GEORGIA POWER - Submittal for PLANT BRANCH

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

April 5, 2010

PART I: GENERAL FACILITY INFORMATION

Process Information

1 Name of legal owner of facility:

Georgia Power

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

3 Address of _X__ legal owner or ____ operator:

241 Ralph McGill Blvd NE, Bin 10221

Atlanta, GA 30308

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

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

Harllee Branch

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):

709

5 Complete street address of facility (physical location):

US Highway 441 Truck Route, P.O. Box 990

Milledgeville, Georgia 31061

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 67 part I, 1-14
GEORGIA POWER - Submittal for PLANT BRANCH

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 (% _____) ____ subbituminous (% _____)

_X__ bituminous (% _100____) ____ anthracite (% _____)

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

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

 that recycle materials) (%_____)

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

____ petroleum coke (% _____)

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

_X___ distillate (% _100____)

____ other (specify __________) (% _____)

____ residual or bunker C (% _____)

Page 2 of 67 part I, 1-14
GEORGIA POWER - Submittal for PLANT BRANCH

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 or not.

1

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

2

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

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

3

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

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

purposes").

4

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

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

5

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

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

Actually burn Quantity/year

None in 2009

Permitted to burn

Synfuel

Other Material

Sawdust

Biomass

None in 2009

None in 2009

Used Oil

Yes

None in 2009

None in 2009

Yes

None in 2009

None in 2009

Yes

Yes None in 2009

Page 3 of 67 part I, 1-14
GEORGIA POWER - PLANT BRANCH

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 bituminous CBI CBI 267 252 89.3 89.5 2400 2400 1000 999 1000 998 bituminous coal (100%), distillate 

oil (100%)

CBI CBI Not 

applicable

None 

planned

2 bituminous CBI CBI 332 316 89.3 89.19 2400 2399 1000 997 1000 1000 bituminous coal (100%), distillate 

oil (100%)

CBI CBI Not 

applicable

None 

planned

3 bituminous CBI CBI 513 488 87 89.23 3500 3501 1000 994 1000 1001 bituminous coal (100%), distillate 

oil (100%)

CBI CBI Not 

applicable

None 

planned

4 bituminous CBI CBI 520 490 86.8 90.2 3500 3499 1000 998 1000 1000 bituminous coal (100%), distillate 

oil (100%)

CBI CBI Not 

applicable

None 

planned

6

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

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

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

7

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

8

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

9

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

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

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

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

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

NOTES: Original Design Fuel

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. 

Page 4 of 67 part I, 15
GEORGIA POWER - PLANT BRANCH

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

MWe Net Capacity Summer

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

Original Design Gross Efficiency

Taken directly from the original contract boiler data sheet.

Present Operating Gross Efficiency 

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

Design Steam Pressure

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

Operating Steam Pressure

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

Design Steam Temperature

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

Operating Steam Temperature 

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

Design Steam Reheat Temperature 

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

Operating Steam Reheat Temperature

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

Fuel

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

Hours/Year Operated

Confidential Business Information

Annual Average Capacity Factor for the Past 3 Years

Confidential Business Information

Applicable NSPS

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

Retirement Year

Georgia Power has not committed to actual retirement dates for Plant Branch 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 67 part I, 15
GEORGIA POWER - PLANT BRANCH

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/NH3 flue gas conditioning and lime injection systems are operated on an as-needed basis.

Dates for future planned controls listed are subject to change.

Boiler ID14 Type15 NOx control16 SO2 control17 PM control18 Other control19

1 cell burner (1) low NOx burners (2/2003)

(2) SCR (12/31/2014), catalyst 

not yet purchased

(6) wet flue gas 

desulfurization (FGD) 

(12/31/2014).

(4) cold-side electrostatic 

precipitator (ESP) (6/1965, 

original install; 1/1978, retrofit 

ESP arranged in series with 

original ESP)

(3) flue gas conditioning (SO3 

injection) (1998)

(5) hydrated lime injection 

(SO3 control, 12/31/2014)

2 dry bottom wallfired(1) low NOx burners (2007, 

replacement of equipment 

installed 3/2002)

(2) SCR (12/31/2014), catalyst 

not yet purchased

(6) wet flue gas 

desulfurization (FGD) 

(12/31/2014).

(4) cold-side electrostatic 

precipitator (ESP) (6/1967, 

original install; 12/1977, 

retrofit ESP arranged in series 

with original ESP)

(3) flue gas conditioning (SO3 

injection) (1998)

(5) hydrated lime injection 

(SO3 control, 12/31/2014)

3 cell burner (1) low NOx burners (3/2003)

(2) SCR (12/31/2013), catalyst 

not yet purchased

(6) wet flue gas 

desulfurization (FGD) 

(12/31/2013).

(3) cold-side electrostatic 

precipitator (ESP) (7/1968, 

original install; 11/1981, 

retrofit ESP arranged in 

parallel with original ESP)

(5) hydrated lime injection 

(SO3 control, 12/31/2013)

4 cell burner (1) low NOx burners (5/2002)

(2) SCR (6/1/2014), catalyst 

not yet purchased

(6) wet flue gas 

desulfurization (FGD) 

(6/1/2014).

(3) cold-side electrostatic 

precipitator (ESP) (6/1969, 

original install; 3/1982, retrofit 

ESP arranged in parallel with 

original ESP)

(5) hydrated lime injection 

(SO3 control, 6/1/2014)

Page 6 of 67 part I, 16
GEORGIA POWER - PLANT BRANCH

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/NH3 flue gas conditioning and lime injection systems are operated on an as-needed basis.

Dates for future planned controls listed are subject to change.

Boiler ID14 Type15 NOx control16 SO2 control17 PM control18 Other control19

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Page 7 of 67 part I, 16
GEORGIA POWER - PLANT BRANCH

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 67 part I, 17
GEORGIA POWER - PLANT BRANCH

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 67 part I, 18
GEORGIA POWER - PLANT BRANCH

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

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

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

Name Telephone Address

1 Not applicable Not applicable Not applicable Not applicable

2 Not applicable Not applicable Not applicable Not applicable

3 Not applicable Not applicable Not applicable Not applicable

4 Not applicable Not applicable Not applicable Not applicable

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

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

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

Boiler Company (vendor) contact information

ID24 Company (vendor) name

Page 10 of 67 part I, 19
GEORGIA POWER - PLANT BRANCH

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

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

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

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

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

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

"inlet" and "outlet" are).

Boiler 

ID25 Actual start-up date

Expected or 

projected start-up 

date

Type of control (e.g., 

sorbent and type; 

chemical additive)26

Guaranteed HAP 

emission reduction 

(%) or emission rate

Sorbent or additive 

feed rate on which 

guarantee is based

Coal rank(s) upon 

which guarantee is 

based

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

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 11 of 67 part I, 20
GEORGIA POWER - PLANT BRANCH

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

stack test using Method 5 of 17; test conducted 

every 13 months, but may be deferred for 12 

months if test results from the previous annual 

tests are fifty percent or less of the limit)

Not 

applicable

Not 

applicable

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

analysis of coal sample acquired for each 

operating day and supplier certification 

statement for No. 2 oil)

5% of potential combustion concentration (95% 

removal by FGD), effective Jan 1, 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: 0.55 lb/MMBtu from May 1 through 

September 30 OR compliance with 7-plant NOx 

average of 0.18 lb/MMBtu (Title V permit; based 

on 30-day rolling averages determined by CEMS)

Other NOx Multi-Unit Plans: Southern Company 

Phase II NOx Averaging Plan 0.46 lb/MMBtu 

annual average over all units; 7-plant NOx cap 

32, 335.8 tons from May 1 to September 30 

(Title V permit; determined by CEMS)

2 0.24 lb/MMBtu (Title V permit; based on 3-run 

stack test using Method 5 of 17; test conducted 

every 13 months, but may be deferred for 12 

months if test results from the previous annual 

tests are fifty percent or less of the limit)

Not 

applicable

Not 

applicable

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

analysis of coal sample acquired for each 

operating day and supplier certification 

statement for No. 2 oil)

5% of potential combustion concentration (95% 

removal by FGD), effective Jan 1, 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: 0.55 lb/MMBtu from May 1 through 

September 30 OR compliance with 7-plant NOx 

average of 0.18 lb/MMBtu (Title V permit; based 

on 30-day rolling averages determined by CEMS)

Other NOx Multi-Unit Plans: Southern Company 

Phase II NOx Averaging Plan 0.46 lb/MMBtu 

annual average over all units; 7-plant NOx cap 

32, 335.8 tons from May 1 to September 30 

(Title V permit; determined by CEMS).

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

stack test using Method 5 of 17; test conducted 

every 13 months, but may be deferred for 12 

months if test results from the previous annual 

tests are fifty percent or less of the limit)

Not 

applicable

Not 

applicable

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

analysis of coal sample acquired for each 

operating day and supplier certification 

statement for No. 2 oil)

5% of potential combustion concentration (95% 

removal by FGD), effective Jan 1, 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: 0.45 lb/MMBtu from May 1 through 

September 30 OR compliance with 7-plant NOx 

average of 0.18 lb/MMBtu (Title V permit; based 

on 30-day rolling averages determined by CEMS)

Other NOx Multi-Unit Plans: Southern Company 

Phase II NOx Averaging Plan 0.46 lb/MMBtu 

annual average over all units; 7-plant NOx cap 

32, 335.8 tons from May 1 to September 30 

(Title V permit; determined by CEMS).

Permitted emission limit (indicate type of permit and format of emission limit)

Boiler ID27

Page 12 of 67 part I, 21
GEORGIA POWER - PLANT BRANCH

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

stack test using Method 5 of 17; test conducted 

every 13 months, but may be deferred for 12 

months if test results from the previous annual 

tests are fifty percent or less of the limit)

Not 

applicable

Not 

applicable

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

analysis of coal sample acquired for each 

operating day and supplier certification 

statement for No. 2 oil)

5% of potential combustion concentration (95% 

removal by FGD), effective June 1, 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: 0.45 lb/MMBtu from May 1 through 

September 30 OR compliance with 7-plant NOx 

average of 0.18 lb/MMBtu (Title V permit; based 

on 30-day rolling averages determined by CEMS)

Other NOx Multi-Unit Plans: Southern Company 

Phase II NOx Averaging Plan 0.46 lb/MMBtu 

annual average over all units; 7-plant NOx cap 

32, 335.8 tons from May 1 to September 30 

(Title V permit; determined by CEMS).

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 13 of 67 part I, 21
GEORGIA POWER - PLANT BRANCH

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

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

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

PM33 PM10 PM2.5 SO2

HCl 

and/or HF HCN

Metal 

HAP34 Hg CO

Other 

organics 

(specify)

Other pollutant (specify)

1 ESP 1A and 1B rebuild: 75.0 % collection 

efficiency filterable (expired in 2000)

ESP 1C and 1C: 98.5 % collection efficiency 

filterable (expired in 1978)

Not 

applicable

Not 

applicable

Not applicable Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Low NOx burners: 0.45 lb/MMBtu (expired in 

2004)

2 ESP 2A and 2B rebuild: 98.0 % collection 

efficiency filterable (expired in 2000)

ESP 2C and 2C: 98.5 % collection efficiency 

filterable (expired in 1977)

Not 

applicable

Not 

applicable

Not applicable Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Low NOx burners: 0.48 lb/MMBtu (expired in 

2003)

3 ESP rebuild: 98.7 % collection efficiency 

filterable (expired in 2009)

Not 

applicable

Not 

applicable

Not applicable Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Low NOx burners: 0.45 lb/MMBtu (expired in 

2004)

4 ESP rebuild: 0.1 lb/MMBtu filterable (expired in 

1999)

Not 

applicable

Not 

applicable

Not applicable Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Low NOx burners: 0.45 lb/MMBtu (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 14 of 67 part I, 22-23
GEORGIA POWER - PLANT BRANCH

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 36%) reported quarterly.

The facility shall submit 30-day advance notifications of required testing and test reports 

within 60 days of completion of the testing.

All records related to the Title V permit are retained for five years.

Not 

applicable

Not 

applicable

Coal sulfur content monitored through daily coal sampling; 

fuel oil sulfur content monitored through vendor 

certification; exceedances of 3% limit reported quarterly; 

records retained for 5 years.

Effective Jan 1, 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 36%) reported quarterly.

The facility shall submit 30-day advance notifications of required testing and test reports 

within 60 days of completion of the testing.

All records related to the Title V permit are retained for five years.

Not 

applicable

Not 

applicable

Coal sulfur content monitored through daily coal sampling; 

fuel oil sulfur content monitored through vendor 

certification; exceedances of 3% limit reported quarterly; 

records retained for 5 years.

Effective Jan 1, 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

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 40%) reported quarterly.

The facility shall submit 30-day advance notifications of required testing and test reports 

within 60 days of completion of the testing.

All records related to the Title V permit are retained for five years.

Not 

applicable

Not 

applicable

Coal sulfur content monitored through daily coal sampling; 

fuel oil sulfur content monitored through vendor 

certification; exceedances of 3% limit reported quarterly; 

records retained for 5 years.

Effective Jan 1, 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

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

Boiler ID35

Page 15 of 67 part I, 24
GEORGIA POWER - PLANT BRANCH

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 40%) reported quarterly.

The facility shall submit 30-day advance notifications of required testing and test reports 

within 60 days of completion of the testing.

All records related to the Title V permit are retained for five years.

Not 

applicable

Not 

applicable

Coal sulfur content monitored through daily coal sampling; 

fuel oil sulfur content monitored through vendor 

certification; exceedances of 3% limit reported quarterly; 

records retained for 5 years.

Effective June 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

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 16 of 67 part I, 24
GEORGIA POWER - PLANT BRANCH

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

Facility Name/Unit No.: Not applicable

Retrofit to existing boiler? Not applicable

Installation on a new boiler? Not applicable

Total Capital Investment: $ -

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

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

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

No.

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

Page 17 of 67 part I, 25-26
GEORGIA POWER - PLANT BRANCH

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: 

Branch

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

709

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

Page 18 of 67 part II, 1
GEORGIA POWER - PLANT BRANCH

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

9,777 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.25 12.02 13,058

10,245 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.43 12.94 12,865

10,166 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.19 11.91 13,104

9,789 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.29 13.63 12,803

9,988 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.35 14.67 12,595

10,072 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.23 12.72 12,947

9,746 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.06 12.39 12,982

9,792 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.03 13.14 12,885

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

Page 19 of 67 part II, 2 (coal)
GEORGIA POWER - PLANT BRANCH

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

10,012 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 0.95 13 12,934

10,222 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.2 11.92 13,055

9,711 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.33 13.37 12,828

9,654 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 0.92 13.93 12,710

9,757 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 0.92 11.7 13,132

9,781 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 0.92 13.73 12,763

9,936 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.27 11.92 13,005

10,053 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.57 12.65 12,943

Page 20 of 67 part II, 2 (coal)
GEORGIA POWER - PLANT BRANCH

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

9,539 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.51 12.72 12,949

10,012 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.37 12.39 12,960

9,681 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.41 12.83 12,965

9,711 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.31 13.77 12,826

10,149 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.31 11.8 13,073

10,474 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.28 11.72 13,154

10,066 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.39 13.36 12,817

10,117 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.39 12.06 13,020

Page 21 of 67 part II, 2 (coal)
GEORGIA POWER - PLANT BRANCH

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

10,377 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.63 12.85 12,845

9,872 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.53 13.5 12,742

9,596 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.45 12.54 12,916

9,974 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.3 13.13 12,854

9,892 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.4 12.62 12,876

10,081 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.43 12.16 12,964

10,414 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.73 12.66 12,933

9,980 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.63 12.58 12,916

Page 22 of 67 part II, 2 (coal)
GEORGIA POWER - PLANT BRANCH

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

9,959 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.42 11.26 13,074

10,079 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.61 12.85 12,890

10,487 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.52 12.29 13,066

10,070 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.37 11.37 13,183

10,017 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.28 12.56 13,005

10,439 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.54 11.9 13,189

9,910 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.3 11.32 13,165

9,892 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.47 12.63 13,027

Page 23 of 67 part II, 2 (coal)
GEORGIA POWER - PLANT BRANCH

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

9,966 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.23 11.82 13,177

10,132 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.51 12.27 13,015

9,913 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.4 12.89 12,962

9,837 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.51 12.6 12,984

9,952 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.19 12.78 12,916

9,564 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.34 13.66 12,789

9,665 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.28 12.63 12,904

10,010 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.39 11.41 13,232

Page 24 of 67 part II, 2 (coal)
GEORGIA POWER - PLANT BRANCH

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

10,084 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.3 12.77 12,952

10,154 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.38 12.78 13,021

10,071 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.46 13.79 12,767

9,915 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.16 11.93 13,009

9,933 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.14 13.4 12,717

9,923 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.21 12.88 12,946

9,982 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.19 11.7 13,112

9,995 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.2 13.34 12,793

Page 25 of 67 part II, 2 (coal)
GEORGIA POWER - PLANT BRANCH

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

9,969 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.04 12.99 12,901

9,321 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.05 13.54 12,696

10,013 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.08 13.76 12,836

9,944 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.21 13.11 12,781

10,057 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.28 12.72 12,776

10,326 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.36 12.42 13,010

9,955 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.54 11.23 13,159

10,092 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.48 12.59 12,957

Page 26 of 67 part II, 2 (coal)
GEORGIA POWER - PLANT BRANCH

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

9,846 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.3 11.89 13,067

9,911 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.57 12.16 13,024

10,068 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.51 13.17 12,801

10,162 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.52 11.95 13,100

9,793 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.35 12.46 12,916

9,984 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.51 13.09 12,845

10,179 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.33 13.13 12,812

9,891 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.56 13.27 12,860

Page 27 of 67 part II, 2 (coal)
GEORGIA POWER - PLANT BRANCH

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

9,923 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.6 11.72 13,169

10,252 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.44 12.48 12,926

9,894 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.25 12.42 12,803

10,122 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.45 14.26 12,690

10,106 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.44 12.21 12,977

9,732 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.65 12.2 13,033

10,059 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.58 13.2 12,869

10,158 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.26 13.12 12,837

Page 28 of 67 part II, 2 (coal)
GEORGIA POWER - PLANT BRANCH

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

9,887 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.4 11.62 13,091

10,067 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.55 13.2 12,805

9,970 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.17 14.08 12,798

10,127 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.25 14 12,789

10,047 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.16 13.56 12,843

10,422 1, 2, 3, 4 KY KNOTT

5A, 7, 8, 9, ELKHORN 2, 

ELKHORN 3, HAZARD #7 TRAIN 1.18 14.78 12,603

9,839 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.55 9.73 13,603

10,127 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.13 8.66 13,717

10,023 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.39 7.94 13,866

9,819 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.7 9.29 13,582

9,868 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.37 7.8 13,878

10,645 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.46 9.22 13,709

Page 29 of 67 part II, 2 (coal)
GEORGIA POWER - PLANT BRANCH

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

10,472 1, 2, 3, 4 KY

PERRY, 

LETCHER

AMBURGY, HAZARD #4, 

HAZARD TRAIN 0.93 10.62 13,460

9,504 1, 2, 3, 4 KY

PERRY, 

LETCHER

AMBURGY, HAZARD #4, 

HAZARD TRAIN 0.87 10.94 13,342

10,477 1, 2, 3, 4 KY

PERRY, 

LETCHER

AMBURGY, HAZARD #4, 

HAZARD TRAIN 1.03 9.48 13,658

10,660 1, 2, 3, 4 KY

PERRY, 

LETCHER

AMBURGY, HAZARD #4, 

HAZARD TRAIN 1.02 10.19 13,564

10,390 1, 2, 3, 4 KY

PERRY, 

LETCHER

AMBURGY, HAZARD #4, 

HAZARD TRAIN 0.74 10.8 13,441

10,393 1, 2, 3, 4 KY

PERRY, 

LETCHER

AMBURGY, HAZARD #4, 

HAZARD TRAIN 0.88 9.36 13,651

10,486 1, 2, 3, 4 KY

PERRY, 

LETCHER

AMBURGY, HAZARD #4, 

HAZARD TRAIN 0.89 11.15 13,312

10,442 1, 2, 3, 4 KY

PERRY, 

LETCHER

AMBURGY, HAZARD #4, 

HAZARD TRAIN 0.78 9.32 13,648

10,504 1, 2, 3, 4 KY

PERRY, 

LETCHER

AMBURGY, HAZARD #4, 

HAZARD TRAIN 0.97 10.16 13,783

10,478 1, 2, 3, 4 KY

PERRY, 

LETCHER

AMBURGY, HAZARD #4, 

HAZARD TRAIN 0.95 9.79 13,595

10,384 1, 2, 3, 4 KY

PERRY, 

LETCHER

AMBURGY, HAZARD #4, 

HAZARD TRAIN 1.1 9.65 13,578

10,568 1, 2, 3, 4 KY

PERRY, 

LETCHER

AMBURGY, HAZARD #4, 

HAZARD TRAIN 0.91 8.91 13,782

Page 30 of 67 part II, 2 (coal)
GEORGIA POWER - PLANT BRANCH

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

10,714 1, 2, 3, 4 KY

PERRY, 

LETCHER

AMBURGY, HAZARD #4, 

HAZARD TRAIN 1.11 8.8 13,695

10,524 1, 2, 3, 4 KY

PERRY, 

LETCHER

AMBURGY, HAZARD #4, 

HAZARD TRAIN 0.88 9.29 13,641

10,512 1, 2, 3, 4 KY

PERRY, 

LETCHER

AMBURGY, HAZARD #4, 

HAZARD TRAIN 0.87 10.27 13,515

10,507 1, 2, 3, 4 KY

PERRY, 

LETCHER

AMBURGY, HAZARD #4, 

HAZARD TRAIN 0.78 9.67 13,530

10,238 1, 2, 3, 4 KY

PERRY, 

LETCHER

AMBURGY, HAZARD #4, 

HAZARD TRAIN 0.98 9.91 13,519

10,720 1, 2, 3, 4 KY

PERRY, 

LETCHER

AMBURGY, HAZARD #4, 

HAZARD TRAIN 0.97 9.49 13,554

10,802 1, 2, 3, 4 KY

PERRY, 

LETCHER

AMBURGY, HAZARD #4, 

HAZARD TRAIN 0.89 9.52 13,631

10,358 1, 2, 3, 4 KY

PERRY, 

LETCHER

AMBURGY, HAZARD #4, 

HAZARD TRAIN 0.81 10.47 13,492

10,462 1, 2, 3, 4 KY

PERRY, 

LETCHER

AMBURGY, HAZARD #4, 

HAZARD TRAIN 0.79 10.3 13,484

10,583 1, 2, 3, 4 KY

PERRY, 

LETCHER

AMBURGY, HAZARD #4, 

HAZARD TRAIN 0.88 10.04 13,497

10,639 1, 2, 3, 4 KY

PERRY, 

LETCHER

AMBURGY, HAZARD #4, 

HAZARD TRAIN 1.01 9.06 13,595

10,664 1, 2, 3, 4 KY

PERRY, 

LETCHER

AMBURGY, HAZARD #4, 

HAZARD TRAIN 0.9 8.78 13,705

Page 31 of 67 part II, 2 (coal)
GEORGIA POWER - PLANT BRANCH

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

10,666 1, 2, 3, 4 KY

PERRY, 

LETCHER

AMBURGY, HAZARD #4, 

HAZARD TRAIN 1.06 9.64 13,583

10,394 1, 2, 3, 4 KY PIKE

ELKHORN #2, ELKHORN 

#3 TRAIN 1.49 8.99 13,689

10,450 1, 2, 3, 4 KY PIKE

ELKHORN #2, ELKHORN 

#3 TRAIN 1.48 9.09 13,635

10,397 1, 2, 3, 4 KY PIKE

ELKHORN #2, ELKHORN 

#3 TRAIN 1.48 8.75 13,714

10,158 1, 2, 3, 4 KY PIKE

ELKHORN #2, ELKHORN 

#3 TRAIN 1.58 10.44 13,393

10,603 1, 2, 3, 4 KY PIKE

ELKHORN #2, ELKHORN 

#3 TRAIN 1.63 8.75 13,710

10,502 1, 2, 3, 4 KY PIKE

ELKHORN #2, ELKHORN 

#3 TRAIN 1.35 8.39 13,822

10,486 1, 2, 3, 4 KY PIKE

ELKHORN #2, ELKHORN 

#3 TRAIN 1.37 8.19 13,866

10,424 1, 2, 3, 4 KY PIKE

ELKHORN #2, ELKHORN 

#3 TRAIN 1.41 7.96 13,864

10,566 1, 2, 3, 4 KY PIKE

ELKHORN #2, ELKHORN 

#3 TRAIN 1.47 7.92 13,899

10,387 1, 2, 3, 4 KY PIKE

ELKHORN #2, ELKHORN 

#3 TRAIN 1.47 8.95 13,627

10,036 1, 2, 3, 4 KY PIKE

ELKHORN #2, ELKHORN 

#3 TRAIN 1.5 8.5 13,987

Page 32 of 67 part II, 2 (coal)
GEORGIA POWER - PLANT BRANCH

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

10,459 1, 2, 3, 4 KY LETCHER

LOW SPLINT, HIGH 

SPLINT, WINIFREDE, 

HARLAN TRAIN 0.95 11.64 13,289

10,501 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.29 13.15 12,928

10,426 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.01 13.45 12,868

10,419 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.05 12.95 12,918

10,488 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.08 13.11 12,759

10,324 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.09 13.54 12,781

10,632 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.1 13.24 12,833

10,474 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.05 12.86 12,855

10,429 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1 12.84 12,916

10,429 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.18 13.67 12,847

10,725 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.14 12.47 13,040

10,529 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.22 13.13 12,873

10,474 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.35 12.54 12,969

10,696 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.28 13.37 12,869

10,668 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.26 13.12 12,891

10,500 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.18 13.22 12,875

10,474 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.25 12.28 13,068

10,450 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.2 13.13 12,884

10,387 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.51 13.29 12,823

10,621 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.36 13.09 12,881

Page 33 of 67 part II, 2 (coal)
GEORGIA POWER - PLANT BRANCH

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

10,613 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.29 12.51 12,999

10,424 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.29 12.84 12,979

10,596 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.24 12.76 12,914

10,722 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.28 13.24 12,858

10,683 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.3 12.82 12,895

10,656 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.37 12.87 12,920

10,318 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.33 11.51 13,045

10,082 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.05 12.38 13,025

10,608 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.27 12.61 12,934

10,250 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.22 11.95 13,046

10,647 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.41 12.54 12,940

10,476 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.35 12.18 12,968

10,468 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.41 12.14 13,032

10,598 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.32 11.85 13,047

10,401 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.34 12.32 12,975

10,643 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.27 11.62 13,139

10,571 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.32 12.16 13,004

10,661 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.28 11.99 13,031

10,716 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.28 12.07 13,026

10,706 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.31 11.58 13,101

10,583 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.45 11.45 13,162

10,589 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.34 11.57 13,111

Page 34 of 67 part II, 2 (coal)
GEORGIA POWER - PLANT BRANCH

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

10,728 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.36 11.6 13,112

10,529 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.26 11.72 13,062

10,533 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.4 11.72 13,069

10,552 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.23 11.51 13,159

10,773 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.23 11.72 13,065

10,653 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.33 12.02 13,012

10,596 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.36 10.77 13,256

10,497 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.35 11.76 13,068

10,552 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.3 11.67 13,112

10,672 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.31 11.36 13,140

10,749 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.41 12.67 12,919

10,715 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.31 11.81 13,028

10,577 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.35 11.42 13,106

10,549 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.14 11.2 13,124

10,024 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.4 11.33 13,107

10,667 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.39 12.71 12,923

10,581 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.48 11.55 13,094

10,651 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.29 12.23 13,039

10,664 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.47 11.57 13,112

10,494 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.39 11.84 13,087

10,651 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.39 12.3 13,051

10,659 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.33 11.71 13,078

Page 35 of 67 part II, 2 (coal)
GEORGIA POWER - PLANT BRANCH

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

10,868 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.24 11.54 13,109

10,710 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.2 12.42 12,959

10,780 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.23 12.53 12,972

10,670 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.26 12.53 12,976

10,717 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.26 12.21 12,984

10,667 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.25 12.11 13,067

10,577 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.27 13.12 12,870

10,567 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.25 13.07 12,839

10,694 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.27 11.81 13,078

10,567 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.34 12.24 13,020

10,663 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.24 13.68 12,796

10,536 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.32 13.22 12,860

10,713 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.26 13.02 12,879

10,550 1, 2, 3, 4 KY KNOTT, PERRY VARIOUS HAZARD TRAIN 1.06 11.41 13,129

10,070 1, 2, 3, 4 KY HARLAN

HARLAN, HIGH SPLINT, 

IMBODE, LOW SPLINT, 

WINIFREDE TRAIN 1.03 10.71 13,534

10,107 1, 2, 3, 4 KY HARLAN

HARLAN, HIGH SPLINT, 

IMBODE, LOW SPLINT, 

WINIFREDE TRAIN 1.01 9.61 13,694

10,073 1, 2, 3, 4 KY HARLAN

HARLAN, HIGH SPLINT, 

IMBODE, LOW SPLINT, 

WINIFREDE TRAIN 1 9.78 13,599

Page 36 of 67 part II, 2 (coal)
GEORGIA POWER - PLANT BRANCH

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

10,442 1, 2, 3, 4 KY HARLAN

HARLAN, HIGH SPLINT, 

IMBODE, LOW SPLINT, 

WINIFREDE TRAIN 1.04 9.87 13,607

10,342 1, 2, 3, 4 KY HARLAN

HARLAN, HIGH SPLINT, 

IMBODE, LOW SPLINT, 

WINIFREDE TRAIN 1.04 9.5 13,731

10,717 1, 2, 3, 4 KY HARLAN

HARLAN, HIGH SPLINT, 

IMBODE, LOW SPLINT, 

WINIFREDE TRAIN 1.02 9.91 13,552

9,910 1, 2, 3, 4 KY HARLAN

HARLAN, HIGH SPLINT, 

IMBODE, LOW SPLINT, 

WINIFREDE TRAIN 0.97 9.33 13,760

10,295 1, 2, 3, 4 KY HARLAN

HARLAN, HIGH SPLINT, 

IMBODE, LOW SPLINT, 

WINIFREDE TRAIN 1.06 9.68 13,741

10,358 1, 2, 3, 4 KY HARLAN

HARLAN, HIGH SPLINT, 

IMBODE, LOW SPLINT, 

WINIFREDE TRAIN 0.96 10.47 13,549

9,795 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.69 10.42 13,473

9,820 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.69 10.32 13,495

10,599 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.68 13.07 13,045

9,994 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.14 9.23 13,617

9,760 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.15 9.22 13,610

9,704 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.37 9.45 13,569

Page 37 of 67 part II, 2 (coal)
GEORGIA POWER - PLANT BRANCH

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

9,888 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.32 8.2 13,770

10,042 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.2 8.96 13,669

10,008 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.36 8.29 13,717

10,079 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.71 9 13,587

10,577 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.68 8.67 13,621

10,537 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.38 9.89 13,601

10,089 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.72 11.37 13,330

10,173 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1 11 13,376

10,288 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.73 10.06 13,562

10,130 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.72 9.84 13,612

10,360 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.75 11.64 13,285

10,407 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.77 10.94 13,417

10,151 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.72 12.19 13,162

10,411 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.97 10.78 13,409

10,357 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.76 11.67 13,245

10,308 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.81 11.61 13,496

10,512 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.81 10.61 13,439

10,289 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.75 10.5 13,493

10,466 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.94 11.02 13,384

10,472 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.94 11.94 13,246

10,576 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.04 9.51 13,650

10,446 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.87 9.17 13,667

Page 38 of 67 part II, 2 (coal)
GEORGIA POWER - PLANT BRANCH

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

10,568 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.86 10.82 13,368

10,327 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.87 10.81 13,402

9,969 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.83 10.29 13,500

10,673 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.07 9.21 13,665

10,675 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.89 10.88 13,412

10,658 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.04 9.89 13,523

10,741 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.03 9.44 13,643

10,502 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.04 10.83 13,423

10,610 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.79 9.24 13,676

10,645 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.82 10.13 13,485

10,560 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1 10.32 13,449

10,439 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.1 9.57 13,619

10,614 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.17 9.82 13,593

10,604 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.83 11.33 13,303

10,771 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.1 9.75 13,575

10,464 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.9 10.26 13,388

10,698 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.91 10.09 13,498

10,410 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.86 11.23 13,259

10,367 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.9 10.35 13,465

10,606 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.25 10.31 13,515

10,510 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.94 11.07 13,309

10,793 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.84 10.58 13,413

Page 39 of 67 part II, 2 (coal)
GEORGIA POWER - PLANT BRANCH

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

10,425 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.86 10.36 13,460

10,674 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.96 10.57 13,427

10,583 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.86 10.53 13,442

10,438 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.86 11.06 13,378

10,429 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.83 10.29 13,456

10,622 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.09 10.08 13,535

10,624 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.83 10.38 13,475

10,657 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1 9.56 13,542

10,526 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.11 8.36 13,810

10,663 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.04 9.64 13,623

10,613 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1 9.12 13,685

10,429 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 0.83 10.6 13,421

10,423 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.48 8.75 13,650

10,350 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.48 9.11 13,698

10,146 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.52 9.45 13,596

9,945 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.62 9.04 13,653

10,502 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.65 9.37 13,584

10,584 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.42 8.49 13,737

10,844 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.51 8.52 13,799

10,517 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.86 8.39 13,815

10,626 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.28 9.34 13,669

10,667 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.35 8.87 13,751

Page 40 of 67 part II, 2 (coal)
GEORGIA POWER - PLANT BRANCH

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

10,567 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.44 7.82 13,879

10,429 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.46 8.33 13,845

10,264 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.46 8.35 13,769

10,563 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.52 7.81 13,846

10,510 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.38 8.67 13,724

10,549 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.49 8.31 13,769

10,500 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.48 9.52 13,577

10,505 1, 2, 3, 4 KY LESLIE, BELL 4, 5A, 7, 8, COAL CREEK TRAIN 1.44 8.42 13,782

1,021 1, 2, 3, 4 KY MARTIN MULTIPLE TRAIN 1.92 13.37 12,800

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 41 of 67 part II, 2 (coal)
GEORGIA POWER - PLANT BRANCH

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):

State/Country County42 Coal seam43

7,492 1, 2 Georgia/USA N/A N/A Truck

7,491 3, 4 Georgia/USA N/A N/A Truck

7,515 1, 2 Georgia/USA N/A N/A Truck

7,515 3, 4 Georgia/USA N/A N/A Truck

7,553 1, 2 Georgia/USA N/A N/A Truck

7,556 3, 4 Georgia/USA N/A N/A Truck

7,523 3, 4 Georgia/USA N/A N/A Truck

15,017 1, 2 Georgia/USA N/A N/A Truck

15,010 3, 4 Georgia/USA N/A N/A Truck

15,047 3, 4 Georgia/USA N/A N/A Truck

15,010 1, 2 Georgia/USA N/A N/A Truck

7,507 3, 4 Georgia/USA N/A N/A Truck

22,589 1, 2 Georgia/USA N/A N/A Truck

14,981 1, 2 Georgia/USA N/A N/A Truck

14,997 1, 2 Georgia/USA N/A N/A Truck

7,498 3, 4 Georgia/USA N/A N/A Truck

7,488 1, 2 Georgia/USA N/A N/A Truck

7,485 3, 4 Georgia/USA N/A N/A Truck

7,503 1, 2 Georgia/USA N/A N/A Truck

22,432 1, 2 Georgia/USA N/A N/A Truck

7,470 3, 4 Georgia/USA N/A N/A Truck

14,914 1, 2 Georgia/USA N/A N/A Truck

14,929 3, 4 Georgia/USA N/A N/A Truck

29,890 1, 2 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 42 of 67 part II, 2 (oil)
GEORGIA POWER - PLANT BRANCH

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):

State/Country County42 Coal seam43

FUEL OIL SHIPMENTS

Amount received, 

gallons40

ID # of boiler(s) 

firing fuel41

Fuel source Fuel shipment 

method

7,479 1, 2 Georgia/USA N/A N/A Truck

7,449 3, 4 Georgia/USA N/A N/A Truck

14,904 1, 2 Georgia/USA N/A N/A Truck

14,899 3, 4 Georgia/USA N/A N/A Truck

7,436 1, 2 Georgia/USA N/A N/A Truck

14,882 3, 4 Georgia/USA N/A N/A Truck

14,867 1, 2 Georgia/USA N/A N/A Truck

7,421 3, 4 Georgia/USA N/A N/A Truck

7,424 1, 2 Georgia/USA N/A N/A Truck

14,868 1, 2 Georgia/USA N/A N/A Truck

7,426 3, 4 Georgia/USA N/A N/A Truck

7,455 1, 2 Georgia/USA N/A N/A Truck

7,420 3, 4 Georgia/USA N/A N/A Truck

7,447 1, 2 Georgia/USA N/A N/A Truck

7,416 3, 4 Georgia/USA N/A N/A Truck

14,839 1, 2 Georgia/USA N/A N/A Truck

14,828 1, 2 Georgia/USA N/A N/A Truck

7,433 3, 4 Georgia/USA N/A N/A Truck

14,874 1, 2 Georgia/USA N/A N/A Truck

44,746 3, 4 Georgia/USA N/A N/A Truck

7,485 1, 2 Georgia/USA N/A N/A Truck

14,882 1, 2 Georgia/USA N/A N/A Truck

7,562 3, 4 Georgia/USA N/A N/A Truck

7,544 1, 2 Georgia/USA N/A N/A Truck

Page 43 of 67 part II, 2 (oil)
GEORGIA POWER - PLANT BRANCH

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):

State/Country County42 Coal seam43

FUEL OIL SHIPMENTS

Amount received, 

gallons40

ID # of boiler(s) 

firing fuel41

Fuel source Fuel shipment 

method

7,518 3, 4 Georgia/USA N/A N/A Truck

45,399 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 44 of 67 part II, 2 (oil)
GEORGIA POWER - PLANT BRANCH

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

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

Hazard 8, 

Elkhorn #1, 

Elkhorn #2, 

Elkhorn #3, 

Whitesburg, 

Hazard #4 Train

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

Harlan, 

Leslie

Hazard 4, 

Hazard 4R, 

Hazard 8, 

Hazard 7 Train

09-207 11,309 1.32 13.23 12,872 0.089 588 97 14.3 1.2 9.1 2.3 0.03 21.0 8.1 9.2 15.1 3.8 KY

Perry, 

Breathitt

Hazard #8, 

Hazard #7 Train

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

Perry, 

Letcher

Hazard 4, 

Hazard 4R, 

Hazard 8, 

Hazard 7 Train

09-404 11,324 0.96 10.64 13,265 ND 95 64 12.0 1.2 7.2 2.0 0.05 16.7 7.0 8.4 21.8 2.8 KY Harlan

Highsplint, 

Winifrede, 

Low splint, 

Lower Harlan, 

D seam, 

Kellioki, 

Imbodden, 

Owl Train

09-406 11,090 0.85 11.16 13,267 ND 1278 52 12.8 <1 6.8 2.7 ND 14.7 7.4 6.2 12.5 3.2 KY Perry

Hazard #4, 

Amburgey, 

Hazard #8 Train

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

Garmeda 

Seam, Buckeye 

Springs Seam, 

Stray Seam Train

09-209 11,230 1.51 8.93 13,727 0.081 1619 62 14.9 1.2 11.6 2.7 0.08 11.9 7.8 7.1 20.7 3.4 KY Pike

Elkhorn #3, 

Millard Train

09-222 11,142 0.89 8.72 13,685 ND ND 59 10.3 1.0 3.8 3.1 0.02 11.6 6.1 7.8 17.5 2.3 kY

Perry, 

Letcher

Hazard 4, 

Hazard 4R, 

Hazard 8, 

Hazard 7 Train

Fuel 

Shipment 

Method

Nickel, 

ppm

Other trace metal HAP, ppm45 Total amount of 

fuel represented 

by sample, tons

Coal Seam Sample 

ID #

State/ 

Country

County

Total 

Sulfur, %

Ash 

Content, 

%

Heating 

Value, 

Btu/lb

Mercury, 

ppm

Chlorine, 

ppm

Fluorine, 

ppm

Page 45 of 67 part II, 3
GEORGIA POWER - PLANT BRANCH

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

Fuel 

Shipment 

Method

Nickel, 

ppm

Other trace metal HAP, ppm45 Total amount of 

fuel represented 

by sample, tons

Coal Seam Sample 

ID #

State/ 

Country

County

Total 

Sulfur, %

Ash 

Content, 

%

Heating 

Value, 

Btu/lb

Mercury, 

ppm

Chlorine, 

ppm

Fluorine, 

ppm

09-420 11,327 1.33 12.34 12,926 0.100 637 93 14.5 1.1 10.4 2.6 ND 20.6 8.9 7.6 16.6 3.6 KY Perry

Hazard 5A, 

Hazard#7, 

Hazard #8, 

Hazard #9 Train

09-422 12,662 0.77 10.97 13,368 ND 1373 79 13.0 <1 6.2 2.4 ND 16.2 7.8 6.3 12.4 3.2 KY Perry

Hazard #4, 

Amburgey, 

Hazard #8 Train

09-418 12,392 1.12 11.36 13,390 ND 111 89 13.9 1.3 9.7 2.1 ND 17.3 8.0 8.8 26.4 2.4 KY Harlan

 Highsplint, 

Winifrede, 

Low splint, 

Lower Harlan, 

D seam, 

Kellioki, 

Imbodden, 

Owl Train

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

Garmeda 

Seam, Buckeye 

Springs Seam, 

Stray Seam Train

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

Hazard 8, 

Elkhorn #1, 

Elkhorn #2, 

Elkhorn #3, 

Whitesburg, 

Hazard #4 Train

09-218 11,336 1.44 7.97 13,885 0.077 ND 54 13.4 1.2 11.1 2.5 0.12 11.7 7.0 6.9 20.9 3.4 KY Pike

Elkhorn #3, 

Millard Train

09-224 11,255 0.89 10.78 13,329 ND 1324 71 10.3 1.0 3.8 3.1 0.02 11.6 6.1 7.8 17.5 2.3 KY Perry

Amburgy, 

Hazard 8, 

Hazard 7, 

Hazard 5A Train

09-225 10,998 1.47 8.13 13,831 ND 1669 56 14.2 1.3 11.2 2.2 0.06 12.3 7.7 6.2 20.8 3.4 KY Pike

Elkhorn #3, 

Millard Train

09-423 11,403 1.34 11.99 13,000 0.071 609 87 16.0 <1 11.6 2.9 0.05 21.1 10.7 10.8 18.5 3.7 KY Perry

Hazard 5A, 

Hazard#7, 

Hazard #8, 

Hazard #9 Train

Page 46 of 67 part II, 3
GEORGIA POWER - PLANT BRANCH

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

Fuel 

Shipment 

Method

Nickel, 

ppm

Other trace metal HAP, ppm45 Total amount of 

fuel represented 

by sample, tons

Coal Seam Sample 

ID #

State/ 

Country

County

Total 

Sulfur, %

Ash 

Content, 

%

Heating 

Value, 

Btu/lb

Mercury, 

ppm

Chlorine, 

ppm

Fluorine, 

ppm

09-424 11,170 1.06 10.8 13,433 ND 111 84 18.0 1.0 6.7 2.5 0.07 19.6 10.5 12.0 30.3 2.5 KY Harlan

 Highsplint, 

Winifrede, 

Low splint, 

Lower Harlan, 

D seam, 

Kellioki, 

Imbodden, 

Owl Train

09-432 12,905 1.24 10.22 13,490 ND 1262 66 12.4 <1 9.4 2.4 0.04 15.4 7.0 10.3 23.0 2.4 KY Perry

Hazard #4, 

Alma, Hazard 

#8, Hazard #9, 

Hazard #10 Train

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

Garmeda 

Seam, Buckeye 

Springs Seam, 

Stray Seam Train

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

Hazard 8, 

Elkhorn #1, 

Elkhorn #2, 

Elkhorn #3, 

Whitesburg, 

Hazard #4 Train

09-237 11,038 1.02 10.17 13,539 ND 1333 67 14.1 1.0 7.1 2.8 ND 16.7 9.3 7.5 13.6 3.3 KY Perry

Amburgy, 

Hazard 8, 

Hazard 7, 

Hazard 5A Train

09-441 11,536 1.58 11.78 13,077 0.092 697 74 14.1 <1 8.4 2.3 0.03 20.1 7.1 8.3 10.8 4.0 KY Perry

Hazard 5A, 

Hazard#7, 

Hazard #8, 

Hazard #9 Train

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

Perry, 

Letcher

Hazard 4, 

Hazard 5A, 

Alma Train

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

Hazard #4, 

Hazard #4 

rider, Hazard 

#7, Hazard #8, 

Hazard #9 Train

Page 47 of 67 part II, 3
GEORGIA POWER - PLANT BRANCH

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

Fuel 

Shipment 

Method

Nickel, 

ppm

Other trace metal HAP, ppm45 Total amount of 

fuel represented 

by sample, tons

Coal Seam Sample 

ID #

State/ 

Country

County

Total 

Sulfur, %

Ash 

Content, 

%

Heating 

Value, 

Btu/lb

Mercury, 

ppm

Chlorine, 

ppm

Fluorine, 

ppm

09-443 12,664 0.9 10.3 13,598 ND 105 60 12.4 1.0 4.7 2.1 0.03 16.7 7.9 9.1 23.4 2.8 KY Harlan

 Highsplint, 

Winifrede, 

Low splint, 

Lower Harlan, 

D seam, 

Kellioki, 

Imbodden, 

Owl Train

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

Garmeda 

Seam, Buckeye 

Springs Seam, 

Stray Seam Train

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.

Page 48 of 67 part II, 3
GEORGIA POWER - PLANT BRANCH

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

__X__ permit requirements (for coal)

____ contractual obligations

____ standard operational procedures

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

5 Analyses provided in Part II, question 3 above, supplied by

____ Fuel supplier (name and address)

__X__ Other (name and address)

Georgia Power Environmental Lab

5131 Maner Road, Smyrna GA 30080

6 Name and address of laboratory performing analyses:

Georgia Power Environmental Lab (same as above)

Page 49 of 67 part II, 4-6
GEORGIA POWER - PLANT BRANCH

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 P2O5 K2O SiO2 Na2O SO3 TiO2

09-201 6.97 34.57 13.67 51.75 74.26 4.65 1.37 1.24 4.8 225 21.2 0.118 0.037 32.9 17.1 25.8 10 1.89 1.32 ND 3.11 50.2 0.389 1.47 1.47

09-206 6.27 36.41 12.5 51.09 74.39 4.94 1.59 1.58 5 132 25.4 0.083 0.041 42.5 32.7 24.7 12.4 1.66 1.04 ND 2.35 48.4 0.494 0.938 1.36

09-207 5.78 35.9 13.23 50.88 72.61 4.76 1.45 1.32 6.64 163 20.4 0.063 0.016 37.5 13.1 28.9 7.92 1.14 0.75 ND 2.13 52.5 0.214 0.524 1.4

09-208 6.52 36.53 10.53 52.94 76.33 4.92 1.65 1.01 5.56 112 19.3 0.073 0.032 28.2 19.2 26.3 8.31 1.78 1.13 ND 2.61 52.8 0.512 1.32 1.34

09-404 6.37 34.25 10.64 55.11 77.44 4.83 1.51 0.96 4.6 122 20.9 0.071 0.034 33.5 15.7 27.4 7.05 1.59 0.955 ND 2.68 53.7 0.422 0.878 1.43

09-406 4.82 34.97 11.16 53.88 76.49 4.79 1.56 0.85 5.15 112 17.4 0.055 0.028 26.1 9.6 26.3 5.4 1.25 0.785 ND 2.23 56 0.37 0.633 1.45

09-407 6.02 36.85 9.83 53.32 75.27 4.88 1.77 1.82 6.43 102 20.6 0.069 0.016 46.6 20.6 24.6 16.7 3.07 0.895 1.68 ND 44.6 0.203 0.636 1.34

09-209 6.45 37.34 8.93 53.73 76.98 5.08 1.24 1.51 6.26 143 23.5 0.057 0.030 33.3 17.1 25.3 14.4 2.6 1.09 ND 2.32 43.8 0.545 2.03 1.31

09-222 6.43 36.45 8.72 54.83 74.25 4.95 1.82 0.89 9.37 92 17.0 0.045 0.035 26.1 14.9 27.2 6.94 1.34 0.819 ND 1.93 49.7 0.564 0.835 1.37

09-420 7.31 36.44 12.34 51.22 69.95 4.65 1.47 1.33 10.26 154 18.1 0.063 0.016 34.5 16.5 25.1 9.16 1.48 0.916 ND 2.08 50.5 0.216 0.803 1.36

09-422 4.89 35.09 10.97 53.94 73.33 4.8 1.57 0.77 8.56 102 15.3 0.056 0.024 26.1 9.5 27.4 5.1 1.23 0.903 ND 2.11 54 0.391 0.639 1.52

09-418 5.99 34.06 11.36 54.58 75.53 4.88 1.48 1.12 5.63 102 20.7 0.075 0.037 35.9 16.4 26.4 8.43 1.58 1.02 ND 2.53 49.3 0.532 1.15 1.52

09-419 6.23 36.36 9.59 54.05 74.33 4.91 1.81 1.33 8.04 82 20.6 0.069 0.015 43.3 26.4 25.7 13.9 2.52 1.18 1.26 2.39 45.3 0.29 0.809 1.37

09-214 5.92 34.69 12.9 52.41 74.42 4.82 1.42 1.41 5.02 174 19.9 0.096 0.031 30.2 13.4 23 10.9 1.59 1.19 ND 2.76 48.6 0.354 1.28 1.21

09-218 6.69 36.94 7.97 55.1 77.68 5.02 1.53 1.44 6.36 112 23.8 0.053 0.030 30.7 14.4 26.2 12.7 2.48 1.04 ND 2.47 47.5 0.559 2.06 1.14

09-224 5.12 35.23 10.78 53.99 74.91 4.9 1.74 0.89 6.77 92 17.0 0.045 0.035 26.1 14.9 28.3 6.71 1.62 0.962 ND 2.09 61.7 0.49 1.13 1.42

09-225 5.15 37.79 8.13 54.09 77.75 5.12 1.77 1.47 5.76 122 22.8 0.054 0.031 31.1 16.2 24.8 15.1 2.84 1.07 ND 2.24 49 0.585 2.34 1.13

09-423 6.5 35.5 11.99 52.51 72.73 4.6 1.55 1.34 7.78 143 24.2 0.055 0.014 38.3 15.3 29.7 7.94 1.24 0.773 ND 1.99 55.4 0.211 0.884 1.53

09-424 6.46 34.53 10.8 54.66 75.06 4.72 1.6 1.06 6.76 81 27.0 0.062 0.030 40.6 17.6 28.3 5.86 1.56 0.979 ND 2.37 54 0.453 1.28 1.54

09-432 6.09 35 10.22 54.78 75.13 4.76 1.61 1.24 7.05 92 19.9 0.052 0.036 30.3 17.3 24.4 8.4 1.27 0.791 ND 1.98 52.8 0.469 0.888 1.47

09-435 4.86 35.82 8.52 55.65 76.05 4.94 1.87 1.38 7.23 193 18.6 0.058 0.016 37.1 16.9 26 13.8 2.7 1.03 1.35 2.15 44.5 0.314 1.28 1.28

09-235 5.48 34.35 13.43 52.22 71.09 4.56 1.5 1.22 8.2 194 18.8 0.114 0.040 28.5 19.2 26.2 9.29 1.57 1.42 ND 3.54 50.7 0.464 1.46 1.28

09-237 5.52 34.93 10.17 54.89 74.91 4.79 1.59 1.02 7.52 81 18.4 0.053 0.024 30.3 19.6 30.7 4.89 1.22 0.825 ND 1.77 54.7 0.347 0.911 1.4

09-441 7.66 36.36 11.78 51.85 72.24 4.72 1.44 1.58 8.25 103 17.2 0.054 0.012 32.6 12.2 30.1 9.25 1 0.763 ND 1.97 53.7 0.229 0.528 1.63

09-240 7.39 35.3 9.46 55.23 75.99 4.79 1.72 1.01 7.04 92 16.2 0.051 0.032 26.4 15.8 25.5 7.8 1.54 0.916 ND 2.23 54.7 0.532 0.795 1.51

09-442 6.98 36.33 9.79 53.88 75.62 4.89 1.71 1.44 6.55 92 22.8 0.052 0.035 36.1 30.4 24.5 10.5 1.73 0.902 ND 2.2 57.8 0.553 0.979 1.53

09-443 6.03 34.1 10.3 55.59 76.39 4.73 1.53 0.9 6.14 81 19.5 0.064 0.033 32.1 14.7 25.8 6 1.92 0.922 ND 2.28 55.1 0.463 1.3 1.54

09-445 4.07 36.77 8.45 54.77 76.74 4.91 1.83 1.53 6.55 193 18.2 0.058 0.016 39.9 16.8 24.5 14.5 3.11 1.02 1.45 2.08 46.9 0.308 0.971 1.35

Sample 

ID #

Proximate Analyses, % by wt Ultimate Analyses, % by wt Other Trace Metals, ppm, dry basis Ash Mineralogy, % by wt

Page 50 of 67 part II, 7
GEORGIA POWER - PLANT BRANCH

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

8a What emission test report(s), parametric monitoring data, and other data or monitoring are available for the boilers noted in Part I,

question 15, for tests conducted since January 1, 2005. Please consider reports prepared for all testing and monitoring programs, for

all pollutants, including (but not limited to) those required under Title V, compliance with State or local requirements, fulfillment of

contractual obligations, U.S. Department of Energy (DOE) programs, etc. (NOTE: EPA is not requesting copies of the test reports or data

at this time; however we may request actual copies in the future.) Use additional pages as necessary.

Report 1 Unit 1&2 Particulate Emissions Test (June 15, 2005)

Report 2 Unit 3&4 Particulate Emissions Test (May 24, 2006)

Report 3 Unit 1&2 Particulate Emissions Test (May 24, 2007)

Report 4 Unit 3&4 Particulate Emissions Test (May 22, 2008)

Report 5 Unit 1&2 Particulate Emissions Test (June 11, 2009)

Report 6 Unit 1 Boiler Optimization (September 10, 2007 to November 1, 2007)

Report 7 Unit 2 Boiler Optimization (February 27, 2008)

Report 8 Unit 3 Boiler Optimization (November 13, 2007)

Report 9 Unit 4 Boiler Optimization (May 7, 2008 to May 8, 2008)

8b Please indicate the date(s) and types (e.g., stack, fuel, parametric, etc.) of the test(s) and the constituents (including criteria and hazardous

air pollutants) sampled for:

Report 1 Date: 6/15/2005 Type: stack Constituents: PM

Report 2 Date: 5/24/2006 Type: stack Constituents: PM

Report 3 Date: 5/24/2007 Type: stack Constituents: PM

Report 4 Date: 5/22/2008 Type: stack Constituents: PM

Report 5 Date: 6/11/2009 Type: stack Constituents: PM

Report 6 Date: 9/10/2007 - 11/1/2007 Type: duct Constituents: CO

Report 7 Date: 2/27/2008 Type: duct Constituents: CO

Report 8 Date: 11/13/2007 Type: duct Constituents: CO

Report 9 Date: 5/7/2008-5/8/2008 Type: duct Constituents: CO

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).

Reports 6, 7, 8, 9 reflect testing at the economizer outlet (upstream of all post-combustion control devices).

Note that there are no control devices downstream designed to reduce CO.

Page 51 of 67 part II, 8
GEORGIA POWER - PLANT BRANCH

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

8d Were any of these test reports conducted when use of other material(s) or non-fossil fuels were fired in the boiler?

Yes ____ No _X___ If yes, please not which reports and identify the other material(s) or non-fossil fuels used.

8e Do any of these test reports reflect testing during periods of startup, shutdown, and malfunction?

Yes ____ No _X___ If yes, please note which reports.

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

Yes _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.

Boiler ID Type NOx control SO2 control PM control Other control

1 cell burner (1) low NOx burner (4) cold-side 

electrostatic 

precipitator

2 dry bottom 

wall-fired

(1) low NOx burner (4) cold-side 

electrostatic 

precipitator

3 cell burner (1) low NOx burner (3) cold-side 

electrostatic 

precipitator

4 cell burner (1) low NOx burner (3) cold-side 

electrostatic 

precipitator 

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

Yes ____ No _X___ If yes, please note which reports and, in addition to the detailed description of the location of the sampling point(s)

(question 8c above), include detail about how much, if any, bypass of unscrubbed flue gas was utilized at at the time of testing (including

percentage of total scrubber flue gas flow). Note by diagram where sampling ports were located in relation to the bypass ductwork.

Page 52 of 67 part II, 8
GEORGIA POWER - PLANT BRANCH

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

Specified deviations are reported quarterly. Emissions exceeding a standard for 

a period of 4 hours or more are reported within 7 days. 

Other deviations are reported semiannually.

Note: Not all reported deviations are considered violations of permit requirements

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

Yes _X__ No ____ If yes, please note which reports.

Deviation reports including periods of malfuncation are available where required in quarterly monitor 

breakdown reports and excess emissions, exdeedances, and excursion reports.

Note: A malfunction is not necessarily a period of noncompliance with permit terms and conditions. 

Not all reported deviations are considered violations of permit requirements

11 Are continuous emissions monitoring system (CEMS) data available (e.g., mercury, continuous opacity monitoring systems) that are not

already being provided to the U.S. EPA, even if from short-term testing?

Yes _X__ No ____ If yes46, please note for which pollutants CEMS data are available and the period of time (both total period and calendar

period) for which the data are available. If CEM data are being provided to EPA, please note to which Office the data are being provided.

Mercury CEMS data are available for the following periods of time:

Unit 3&4 (common stack/liner): 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 53 of 67 part II, 9-11
GEORGIA POWER - PLANT BRANCH

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)

1&2 6/15/2005 See Attachment 1 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

3&4 5/24/2006 See Attachment 2 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

1&2 5/24/2007 See Attachment 3 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

3&4 5/22/2008 See Attachment 4 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

1&2 6/11/2009 See Attachment 5 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

1 9/10/2007 - 11/1/2007 Not applicable Not applicable Not applicable Not applicable Not applicable See Attachment 6 Not applicable

2 2/27/2008 Not applicable Not applicable Not applicable Not applicable Not applicable See Attachment 7 Not applicable

3 11/13/2007 Not applicable Not applicable Not applicable Not applicable Not applicable See Attachment 8 Not applicable

4 5/7/2008-5/8/2008 Not applicable Not applicable Not applicable Not applicable Not applicable See Attachment 9 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).

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.

Boiler 

ID

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

Page 54 of 67 part II, 12
ATTACHMENT 1 - Branch Report 1 Test Results

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

Run 1 Run 2 Run 3

Test Date 6/15/2005 6/15/2005 6/15/2005

Run Start Time 8:30 10:11 11:55

Run End Time 9:45 11:30 13:12

Meter Volume (dacf), Vm: 36.279 36.556 36.252

Sqrt Delta P ("wc): 1.25 1.25 1.25

Sampling Time (min): 60 60 60

Barometric Pressure ("Hg), Pbar: 29.65 29.65 29.65

Delta H ("wc): 1.0 1.0 1.0

Volume in Impingers (mls), VIc: 64.1 64.5 64.8

Static Pressure ("wc), Pg: -3.10 -3.20 -3.00

Stack Pressure ("Hg), Ps: 29.42 29.41 29.43

Stack Temperature (F), Ts: 289 290 295

Meter Coefficient (no units), Y: 0.983 0.983 0.983

Pitot Coefficient (no units) Cp: 0.840 0.840 0.840

Meter OutletTemperature (F), Tm: 94 99 101

Stack Diameter (inches): 270 270 270

Area Stack (sq. ft.), As: 397.61 397.61 397.61

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): 12.0 12.1 12.2

Percent O2 (% dry volume): 6.8 6.6 6.8

Percent (N2 + CO) (% dry volume): 81.2 81.3 81.0

Particulate Collected (mg), Mn: 24.5 20.6 21.4

Molec. Wt. Dry (lb/lb-mole), Md: 30.192 30.200 30.220

Volume Water (scf), Vwstd 3.017 3.036 3.050

Meter Volume (dscf), Vmstd: 33.728 33.719 33.313

Wet Fraction (v/v), Bws: 0.082 0.083 0.084

Molec. Wt. Wet (lb/lb-mole), Ms: 29.191 29.192 29.195

Stack Gas Sampled (acf), Vma: 52.990 53.118 52.845 Averages

Stack Gas Velocity (fps), Vs: 84.07 83.97 84.42 84.15

Volumetric Flowrate (dscfm), Qs: 1,276,562 1,271,619 1,269,619 1,272,600

Volumetric Flowrate (acfm), Qa: 2,005,593 2,003,178 2,014,051 2,007,607

Grainloading (gr/dscf), cs: 0.0112 0.0094 0.0099 0.01

Emission Rate (lb/hour), E: 122.89 102.75 107.67 111.10

Percent Isokinetic Sampling (%), I: 103.70 104.08 102.98 103.59

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780

Heat Input (mmBtu/hour): 5283.57 5337.76 5254.83 5292.05

Particulate Emission Results Summary

Plant Branch, Units 1&2

Page 55 of 67 Att. 1
ATTACHMENT 1 - Branch Report 1 Test Results

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

Run 1 Run 2 Run 3

Particulate Emission Results Summary

Plant Branch, Units 1&2

Emission Rate (lbs/mmBtu), E: 0.02 0.02 0.02 0.02

Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.240

Average Unit 1 Gross Load (MW) 266 266 267 266

Average Unit 2 Gross Load (MW) 332 332 332 332

Average Sum Gross Load (MW) 598 598 598 598

Page 56 of 67 Att. 1
ATTACHMENT 2 - Branch Report 2 Test Results

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

Run 1 Run 2 Run 3

Test Date 5/24/2006 5/24/2006 5/24/2006

Run Start Time 10:30 11:55 13:20

Run End Time 11:38 13:03 14:28

Meter Volume (dacf), Vm: 37.849 39.055 40.088

Sqrt Delta P ("wc): 1.35 1.36 1.37

Sampling Time (min): 60 60 60

Barometric Pressure ("Hg), Pbar: 29.45 29.42 29.42

Delta H ("wc): 1.2 1.2 1.2

Volume in Impingers (mls), VIc: 48.5 50.1 50.2

Static Pressure ("wc), Pg: -3.00 -3.10 -3.00

Stack Pressure ("Hg), Ps: 29.23 29.19 29.20

Stack Temperature (F), Ts: 274 276 277

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: 97 102 104

Stack Diameter (inches): 348 348 348

Area Stack (sq. ft.), As: 660.52 660.52 660.52

Nozzle Diameter (inches), dp: 0.178 0.178 0.178

Area Nozzle (sq. ft.), An: 0.000172 0.000172 0.000172

Percent CO2 (% dry volume): 11.9 11.9 12.0

Percent O2 (% dry volume): 7.3 7.4 7.4

Percent (N2 + CO) (% dry volume): 80.9 80.7 80.7

Particulate Collected (mg), Mn: 98.7 82.1 82.3

Molec. Wt. Dry (lb/lb-mole), Md: 30.189 30.204 30.209

Volume Water (scf), Vwstd 2.283 2.358 2.363

Meter Volume (dscf), Vmstd: 34.993 35.768 36.572

Wet Fraction (v/v), Bws: 0.061 0.062 0.061

Molec. Wt. Wet (lb/lb-mole), Ms: 29.443 29.449 29.468

Stack Gas Sampled (acf), Vma: 53.008 54.464 55.707 Averages

Stack Gas Velocity (fps), Vs: 89.50 90.14 91.00 90

Volumetric Flowrate (dscfm), Qs: 2,341,684 2,346,079 2,367,751 2,351,838

Volumetric Flowrate (acfm), Qa: 3,547,176 3,572,427 3,606,574 3,575,392

Grainloading (gr/dscf), cs: 0.0435 0.0354 0.0347 0.04

Emission Rate (lb/hour), E: 873.89 712.31 704.45 763.5

Percent Isokinetic Sampling (%), I: 95.53 97.46 98.74 97.24

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780

Heat Input (mmBtu/hour): 9371.23 9319.95 9406.04 9365.74

Particulate Emission Results Summary

Plant Branch, Units 3&4

Page 57 of 67 Att. 2
ATTACHMENT 2 - Branch Report 2 Test Results

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

Run 1 Run 2 Run 3

Particulate Emission Results Summary

Plant Branch, Units 3&4

Emission Rate (lbs/mmBtu), E: 0.09 0.08 0.07 0.08

Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.240

Average Unit 3 Gross Load (MW) 517 517 516 517

Average Unit 4 Gross Load (MW) 517 517 516 517

Average Sum Gross Load (MW) 1033 1033 1033 1033

Page 58 of 67 Att. 2
ATTACHMENT 3 - Branch Report 3 Test Results

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

Run 1 Run 2 Run 3

Test Date 5/24/2007 5/24/2007 5/24/2007

Run Start Time 8:20 9:50 11:10

Run End Time 9:35 11:00 12:15

Meter Volume (dacf), Vm: 34.053 35.565 35.903

Sqrt Delta P ("wc): 1.26 1.27 1.28

Sampling Time (min): 60 60 60

Barometric Pressure ("Hg), Pbar: 29.70 29.70 29.70

Delta H ("wc): 1.0 1.0 1.0

Volume in Impingers (mls), VIc: 51.2 52.8 54.3

Static Pressure ("wc), Pg: -2.90 -3.00 -2.90

Stack Pressure ("Hg), Ps: 29.49 29.48 29.49

Stack Temperature (F), Ts: 271 275 277

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: 86 92 95

Stack Diameter (inches): 270 270 270

Area Stack (sq. ft.), As: 397.61 397.61 397.61

Nozzle Diameter (inches), dp: 0.178 0.178 0.178

Area Nozzle (sq. ft.), An: 0.000172 0.000172 0.000172

Percent CO2 (% dry volume): 12.6 12.5 12.6

Percent O2 (% dry volume): 6.4 6.6 6.5

Percent (N2 + CO) (% dry volume): 80.9 80.9 80.9

Particulate Collected (mg), Mn: 28.5 27.8 28.0

Molec. Wt. Dry (lb/lb-mole), Md: 30.279 30.259 30.276

Volume Water (scf), Vwstd 2.410 2.485 2.556

Meter Volume (dscf), Vmstd: 32.325 33.427 33.530

Wet Fraction (v/v), Bws: 0.069 0.069 0.071

Molec. Wt. Wet (lb/lb-mole), Ms: 29.427 29.410 29.407

Stack Gas Sampled (acf), Vma: 48.773 50.756 51.122 Averages

Stack Gas Velocity (fps), Vs: 83.29 84.24 84.57 84.15

Volumetric Flowrate (dscfm), Qs: 1,316,837 1,323,527 1,323,208 1,272,600

Volumetric Flowrate (acfm), Qa: 1,986,921 2,009,659 2,017,429 2,007,607

Grainloading (gr/dscf), cs: 0.0136 0.0128 0.0129 0.01

Emission Rate (lb/hour), E: 153.46 145.75 146.23 111.10

Percent Isokinetic Sampling (%), I: 94.46 97.19 97.51 103.59

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780

Heat Input (mmBtu/hour): 5591.99 5555.65 5593.15 5292.05

Particulate Emission Results Summary

Plant Branch, Units 1&2

Page 59 of 67 Att. 3
ATTACHMENT 3 - Branch Report 3 Test Results

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

Run 1 Run 2 Run 3

Particulate Emission Results Summary

Plant Branch, Units 1&2

Emission Rate (lbs/mmBtu), E: 0.03 0.03 0.03 0.03

Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.240

Average Unit 1 Gross Load (MW) 267 267 267 267

Average Unit 2 Gross Load (MW) 331 331 331 331

Average Sum Gross Load (MW) 598 598 598 598

Page 60 of 67 Att. 3
ATTACHMENT 4 - Branch Report 4 Test Results

Performed by: TRC Environmental Corporation, Raleigh, North Carolina

RUN NUMBER U3/4-M17-1 U3/4-M17-2 U3/4-M17-3

RUN DATE 5/22/2008 5/22/2008 5/22/2008 AVERAGE

RUN TIME 0720-0829 0852-1002 1021-1128

MEASURED DATA

Static Pressure, inches H2O -2.60 -2.80 -2.80 -2.73

Average Stack Temp, deg F 271 276 279 276

Carbon Dioxide, % 12.2 12.3 12.0 12.2

Oxygen, % 6.9 6.8 7.2 7.0

Nitrogen, % 80.9 80.9 80.8 80.9

Sample Time, min 60.0 60.0 60.0 60.0

CALCULATED DATA

Stack Pressure, inches Hg 28.84 28.82 28.82 28.83

Moisture (gravimetrically), % 6.7 6.4 6.9 6.7

Velocity, ft/s 91.5 91.7 92.6 92.0

Stack Area, ft2

660.52 660.52 660.52 660.52

Volumetric flow, acfm 3,625,006 3,635,821 3,671,760 3,644,196

Volumetric flow, dscfm 2,351,215 2,349,409 2,352,507 2,351,043

Isokinetic Rate, % 95.9 96.6 98.1 96.9

F-factor, DSCF/MMBtu 9780.0 9780.0 9780.0 9780.0

FILTERABLE PARTICULATE EMISSIONS DATA

Filterable Catch, g 0.0469 0.0402 0.0468 0.0446

Probe wash Catch, g 0.0015 0.0020 0.0021 0.0019

Total Filterable Particulate Catch, g 0.0484 0.0422 0.0489 0.0465

Concen., mg/dscm 36.4 31.5 36.0 34.6

Concen., mg/actual m3

23.6 20.4 23.0 22.4

Concen., gr/dscf 0.01591 0.01378 0.01571 0.01514

Concen., gr/dscf@8% Oxygen 0.0147 0.0126 0.0148 0.0140

Emission Rate, lb/hr 320.713 277.599 316.849 305.054

Emission Rate, lb/MMBtu 0.0332 0.0285 0.0335 0.0317

Unit 3 Gross Load, MW 511 511 511 511

Unit 4 Gross Load, MW 517 517 517 517

Sum Gross Load, MW 1028 1028 1028 1028

FILTERABLE PARTICULATE TEST RESULTS SUMMARY

PLANT Branch

UNIT 3/4 STACK

Page 61 of 67 Att. 4
ATTACHMENT 5 - Branch Report 5 Test Results

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

Run 1 Run 2 Run 3

Test Date 6/11/2009 6/11/2009 6/11/2009

Run Start Time 11:10 12:40 14:05

Run End Time 12:25 13:50 15:20

Meter Volume (dacf), Vm: 48.881 48.975 48.969

Sqrt Delta P ("wc): 1.20 1.21 1.20

Sampling Time (min): 60 60 60

Barometric Pressure ("Hg), Pbar: 29.30 29.30 29.30

Delta H ("wc): 1.9 1.9 1.9

Volume in Impingers (mls), VIc: 74.5 74.3 71.3

Static Pressure ("wc), Pg: -2.50 -2.40 -2.40

Stack Pressure ("Hg), Ps: 29.12 29.12 29.12

Stack Temperature (F), Ts: 281 284 284

Meter Coefficient (no units), Y: 0.966 0.966 0.966

Pitot Coefficient (no units) Cp: 0.840 0.840 0.840

Meter OutletTemperature (F), Tm: 92 96 97

Stack Diameter (inches): 270 270 270

Area Stack (sq. ft.), As: 397.61 397.61 397.61

Nozzle Diameter (inches), dp: 0.210 0.210 0.210

Area Nozzle (sq. ft.), An: 0.000241 0.000241 0.000241

Percent CO2 (% dry volume): 11.0 11.1 11.2

Percent O2 (% dry volume): 7.5 7.6 7.5

Percent (N2 + CO) (% dry volume): 81.5 81.3 81.3

Particulate Collected (mg), Mn: 34.4 36.6 40.5

Molec. Wt. Dry (lb/lb-mole), Md: 30.065 30.085 30.093

Volume Water (scf), Vwstd 3.507 3.497 3.356

Meter Volume (dscf), Vmstd: 44.404 44.218 44.127

Wet Fraction (v/v), Bws: 0.073 0.073 0.071

Molec. Wt. Wet (lb/lb-mole), Ms: 29.182 29.200 29.239

Stack Gas Sampled (acf), Vma: 69.094 69.035 68.761 Averages

Stack Gas Velocity (fps), Vs: 80.43 81.04 80.53 81

Volumetric Flowrate (dscfm), Qs: 1,233,185 1,238,317 1,232,910 1,234,804

Volumetric Flowrate (acfm), Qa: 1,918,892 1,933,321 1,921,181 1,924,464

Grainloading (gr/dscf), cs: 0.0119 0.0128 0.0142 0.01

Emission Rate (lb/hour), E: 126.20 135.65 149.60 137.1

Percent Isokinetic Sampling (%), I: 99.27 98.44 98.67 98.79

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780

Heat Input (mmBtu/hour): 4850.64 4834.48 4837.50 4840.87

Particulate Emission Results Summary

Branch Units 1-2

Page 62 of 67 Att. 5
ATTACHMENT 5 - Branch Report 5 Test Results

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

Run 1 Run 2 Run 3

Particulate Emission Results Summary

Branch Units 1-2

Emission Rate (lbs/mmBtu), E: 0.03 0.03 0.03 0.03

Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.240

Average Unit 1 Gross Load (MW) 233 234 233 233

Average Unit 2 Gross Load (MW) 293 293 293 293

Average Sum Gross Load (MW) 526 527 526 526

Page 63 of 67 Att. 5
ATTACHMENT 6 - Branch Report 6 Test Results

Title of 

Run

Description Date

Start 

Time

End 

Time

Test 

Load

Avg. 

Econ. 

Gas 

Outlet 

CO 

Avg. 

Econ. 

Gas 

Outlet 

O2 

Avg. 

Econ. 

Gas 

Outlet 

CO2

Avg. AH 

Gas Inlet 

Temp.

Military Military MW ppm % Dry % Dry Deg F 

Test 1 0 9/10/2007 13:46 14:22 267 27.31 4.73 14.04 613

Test 2 Reduced O2 -0.5% 9/11/2007 7:12 7:48 267 119 4.43 14.49 604

Test 3 

Reduced O2 -0.5% / Biased 

air to Rear Burners 9/11/2007 9:00 9:36 267 111 4.35 14.52 605

Test 4 

Reduced O2 -0.5% / Biased 

air to Rear Burners 9/11/2007 11:57 12:33 267 115 4.32 14.48 606

Test 5 Abnormal Firing Conditions 9/12/2007 14:23 14:59 267 135 4.36 14.26 578

Test 6 Reduced O2 9/13/2007 9:05 9:41 267 490 4.2 14.6 608

Test 7 

Reduced O2 - PA flow Adj. 9/13/2007 11:49 12:25 267 156 4.32 14.44 611

Test 8 Baseline 10/24/2007 13:54 14:30 267 36 4.56 14.28 604

Test 9 Baseline 10/29/2007 12:27 13:03 267 36 4.9 13.95 606

Test 10 B3 B1 C1 Dmp 60% 10/29/2007 14:37 15:13 267 90 4.44 14.26 605

Test 11 Baseline 10/30/2007 6:43 7:19 267 36 4.91 14.09 605

Test 12 Reduced B Mill PA Bias 10/30/2007 6:43 7:19 267 22 4.94 14.03 601

Test 13 Mill at 54 klb/hr 10/31/2007 11:17 11:53 267 114 4.46 14.22 603

Test 14 Bias Removed 11/1/2007 7:48 8:24 267 109 4.77 14.15 602

Test 15 O2 SP 4.28% 11/1/2007 9:47 10:23 267 28 5.33 13.42 605

Test 16 O2 SP 4.28% 11/1/2007 12:21 12:57 267 79.49 4.82 14 606

Test 17 O2 SP 4.28% 11/1/2007 13:39 14:15 267 73.73 4.77 14.02 605

Boiler Optimization Test Results Summary

Branch Unit 1

Page 64 of 67 Att. 6
ATTACHMENT 7 - Branch Report 7 Test Results

Title of Run Description Date Start Time End Time Test Load

Avg. Econ. 

Gas Outlet 

CO 

Avg. Econ. 

Gas Outlet 

O2 

Avg. Econ. 

Gas Outlet 

CO2

Military Military MW ppm % Dry % Dry

Test 01 Baseline 2/27/2008 14:26 15:39 320 49 4.26 14.55

Test 02 Baseline 2/27/2008 11:02 11:47 320 77 4.26 14.61

Test 03 Baseline 2/27/2008 13:00 13:45 320 73 4.3 14.54

Test 04 Baseline 2/27/2008 6:32 7:17 320 62 4.31 14.65

Test 05 Baseline 2/27/2008 9:48 10:33 320 42 4.31 14.7

Test 06 Baseline 2/27/2008 11:53 12:38 320 23 4.44 14.56

Boiler Optimization Test Results Summary

Branch Unit 2

Page 65 of 67 Att. 7
ATTACHMENT 8 - Branch Report 8 Test Results

Title of 

Run

Description Date

Start 

Time End Time Test 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 Baseline 11/13/2007 8:38 9:41 511 29 4.16 14.65 529

Test 2 Confirmation 11/13/2007 11:32 12:25 513 18 4.51 14.22 557

Boiler Optimization Test Results Summary

Branch Unit 3

Page 66 of 67 Att. 8
ATTACHMENT 9 - Branch Report 9 Test Results

Title of 

Run

Description Date Start Time End Time Test 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 Baseline 5/7/2008 7:06 8:10 518 5 4.24 14.63 584

Test 2 Opt - 1 5/7/2008 9:38 10:41 518 10 3.71 15.11 580

Test 3 Opt - 2 5/7/2008 12:39 13:42 518 10 3.77 15.04 580

Test 4 Opt - 2 5/8/2008 12:50 13:53 518 8 4.08 14.47 581

Boiler Optimization Test Results Summary

Branch Unit 4

Page 67 of 67 Att. 9