78.2 78.3

Static Pressure ("wc), Pg: -4.10 -4.00 -4.00

Stack Pressure ("Hg), Ps: 29.10 29.11 29.12

Stack Temperature (F), Ts: 327 331 333

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: 88 97 99

Stack Diameter (inches): 324 324 324

Area Stack (sq. ft.), As: 572.56 572.56 572.56

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): 13.7 13.8 13.7

Percent O2 (% dry volume): 5.4 5.5 5.5

Percent (N2 + CO) (% dry volume): 80.9 80.8 80.8

Particulate Collected (mg), Mn: 16.3 22.0 19.9

Molec. Wt. Dry (lb/lb-mole), Md: 30.409 30.421 30.417

Volume Water (scf), Vwstd 3.723 3.681 3.686

Meter Volume (dscf), Vmstd: 32.024 31.917 32.620

Wet Fraction (v/v), Bws: 0.104 0.103 0.102

Molec. Wt. Wet (lb/lb-mole), Ms: 29.117 29.137 29.157

Stack Gas Sampled (acf), Vma: 54.804 54.786 56.062 Averages

Stack Gas Velocity (fps), Vs: 93.26 93.64 94.19 111

Volumetric Flowrate (dscfm), Qs: 1,872,186 1,874,116 1,882,680 2,134,702

Volumetric Flowrate (acfm), Qa: 3,203,949 3,216,974 3,235,678 3,829,524

Grainloading (gr/dscf), cs: 0.0079 0.0106 0.0094 0.01

Emission Rate (lb/hour), E: 126.19 170.70 152.06 138.6

Percent Isokinetic Sampling (%), I: 96.40 95.98 97.65 98.92

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780

Heat Input (mmBtu/hour): 8499.86 8490.29 8510.66 8522.26

Emission Rate (lbs/mmBtu), E: 0.01 0.02 0.02 0.02

Allowable Rate (lb/mmBtu): 0.10 0.10 0.10 0.10

Average Unit Gross Load (MW) 895 895 886 892

Particulate Emission Results Summary

Scherer Unit 4

Page 80 of 93 Att. 6
ATTACHMENT 7 - Scherer Report 7 Test Results

Performed by: TRC Environmental Corporation, Raleigh, North Carolina

RUN NUMBER U1-H-M5-1 U1-H-M5-2 U1-H-M5-3

RUN DATE 6/3/2008 6/4/2008 6/4/2008 AVERAGE

RUN TIME 1510-1629 0650-0805 0840-0957

MEASURED DATA

Meter Box Y 1.0025 1.0025 1.0025 1.0025

Avg Delta H, inches H2O 3.650 3.583 3.450 3.561

Barometric Pressure, inches Hg 29.10 29.04 29.04 29.06

Volume Metered, cubic feet 64.040 63.681 62.790 63.504

Average Meter Temp, deg F 107.1 98.3 102.2 102.53

Static Pressure, inches H2O -3.5 -3.5 -3.5 -3.500

Average Stack Temp, deg F 358.6 339.9 347.3 348.6

Water Collected, mL 178.0 177.0 182.0 179.0

Carbon Dioxide, % 12.66 12.47 12.89 12.673

Oxygen, % 6.95 7.1 6.63 6.893

Nitrogen, % 80.39 80.43 80.48 80.433

Pitot Tube Coefficient 0.84 0.84 0.84 0.84

Avg Sqrt Delta P, (inches H2O)1/2 1.552 1.538 1.510 1.533

Sample Time, min 60.0 60.0 60.0 60.0

Nozzle Diameter, inches 0.226 0.226 0.226 0.226

CALCULATED DATA

Nozzle Area, square feet 2.786E-04 2.786E-04 2.786E-04 2.786E-04

Standard Meter Volume, ft3

58.650 59.104 57.861 58.538

Standard Water Vapor Volume, ft3

8.393 8.346 8.581 8.440

Moisture (gravimetrically), % 12.52 12.37 12.92 12.60

Moisture (at saturation), % NA NA NA NA

Moisture (actual) 12.52 12.37 12.92 12.60

Dry Mole Fraction 0.875 0.876 0.871 0.874

Molecular Weight-dry, lb/lb-mole 30.30 30.28 30.33 30.30

Molecular Weight-wet, lb/lb-mole 28.76 28.76 28.74 28.75

Stack Pressure, inches Hg 28.84 28.78 28.78 28.80

Velocity, ft/s 110.67 108.59 107.16 108.81

Stack Area, in2

82,448.0 82,448.0 82,448.0 82,448.0

Stack Area, ft2

572.56 572.56 572.56 572.56

Percent Excess Air 48.7 50.2 45.4 48.1

Volumetric flow, acfm 3,802,036 3,730,298 3,681,385 3,737,906

Volumetric flow, dscfm 2,067,300 2,074,752 2,016,176 2,052,742

Isokinetic Rate, % 97.2 97.6 98.3 97.7

F-factor, DSCF/MMBtu 9780 9780 9780

FILTERABLE PARTICULATE TEST RESULTS SUMMARY

PLANT SCHERER

UNIT 1 STACK

Page 81 of 93 Att. 7
ATTACHMENT 7 - Scherer Report 7 Test Results

Performed by: TRC Environmental Corporation, Raleigh, North Carolina

RUN NUMBER U1-H-M5-1 U1-H-M5-2 U1-H-M5-3

RUN DATE 6/3/2008 6/4/2008 6/4/2008 AVERAGE

RUN TIME 1510-1629 0650-0805 0840-0957

FILTERABLE PARTICULATE TEST RESULTS SUMMARY

PLANT SCHERER

UNIT 1 STACK

FILTERABLE PARTICULATE EMISSIONS DATA

Filterable Particulate Catch, g 0.0128 0.0096 0.0124

Concen., mg/dscm 7.71 5.74 7.57 7.00

Concen., mg/actual m3

4.19 3.19 4.15 3.84

Concen., gr/dscf 0.003 0.003 0.003 0.003

Concen., gr/dscf@8% Oxygen 0.003 0.002 0.003 0.003

Emission Rate, lb/hr 59.68 44.58 57.15 53.80

Emission Rate, lb/MMBtu 0.007 0.005 0.007 0.006

Gross Load, MW 876 887 879 881

Page 82 of 93 Att. 7
ATTACHMENT 8 - Scherer Report 8 Test Results

Performed by: TRC Environmental Corporation, Raleigh, North Carolina

RUN NUMBER U2-H-M5-1 U2-H-M5-2 U2-H-M5-3

RUN DATE 6/5/2008 6/5/2008 6/5/2008 AVERAGE

RUN TIME 0630-0747 0825-0939 1010-1123

MEASURED DATA

Meter Box Y 1.0025 1.0025 1.0025 1.0025

Avg Delta H, inches H2O 3.775 3.833 3.867 3.825

Barometric Pressure, inches Hg 29.13 29.13 29.13 29.13

Volume Metered, cubic feet 64.846 65.740 65.867 65.484

Average Meter Temp, deg F 94.4 98.5 102.0 98.31

Static Pressure, inches H2O -3.5 -3.5 -3.5 -3.500

Average Stack Temp, deg F 355.5 358.8 364 359.4

Water Collected, mL 186.0 188.0 191.0 188.3

Carbon Dioxide, % 12.41 12.76 12.24 12.470

Oxygen, % 7.21 6.8 7.37 7.127

Nitrogen, % 80.38 80.44 80.39 80.403

Pitot Tube Coefficient 0.84 0.84 0.84 0.84

Avg Sqrt Delta P, (inches H2O)1/2 1.586 1.593 1.599 1.593

Sample Time, min 60.0 60.0 60.0 60.0

Nozzle Diameter, inches 0.226 0.226 0.226 0.226

CALCULATED DATA

Nozzle Area, square feet 2.786E-04 2.786E-04 2.786E-04 2.786E-04

Standard Meter Volume, ft3

60.826 61.223 60.964 61.004

Standard Water Vapor Volume, ft3

8.770 8.864 9.006 8.880

Moisture (gravimetrically), % 12.60 12.65 12.87 12.71

Moisture (at saturation), % NA NA NA NA

Moisture (actual) 12.60 12.65 12.87 12.71

Dry Mole Fraction 0.874 0.874 0.871 0.873

Molecular Weight-dry, lb/lb-mole 30.27 30.31 30.25 30.28

Molecular Weight-wet, lb/lb-mole 28.73 28.76 28.68 28.72

Stack Pressure, inches Hg 28.87 28.87 28.87 28.87

Velocity, ft/s 112.92 113.63 114.56 113.70

Stack Area, in2

82,448.0 82,448.0 82,448.0 82,448.0

Stack Area, ft2

572.56 572.56 572.56 572.56

Percent Excess Air 51.5 47.1 53.2 50.6

Volumetric flow, acfm 3,879,333 3,903,500 3,935,347 3,906,060

Volumetric flow, dscfm 2,117,502 2,120,896 2,119,360 2,119,253

Isokinetic Rate, % 98.4 98.9 98.6 98.6

F-factor, DSCF/MMBtu 9780 9780 9780

FILTERABLE PARTICULATE TEST RESULTS SUMMARY

PLANT SCHERER

UNIT 2 STACK

Page 83 of 93 Att. 8
ATTACHMENT 8 - Scherer Report 8 Test Results

Performed by: TRC Environmental Corporation, Raleigh, North Carolina

RUN NUMBER U2-H-M5-1 U2-H-M5-2 U2-H-M5-3

RUN DATE 6/5/2008 6/5/2008 6/5/2008 AVERAGE

RUN TIME 0630-0747 0825-0939 1010-1123

FILTERABLE PARTICULATE TEST RESULTS SUMMARY

PLANT SCHERER

UNIT 2 STACK

FILTERABLE PARTICULATE EMISSIONS DATA

Filterable Particulate Catch, g 0.0169 0.0176 0.0172

Concen., mg/dscm 9.81 10.15 9.96 9.97

Concen., mg/actual m3

5.36 5.52 5.37 5.41

Concen., gr/dscf 0.004 0.004 0.004 0.004

Concen., gr/dscf@8% Oxygen 0.004 0.004 0.004 0.004

Emission Rate, lb/hr 77.82 80.65 79.09 79.19

Emission Rate, lb/MMBtu 0.009 0.009 0.009 0.009

Gross Load, MW 882 879 879 880

Page 84 of 93 Att. 8
ATTACHMENT 9 - Scherer Report 9 Test Results

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

Run 1 Run 2 Run 3

Test Date 1/5/2010 1/5/2010 1/5/2010

Run Start Time 9:05 10:40 12:10

Run End Time 10:15 11:50 13:20

Meter Volume (dacf), Vm: 33.828 33.589 33.791

Sqrt Delta P ("wc): 1.36 1.35 1.37

Sampling Time (min): 60 60 60

Barometric Pressure ("Hg), Pbar: 30.01 30.01 30.01

Delta H ("wc): 1.1 1.0 1.1

Volume in Impingers (mls), VIc: 119.1 120.3 117.6

Static Pressure ("wc), Pg: -2.60 -2.50 -2.70

Stack Pressure ("Hg), Ps: 29.82 29.83 29.81

Stack Temperature (F), Ts: 262 265 270

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: 52 55 58

Stack Diameter (inches): 324 324 324

Area Stack (sq. ft.), As: 572.56 572.56 572.56

Nozzle Diameter (inches), dp: 0.173 0.173 0.173

Area Nozzle (sq. ft.), An: 0.000164 0.000164 0.000164

Percent CO2 (% dry volume): 12.6 12.6 12.5

Percent O2 (% dry volume): 7.0 7.0 7.1

Percent (N2 + CO) (% dry volume): 80.4 80.3 80.4

Particulate Collected (mg), Mn: 5.0 3.1 4.3

Molec. Wt. Dry (lb/lb-mole), Md: 30.297 30.303 30.289

Volume Water (scf), Vwstd 5.606 5.663 5.535

Meter Volume (dscf), Vmstd: 34.532 34.121 34.123

Wet Fraction (v/v), Bws: 0.140 0.142 0.140

Molec. Wt. Wet (lb/lb-mole), Ms: 28.580 28.552 28.574

Stack Gas Sampled (acf), Vma: 55.098 54.773 54.999 Averages

Stack Gas Velocity (fps), Vs: 90.11 89.68 90.79 90

Volumetric Flowrate (dscfm), Qs: 1,940,079 1,919,224 1,935,036 1,931,446

Volumetric Flowrate (acfm), Qa: 3,095,479 3,080,889 3,118,864 3,098,411

Grainloading (gr/dscf), cs: 0.0022 0.0014 0.0020 0.00

Emission Rate (lb/hour), E: 36.94 22.96 32.41 30.8

Percent Isokinetic Sampling (%), I: 103.82 103.70 102.86 103.46

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780

Heat Input (mmBtu/hour): 7896.92 7812.03 7838.52 7849.16

Emission Rate (lbs/mmBtu), E: 0.005 0.003 0.004 0.004

Allowable Rate (lb/mmBtu): 0.100 0.100 0.100 0.100

Average Unit Gross Load (MW) 899 898 894 897

Particulate Emission Results Summary

Scherer Unit 3

Page 85 of 93 Att. 9
ATTACHMENT 10 - Scherer Report 10 Test Results

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

Run 1 Run 2 Run 3

Test Date 1/5/2010 1/5/2010 1/5/2010

Run Start Time 9:05 10:40 12:10

Run End Time 10:15 11:50 13:20

Meter Volume (dacf), Vm: 36.333 35.892 36.915

Sqrt Delta P ("wc): 1.41 1.42 1.41

Sampling Time (min): 60 60 60

Barometric Pressure ("Hg), Pbar: 30.01 30.01 30.01

Delta H ("wc): 1.1 1.1 1.1

Volume in Impingers (mls), VIc: 126.0 123.2 121.7

Static Pressure ("wc), Pg: -2.90 -2.80 -2.80

Stack Pressure ("Hg), Ps: 29.80 29.80 29.80

Stack Temperature (F), Ts: 310 314 315

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: 50 53 56

Stack Diameter (inches): 324 324 324

Area Stack (sq. ft.), As: 572.56 572.56 572.56

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): 13.2 13.2 13.3

Percent O2 (% dry volume): 5.9 5.8 5.8

Percent (N2 + CO) (% dry volume): 80.9 81.0 81.0

Particulate Collected (mg), Mn: 42.8 28.6 29.7

Molec. Wt. Dry (lb/lb-mole), Md: 30.347 30.344 30.353

Volume Water (scf), Vwstd 5.931 5.799 5.728

Meter Volume (dscf), Vmstd: 37.658 36.987 37.798

Wet Fraction (v/v), Bws: 0.136 0.136 0.132

Molec. Wt. Wet (lb/lb-mole), Ms: 28.667 28.671 28.728

Stack Gas Sampled (acf), Vma: 63.795 62.985 64.136 Averages

Stack Gas Velocity (fps), Vs: 96.17 96.85 96.41 96

Volumetric Flowrate (dscfm), Qs: 1,950,249 1,953,887 1,951,829 1,951,988

Volumetric Flowrate (acfm), Qa: 3,303,867 3,327,244 3,311,914 3,314,342

Grainloading (gr/dscf), cs: 0.0176 0.0119 0.0121 0.01

Emission Rate (lb/hour), E: 293.50 199.99 203.01 232.2

Percent Isokinetic Sampling (%), I: 109.14 106.99 109.45 108.53

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780

Heat Input (mmBtu/hour): 8606.20 8660.49 8670.47 8645.72

Emission Rate (lbs/mmBtu), E: 0.034 0.023 0.023 0.027

Allowable Rate (lb/mmBtu): 0.100 0.100 0.100 0.100

Average Unit Gross Load (MW) 883 882 883 883

Particulate Emission Results Summary

Scherer Unit 4

Page 86 of 93 Att. 10
ATTACHMENT 11 - Scherer Report 11 Test Results

Title of 

Run

Description Date

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 

Test01 -0.7% O2 Bias, "A & B 

Mills Off", Pegasus Off

9/20/2007 8:09 9:09 875 902 2.5 16.43 799.7

Test02 -0.7% O2 Bias, "A & B 

Mills Off", Pegasus Off

9/20/2007 9:49 10:49 875 902 2.51 16.4 812.7

Test03 No O2 Bias, "A & B 

Mills Off", Pegasus Off

9/20/2007 12:56 13:56 875 235 3.29 15.67 823.9

Test04 No O2 Bias, "A & B 

Mills Off", Pegasus Off

9/20/2007 15:11 16:11 875 289 3.28 15.61 827.9

Test05 No O2 Bias, "A & B 

Mills Off", Pegasus On

9/24/2007 12:35 13:35 893 598 3.1 15.79 830.2

Test06 No O2 Bias, "A & B 

Mills Off", Pegasus On

9/25/2007 8:29 9:39 873 560 2.82 16.03 816.3

Test07 +0.2 O2 Bias, "A & B 

Mills Off", Pegasus On

9/25/2007 13:25 14:25 873 352 3.4 15.42 818.5

Test08 +0.2 O2 Bias, "A & B 

Mills Off", Pegasus On

9/25/2007 15:28 16:28 873 304 3.37 15.41 813

Boiler Optimization Test Results Summary

Scherer Unit 1
ATTACHMENT 12 - Scherer Report 12 Test Results

Title of 

Run

Description Date

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 

24-1 VWO; A&B Mills off 8/25/2009 7:00 8:24 872 6 4.12 15.14 714

24-2 VWO; A&B Mills off 8/25/2009 8:31 9:55 870 6 4.08 15.1 728

24-3 VWO; A&B Mills off 8/25/2009 10:14 11:38 874 5 4.07 15.12 740

24-4 VWO; A&B Mills off 8/25/2009 11:52 12:52 879 4 4.11 15.02 749

24-5 VWO; A&B Mills off 8/25/2009 13:04 14:28 874 5 4 15.16 753

24-9 VWO; A&B Mills off 8/25/2009 19:48 21:12 873 16 4 15.22 715

24-13 VWO; A&B Mills off 8/26/2009 5:29 6:53 873 12 4.01 15.25 710

Moved JJ Aux Air dmpr to 60%

Moved OFA dmpr to 0%

Lowered tilts to 0 deg

Upper Sofa 90% Lower Sofa 90%

B Side Aux Air +10 bias

Took all bias out of SOFA dampers

Economizer Performance Test Results Summary

Scherer Unit 2
ATTACHMENT 13 - Scherer Report 13 Test Results

Title of Run Date 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 3/3/2009 7:25 8:10 883 166 2.78 16.59 712

3 3/3/2009 8:13 8:58 897 216 2.75 16.65 716

4 3/3/2009 8:59 9:44 895 208 2.78 16.67 717

7 3/3/2009 13:49 14:34 877 142 2.92 16.48 698

8 3/3/2009 14:35 15:20 878 115 2.94 16.4 701

Economizer Performance Test Results Summary

Scherer Unit 3
ATTACHMENT 14 - Scherer Report 14 Test Results

Title of 

Run

Description Date 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 

Test 1 A & B Mills Off 10/24/2006 8:40 10:04 881 18 3.3 15.86 824

Test 2 A & B Mills Off 10/24/2006 12:45 14:09 881 217 2.31 16.65 830

Test 4 A Mills Off 10/25/2006 7:25 8:49 896 191 2.42 16.8 823

Test 6 A Mills Off 10/25/2006 11:30 12:54 894 616 2.28 16.92 834

Test 7 J Mills Off 10/26/2006 7:20 8:44 881 147 2.46 16.84 792

Test 7B A Mills Off 10/26/2006 10:20 11:44 881 160 2.34 16.97 799

Test 8 A, B & J Mills Off 10/31/2006 0:05 1:29 682 17 3.12 16.05 754

Test 9 A, B, G, H, J Mills Off 10/31/2006 3:05 4:29 351 3 5.22 14.07 635

SCR Baseline Test Results Summary

Scherer Unit 4
ATTACHMENT 15 - Scherer Report 15 Test Results

Performed by: Weston Solutions

Unit 2 Stack

Summary of PM Emission Results

Run 1 Run 2 Run 3 Mean

Date 5/28/2009 5/28/2009 5/28/2009

Time Began 743 1218 1511

Time Ended 1001 1435 1728

Stack Gas Data

Temperature, oF 312 317 319 316

Velocity, ft/sec 104 101 100 102

Moisture, % 12 13 12 12

CO2, %vd 12.9 12.8 12.9 12.9

O2, %vd 6.9 6.9 6.8 6.9

VFR, x 10^6 dscfm 2.02 1.97 2.01 2.00

Process Operating Data

Gross Load, MW 871.5 875.2 875.1 873.9

F-Factor, dscf/MMBtu 9780 9780 9780 9780

Particulate Matter

Isokinetic Sampling Rate, % 104 101 100 102

Concentration, gr/dscf 0.0003 0.0005 0.0008 0.0005

Emission Rate, lb/MMBtu 0.0006 0.0010 0.0017 0.0011

Unit 2 Baghouse Inlet

Summary of Mercury Emission Results

Run 1 Run 2 Run 3 Mean

Date 6/1/2009 6/1/2009 6/1/2009

Time Began 949 1300 1532

Time Ended 1221 1511 1745

Stack Gas Data

Temperature, oF 304 309 312 308

Velocity, ft/sec 74 74 77 75

Moisture, % 11 10 11 11

CO2, %vd 12.7 13.1 13 12.9

O2, %vd 6.7 6.6 6.6 6.6

VFR, x 10^6 dscfm 2.36 2.37 2.45 2.39

PAC Injection Rate, lb/hr 787.1 797.3 797.3 793.9

Mercury

Baghouse Inlet (30B) Concentration, μg/m^3 5.43 5.6 6.29 5.77

Stack (CMMS) Concentration, μg/m^3 0.23 0.23 0.19 0.22

Removal Efficiency, % 95.7 95.9 96.9 96.2

Stack (CMMS) Emission Factor, lb Hg/Tbtu 0.23 0.23 0.19 0.22
ATTACHMENT 16 - Scherer Report 16 Test Results

Performed by: Weston Solutions

Unit 3 Stack

Summary of PM Emission Results

Run 1 Run 2 Run 3 Run 4 Mean

Date 1/28/2009 1/28/2009 1/29/2009 1/29/2009

Time Began 1129 1534 951 1402

Time Ended 1345 1743 1227 1613

Stack Gas Data

Temperature, oF 287 282 274 278 280

Velocity, ft/sec 92 92 90 90 91

Moisture, % 9.9 10.9 12.2 12.2 11.3

CO2, %vd 14.3 14.4 14.4 14.4 14.4

O2, %vd 5.0 5.0 5.1 5.1 5.1

VFR, x 10^6 wscfm 2.14 2.17 2.14 2.14 2.15

VFR, x 10^6 dscfm 1.93 1.93 1.88 1.88 1.90

Process Operating Data

Gross Load, MW 883 894 893 887 889

F-Factor, dscf/MMBtu 9780 9780 9780 9780 9780

Particulate Matter

Isokinetic Sampling Rate, % 100 104 101 100 102

Concentration, gr/dscf 0.0005 0.0004 0.0007 0.0019 0.0009

Emission Rate, lb/MMBtu 0.0008 0.0007 0.0014 0.0035 0.0016

Unit 3 Baghouse Inlet

Summary of Mercury Emission Results

Run 1 Run 2 Run 3 Run 4 Mean

Date 1/28/2009 1/28/2009 1/29/2009 1/29/2009

Time Began 1129 1534 951 1402

Time Ended 1342 1743 1220 1603

Stack Gas Data

Temperature, oF 284 275 270 273 276

Velocity, ft/sec 58 58 58 57 58

Moisture, % 9.0 10.4 11.5 11.3 10.6

CO2, %vd 14.7 14.9 15 14.9 14.9

O2, %vd 4.8 4.7 4.6 4.6 4.7

VFR, x 10^6 wscfm 2.24 2.25 2.29 2.24 2.25

VFR, x 10^6 dscfm 2.03 2.01 2.02 1.99 2.02

PAC Injection Rate, lb/hr 227.3 230.2 185.6 180.1 205.8

Mercury

Baghouse Inlet (30B) Concentration, μg/m^3 5.51 4.39 --- 5.4 5.1

Stack (CMMS) Concentration, μg/m^3 0.77 0.38 0.42 0.50 0.55

Removal Efficiency, % 86 91.4 --- 90.7 89.4

Stack (CMMS) Emission Factor, lb Hg/Tbtu 0.66 0.32 0.37 0.43 0.47

Run 3 was determined void at the Baghouse Inlet because the mercury sorbent Trap A was

compromised during the test. 
ATTACHMENT 16 - Scherer Report 16 Test Results

Unit 3 Baghouse Inlet

Summary of 30B and Ontario Hydro Single Point Test Results

Run 1

Date 1/27/2009

Time Began 1719

Time Ended 1919

Stack Gas Data

Temperature, oF 276

Velocity, ft/sec 58

Moisture, % 13.5

CO2, %vd 14.6

O2, %vd 5.1

VFR, x 10^6 wscfm 2.28

VFR, x 10^6 dscfm 1.97

Mercury - 30B

Concentration, μg/m^3 6.86

Mercury - Ontario Hydro

Total Concentration, μg/scm 5.59

Elemental Hg, μg/dscm 2.59

Oxidized Hg, μg/dscm 3.87

Particle Bound Hg, μg/dscm 0.01