GEORGIA POWER - Submittal for PLANT HAMMOND

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):

Hammond

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):

708

5 Complete street address of facility (physical location):

5963 Alabama Highway,SW

Rome, Georgia 30165

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 61 part I, 1-14
GEORGIA POWER - Submittal for PLANT HAMMOND

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

April 5, 2010

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

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

_X__ 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 61 part I, 1-14
GEORGIA POWER - Submittal for PLANT HAMMOND

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

April 5, 2010

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

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

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

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

Other Material

Sawdust

Biomass

Synfuel Yes

Permitted to burn

Yes

Yes

Used Oil Yes

Quantity/year

None in 2009

None in 2009

200 tons/year in 2009

None in 2009

Actually burn

None in 2009

None in 2009

Yes

None in 2009

Page 3 of 61 part I, 1-14
GEORGIA POWER - PLANT HAMMOND

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 115 107 88.6 87.65 1800 1802 1000 998 1000 1000 bituminous coal (100%), biomass 

(<1%), distillate oil (100%)

CBI CBI Not 

applicable

None 

planned

2 bituminous CBI CBI 115 107 88.6 88.28 1800 1800 1000 1000 1000 1000 bituminous coal (100%), distillate 

oil (100%)

CBI CBI Not 

applicable

None 

planned

3 bituminous CBI CBI 115 107 88.6 87.65 1800 1806 1000 1000 1000 1000 bituminous coal (100%), distillate 

oil (100%)

CBI CBI Not 

applicable

None 

planned

4 bituminous CBI CBI 520 485 89.01 88.71 2400 2403 1000 1000 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 61 part I, 15
GEORGIA POWER - PLANT HAMMOND

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 Hammond 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 61 part I, 15
GEORGIA POWER - PLANT HAMMOND

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.

SCR catalyst: When making catalyst decisions, the primary goal is to achieve the desired NOx performance, with a secondary goal of 

minimizing SO3 formation.

Boiler ID14 Type15 NOx control16 SO2 control17 PM control18 Other control19

1 dry bottom wallfired(1) low NOX burner (12/2002) (5) wet flue gas 

desulfurization (FGD) - 1 

vessel for all four units 

(5/2008), calcium-based.

(3) cold-side electrostatic 

precipitator (ESP) (2/1971)

(2) flue gas conditioning - SO3 

injection (10/1993)

(4) hydrated lime injection - 1 

system for all four units (SO3 

control, 11/2009)

2 dry bottom wallfired(1) low NOX burner (12/2001) (5) wet flue gas 

desulfurization (FGD) - 1 

vessel for all four units 

(5/2008), calcium-based.

(3) cold-side electrostatic 

precipitator (ESP) (4/1969)

(2) flue gas conditioning - SO3 

injection (10/1993)

(4) hydrated lime injection - 1 

system for all four units (SO3 

control, 11/2009)

3 dry bottom wallfired(1) low NOX burner (11/2002) (5) wet flue gas 

desulfurization (FGD) - 1 

vessel for all four units 

(5/2008), calcium-based.

(3) cold-side electrostatic 

precipitator (ESP) (12/1968)

(2) flue gas conditioning - SO3 

injection (10/1993)

(4) hydrated lime injection - 1 

system for all four units (SO3 

control, 11/2009)

4 dry bottom wallfired(1) low NOX burner + overfire 

air (1991)

(2) SCR (5/2002), using titaniavanadia catalyst and 

anhydrous ammonia 

reductant; the catalyst is 

designed to reduce SO3 

formation (SEE NOTES).

(7) wet flue gas 

desulfurization (FGD) - 1 

vessel for all four units 

(5/2008), calcium-based.

(5) cold-side electrostatic 

precipitator (ESP) (12/1970, 

original install)

(3) flue gas conditioning - SO3 

injection (1990)

(6) hydrated lime injection - 1 

system for all four units (SO3 

control, 11/2009)

(4) flue gas conditioning - 

ammonia (SO3 control, 2005)

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)

Page 6 of 61 part I, 16
GEORGIA POWER - PLANT HAMMOND

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.

SCR catalyst: When making catalyst decisions, the primary goal is to achieve the desired NOx performance, with a secondary goal of 

minimizing SO3 formation.

Boiler ID14 Type15 NOx control16 SO2 control17 PM control18 Other control19

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 61 part I, 16
GEORGIA POWER - PLANT HAMMOND

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 61 part I, 17
GEORGIA POWER - PLANT HAMMOND

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 61 part I, 18
GEORGIA POWER - PLANT HAMMOND

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 61 part I, 19
GEORGIA POWER - PLANT HAMMOND

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 61 part I, 20
GEORGIA POWER - PLANT HAMMOND

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 one 

year if test results from the previous annual 

tests are fifty percent or less of the limit on 

scrubber stack; once every 5 years or operating 

8760 hours, whichever first, on bypass stack)

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, 2012 (State 

rule, Title V permit revision not complete; based 

on 30-day rolling average, monitored by CEMS 

at inlet to scrubber and at scrubber stack during 

scrubber operations, excluding startup, 

shutdown, malfunction, and other exemptions)

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

NOx: [0.42 * (Heat Input of Units 1-3) + 0.07 

*(Heat Input of Unit 4)]/[Heat Input of Units 1-3 

+ Heat Input of Unit 4] lb/MMBtu from May 1 

through September 30 OR compliance with 5 

and 7-plant Nox averages of 0.13 lb/MMBtu and 

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

rolling averages determined by CEMS)

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 one 

year if test results from the previous annual 

tests are fifty percent or less of the limit on 

scrubber stack; once every 5 years or operating 

8760 hours, whichever first, on bypass stack)

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, 2012 (State 

rule, Title V permit revision not complete; based 

on 30-day rolling average, monitored by CEMS 

at inlet to scrubber and at scrubber stack during 

scrubber operations, excluding startup, 

shutdown, malfunction, and other exemptions)

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

NOx: [0.42 * (Heat Input of Units 1-3) + 0.07 

*(Heat Input of Unit 4)]/[Heat Input of Units 1-3 

+ Heat Input of Unit 4] lb/MMBtu from May 1 

through September 30 OR compliance with 5 

and 7-plant Nox averages of 0.13 lb/MMBtu and 

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

rolling averages determined by CEMS)

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 61 part I, 21
GEORGIA POWER - PLANT HAMMOND

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

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 one 

year if test results from the previous annual 

tests are fifty percent or less of the limit on 

scrubber stack; once every 5 years or operating 

8760 hours, whichever first, on bypass stack)

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, 2012 (State 

rule, Title V permit revision not complete; based 

on 30-day rolling average, monitored by CEMS 

at inlet to scrubber and at scrubber stack during 

scrubber operations, excluding startup, 

shutdown, malfunction, and other exemptions)

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

NOx: [0.42 * (Heat Input of Units 1-3) + 0.07 

*(Heat Input of Unit 4)]/[Heat Input of Units 1-3 

+ Heat Input of Unit 4] lb/MMBtu from May 1 

through September 30 OR compliance with 5 

and 7-plant Nox averages of 0.13 lb/MMBtu and 

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

rolling averages determined by CEMS)

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).

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 one 

year if test results from the previous annual 

tests are fifty percent or less of the limit on 

scrubber stack; once every 5 years or operating 

8760 hours, whichever first, on bypass stack)

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, 2012 (State 

rule, Title V permit revision not complete; based 

on 30-day rolling average, monitored by CEMS 

at inlet to scrubber and at scrubber stack during 

scrubber operations, excluding startup, 

shutdown, malfunction, and other exemptions)

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

NOx: [0.42 * (Heat Input of Units 1-3) + 0.07 

*(Heat Input of Unit 4)]/[Heat Input of Units 1-3 

+ Heat Input of Unit 4] lb/MMBtu from May 1 

through September 30 OR compliance with 5 

and 7-plant Nox averages of 0.13 lb/MMBtu and 

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

rolling averages determined by CEMS)

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 61 part I, 21
GEORGIA POWER - PLANT HAMMOND

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 rebuild: 0.12 lb/MMBtu filterable (expired in 

2001)

FGD (one vessel for all 4 units): CBI

Not 

applicable

Not 

applicable

FGD: 98% instantaneous removal efficiency to 

meet a 95% 30-day rolling average removal 

efficiency (expired in 2009)

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Low NOx burners: 0.38 lb/MMBtu (expired in 

2003)

2 ESP rebuild: 0.12 lb/MMBtu filterable (expired in 

1997)

FGD (one vessel for all 4 units): CBI

Not 

applicable

Not 

applicable

FGD: 98% instantaneous removal efficiency to 

meet a 95% 30-day rolling average removal 

efficiency (expired in 2009)

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Low NOx burners: 0.38 lb/MMBtu (expired in 

2002)

3 ESP rebuild: 0.12 lb/MMBtu filterable (expired in 

1993)

FGD (one vessel for all 4 units): CBI

Not 

applicable

Not 

applicable

FGD: 98% instantaneous removal efficiency to 

meet a 95% 30-day rolling average removal 

efficiency (expired in 2009)

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Low NOx burners: 0.38 lb/MMBtu (expired in 

2003)

4 ESP rebuild: 0.03 lb/MMBtu filterable (expired in 

1994)

FGD (one vessel for all 4 units): CBI

Not 

applicable

Not 

applicable

FGD: 98% instantaneous removal efficiency to 

meet a 95% 30-day rolling average removal 

efficiency (expired in 2009)

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not applicable

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

Please elaborate.

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

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

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

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

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

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

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

Boiler ID32

Page 14 of 61 part I, 22-23
GEORGIA POWER - PLANT HAMMOND

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 Scrubber stack: 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, ESP power level and running of scrubber recycle pumps running 

monitored continuously, excursions (3-hour block averages) reported quarterly. 

Bypass stack: Stack test performed within 30 days following 8760 operating hours or 

every 5 years, whichever comes first; 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 January 1, 2012, SO2 removal by the scrubber will 

be monitored by inlet and stack SO2 CEMS operated, 

maintained, and certified using 40 CFR Part 75 procedures. 

Data from these monitors will provide the SO2 removal 

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

shutdown, and malfunction. Exceedances of the 5% limit 

will be reported quarterly; records retained for 5 years 

(permit revision not yet issued).

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

2 Scrubber stack: 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, ESP power level and running of scrubber recycle pumps running 

monitored continuously, excursions (3-hour block averages) reported quarterly. 

Bypass stack: Stack test performed within 30 days following 8760 operating hours or 

every 5 years, whichever comes first; 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 January 1, 2012, SO2 removal by the scrubber will 

be monitored by inlet and stack SO2 CEMS operated, 

maintained, and certified using 40 CFR Part 75 procedures. 

Data from these monitors will provide the SO2 removal 

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

shutdown, and malfunction. Exceedances of the 5% limit 

will be reported quarterly; records retained for 5 years 

(permit revision not yet issued).

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

3 Scrubber stack: 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, ESP power level and running of scrubber recycle pumps running 

monitored continuously, excursions (3-hour block averages) reported quarterly. 

Bypass stack: Stack test performed within 30 days following 8760 operating hours or 

every 5 years, whichever comes first; 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 January 1, 2012, SO2 removal by the scrubber will 

be monitored by inlet and stack SO2 CEMS operated, 

maintained, and certified using 40 CFR Part 75 procedures. 

Data from these monitors will provide the SO2 removal 

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

shutdown, and malfunction. Exceedances of the 5% limit 

will be reported quarterly; records retained for 5 years 

(permit revision not yet issued).

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

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

Boiler ID35

Page 15 of 61 part I, 24
GEORGIA POWER - PLANT HAMMOND

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 Scrubber stack: 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, ESP power level and running of scrubber recycle pumps running 

monitored continuously, excursions (3-hour block averages) reported quarterly. 

Bypass stack: Stack test performed within 30 days following 8760 operating hours or 

every 5 years, whichever comes first; under the CAM plan, opacity monitored 

continuously by COMS, excursions (3-hour block averages greater than 37%) reported 

quarterly.

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

within 60 days of completion of the testing.

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

Not 

applicable

Not 

applicable

Coal sulfur content monitored through daily coal sampling; 

fuel oil sulfur content monitored through vendor 

certification; exceedances of 3% limit reported quarterly; 

records retained for 5 years.

Effective January 1, 2012, SO2 removal by the scrubber will 

be monitored by inlet and stack SO2 CEMS operated, 

maintained, and certified using 40 CFR Part 75 procedures. 

Data from these monitors will provide the SO2 removal 

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

shutdown, and malfunction. Exceedances of the 5% limit 

will be reported quarterly; records retained for 5 years 

(permit revision not yet issued).

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

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 61 part I, 24
GEORGIA POWER - PLANT HAMMOND

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 61 part I, 25-26
GEORGIA POWER - PLANT HAMMOND

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: 

Hammond

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

708

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

Page 18 of 61 part II, 1
GEORGIA POWER - PLANT HAMMOND

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

12,196 1, 2, 3, 4 VA WISE

EDWARDS, JAWBONE, NORTON, 

RAVEN, SPLASHDAM TRAIN 1.17 10.93 13,777

12,171 1, 2, 3, 4 VA WISE

EDWARDS, JAWBONE, NORTON, 

RAVEN, SPLASHDAM TRAIN 1.03 11.93 13,525

12,076 1, 2, 3, 4 VA WISE

EDWARDS, JAWBONE, NORTON, 

RAVEN, SPLASHDAM TRAIN 1.18 11.11 13,741

12,025 1, 2, 3, 4 VA WISE

EDWARDS, JAWBONE, NORTON, 

RAVEN, SPLASHDAM TRAIN 1.17 12 13,405

12,100 1, 2, 3, 4 VA WISE

EDWARDS, JAWBONE, NORTON, 

RAVEN, SPLASHDAM TRAIN 1.29 11.11 13,557

12,345 1, 2, 3, 4 VA WISE

EDWARDS, JAWBONE, NORTON, 

RAVEN, SPLASHDAM TRAIN 1.23 12.16 13,529

12,180 1, 2, 3, 4 VA WISE

EDWARDS, JAWBONE, NORTON, 

RAVEN, SPLASHDAM TRAIN 1.18 11.44 13,629

12,247 1, 2, 3, 4 VA WISE

EDWARDS, JAWBONE, NORTON, 

RAVEN, SPLASHDAM TRAIN 1.29 12.95 13,283

11,825 1, 2, 3, 4 VA WISE

EDWARDS, JAWBONE, NORTON, 

RAVEN, SPLASHDAM TRAIN 1.33 11.86 13,556

12,031 1, 2, 3, 4 VA WISE

EDWARDS, JAWBONE, NORTON, 

RAVEN, SPLASHDAM TRAIN 1.37 12.74 13,436

12,063 1, 2, 3, 4 VA WISE

EDWARDS, JAWBONE, NORTON, 

RAVEN, SPLASHDAM TRAIN 1.26 13.27 13,304

11,063 1, 2, 3, 4 VA WISE

EDWARDS, JAWBONE, NORTON, 

RAVEN, SPLASHDAM TRAIN 1.28 14.56 13,129

11,862 1, 2, 3, 4 VA WISE

EDWARDS, JAWBONE, NORTON, 

RAVEN, SPLASHDAM TRAIN 1.27 15.07 13,026

11,930 1, 2, 3, 4 VA WISE

EDWARDS, JAWBONE, NORTON, 

RAVEN, SPLASHDAM TRAIN 1.11 13.74 13,185

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

Page 19 of 61 part II, 2 (coal)
GEORGIA POWER - PLANT HAMMOND

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

11,818 1, 2, 3, 4 KY MARTIN ALMA TRAIN 1.39 9.06 13,536

11,866 1, 2, 3, 4 KY MARTIN ALMA TRAIN 1.5 8.82 13,522

10,683 1, 2, 3, 4 KY MARTIN ALMA TRAIN 1.47 9.23 13,415

11,971 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 1.05 12.79 13,321

12,000 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.87 12.56 13,404

12,040 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.96 12.04 13,471

12,118 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.96 12.62 13,357

12,146 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 1.04 14.11 13,179

12,138 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 1.01 13.27 13,205

12,101 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.89 12.06 13,442

12,059 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.9 13.32 13,267

12,290 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.99 12.49 13,343

11,787 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.91 12.18 13,469

12,068 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 1.11 12.53 13,391

11,936 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.84 11.68 13,536

12,087 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.99 12.67 13,321

12,115 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.97 11.31 13,623

12,040 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.92 11.96 13,467

11,989 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 1.06 10.96 13,646

12,047 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.99 12.41 13,449

11,443 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.96 12.9 13,352

11,861 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.93 12.08 13,463

12,105 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 1 13.52 13,242

11,850 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.99 12.27 13,409

Page 20 of 61 part II, 2 (coal)
GEORGIA POWER - PLANT HAMMOND

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

11,853 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.9 11.72 13,534

11,750 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN 0.92 14.05 13,132

N/A 1, 2, 3, 4 VA WISE IMBODEN, LOW SPLINT, TIGER TRAIN N/A N/A N/A

9,890 1, 2, 3, 4 KY HARLAN, LEE CREECH, DARBY, HARLAN, KELLIOKA TRAIN 0.94 11.03 13,249

9,747 1, 2, 3, 4 KY HARLAN, LEE CREECH, DARBY, HARLAN, KELLIOKA TRAIN 1.25 14.1 12,851

10,923 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.04 6.16 14,059

11,204 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.04 7.66 13,842

11,133 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.07 7 13,931

11,492 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.04 6.91 13,921

11,424 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.18 7.25 13,903

11,487 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 0.95 8.98 13,527

11,855 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 0.91 7.4 13,759

10,348 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.06 9.35 13,424

11,149 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.07 5.36 14,145

11,140 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.01 8.63 13,562

11,303 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.06 8.68 13,606

10,128 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.07 10.05 13,249

11,033 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.02 7.46 13,744

10,911 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 0.83 8.59 13,557

10,379 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 0.93 11.09 13,129

10,978 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 0.93 10.73 13,343

11,181 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.11 6.58 13,944

10,506 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.04 6.7 13,966

Page 21 of 61 part II, 2 (coal)
GEORGIA POWER - PLANT HAMMOND

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

10,298 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.02 7.3 13,896

11,001 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.14 7.1 13,927

11,416 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.08 6.22 14,030

9,823 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 0.98 9.04 13,561

11,530 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.04 7.26 13,874

11,257 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.03 8.89 13,495

11,382 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.29 7.47 13,823

11,241 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.35 11.1 13,316

11,481 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 0.99 6.65 13,985

11,773 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.01 8.71 13,611

10,779 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.2 7.37 13,859

11,178 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.17 8.12 13,749

12,218 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.53 13.34 12,978

11,718 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1 13.15 13,126

11,449 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.3 10.44 13,539

11,323 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.39 10.18 13,577

10,707 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.24 11.92 13,313

12,068 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.59 11.91 13,360

11,876 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.38 13.6 13,024

Page 22 of 61 part II, 2 (coal)
GEORGIA POWER - PLANT HAMMOND

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

11,716 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.4 12.01 13,327

11,969 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.98 11.38 13,458

12,024 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.86 13.05 13,182

12,223 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 2.05 13.39 13,116

12,079 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 2.11 13.83 13,089

12,169 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.97 12.84 13,240

12,116 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.76 13.26 13,134

11,946 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.81 11.17 13,369

11,765 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.98 10.31 13,530

12,087 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.77 10.34 13,549

12,229 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.9 12.95 13,109

12,212 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.95 11.28 13,415

12,127 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.99 13.78 13,021

12,282 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.87 12.88 13,223

Page 23 of 61 part II, 2 (coal)
GEORGIA POWER - PLANT HAMMOND

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

12,186 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.51 13.29 13,129

11,869 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.84 11.32 13,453

12,245 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.42 12.57 13,215

12,180 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.96 13.31 13,193

12,380 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 2.08 14.1 13,013

11,383 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.78 10.6 13,589

12,093 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.67 12.89 13,177

12,109 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.66 13.03 13,217

11,973 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.68 11.79 13,346

12,088 1, 2, 3, 4 VA WISE CEDAR GROVE, LYONS, STANIFORD TRAIN 1.81 11.68 13,240

2,133 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.76 12.3 13,548

1,297 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.78 12.12 13,625

453 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.85 12.44 13,527

430 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.6 12.68 13,340

254 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.24 16.12 12,932

989 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.94 15.75 13,028

762 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.61 17.48 12,790

Page 24 of 61 part II, 2 (coal)
GEORGIA POWER - PLANT HAMMOND

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

927 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.87 30.01 10,576

697 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.81 15.9 12,991

521 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.95 11.8 13,669

1,471 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.7 13.81 13,455

714 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.71 12.66 13,549

908 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.2 13.88 13,321

466 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.71 11.99 13,644

1,728 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.65 11.09 13,743

2,587 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.66 12.68 13,492

1,442 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.7 16.16 12,825

1,147 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.6 12.04 13,605

883 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.7 12.74 13,489

1,086 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.65 16.74 12,768

1,485 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.75 12.15 13,574

1,205 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.73 13.46 13,406

1,066 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.71 15.49 13,009

827 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.73 12.59 13,542

843 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.74 11.39 13,739

509 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.56 12.52 13,620

254 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.7 13.09 13,496

257 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.67 10.43 13,911

487 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.63 12.86 13,587

1,472 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.66 12.93 13,540

1,722 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.9 12.73 13,542

Page 25 of 61 part II, 2 (coal)
GEORGIA POWER - PLANT HAMMOND

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

1,307 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.81 14.11 13,306

824 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.92 15.37 13,071

1,476 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.92 13.47 13,394

1,516 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.82 13.44 13,409

1,359 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.9 12.84 13,472

1,153 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.98 14.1 13,304

904 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.02 14.64 13,238

839 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.82 15.13 13,136

1,230 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.17 14.13 13,253

977 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.86 13.57 13,347

1,500 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.05 13.46 13,337

1,302 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.73 13.54 13,304

723 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.76 13.52 13,350

960 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.42 14.38 13,119

1,309 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.19 14.57 13,140

667 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.97 14.53 12,992

1,550 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.9 13.79 13,270

744 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.13 19.06 12,319

821 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.18 15.3 13,016

1,458 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.16 17.12 12,721

782 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.07 16.63 12,790

648 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.04 16.49 12,816

834 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.04 16.17 12,854

667 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.22 14.8 13,066

Page 26 of 61 part II, 2 (coal)
GEORGIA POWER - PLANT HAMMOND

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

394 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.63 14.61 13,182

1,377 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.89 15.99 12,917

1,055 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.94 18.22 12,517

1,857 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1 14.14 13,209

1,739 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.78 16.78 12,751

944 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.86 15.54 12,943

486 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.86 14.62 13,183

595 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.96 15.93 12,875

1,171 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.95 14.31 13,180

1,764 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.96 15.93 12,875

644 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.84 14.16 13,181

1,858 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.8 14.38 13,212

1,009 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.96 16.78 12,740

375 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.85 12.89 13,470

1,575 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.93 13.64 13,236

1,299 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.46 15.14 13,014

1,697 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.06 13.78 13,254

652 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.02 13.79 13,255

489 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.83 16.78 12,769

1,368 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.84 14.43 13,155

1,416 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.93 15.66 12,926

1,360 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.32 16.23 12,816

1,160 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.81 15.17 13,035

1,432 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.89 14.67 13,143

Page 27 of 61 part II, 2 (coal)
GEORGIA POWER - PLANT HAMMOND

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

1,349 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.1 17.18 12,662

1,696 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.42 13.12 13,392

426 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.13 14.47 13,190

351 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.22 14.41 13,142

1,287 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.91 13.92 13,286

418 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.98 14.4 13,206

1,070 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.98 14.38 13,154

891 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.99 13.32 13,335

655 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1 12.98 13,330

994 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.11 12.48 13,454

975 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.17 13.36 13,291

1,003 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.3 15.59 12,938

714 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.04 15.18 13,012

1,000 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.1 16.03 12,866

1,001 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.27 14.44 13,144

902 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.14 13.75 13,253

905 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.95 15.6 12,930

1,208 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.64 12.6 13,553

1,931 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1 13.2 13,451

1,082 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.89 12.85 13,510

1,002 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.79 13.49 13,326

141 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.95 13.34 13,348

923 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.78 14.95 13,130

924 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.78 14 13,262

Page 28 of 61 part II, 2 (coal)
GEORGIA POWER - PLANT HAMMOND

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

1,004 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.93 16.31 12,846

1,253 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.77 10.82 13,905

1,289 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.88 11.75 13,791

1,211 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.77 13.47 13,403

851 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.8 13.72 13,361

983 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.74 13.12 13,433

1,065 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.91 14.25 13,239

1,114 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.05 13.66 13,373

912 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.81 15.63 12,954

884 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.82 12.01 13,423

928 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.79 12.01 13,598

935 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.73 12.58 13,502

N/A 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK N/A N/A N/A

867 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.93 13.65 13,267

912 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.91 13.18 13,317

1,054 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.8 12.87 13,438

382 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.72 14.17 13,195

622 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.76 13.21 13,367

1,108 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.71 12.91 13,469

798 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.78 14.34 13,134

878 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.8 13.72 13,300

859 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.84 14.69 13,100

663 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.02 13.67 13,259

1,061 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.91 11.67 13,799

Page 29 of 61 part II, 2 (coal)
GEORGIA POWER - PLANT HAMMOND

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

1,056 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.93 14.15 13,277

1,033 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.96 13.96 13,320

646 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.88 12.52 13,499

528 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.84 13.29 13,395

622 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.92 14.73 13,072

667 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.05 15.51 12,938

922 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.86 12.49 13,453

995 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1 13.25 13,328

820 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.89 15.11 13,007

611 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.87 13.6 13,318

1,625 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.87 14.69 13,071

739 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.09 15.77 12,900

665 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.03 16.54 12,790

1,180 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.87 15.18 13,014

567 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.99 15.67 12,936

1,508 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.94 16.47 12,802

827 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.87 14.66 13,152

993 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.03 14.9 13,032

695 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 1.07 16.16 12,819

806 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.75 13.68 13,406

521 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.72 13.16 13,481

807 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.72 13.27 13,457

1,125 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.72 14.17 13,309

925 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.65 13.3 13,314

Page 30 of 61 part II, 2 (coal)
GEORGIA POWER - PLANT HAMMOND

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

1,148 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.64 14.71 13,174

673 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.69 14.02 13,266

1,575 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.62 12.74 13,521

1,697 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.62 12.75 13,520

1,064 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.66 13.13 13,477

1,049 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.67 13.66 13,394

995 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.66 13.2 13,497

1,800 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.71 13.26 13,408

832 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.69 13.28 13,454

426 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.65 13.05 13,482

998 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.63 12.55 13,487

1,111 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.59 13.05 13,501

766 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.82 14.99 13,160

1,211 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.75 13.87 13,335

998 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.68 13.08 13,481

1,174 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.67 12.63 13,534

1,110 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.61 12.5 13,608

1,323 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.75 12.38 13,605

1,347 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.67 12.09 13,662

882 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.72 14.69 13,176

1,035 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.68 13.54 13,392

1,054 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.71 12.68 13,575

1,213 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.68 12.73 13,523

522 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.68 13 13,479

Page 31 of 61 part II, 2 (coal)
GEORGIA POWER - PLANT HAMMOND

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

964 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.7 13.26 13,410

1,236 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.72 13.19 13,434

1,454 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.7 13.64 13,348

573 1, 2, 3, 4 AL JACKSON UNDERWOOD TRUCK 0.7 13.34 13,417

7,889 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 2.14 11.99 13,128

11,978 1, 2, 3, 4 TN ANDERSON PEE WEE, WALNUT MTN TRAIN 1.01 9.01 13,487

11,759 1, 2, 3, 4 KY PIKE

ALMA, ELKHORN, ELKHORN #2, 

ELKHORN #3 TRAIN 0.74 11.98 13,246

11,723 1, 2, 3, 4 KY PIKE

ALMA, ELKHORN, ELKHORN #2, 

ELKHORN #3 TRAIN 1.01 11.51 13,419

11,164 1, 2, 3, 4 KY PIKE

ALMA, ELKHORN, ELKHORN #2, 

ELKHORN #3 TRAIN 0.97 10.9 13,536

11,692 1, 2, 3, 4 KY PIKE

ALMA, ELKHORN, ELKHORN #2, 

ELKHORN #3 TRAIN 0.87 11.25 13,441

11,594 1, 2, 3, 4 N/A N/A

POND CREEK, TAYLOR, 

WILLIAMSON TRAIN 0.93 12.59 13,209

11,564 1, 2, 3, 4 KY, WV LESLIE, LOGAN ALMA TRAIN 0.72 9.83 13,467

11,986 1, 2, 3, 4 KY, WV LESLIE, LOGAN ALMA TRAIN 0.74 12.89 13,130

11,730 1, 2, 3, 4 KY, WV LESLIE, LOGAN ALMA TRAIN 0.75 12.22 13,245

10,139 1, 2, 3, 4 KY, WV LESLIE, LOGAN ALMA TRAIN 0.87 12.25 13,245

11,728 1, 2, 3, 4 KY, WV LESLIE, LOGAN ALMA TRAIN 0.91 12.82 13,174

11,898 1, 2, 3, 4 KY, WV LESLIE, LOGAN ALMA TRAIN 1.13 12.84 13,217

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

amount fired.

Page 32 of 61 part II, 2 (coal)
GEORGIA POWER - PLANT HAMMOND

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

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 33 of 61 part II, 2 (coal)
GEORGIA POWER - PLANT HAMMOND

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

30,120 1, 2, 3, 4 Georgia/USA N/A N/A Truck

15,071 1, 2, 3, 4 Georgia/USA N/A N/A Truck

15,063 1, 2, 3, 4 Georgia/USA N/A N/A Truck

7,527 1, 2, 3, 4 Georgia/USA N/A N/A Truck

15,098 1, 2, 3, 4 Georgia/USA N/A N/A Truck

15,043 1, 2, 3, 4 Georgia/USA N/A N/A Truck

45,208 1, 2, 3, 4 Georgia/USA N/A N/A Truck

29,980 1, 2, 3, 4 Georgia/USA N/A N/A Truck

14,971 1, 2, 3, 4 Georgia/USA N/A N/A Truck

14,978 1, 2, 3, 4 Georgia/USA N/A N/A Truck

14,981 1, 2, 3, 4 Georgia/USA N/A N/A Truck

29,990 1, 2, 3, 4 Georgia/USA N/A N/A Truck

14,924 1, 2, 3, 4 Georgia/USA N/A N/A Truck

14,922 1, 2, 3, 4 Georgia/USA N/A N/A Truck

14,874 1, 2, 3, 4 Georgia/USA N/A N/A Truck

22,314 1, 2, 3, 4 Georgia/USA N/A N/A Truck

22,300 1, 2, 3, 4 Georgia/USA N/A N/A Truck

22,271 1, 2, 3, 4 Georgia/USA N/A N/A Truck

29,733 1, 2, 3, 4 Georgia/USA N/A N/A Truck

7,429 1, 2, 3, 4 Georgia/USA N/A N/A Truck

22,215 1, 2, 3, 4 Georgia/USA N/A N/A Truck

22,197 1, 2, 3, 4 Georgia/USA N/A N/A Truck

22,269 1, 2, 3, 4 Georgia/USA N/A N/A Truck

22,285 1, 2, 3, 4 Georgia/USA N/A N/A Truck

14,841 1, 2, 3, 4 Georgia/USA N/A N/A Truck

14,820 1, 2, 3, 4 Georgia/USA N/A N/A Truck

FUEL OIL SHIPMENTS

Amount received, 

gallons40

ID # of boiler(s) 

firing fuel41

Fuel source Fuel shipment 

method

Page 34 of 61 part II, 2 (oil)
GEORGIA POWER - PLANT HAMMOND

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

14,833 1, 2, 3, 4 Georgia/USA N/A N/A Truck

22,285 1, 2, 3, 4 Georgia/USA N/A N/A Truck

22,271 1, 2, 3, 4 Georgia/USA N/A N/A Truck

29,744 1, 2, 3, 4 Georgia/USA N/A N/A Truck

14,884 1, 2, 3, 4 Georgia/USA N/A N/A Truck

14,880 1, 2, 3, 4 Georgia/USA N/A N/A Truck

22,361 1, 2, 3, 4 Georgia/USA N/A N/A Truck

22,385 1, 2, 3, 4 Georgia/USA N/A N/A Truck

22,346 1, 2, 3, 4 Georgia/USA N/A N/A Truck

22,455 1, 2, 3, 4 Georgia/USA N/A N/A Truck

22,468 1, 2, 3, 4 Georgia/USA N/A N/A Truck

22,483 1, 2, 3, 4 Georgia/USA N/A N/A Truck

22,483 1, 2, 3, 4 Georgia/USA N/A N/A Truck

29,980 1, 2, 3, 4 Georgia/USA N/A N/A Truck

15,031 1, 2, 3, 4 Georgia/USA N/A N/A Truck

22,560 1, 2, 3, 4 Georgia/USA N/A N/A Truck

22,547 1, 2, 3, 4 Georgia/USA N/A N/A Truck

7,538 1, 2, 3, 4 Georgia/USA N/A N/A Truck

30,149 1, 2, 3, 4 Georgia/USA N/A N/A Truck

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

amount fired.

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

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

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

42 If known.

Page 35 of 61 part II, 2 (oil)
GEORGIA POWER - PLANT HAMMOND

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

43 If known.

Page 36 of 61 part II, 2 (oil)
GEORGIA POWER - PLANT HAMMOND

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

09-101 1,275 0.86 16.01 12,962 0.090 1140 92 18.3 1.4 10.9 1.8 <0.02 23.8 8.0 10.3 13.8 1.0 AL Jackson

Underwood 

Seam Truck

09-501 12,832 0.99 12.79 13,239 0.070 86 116 14.7 1.2 7.9 2.1 <0.02 19.0 7.8 9.7 41.6 2.3 VA Wise

 (1)Parsons (2) 

Imboden 

(3)Taggart 

(4)Taggert 

Marker (5)Low 

Splint C (6) 

Low splint (7) 

Low Splint A Train

09-504 11,367 1.23 11.79 13,262 0.070 93 130 10.7 1.3 17.4 1.6 0.13 15.8 6.1 8.1 21.4 2.5 VA Wise

(1)Morris 

(2)Cedar Grove 

(3) Mixed 

(4)Parsons 

(5)Taggart (6) 

#8 Train

09-505 12,229 1.54 10.24 13,258 0.113 2148 69 13.5 1.6 10.6 2.1 0.06 15.8 7.0 9.6 24.2 3.9 KY Martin Alma, Coalburg Train

09-507 12,420 0.91 13.36 13,049 0.073 995 103 12.9 1.0 12.1 2.9 0.03 17.6 8.9 9.1 50.0 3.0 KY Pike

Broaz, Haddix, 

Chilton, Middle 

Whitesburg, 

Upper/Lower 

Alma, Haddix, 

Cedar Grove, 

Williamson Train

09-103 1,190 0.96 15.38 12,960 0.132 1247 73 16.1 <1 15.0 1.2 <0.02 20.1 6.5 9.2 12.8 1.0 AL Jackson

Underwood 

Seam Truck

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

Creech, House 

Coal Train

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

Braden, Red 

Ash, Walnut 

Mountain Train

Coal Seam

Fuel 

Shipment 

Method

Nickel, 

ppm

Other trace metal HAP, ppm45

State/ 

Country

County

Chlorine, 

ppm

Fluorine, 

ppm

Total amount of 

fuel represented 

by sample, tons

Sample 

ID #

Total 

Sulfur, %

Ash 

Content, 

%

Heating 

Value, 

Btu/lb

Mercury, 

ppm

Page 37 of 61 part II, 3
GEORGIA POWER - PLANT HAMMOND

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

Coal Seam

Fuel 

Shipment 

Method

Nickel, 

ppm

Other trace metal HAP, ppm45

State/ 

Country

County

Chlorine, 

ppm

Fluorine, 

ppm

Total amount of 

fuel represented 

by sample, tons

Sample 

ID #

Total 

Sulfur, %

Ash 

Content, 

%

Heating 

Value, 

Btu/lb

Mercury, 

ppm

09-401 8,500 2.01 8.93 13,675 0.099 643 74 15.6 <1 15.5 1.9 0.13 13.2 6.4 6.2 14.6 2.9 TN Clairborne

Walnut 

Mountain, 

Windrock, Pee 

Wee Train

09-510 12,792 1.07 13.2 13,252 0.066 ND 73 14.4 1.5 14.6 2.5 0.04 18.2 8.2 9.7 43.1 2.5 VA Wise

 (1) Low Splint 

(2) Imboden 

(3)Taggart 

(4)Upper 

Parsons 

(5)Taggart 

Marker 

(6)Lower 

Parsons Train

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

Cedar Grove, 

Morris Ryder Train

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

Lower Elkhorn, 

Elkhorn , Alma, 

Clintwood Train

09-516 12,427 0.94 14.5 12,864 ND 1178 108 17.1 1.1 16.6 3.2 ND 18.1 10.8 9.5 134.3 2.4 KY Pike

Chilton, 

Whitesburg, 

Upper/Lower 

Alma, Cedar 

Grove Train

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

Walnut 

Mountain, 

Windrock, Pee 

Wee Train

09-412 12,474 0.98 9.01 13,460 0.071 1310 98 26.4 1.2 5.0 3.0 0.10 16.9 13.5 9.7 21.9 3.8 TN Clairborne

Braden, Red 

Ash, Walnut 

Mountain Train

09-216 12,723 1.59 9.41 13,416 0.115 2317 60 13.0 1.4 7.9 2.1 0.04 16.0 7.0 9.1 18.9 3.9 KY Martin Alma, Taylor Train

Page 38 of 61 part II, 3
GEORGIA POWER - PLANT HAMMOND

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

Coal Seam

Fuel 

Shipment 

Method

Nickel, 

ppm

Other trace metal HAP, ppm45

State/ 

Country

County

Chlorine, 

ppm

Fluorine, 

ppm

Total amount of 

fuel represented 

by sample, tons

Sample 

ID #

Total 

Sulfur, %

Ash 

Content, 

%

Heating 

Value, 

Btu/lb

Mercury, 

ppm

09-519 12,850 0.9 13.36 13,230 ND 68 119 14.5 1.1 9.7 2.0 ND 19.9 8.0 8.9 49.4 2.5 VA Wise

(1) Imboden 

(2)Taggart 

(3)Lower 

Parsons 

(4)Taggart 

Marker (5)Low 

Splint (6) Low 

Splint A (7) 

Low Splint D 

(8) Upper 

Parsons Train

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

Lower Elkhorn, 

Elkhorn , Alma, 

Clintwood Train

09-523 12,773 1.63 13.7 13,044 0.157 150 113 15.4 ND 40.8 1.8 0.15 16.6 7.6 7.3 40.6 2.3 VA Wise

Cedar Grove, 

High Splint, 

Morris Ryder, 

High Splint 

Marker Train

09-109 1,027 0.67 12.42 13,609 0.022 1181 29 11.6 <1 4.1 1.1 <0.02 17.6 7.3 7.8 12.2 1.0 AL Jackson

Underwood 

Seam Truck

09-106 634 1.15 14.68 12,973 0.111 988 ND 18.3 <1 16.3 1.6 0.07 19.0 8.1 11.9 12.6 0.9 AL Jackson

Underwood 

Seam Truck

09-527 12,691 0.81 11.8 13,156 ND 1018 80 13.8 1.2 13.7 3.6 0.07 12.0 10.9 8.5 130.1 2.2 KY Pike

Chilton, 

Whitesburg, 

Upper/Lower 

Alma, Cedar 

Grove Train

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

Alma, Taylor, 

Stockton Train

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

Walnut 

Mountain, 

Windrock, Pee 

Wee Train

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

Braden, Red 

Ash, Walnut 

Mountain Train

Page 39 of 61 part II, 3
GEORGIA POWER - PLANT HAMMOND

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

Coal Seam

Fuel 

Shipment 

Method

Nickel, 

ppm

Other trace metal HAP, ppm45

State/ 

Country

County

Chlorine, 

ppm

Fluorine, 

ppm

Total amount of 

fuel represented 

by sample, tons

Sample 

ID #

Total 

Sulfur, %

Ash 

Content, 

%

Heating 

Value, 

Btu/lb

Mercury, 

ppm

09-233 11,610 0.74 12.37 13,164 0.067 1151 76 15.4 1.0 13.3 3.9 0.03 13.8 12.6 7.9 157.6 2.2 KY Pike

Chilton, Lower 

Alma, Cedar 

Grove, #3 

Elkhorn Train

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

Walnut 

Mountain, 

Windrock, Pee 

Wee Train

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

Braden, Red 

Ash, Walnut 

Mountain Train

09-529 12,893 1.01 12.13 13,403 ND 155 109 13.5 1.2 7.1 2.2 0.06 20.5 7.8 10.5 26.3 2.8 VA Wise

(1) Parsons 

(2)Taggart 

(3)Low Splint A 

(4)Dorchester Train

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

Mingo, 

Logan

Coalburg, 

Stockton, 

Alma, Lower 

Cedar Grove Train

09-532 12,837 1.59 13.08 13,184 0.101 130 91 17.0 1.6 26.8 3.0 0.15 18.1 9.7 9.1 25.9 2.2 VA Wise

Morris, Cedar 

Grove, High 

Splint, Parsons Train

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

Alma, Taylor, 

Stockton 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 40 of 61 part II, 3
GEORGIA POWER - PLANT HAMMOND

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 41 of 61 part II, 4-6
GEORGIA POWER - PLANT HAMMOND

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

7 In addition to the analyses required in Part II, question 3 above, for samples for which analyses of chlorine and/or any of the HAP metals were 

conducted, please provide copies of any analyses conducted over the preceding 12 calendar months for (a) complete proximate and ultimate 

analyses, (b) additional trace metals, and (c) the mineralogy of the ash that are readily available for the oil(s) or coal(s) listed in Part II, question

2 above. The Agency is requesting these data only as they may already be available; no additional sampling or analyses are required to provide

these data.

Total 

Moisture Volatiles Ash Fixed Carbon Carbon Hydrogen Nitrogen Total Sulfur Oxygen Barium Copper Magnesium Sodium Vanadium Zinc Al2O3 Fe2O3 CaO MgO MnO2 P2O5 K2O SiO2 Na2O SO3 TiO2

09-101 2.75 25.73 16.01 58.26 75.13 4.47 1.37 0.86 2.16 120 17.5 0.117 0.013 43.3 19.6 29.42 5.51 0.95 1.21 0.014 0.67 3.16 57.17 0.11 0.43 1.13

09-501 6.35 32.47 12.79 54.74 75.28 4.65 1.41 0.99 4.88 121 21.1 0.102 0.044 43.2 22.6 27.6 7.96 0.992 1.25 ND ND 3.05 54.2 0.554 0.561 1.45

09-504 5.84 33.51 11.79 54.7 76.11 4.73 1.48 1.23 4.66 131 19.4 0.077 0.025 29.7 17.1 26.5 9.34 1.22 0.972 ND 0.577 2.73 48.6 0.35 0.288 1.36

09-505 6.83 37.22 10.24 52.53 76.72 4.88 1.41 1.54 5.2 317 23.5 0.008 0.000 37.3 16.1 26.3 12.7 2.5 0.876 ND ND 2.2 45.7 0.523 1.82 1.25

09-507 4.92 31.63 13.36 55.01 75.87 4.63 1.35 0.91 3.88 386 20.0 0.092 0.037 29.4 14.7 24.2 6.89 0.858 1.11 ND ND 2.78 55.1 0.397 0.715 1.38

09-103 6.77 27.01 15.38 57.61 74.29 4.43 1.37 0.96 3.57 100 13.7 0.109 0.012 38.0 14.5 28.23 6.4 0.79 1.17 0.013 0.49 3.22 57.62 0.11 0.52 1.23

09-203 5.28 34.06 12.64 53.31 75.25 4.72 1.41 1.45 4.52 152 18.5 0.088 0.027 27.1 15.3 24.6 10.7 1.34 1.13 ND ND 2.5 50.9 0.336 0.658 1.33

09-400 5.42 36.88 7.45 55.68 79.19 4.91 1.83 1.22 5.39 122 21.6 0.063 0.014 31.6 18.9 27.6 11.3 3.44 1.24 ND ND 2.23 49.2 0.36 2.24 1.33

09-401 5.83 36.96 8.93 54.11 77.62 4.92 1.9 2.01 4.63 91 23.9 0.059 0.016 34.8 13.8 22.8 16.7 2.13 0.982 ND ND 2.19 47.5 0.264 1.1 1.19

09-510 6.98 32.91 13.2 53.89 75.61 4.8 1.4 1.07 3.92 132 22.3 0.109 0.042 39.1 22.4 26.6 9.47 1.34 1.26 ND ND 3.26 53.5 0.531 0.96 1.34

09-514 4.99 34.16 12.38 53.47 76.24 4.86 1.34 1.9 3.28 172 20.1 0.098 0.025 31.1 21.7 24.1 17.9 1.11 1.17 ND ND 3.13 45.3 0.322 0.568 1.02

09-515 5.67 31.26 11.76 56.97 75.97 4.62 1.33 0.87 5.45 417 18.6 0.084 0.047 27.3 15.6 25.2 7.17 0.964 1.09 ND ND 3.18 55 0.562 0.727 1.26

09-516 5.81 32.04 14.5 53.46 73.4 4.63 1.25 0.94 5.28 386 21.7 0.110 0.038 31.2 21.0 24.4 10.4 1.48 1.24 ND ND 2.92 56.4 0.42 1.17 1.31

09-411 5.82 36.75 9.32 53.92 75.84 4.98 1.77 1.63 6.46 122 26.6 0.063 0.017 35.5 14.7 28.2 11.7 2.56 1.22 ND 0.459 2.41 58.5 0.615 1.21 1.4

09-412 6.19 36.01 9.01 54.99 76.13 4.9 1.63 0.98 7.36 113 28.7 0.081 0.019 45.4 25.6 28.5 7.19 3.26 1.56 ND 0.502 2.59 51 0.349 1.9 1.28

09-216 6.72 38.03 9.41 52.56 72.88 4.8 1.52 1.59 9.79 82 23.2 0.047 0.033 34.8 14.2 27.7 12.7 3.07 0.839 ND ND 1.86 46.9 0.546 2.15 1.26

09-519 6.16 32.55 13.36 54.1 75.2 4.82 1.56 0.9 4.16 132 21.5 0.109 0.048 40.3 22.7 26.8 8.44 1.64 1.35 ND ND 3.29 58.4 0.542 1.25 1.3

09-521 5.15 31.19 12.11 56.71 75.69 4.76 1.56 0.75 5.13 285 18.6 0.086 0.048 28.6 12.6 27.4 6.87 1.13 1.18 ND ND 3.27 57.8 0.54 0.715 1.35

09-523 5.05 34.22 13.7 52.08 71.4 4.7 1.39 1.63 7.17 183 17.6 0.131 0.026 33.0 25.8 24.8 16.1 0.949 1.4 ND ND 3.39 47 0.302 0.665 1.1

09-109 2.79 25.19 12.42 62.39 77.79 4.55 1.52 0.67 3.05 80 10.6 0.091 0.011 27.2 19.2 25.47 4.76 0.79 1.21 0.016 0.31 3.11 62.38 0.12 0.43 1.31

09-106 2.74 27.37 14.68 57.54 72.27 4.43 1.46 1.15 5.6 91 15.4 0.108 0.012 36.7 18.6 28 7.86 0.879 1.13 ND ND 2.83 52.6 0.149 ND 1.25

09-527 7.86 32.37 11.8 55.83 74.02 4.43 1.5 0.81 7.44 285 17.6 0.083 0.039 20.4 15.6 24.8 11 1.74 1.33 ND ND 3.03 51.8 0.507 1.42 1.11

09-231 6.67 38.81 8.58 52.6 74.73 4.82 1.6 1.47 8.8 62 29.3 14.578 0.029 44.2 18.7 30 9.74 2.59 0.789 ND ND 1.81 47.7 0.501 2.47 1.21

09-429 6.36 35.29 10.27 54.44 73.63 4.69 1.62 2 7.78 92 45.9 0.085 0.015 61.3 34.8 27.5 11.6 2.72 1.35 ND ND 2.21 45.2 0.273 2.14 1.41

09-430 5.44 35.86 7.32 56.82 76.71 4.86 1.61 0.94 8.56 82 32.3 0.056 0.029 49.0 22.6 28.5 7.98 3.13 1.46 ND 0.441 2.25 48.3 0.376 2.33 1.37

09-233 7.03 31.74 12.37 55.89 73.57 4.52 1.35 0.74 7.46 255 20.5 0.084 0.034 23.3 17.2 23.7 12.7 1.67 1.04 0.132 ND 2.9 50.1 0.451 1.27 1.22

09-436 6.32 35.44 9.45 55.11 75 4.78 1.83 1.87 7.06 112 35.2 0.070 0.015 47.6 23.3 28 11.4 2.48 1.25 ND 0.477 2.17 48.2 0.253 2.19 1.38

09-437 6.02 36.44 6.61 56.95 77.61 4.94 1.74 1.31 7.79 71 28.2 0.054 0.015 39.6 20.3 32.3 4.08 0.902 0.651 ND ND 1.54 56.5 0.173 ND 1.75

09-529 6.24 33.15 12.13 54.71 75.15 4.65 1.44 1.01 5.62 122 24.1 0.092 0.037 41.2 20.5 26.9 6.59 1.2 1.06 ND 0.403 2.65 52.4 0.435 0.695 1.51

09-530 6.14 32.04 12.06 55.9 74.64 4.58 1.36 0.8 6.56 317 10.6 0.226 0.082 13.6 14.1 25.3 5.02 0.88 0.998 ND ND 2.38 56.1 0.291 0.556 1.44

09-532 5.65 33.92 13.08 53.01 73.25 4.71 1.31 1.59 6.06 132 23.5 0.109 0.023 37.5 31.6 27.7 14.2 1.02 1.32 ND ND 3.52 54.4 0.292 0.575 1.21

09-535 6.75 37.55 9.27 53.18 74.41 4.84 1.6 1.35 8.53 62 21.3 0.045 0.033 35.5 15.3 30.1 11.7 2.59 0.809 ND ND 1.89 48.5 0.545 1.51 1.34

Sample 

ID #

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

Page 42 of 61 part II, 7
GEORGIA POWER - PLANT HAMMOND

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 Units 1-3 Particulate Emissions Test (July 13, 2006)

Report 2 Unit 4 Particulate Emissions Test (July 13, 2006)

Report 3 Units 1-3 Particulate Emissions Test (February 6, 2008)

Report 4 Unit 4 Particulate Emissions Test (February 6, 2008 to February 7, 2008)

Report 5 Units 1-4 Particulate Emissions Test, FGD Stack (April 22, 2008)

Report 6 Units 1-4 CAM Testing, FGD Stack (April 24, 2008)

Report 7 Units 4 Low NOx Burners Optimization (April 20, 2009 to April 24, 2009)

Report 8 Units 1-4 Scrubber Performance Mercury Test (June 13, 2008 to June 19, 2008)

Report 9 Units 1-4 Scrubber Performance SO3 Test (May 29, 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: 7/13/2006 Type: stack Constituents: PM

Report 2 Date: 7/13/2006 Type: stack Constituents: PM

Report 3 Date: 2/6/2008 Type: stack Constituents: PM

Report 4 Date: 2/6/2008-2/7/2008 Type: stack Constituents: PM

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

Report 6 Date: 4/24/2008 Type: stack Constituents: PM

Report 7 Date: 4/20/2009-4/24/2009 Type: duct Constituents: CO

Report 8 Date: 6/13/2008-6/19/2008 Type: duct/stack Constituents: Hg

Report 9 Date: 5/29/2008 Type: duct/stack Constituents: SO3

Page 43 of 61 part II, 8
GEORGIA POWER - PLANT HAMMOND

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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).

Report 7 reflects testing at the economizer outlet (upstream of all post-combustion control devices).

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

Reports 8, 9 reflect testing upstream of the scrubber, at the inlet duct.

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.

Boiler ID Type NOx control SO2 control PM control Other control

1 dry bottom 

wall-fired

(1) low NOX burner (2) cold-side 

electrostatic 

precipitator

2 dry bottom 

wall-fired

(1) low NOX burner (2) cold-side 

electrostatic 

precipitator

3 dry bottom 

wall-fired

(1) low NOX burner (2) cold-side 

electrostatic 

precipitator

4 dry bottom 

wall-fired

(1) low NOX burner + 

overfire air

(2) SCR

(3) cold-side 

electrostatic 

precipitator

Page 44 of 61 part II, 8
GEORGIA POWER - PLANT HAMMOND

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

The control configuration shown below is representative of the conditions present during Report 4.

Boiler ID Type NOx control SO2 control PM control Other control

4 dry bottom 

wall-fired

(1) low NOX burner + 

overfire air

(2) cold-side 

electrostatic 

precipitator

The control configuration shown below is representative of the conditions present during Reports 5, 6, 7, 8, 9.

Boiler ID Type NOx control SO2 control PM control Other control

1 dry bottom 

wall-fired

(1) low NOX burner (3) wet flue gas 

desulfurization (FGD, 1 

vessel for all four units)

(2) cold-side 

electrostatic 

precipitator 

2 dry bottom 

wall-fired

(1) low NOX burner (3) wet flue gas 

desulfurization (FGD, 1 

vessel for all four units) 

(2) cold-side 

electrostatic 

precipitator 

3 dry bottom 

wall-fired

(1) low NOX burner (3) wet flue gas 

desulfurization (FGD, 1 

vessel for all four units) 

(2) cold-side 

electrostatic 

precipitator

4 dry bottom 

wall-fired

(1) low NOX burner + 

overfire air 

(2) SCR

(4) wet flue gas 

desulfurization (FGD, 1 

vessel for all four units) 

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

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

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

Reports 8, 9 include testing at locations before a post combustion SO2 emission control device.

No bypass of unscrubbed flue gas was utilized at the time of testing.

Page 45 of 61 part II, 8
GEORGIA POWER - PLANT HAMMOND

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:

Units 1-4 (common stack/liner, scrubber stack): 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 46 of 61 part II, 9-11
GEORGIA POWER - PLANT HAMMOND

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, & 3 7/13/2006 See Attachment 1 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

4 7/13/2006 See Attachment 2 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

1, 2, & 3 2/6/2008 See Attachment 3 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

4 2/6/2008 See Attachment 4 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

1, 2, 3, & 4 4/22/2008 See Attachment 5 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

1, 2, 3, & 4 4/24/2008 See Attachment 6 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

4 4/20/2009-4/24/2009 Not applicable Not applicable Not applicable Not applicable Not applicable See Attachment 7 Not applicable

1, 2, 3, & 4 6/13/2008-6/19/2008 Not applicable Not applicable Not applicable Not applicable See Attachment 8 Not applicable Not applicable

47 Provide emission test data for all tests conducted since January 1, 2005. Please indicate test data acquired both before and after

any control device. Use additional pages as necessary. EPA may, at some future date, request a copy of one or more emission test reports.

Data generated to fulfill both Federal and State requirements must be provided. Note that data generated pursuant to CAA Title V

must be maintained and available for 5 years. Also include averaging times and measurement units for all pollutants.

48 For each emissions test run the respondent should provide the following process information: Unit Load (MW), Net generation during run (MWh net),

Flue gas moisture content (%), Flue gas flow rate (dscfm or Nm3/hr), Flue gas oxygen content (%, dry), Flue gas carbon dioxide content (%, dry), Flue gas

temperature at sampling point (oF), Flue gas pressure at sampling point (atm), Standard temperature (oF), Standard pressure (atm).

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 47 of 61 part II, 12
ATTACHMENT 1 - Hammond Report 1 Test Results

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

Run 1 Run 2 Run 3

Test Date 7/13/2006 7/13/2006 7/13/2006

Run Start Time 7:20 9:30 11:15

Run End Time 8:35 10:45 12:30

Meter Volume (dacf), Vm: 39.952 41.701 42.204

Sqrt Delta P ("wc): 0.99 1.00 1.00

Sampling Time (min): 60 60 60

Barometric Pressure ("Hg), Pbar: 29.41 29.41 29.40

Delta H ("wc): 1.3 1.3 1.3

Volume in Impingers (mls), VIc: 62.2 62.9 63.1

Static Pressure ("wc), Pg: -2.10 -1.90 -2.00

Stack Pressure ("Hg), Ps: 29.26 29.27 29.25

Stack Temperature (F), Ts: 286 291 293

Meter Coefficient (no units), Y: 0.997 0.997 0.997

Pitot Coefficient (no units) Cp: 0.840 0.840 0.840

Meter OutletTemperature (F), Tm: 101 106 109

Stack Diameter (inches): 252 252 252

Area Stack (sq. ft.), As: 346.36 346.36 346.36

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): 10.9 10.9 11.0

Percent O2 (% dry volume): 7.7 7.9 7.9

Percent (N2 + CO) (% dry volume): 81.4 81.1 81.1

Particulate Collected (mg), Mn: 86.2 69.3 64.8

Molec. Wt. Dry (lb/lb-mole), Md: 30.048 30.067 30.071

Volume Water (scf), Vwstd 2.928 2.961 2.970

Meter Volume (dscf), Vmstd: 36.974 38.237 38.449

Wet Fraction (v/v), Bws: 0.073 0.072 0.072

Molec. Wt. Wet (lb/lb-mole), Ms: 29.164 29.199 29.205

Stack Gas Sampled (acf), Vma: 57.670 59.879 60.422 Averages

Stack Gas Velocity (fps), Vs: 66.30 67.14 67.56 67

Volumetric Flowrate (dscfm), Qs: 883,351 891,009 893,438 889,266

Volumetric Flowrate (acfm), Qa: 1,377,791 1,395,298 1,404,048 1,392,379

Grainloading (gr/dscf), cs: 0.0360 0.0279 0.0260 0.03

Emission Rate (lb/hour), E: 272.39 213.43 199.07 228.3

Percent Isokinetic Sampling (%), I: 100.28 102.82 103.10 102.07

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780

Heat Input (mmBtu/hour): 3414.09 3391.38 3409.37 3404.95

Emission Rate (lbs/mmBtu), E: 0.08 0.06 0.06 0.07

Allowable Rate (lb/mmBtu): 0.240 0.240 0.240 0.240

Average Unit 1 Gross Load (MW) 99 99 99 99

Particulate Emission Results Summary

Hammond Units 1-3

Page 48 of 61 Att. 1
ATTACHMENT 1 - Hammond Report 1 Test Results

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

Run 1 Run 2 Run 3

Particulate Emission Results Summary

Hammond Units 1-3

Average Unit 2 Gross Load (MW) 105 105 105 105

Average Unit 3 Gross Load (MW) 110 110 110 110

Average Sum Gross Load (MW) 313 314 314 314

Page 49 of 61 Att. 1
ATTACHMENT 2 - Hammond Report 2 Test Results

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

Run 1 Run 2 Run 3

Test Date 7/13/2006 7/13/2006 7/12/2006

Run Start Time 7:20 9:30 11:15

Run End Time 8:35 10:45 12:30

Meter Volume (dacf), Vm: 31.83 34.04 34.314

Sqrt Delta P ("wc): 1.17 1.20 1.18

Sampling Time (min): 60 60 60

Barometric Pressure ("Hg), Pbar: 29.41 29.41 29.40

Delta H ("wc): 0.8 0.9 0.9

Volume in Impingers (mls), VIc: 47.3 52.3 54.0

Static Pressure ("wc), Pg: -2.30 -2.30 -2.40

Stack Pressure ("Hg), Ps: 29.24 29.24 29.22

Stack Temperature (F), Ts: 315 318 323

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: 104 110 110

Stack Diameter (inches): 264 264 264

Area Stack (sq. ft.), As: 380.13 380.13 380.13

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): 12.1 12.2 12.1

Percent O2 (% dry volume): 7.0 6.9 7.0

Percent (N2 + CO) (% dry volume): 80.9 80.9 80.8

Particulate Collected (mg), Mn: 13.2 13.2 14.4

Molec. Wt. Dry (lb/lb-mole), Md: 30.212 30.224 30.223

Volume Water (scf), Vwstd 2.226 2.462 2.542

Meter Volume (dscf), Vmstd: 29.010 30.737 30.931

Wet Fraction (v/v), Bws: 0.071 0.074 0.076

Molec. Wt. Wet (lb/lb-mole), Ms: 29.342 29.318 29.295

Stack Gas Sampled (acf), Vma: 46.888 50.070 50.811 Averages

Stack Gas Velocity (fps), Vs: 79.96 81.85 80.96 81

Volumetric Flowrate (dscfm), Qs: 1,128,402 1,146,081 1,124,093 1,132,859

Volumetric Flowrate (acfm), Qa: 1,823,822 1,866,946 1,846,563 1,845,777

Grainloading (gr/dscf), cs: 0.0070 0.0066 0.0072 0.01

Emission Rate (lb/hour), E: 67.76 64.96 69.28 67.3

Percent Isokinetic Sampling (%), I: 94.58 98.67 101.23 98.16

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780

Heat Input (mmBtu/hour): 4593.06 4698.66 4575.52 4622.41

Emission Rate (lbs/mmBtu), E: 0.01 0.01 0.02 0.01

Allowable Rate (lb/mmBtu): 0.240 0.240 0.240 0.240

Average Unit Gross Load (MW) 475 481 482 479

Particulate Emission Results Summary

Hammond Unit 4

Page 50 of 61 Att. 2
ATTACHMENT 3 - Hammond Report 3 Test Results

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

Run 1 Run 2 Run 3

Test Date 2/6/2008 2/6/2008 2/7/2008

Run Start Time 11:10 13:05 08:10

Run End Time 12:25 14:20 08:25

Meter Volume (dacf), Vm: 50.728 51.992 50.716

Sqrt Delta P ("wc): 1.01 1.01 1.00

Sampling Time (min): 60 60 60

Barometric Pressure ("Hg), Pbar: 28.98 28.98 29.25

Delta H ("wc): 2.2 2.1 2.1

Volume in Impingers (mls), VIc: 64.9 66.3 67.1

Static Pressure ("wc), Pg: -2.40 -2.30 -2.50

Stack Pressure ("Hg), Ps: 28.80 28.81 29.07

Stack Temperature (F), Ts: 278 279 261

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: 99 101 81

Stack Diameter (inches): 252 252 252

Area Stack (sq. ft.), As: 346.36 346.36 346.36

Nozzle Diameter (inches), dp: 0.240 0.240 0.240

Area Nozzle (sq. ft.), An: 0.000314 0.000314 0.000314

Percent CO2 (% dry volume): 11.0 11.1 11.0

Percent O2 (% dry volume): 8.1 7.9 8.0

Percent (N2 + CO) (% dry volume): 80.9 81.0 81.0

Particulate Collected (mg), Mn: 89.8 87.8 96.3

Molec. Wt. Dry (lb/lb-mole), Md: 30.088 30.088 30.085

Volume Water (scf), Vwstd 3.055 3.121 3.158

Meter Volume (dscf), Vmstd: 46.032 47.006 48.004

Wet Fraction (v/v), Bws: 0.062 0.062 0.062

Molec. Wt. Wet (lb/lb-mole), Ms: 29.336 29.335 29.339

Stack Gas Sampled (acf), Vma: 71.285 72.851 71.941 Averages

Stack Gas Velocity (fps), Vs: 67.69 67.55 65.75 67

Volumetric Flowrate (dscfm), Qs: 908,331 905,724 911,738 908,598

Volumetric Flowrate (acfm), Qa: 1,406,650 1,403,714 1,366,373 1,392,246

Grainloading (gr/dscf), cs: 0.0301 0.0288 0.0309 0.03

Emission Rate (lb/hour), E: 234.36 223.88 241.77 233.3

Percent Isokinetic Sampling (%), I: 93.18 95.42 96.81 95.14

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780

Heat Input (mmBtu/hour): 3421.76 3447.39 3452.44 3440.53

Emission Rate (lbs/mmBtu), E: 0.07 0.06 0.07 0.068

Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.240

Average Sum Gross Load (MW) 328 328 323 326

Particulate Emission Results Summary

Hammond Units 1-3

Page 51 of 61 Att. 3
ATTACHMENT 4 - Hammond Report 4 Test Results

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

Run 1 Run 2 Run 3

Test Date 2/6/2008 2/6/2008 2/7/2008

Run Start Time 11:10 13:05 8:10

Run End Time 12:25 14:20 9:25

Meter Volume (dacf), Vm: 45.6 47.735 47.1

Sqrt Delta P ("wc): 1.20 1.22 1.24

Sampling Time (min): 60 60 60

Barometric Pressure ("Hg), Pbar: 28.98 28.98 29.25

Delta H ("wc): 1.7 1.8 1.8

Volume in Impingers (mls), VIc: 71.2 71.9 76.9

Static Pressure ("wc), Pg: -2.80 -2.70 -2.70

Stack Pressure ("Hg), Ps: 28.77 28.78 29.05

Stack Temperature (F), Ts: 308 310 287

Meter Coefficient (no units), Y: 0.998 0.998 0.998

Pitot Coefficient (no units) Cp: 0.840 0.840 0.840

Meter OutletTemperature (F), Tm: 90 89 72

Stack Diameter (inches): 264 264 264

Area Stack (sq. ft.), As: 380.13 380.13 380.13

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): 12.0 12.0 12.0

Percent O2 (% dry volume): 7.0 7.0 7.0

Percent (N2 + CO) (% dry volume): 81.0 80.9 81.0

Particulate Collected (mg), Mn: 45.6 45.6 26.7

Molec. Wt. Dry (lb/lb-mole), Md: 30.204 30.207 30.205

Volume Water (scf), Vwstd 3.351 3.384 3.620

Meter Volume (dscf), Vmstd: 42.514 44.541 45.811

Wet Fraction (v/v), Bws: 0.073 0.071 0.073

Molec. Wt. Wet (lb/lb-mole), Ms: 29.312 29.345 29.312

Stack Gas Sampled (acf), Vma: 69.347 72.633 72.040 Averages

Stack Gas Velocity (fps), Vs: 82.13 83.66 83.26 83

Volumetric Flowrate (dscfm), Qs: 1,148,396 1,170,183 1,207,520 1,175,366

Volumetric Flowrate (acfm), Qa: 1,873,227 1,908,197 1,898,882 1,893,436

Grainloading (gr/dscf), cs: 0.0165 0.0158 0.0090 0.01

Emission Rate (lb/hour), E: 162.73 158.27 93.25 138.1

Percent Isokinetic Sampling (%), I: 97.34 100.09 99.76 99.06

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780

Heat Input (mmBtu/hour): 4696.92 4763.13 4926.92 4795.65

Emission Rate (lbs/mmBtu), E: 0.03 0.03 0.02 0.029

Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.240

Average Unit Gross Load (MW) 485 486 487 486

Particulate Emission Results Summary

Hammond Unit 4

Page 52 of 61 Att. 4
ATTACHMENT 5 - Hammond Report 5 Test Results

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

Run 1 Run 2 Run 3

Test Date 4/22/2008 4/22/2008 4/22/2008

Run Start Time 9:05 10:55 12:25

Run End Time 10:30 12:05 0:00

Meter Volume (dacf), Vm: 43.279 43.485 43.672

Sqrt Delta P ("wc): 0.97 0.98 0.98

Sampling Time (min): 60 60 60

Barometric Pressure ("Hg), Pbar: 28.85 28.90 28.90

Delta H ("wc): 1.4 1.4 1.4

Volume in Impingers (mls), VIc: 118.2 116.5 117.6

Static Pressure ("wc), Pg: -0.60 -0.60 -0.70

Stack Pressure ("Hg), Ps: 28.81 28.86 28.85

Stack Temperature (F), Ts: 121 121 121

Meter Coefficient (no units), Y: 0.998 0.998 0.998

Pitot Coefficient (no units) Cp: 0.840 0.840 0.840

Meter OutletTemperature (F), Tm: 85 89 90

Stack Diameter (inches): 396 396 396

Area Stack (sq. ft.), As: 855.30 855.30 855.30

Nozzle Diameter (inches), dp: 0.214 0.214 0.214

Area Nozzle (sq. ft.), An: 0.000249 0.000249 0.000249

Percent CO2 (% dry volume): 10.8 10.9 10.8

Percent O2 (% dry volume): 8.1 8.0 8.2

Percent (N2 + CO) (% dry volume): 81.1 81.1 81.0

Particulate Collected (mg), Mn: 51.1 68.0 32.3

Molec. Wt. Dry (lb/lb-mole), Md: 30.056 30.064 30.056

Volume Water (scf), Vwstd 5.564 5.484 5.535

Meter Volume (dscf), Vmstd: 40.487 40.466 40.521

Wet Fraction (v/v), Bws: 0.121 0.119 0.120

Molec. Wt. Wet (lb/lb-mole), Ms: 28.599 28.624 28.607

Stack Gas Sampled (acf), Vma: 52.611 52.411 52.516 Averages

Stack Gas Velocity (fps), Vs: 58.42 59.05 59.32 59

Volumetric Flowrate (dscfm), Qs: 2,306,951 2,339,463 2,348,915 2,331,776

Volumetric Flowrate (acfm), Qa: 2,997,742 3,030,075 3,044,274 3,024,030

Grainloading (gr/dscf), cs: 0.0195 0.0259 0.0123 0.02

Emission Rate (lb/hour), E: 385.05 520.25 247.69 384.3

Percent Isokinetic Sampling (%), I: 100.46 99.01 98.75 99.41

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780

Heat Input (mmBtu/hour): 8690.48 8858.74 8756.63 8768.62

Emission Rate (lbs/mmBtu), E: 0.04 0.06 0.03 0.04

Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.24

Average Unit 1 Gross Load (MW) 114 114 114 114

Particulate Emission Results Summary

Hammond Units 1-4 FGD

Page 53 of 61 Att. 5
ATTACHMENT 5 - Hammond Report 5 Test Results

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

Run 1 Run 2 Run 3

Particulate Emission Results Summary

Hammond Units 1-4 FGD

Average Unit 2 Gross Load (MW) 115 115 115 115

Average Unit 3 Gross Load (MW) 115 116 117 116

Average Unit 4 Gross Load (MW) 500 500 500 500

Average Sum Gross Load (MW) 844 845 846 845

Page 54 of 61 Att. 5
ATTACHMENT 6 - Hammond Report 6 Test Results

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

Run 1 Run 2 Run 3

Test Date 4/24/2008 4/24/2008 4/24/2008

Run Start Time 14:30 16:35 18:40

Run End Time 15:50 18:00 19:50

Meter Volume (dacf), Vm: 43.725 45.122 44.007

Sqrt Delta P ("wc): 0.97 1.00 1.00

Sampling Time (min): 60 60 60

Barometric Pressure ("Hg), Pbar: 28.98 28.98 28.98

Delta H ("wc): 1.4 1.4 1.4

Volume in Impingers (mls), VIc: 118.6 121.2 117.6

Static Pressure ("wc), Pg: -0.60 -0.55 -0.50

Stack Pressure ("Hg), Ps: 28.94 28.94 28.94

Stack Temperature (F), Ts: 119 121 121

Meter Coefficient (no units), Y: 0.998 0.998 0.998

Pitot Coefficient (no units) Cp: 0.840 0.840 0.840

Meter OutletTemperature (F), Tm: 92 90 94

Stack Diameter (inches): 396 396 396

Area Stack (sq. ft.), As: 855.30 855.30 855.30

Nozzle Diameter (inches), dp: 0.214 0.214 0.214

Area Nozzle (sq. ft.), An: 0.000250 0.000250 0.000250

Percent CO2 (% dry volume): 11.2 11.3 11.1

Percent O2 (% dry volume): 8.0 8.1 8.1

Percent (N2 + CO) (% dry volume): 80.8 80.7 80.8

Particulate Collected (mg), Mn: 35.0 58.6 71.4

Molec. Wt. Dry (lb/lb-mole), Md: 30.117 30.125 30.100

Volume Water (scf), Vwstd 5.583 5.705 5.535

Meter Volume (dscf), Vmstd: 40.553 41.993 40.656

Wet Fraction (v/v), Bws: 0.121 0.120 0.120

Molec. Wt. Wet (lb/lb-mole), Ms: 28.651 28.675 28.650

Stack Gas Sampled (acf), Vma: 52.343 54.279 52.574 Averages

Stack Gas Velocity (fps), Vs: 58.46 60.08 60.12 60

Volumetric Flowrate (dscfm), Qs: 2,324,458 2,385,435 2,385,780 2,365,224

Volumetric Flowrate (acfm), Qa: 3,000,222 3,083,378 3,085,124 3,056,241

Grainloading (gr/dscf), cs: 0.0133 0.0215 0.0271 0.02

Emission Rate (lb/hour), E: 265.60 440.32 554.50 420.1

Percent Isokinetic Sampling (%), I: 99.63 100.53 97.32 99.16

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780

Heat Input (mmBtu/hour): 8801.92 8986.14 8964.09 8917.38

Emission Rate (lbs/mmBtu), E: 0.030 0.049 0.062 0.047

Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.24

Average Unit 1 Gross Load (MW) 115 115 115 115

Particulate Emission Results Summary

Hammond Units 1-4 FGD CAM

Page 55 of 61 Att. 6
ATTACHMENT 6 - Hammond Report 6 Test Results

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

Run 1 Run 2 Run 3

Particulate Emission Results Summary

Hammond Units 1-4 FGD CAM

Average Unit 2 Gross Load (MW) 115 115 115 115

Average Unit 3 Gross Load (MW) 116 118 116 117

Average Unit 4 Gross Load (MW) 500 500 500 500

Average Sum Gross Load (MW) 846 848 846 847

Run 1 Run 2 Run 3

Test Date 4/24/2008 4/24/2008 4/24/2008

Run Start Time 7:35 9:25 11:50

Run End Time 8:50 10:40 13:05

Meter Volume (dacf), Vm: 52.048 53.105 54.32

Sqrt Delta P ("wc): 0.62 0.63 0.64

Sampling Time (min): 60 60 60

Barometric Pressure ("Hg), Pbar: 29.02 29.02 29.02

Delta H ("wc): 2.0 2.1 2.2

Volume in Impingers (mls), VIc: 141.2 142.6 148.0

Static Pressure ("wc), Pg: -0.27 -0.30 -0.36

Stack Pressure ("Hg), Ps: 29.00 29.00 28.99

Stack Temperature (F), Ts: 114 115 116

Meter Coefficient (no units), Y: 0.998 0.998 0.998

Pitot Coefficient (no units) Cp: 0.840 0.840 0.840

Meter OutletTemperature (F), Tm: 82 86 89

Stack Diameter (inches): 396 396 396

Area Stack (sq. ft.), As: 855.30 855.30 855.30

Nozzle Diameter (inches), dp: 0.292 0.292 0.292

Area Nozzle (sq. ft.), An: 0.000463 0.000463 0.000463

Percent CO2 (% dry volume): 8.3 8.4 8.2

Percent O2 (% dry volume): 11.2 11.2 11.4

Percent (N2 + CO) (% dry volume): 80.5 80.4 80.4

Particulate Collected (mg), Mn: 49.1 38.3 38.4

Molec. Wt. Dry (lb/lb-mole), Md: 29.781 29.792 29.773

Volume Water (scf), Vwstd 6.646 6.712 6.966

Meter Volume (dscf), Vmstd: 49.296 50.006 50.847

Wet Fraction (v/v), Bws: 0.119 0.118 0.120

Molec. Wt. Wet (lb/lb-mole), Ms: 28.382 28.397 28.355

Stack Gas Sampled (acf), Vma: 62.754 63.731 65.054 Averages

Stack Gas Velocity (fps), Vs: 37.00 37.93 38.70 38

Volumetric Flowrate (dscfm), Qs: 1,491,368 1,527,488 1,552,367 1,523,741

Volumetric Flowrate (acfm), Qa: 1,898,523 1,946,732 1,986,097 1,943,784

Grainloading (gr/dscf), cs: 0.0154 0.0118 0.0116 0.01

Emission Rate (lb/hour), E: 196.49 154.61 154.99 168.7

Percent Isokinetic Sampling (%), I: 101.74 100.76 100.82 101.11

Page 56 of 61 Att. 6
ATTACHMENT 6 - Hammond Report 6 Test Results

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

Run 1 Run 2 Run 3

Particulate Emission Results Summary

Hammond Units 1-4 FGD CAM

F-Factor (dscf/mmBtu), F: 9780 9780 9780 9780

Heat Input (mmBtu/hour): 4246.42 4349.26 4328.97 4308.22

Emission Rate (lbs/mmBtu), E: 0.046 0.036 0.036 0.039

Allowable Rate (lb/mmBtu): 0.24 0.24 0.24 0.24

Average Unit 1 Gross Load (MW) 115 115 115 115

Average Unit 2 Gross Load (MW) 40 40 41 40

Average Unit 3 Gross Load (MW) 40 40 41 40

Average Unit 4 Gross Load (MW) 180 180 180 180

Average Sum Gross Load (MW) 375 375 377 376

Page 57 of 61 Att. 6
ATTACHMENT 7 - Hammond Report 7 Test Results

Start 

Time

End 

Time

Unit 

Load

Avg. 

Econ. Gas 

Outlet CO 

Avg. 

Econ. Gas 

Outlet O2 

Avg. 

Econ. Gas 

Outlet 

CO2

Military Military MW ppm % Dry % Dry

1

Full Load, "As Found", O2 SP @ 3.2%, 

SOFA in auto at 45%

4/20/2009 13:22 14:10 510 99 3.11 15.41

2

Full Load, "As Found", O2 SP @ 3.2%, 

SOFA in auto at 45%

4/20/2009 15:31 16:19 510 124 3.07 15.43

5

Full Load, O2 SP 3.8%, SOFA in auto at 

50%, burner adjustments 4/21/2009 13:25 14:13 510 152 3.42 15.15

7

Full Load, O2 SP 3.5%, SOFA dampers in 

manual @ 25%, burner adjustments 4/22/2009 10:48 11:36 510 261 3.55 15.15

8

Full Load, O2 SP 3.4%, SOFA dampers in 

manual @ 25%, burner adjustments 4/22/2009 15:26 510 284 3.48 15.17

9

Full Load, O2 SP 3.5%, SOFA in auto @ 

45%, final sleeve settings 4/23/2009 7:47 8:35 510 314 3.58 15.14

10 Minimum Load, No O2 Bias, SOFA closed 

at 5% 

4/24/2009 8:03 8:51 225 31 5.74 13.11

Hammond Unit 4

LNB Optimization Test Results Summary

Title 

of Run Description Date

Page 58 of 61 Att. 7
ATTACHMENT 8 - Hammond Report 8 Test Results

Hammond Scrubber Performance Hg Test Results

Ontario Hydro Test Results Summary

Inlet O2 Outlet O2

%, dry %, dry Inlet HgO Inlet Hg+2 Inlet HgT % Oxidized Outlet HgO Outlet Hg+2 Outlet HgT % Oxidized

1 6/13/2008 1602-1802 6.8 6.9 0.61 3.16 3.77 83.80% 0.62 0.77 1.39 55.40%

2 6/14/2008 1004-1204 6.8 6.9 0.23 3.99 4.22 94.50% 0.5 0.7 1.2 58.30%

3 6/15/2008 0953-1153 6.8 6.9 0.67 6.14 6.81 90.20% 0.92 0.27 1.19 22.70%

4 6/16/2008 1430-1630 6.8 6.9 0.65 5.9 6.55 90.10% 0.94 0.32 1.26 25.40%

5 6/17/2008 1009-1220 6.8 6.9 0.54 6.19 6.73 92.00% 0.71 0.07 0.78 9.00%

6 6/18/2008 1258-1458 6.8 6.9 0.45 4.99 5.44 91.70% 0.52 0.09 0.61 14.80%

7 6/18/2008 1743-1943 6.8 6.9 0.18 7.99 8.17 97.80% 1.17 0.08 1.25 6.40%

1 6/13/2008 1602-1802 6.8 6.9 0.83 4.3 5.13 83.80% 0.85 1.05 1.9 55.40% 75%

2 6/14/2008 1004-1204 6.8 6.9 0.31 5.43 5.74 94.50% 0.69 0.96 1.64 58.30% 76%

3 6/15/2008 0953-1153 6.8 6.9 0.91 8.35 9.26 90.20% 1.26 0.37 1.63 22.70% 91%

4 6/16/2008 1430-1630 6.8 6.9 0.88 8.03 8.91 90.10% 1.29 0.44 1.73 25.40% 90%

5 6/17/2008 1009-1220 6.8 6.9 0.73 8.42 9.16 92.00% 0.97 0.1 1.07 9.00% 96%

6 6/18/2008 1258-1458 6.8 6.9 0.61 6.79 7.4 91.70% 0.71 0.12 0.84 14.80% 97%

7 6/18/2008 1743-1943 6.8 6.9 0.24 10.87 11.11 97.80% 1.6 0.11 1.71 6.40% 87%

1

 Based upon guarantee equation – no credit given for elemental mercury removal, elemental re-emission noted in all cases.

Absorber Outlet

UN-CORRECTED VALUES (ug/m3, actual O2, dry, 68 oF)

CORRECTED VALUES (ug/Nm3, 3% O2, dry, 0 oC) 

Hg2+ 

Removal 

Efficiency1

Run Date Time

Absorber Inlet

Page 59 of 61 Att. 8
ATTACHMENT 8 - Hammond Report 8 Test Results

Hammond Scrubber Performance Hg Test Results

EPA Method 30B (Sorbent Trap) Summary Data – Absorber Inlet

O2 Regular Trap

%, dry Inlet HgO Inlet Hg+2 Inlet HgT % Oxidized Inlet HgT

1 6/13/2008 1606-1806 6.8 2.29 1.54 3.85 40.00% 3.85

2 6/14/2008 1000-1200 6.8 2.06 1.9 4 47.50% 4

3 6/15/2008 0950-1150 6.8 na 0.6 na na 9.34

4 6/16/2008 1427-1627 6.8 6.85 3.05 9.93 30.70% 10.5

5 6/17/2008 1008-1208 6.8 3.71 4.34 8.08 53.70% 7.48

6 6/18/2008 1255-1455 6.8 2.45 2.32 4.79 48.40% 4.9

7 6/18/2008 1740-1940 6.8 2.69 2.06 4.77 43.20% 5.15

1 6/13/2008 1606-1806 6.8 3.12 2.09 5.24 40.20% 5.24

2 6/14/2008 1000-1200 6.8 2.8 2.58 5.44 48.00% 5.44

3 6/15/2008 0950-1150 6.8 na 0.82 na na 12.71

4 6/16/2008 1427-1627 6.8 9.32 4.15 13.51 30.80% 14.28

5 6/17/2008 1008-1208 6.8 5.05 5.9 10.99 53.90% 10.18

6 6/18/2008 1255-1455 6.8 3.33 3.16 6.52 48.60% 6.67

7 6/18/2008 1740-1940 6.8 3.66 2.8 6.49 43.40% 7.01

CORRECTED VALUES (ug/Nm3, 3% O2, dry, 0 oC) 

UN-CORRECTED VALUES (ug/m3, actual O2, dry, 68 oF)

Speciated Trap

Run Date Time

Page 60 of 61 Att. 8
ATTACHMENT 8 - Hammond Report 8 Test Results

Hammond Scrubber Performance Hg Test Results

Continuous Mercury Data – Daily Averages

Hg0 Hg+2 HgT % Hg+2 Hg0 Hg+2 HgT % Hg+2

6/12/2008 0821-2355 1.22 3.47 4.69 74% 1.02 0.07 1.09 6% -0.2 98%

6/13/2008 0003-2356 0.66 3.3 3.96 83% 0.58 0.05 0.63 8% -0.08 98%

6/14/2008 1026-2349 1.06 4.71 5.77 82% 1.27 0.19 1.46 13% 0.21 92%

6/15/2008 0149-2353 0.95 6.16 7.11 87% 1.31 0.14 1.45 10% 0.36 92%

6/16/2008 0908-1732 1.86 7.26 9.12 80% 2.98 0.12 3.1 4% 1.12 83%

6/17/2008 0151-1305 0.8 8.9 9.7 92% 1.12 0.04 1.16 3% 0.32 96%

6/18/2008 0151-1305 0.55 5.37 5.92 91% 0.92 0 0.92 0% 0.37 93%

6/19/2008 0000-1236 0.25 5.43 5.68 96% 0.38 0.05 0.43 12% 0.13 97%

Continuous Mercury Data –Averages Corresponding to Ontario Hydro Run Times

Hg0 Hg+2 HgT % Hg+2 Hg0 Hg+2 HgT % Hg+2

1 6/13/2008 1602-1802 0.91 3.08 3.99 77.20% 0.92 0.08 1 8.00% 0.01 97%

2 6/14/2008 1004-1204 0.66 3.46 4.12 84.00% 0.9 0.14 1.04 13.50% 0.24 89%

3 6/15/2008 0953-1153 1.16 5.5 6.66 82.60% 1.6 0.15 1.75 8.60% 0.44 89%

4 6/16/2008 1430-1630 1.78 7.59 9.37 81.00% 2.98 0.18 3.16 5.70% 1.2 82%

5 6/17/2008 1009-1220 1.41 7.65 9.06 84.40% 2.26 0.01 2.27 0.40% 0.85 89%

6 6/18/2008 1258-1458 0.64 5.42 6.06 89.40% 1.11 0.02 1.13 1.80% 0.47 91%

7 6/18/2008 1743-1943 0.55 5.22 5.77 90.50% 1.11 0.05 1.16 4.30% 0.56 88%

Hg0 Reemission

Hg+2 

Removal - 

guarantee 

Hg+2 

Removal - 

Date Time guarantee 

Inlet (ug/m3 @ 3% O2, 0 C) Outlet (ug/m3 @ 3% O2, 0 C) Hg0 Reemission

Run Date Time

Inlet (ug/Nm3 @ 3% O2, dry, 0 C) Outlet (ug/Nm3 @ 3% O2, dry, 0 C)

Page 61 of 61 Att. 8