GEORGIA POWER ‐ Submittal for PLANT MITCHELL

Electric Utility Steam Generating Unit (EGU) Hazardous Air Pollutant Emissions (HAPs) Information Collection Request (ICR), OMB 

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, qu

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

Mitchell

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 

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

727

5 Complete street address of facility (physical location):

5200 Radium Springs Rd.

Albany, GA 31705

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 26 
GEORGIA POWER ‐ Submittal for PLANT MITCHELL

Electric Utility Steam Generating Unit (EGU) Hazardous Air Pollutant Emissions (HAPs) Information Collection Request (ICR), OMB 

April 5, 2010

PART I: GENERAL FACILITY INFORMATION

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

_

X

__

coal

__

X

__

oil (including pet coke) ___ natural gas

___

other (specify in question 14 below)

11 Which of the following fossil fuel or other material(s) are permitted1 to be fired in any steam generating unit at this facility?

_

X

__

coal

_

X

__

oil (including pet coke) ___ natural gas

_

X

__

other (specify in question 14 below)

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

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 process

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 26 
GEORGIA POWER ‐ Submittal for PLANT MITCHELL

Electric Utility Steam Generating Unit (EGU) Hazardous Air Pollutant Emissions (HAPs) Information Collection Request (ICR), OMB 

April 5, 2010

PART I: GENERAL FACILITY INFORMATION

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

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 quantitie

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

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 limit

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 a

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").

None in 2009

Permitted to burn

YesYes

None in 2009

Quantity/year

None in 2009

None in 2009 None in 2009

Synfuel None in 2009

None in 2009

Other Material

SawdustBiomassUsed Oil Yes

Actually burn

None in 2009

Yes

Page 3 of 26 
GEORGIA POWER ‐ PLANT MITCHELL

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

Original design fuel (i.e.,

coal rank or type of oil)

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 (o

F)

Operating steam

temperature(

o

F)

Design steam reheat

temperature(

o

F)

9

Operating steam reheat

temperature(

o

F)10

3 bituminous CBI CBI 164 155 89.18 88.91 1800 1801 1000 989 1000 995 

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

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

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

7 Per fuel burned in the boiler. Report this based on higher heating value (HHV).8 Per fuel burned in the boiler. Report this based on higher heating value (HHV).9 Please indicate if more than one steam reheat cycle is utilized, and, if so, please provide information for both.10 Please indicate if more than one steam reheat cycle is utilized, and, if so, please provide information for both.11 Indicate the fuels utilized for the indicated boiler, and percentages, as indicated in questions 11 ‐ 13.12 The "hours/year operated" would be the average of the actual number of hours the unit operated in 1 year based on the last 3 years of operation.13 This can be treated as CBI and can be submitted through the proper CBI procedure if desired.

NOTES: Original Design Fuel

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

Design Heat Input

Confidential Business Information

Present Maximum Heat Input

Confidential Business Information

MWe Gross Capacity Summer

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

MWe Net Capacity Summer

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

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 availab

Design Steam Pressure

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

Page 4 of 26 
GEORGIA POWER ‐ PLANT MITCHELL

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

Original design fuel (i.e.,

coal rank or type of oil)

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 (o

F)

Operating steam

temperature(

o

F)

Design steam reheat

temperature(

o

F)

9

Operating steam reheat

temperature(

o

F)10

Operating Steam PressureRepresents the average throttle pressure when the unit operated at gross normal full load over a three year period (January 2007 to December 200

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 2

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 Dece

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 an actual retirement date for Plant Mitchell Unit 3. Georgia Power continually evaluates retirement scenarios 

purposes, taking into account a wide range of variables. While the company assumes financial "retirement dates" for accounting purposes, for exam

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

Page 5 of 26 
GEORGIA POWER ‐ PLANT MITCHELL

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 installe

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

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

Boiler ID14 Type15 NOx control16 SO2 control17 PM control18 Other 

3 tangential‐fired Not applicable Not applicable (1) cold‐side electrostatic

precipitator (ESP) (4/1975)

Not applicabl

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

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

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

15 Examples: tangential‐fired; cyclone; wall‐fired; circulating fluidized bed (CFB)16 Examples: low‐NOx burners; selective catalytic reduction (SCR); selective non‐catalytic reduction (SNCR); over‐fire air (OFA). Include

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

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

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

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

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

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

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

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

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

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

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

Page 6 of 26 
GEORGIA POWER ‐ PLANT MITCHELL

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 informati

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

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

etc.).

Name Telephone Addr

3 Not applicable Not applicable Not applicable Not app

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 t

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 5

[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 1

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 7 of 26 
GEORGIA POWER ‐ PLANT MITCHELL

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 (i

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

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

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

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

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

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

Boiler ID22

Demonstration

activity actual start‐

up 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 reduct

(%) or emission 

3 Not applicable Not applicable Not applicable Not applicable Not applicabl

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 5

[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 1

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 8 of 26 
GEORGIA POWER ‐ PLANT MITCHELL

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 informati

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

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

Name Telephone Addres

3 Not applicable Not applicable Not applicable Not applica

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 5

[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 1

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

Company (vendor) contact information Boiler ID24 Company (vendor) name

Page 9 of 26 
GEORGIA POWER ‐ PLANT MITCHELL

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 current

date of expected or projected start‐up, the type of HAP control installed (e.g., sorbent and type; pre‐construction boile

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

guarantee is based, and the coal rank(s) upon which the guarantee is based. Please specify the format of the guarantee 

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

rate would be (and specify the format of the equivalent emission rate), and (2) the basis for calculating the percent red

"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 addit

feed rate on wh

guarantee is bas

3 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 5

[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 1

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 10 of 26 
GEORGIA POWER ‐ PLANT MITCHELL

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 

3 E = 0.7 x (10/R)^0.202, where E equals the

allowable particulate emission rate in pounds

per million Btu heat input and R equals the heat

input in million Btu per hour (Title V permit;

based on 3‐run stack test using Method 5 of 17;

test conducted every 13 months, but may be

deferred for 12 months if test results from the

previous annual tests are fifty percent or less of

the limit)

Notapplicable

Notapplicable

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)

Notapplicable

Notapplicable

Notapplicable

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.

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

Boiler ID27

Page 11 of 26 
GEORGIA POWER ‐ PLANT MITCHELL

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 te

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

PM33 PM10 PM2.5 SO2 HCl and/or HF HCN Metal HAP34 

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

2000)

Notapplicable

Notapplicable

Not applicable Not

applicable

Notapplicable

Notapplicable

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 perm

Boiler ID32

Page 12 of 26 
GEORGIA POWER ‐ PLANT MITCHELL

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 

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

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

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

than 40%) reported quarterly.

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

within 60 days of completion of the testing.

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

Notapplicable

Notapplicable

Coal sulfur content monitored through daily co

fuel oil sulfur content monitored through vend

certification; exceedances of 3% limit reported 

records retained for 5 years.

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.

Required monitoring, recordkeeping, and reporting requirements for each pollutant for which t

Boiler ID35

Page 13 of 26 
GEORGIA POWER ‐ PLANT MITCHELL

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 applicableInstallation 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., lo

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 14 of 26 
GEORGIA POWER ‐ PLANT MITCHELL

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:

Mitchell

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

727

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

Page 15 of 26 
GEORGIA POWER ‐ PLANT MITCHELL

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 info

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 m

from each seam listed. The information being provided is on a shipment by shipment basis. Georgia Power cannot gua

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

State/Country County42 Coal seam43 

10,425 3 KY HARLAN

HARLAN, HIGH SPLINT,

IMBODE, LOW SPLINT,

WINIFREDE TRAIN 

10,454 3 KY HARLAN

HARLAN, HIGH SPLINT,

IMBODE, LOW SPLINT,

WINIFREDE TRAIN 

10,326 3 KY HARLAN

HARLAN, HIGH SPLINT,

IMBODE, LOW SPLINT,

WINIFREDE TRAIN 

10,221 3 KY HARLAN

HARLAN, HIGH SPLINT,

IMBODE, LOW SPLINT,

WINIFREDE TRAIN 

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

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 5

[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 1

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.

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s)

firing fuel41

Fuel shipment

method

Page 16 of 26 
GEORGIA POWER ‐ PLANT MITCHELL

EGU HAPs ICR, OMB Control No. 2060‐0631

April 5, 2010

3 For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information 44, as

available (dry basis) (indicate N/A if not available):

NOTES: "ND" indicates results are non detect. All results presented on a dry basis.

Georgia Power collects this information on select coal shipments on a quarterly basis, but does not have this information available on a shipment by shipment basis. The info

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 

Antimony Arsenic Beryllium Cadmium Chromium Coba

09‐208 22,300 1.01 10.53 13,482 0.056 1301 71 12.3 1.1 6.8 2.5 0.04 14.6 

09‐404 11,324 0.96 10.64 13,265 ND 95 64 12.0 1.2 7.2 2.0 0.05 16.7 

09‐222 11,142 0.89 8.72 13,685 ND ND 59 10.3 1.0 3.8 3.1 0.02 11.6 

09‐418 12,392 1.12 11.36 13,390 ND 111 89 13.9 1.3 9.7 2.1 <0.02 17.3 

09‐424 11,170 1.06 10.8 13,433 ND 111 84 18.0 1.0 6.7 2.5 0.07 19.6 109‐240 12,908 1.01 9.46 13,576 ND 1501 133 11.7 1.0 5.7 2.5 0.05 14.0 

09‐443 12,664 0.9 10.3 13,598 ND 105 60 12.4 1.0 4.7 2.1 0.03 16.7 

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.

Total amount of

fuel represented

by sample, tons

Sample

ID #

Nickel, ppm Other trace metal HAP, ppm

Total Sulfur, % Ash Content, % Heating Value, Btu/lb Mercury, ppm Chlorine, ppm Fluorine, ppm

Page 17 of 26 
GEORGIA POWER ‐ PLANT MITCHELL

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 18 of 26 
GEORGIA POWER ‐ PLANT MITCHELL

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 

09‐208 6.52 36.53 10.53 52.94 76.33 4.92 1.65 1.01 5.56 112 19.3 0.073 0.032 28.2 

09‐404 6.37 34.25 10.64 55.11 77.44 4.83 1.51 0.96 4.6 122 20.9 0.071 0.034 33.5 

09‐222 6.43 36.45 8.72 54.83 74.25 4.95 1.82 0.89 9.37 92 17.0 0.045 0.035 26.1 

09‐418 5.99 34.06 11.36 54.58 75.53 4.88 1.48 1.12 5.63 102 20.7 0.075 0.037 35.9 

09‐424 6.46 34.53 10.8 54.66 75.06 4.72 1.6 1.06 6.76 81 27.0 0.062 0.030 40.6 

09‐240 7.39 35.3 9.46 55.23 75.99 4.79 1.72 1.01 7.04 92 16.2 0.051 0.032 26.4 

09‐443 6.03 34.1 10.3 55.59 76.39 4.73 1.53 0.9 6.14 81 19.5 0.064 0.033 32.1 

Sample

ID #

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

Page 19 of 26 
GEORGIA POWER ‐ PLANT MITCHELL

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 no

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

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

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

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

Report 1 Unit 3 Particulate Emissions Test (August 8, 2006)

Report 2 Unit 3 Particulate Emissions Test (August 6, 2008)

Report 3 Unit 3 Boiler Baseline Test (February 27, 2008 to February 28, 2008)

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

air pollutants) sampled for:

Report 1 Date: 8/8/2006 Type: stack Constituents: PM

Report 2 Date: 8/6/2008 Type: stack Constituents: PM

Report 3 Date: 2/27/2008‐2/28/2008 Type: duct Constituents: CO

8c Do any of these test reports reflect testing at a location upstream of any emission control devices?

Yes

_

X

___

No ____ If yes, please note which reports and provide a detailed description of the location of the emissio

Report 3 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.

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

____

No

_

X

___

If yes, please list the unit's complete control configuration at time of testing in a similar format t

Page 20 of 26 
GEORGIA POWER ‐ PLANT MITCHELL

EGU HAPs ICR, OMB Control No. 2060‐0631

April 5, 2010

8g Do any of these test reports reflect testing at a location before a post combustion SO2 emission control device (e.g., FG

Yes

____

No

_

X

___

If yes, please note which reports and, in addition to the detailed description of the location of th

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

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

Page 21 of 26 
GEORGIA POWER ‐ PLANT MITCHELL

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 syste

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 to

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

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 

that this CEM data by submitted by the respondent. The respondent should also mark the periods of start up, shut down and malfu

in the data sets.

Page 22 of 26 
GEORGIA POWER ‐ PLANT MITCHELL

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 t

Date of test PM49 SO2 HCl/HF/HCN Metal HAP50 Hg51 

3 8/8/2006 See Attachment 1 Not applicable Not applicable Not applicable Not applicable Not a

3 8/6/2008 See Attachment 2 Not applicable Not applicable Not applicable Not applicable Not a

3 2/27/2008‐2/28/2008 Not applicable Not applicable Not applicable Not applicable Not applicable See A

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 repo

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 

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

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 result

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 

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 record

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 

Boiler

ID

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

Page 23 of 26 
ATTACHMENT 1 ‐ Mitchell Report 1 Test Results

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

Run 1 Run 2 Run 3

Test Date 8/8/2006 8/8/2006 8/8/2006

Run Start Time 11:50 13:25 1455

Run End Time 13:00 14:35 16:05

Meter Volume (dacf), Vm: 36.66 37.055 37.455

Sqrt Delta P ("wc): 0.48 0.48 0.48

Sampling Time (min): 60 60 60

Barometric Pressure ("Hg), Pbar: 29.92 29.89 29.88

Delta H ("wc): 1.1 1.1 1.1

Volume in Impingers (mls), VIc: 63.3 67.4 65.4

Static Pressure ("wc), Pg: -1.00 -0.98 -1.00

Stack Pressure ("Hg), Ps: 29.85 29.82 29.81

Stack Temperature (F), Ts: 284 290 291

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: 100 100 102

Stack Diameter (inches): 252 252 252

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

Nozzle Diameter (inches), dp: 0.292 0.292 0.292

Area Nozzle (sq. ft.), An: 0.000465 0.000465 0.000465

Percent CO2 (% dry volume): 11.9 12.0 12.1

Percent O2 (% dry volume): 6.8 6.9 6.8

Percent (N2 + CO) (% dry volume): 81.3 81.1 81.1

Particulate Collected (mg), Mn: 31.5 20.9 19.5

Molec. Wt. Dry (lb/lb-mole), Md: 30.176 30.196 30.208

Volume Water (scf), Vwstd 2.980 3.173 3.078

Meter Volume (dscf), Vmstd: 34.562 34.867 35.142

Wet Fraction (v/v), Bws: 0.079 0.083 0.081

Molec. Wt. Wet (lb/lb-mole), Ms: 29.210 29.179 29.225

Stack Gas Sampled (acf), Vma: 53.047 54.243 54.588 Averages

Stack Gas Velocity (fps), Vs: 32.10 32.10 31.99 32

Volumetric Flowrate (dscfm), Qs: 434,618 428,864 427,955 430,479

Volumetric Flowrate (acfm), Qa: 667,076 667,182 664,765 666,341

Grainloading (gr/dscf), cs: 0.0140 0.0093 0.0085 0.01

Emission Rate (lb/hour), E: 52.33 34.03 31.35 39.2

Percent Isokinetic Sampling (%), I: 98.78 100.99 102.00 100.59

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

Heat Input (mmBtu/hour): 1798.84 1762.44 1771.27 1777.52

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

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

Average Unit Gross Load (MW) 164 164 164 164

Particulate Emission Results Summary

Mitchell Unit 3

Page 24 of 26 Att. 1
ATTACHMENT 2 ‐ Mitchell Report 2 Test Results

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

Run 1 Run 2 Run 3

Test Date 8/6/2008 8/6/2008 8/6/2008

Run Start Time 11:45 13:20 14:45

Run End Time 12:55 14:30 15:55

Meter Volume (dacf), Vm: 34.429 35.906 36.245

Sqrt Delta P ("wc): 0.44 0.45 0.46

Sampling Time (min): 60 60 60

Barometric Pressure ("Hg), Pbar: 29.75 29.75 29.75

Delta H ("wc): 0.9 1.0 1.0

Volume in Impingers (mls), VIc: 45.8 47.1 48.2

Static Pressure ("wc), Pg: -0.95 -1.00 -0.90

Stack Pressure ("Hg), Ps: 29.68 29.68 29.68

Stack Temperature (F), Ts: 296 299 299

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: 102 108 109

Stack Diameter (inches): 252 252 252

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

Nozzle Diameter (inches), dp: 0.292 0.292 0.292

Area Nozzle (sq. ft.), An: 0.000465 0.000465 0.000465

Percent CO2 (% dry volume): 12.6 12.3 12.4

Percent O2 (% dry volume): 6.1 6.2 6.3

Percent (N2 + CO) (% dry volume): 81.4 81.5 81.3

Particulate Collected (mg), Mn: 33.2 62.1 56.9

Molec. Wt. Dry (lb/lb-mole), Md: 30.253 30.221 30.231

Volume Water (scf), Vwstd 2.156 2.217 2.269

Meter Volume (dscf), Vmstd: 31.809 32.797 33.075

Wet Fraction (v/v), Bws: 0.063 0.063 0.064

Molec. Wt. Wet (lb/lb-mole), Ms: 29.476 29.448 29.446

Stack Gas Sampled (acf), Vma: 49.009 50.729 51.205

Stack Gas Velocity (fps), Vs: 29.56 30.16 30.55

Volumetric Flowrate (dscfm), Qs: 398,761 405,229 410,078

Volumetric Flowrate (acfm), Qa: 614,372 626,790 634,865

Grainloading (gr/dscf), cs: 0.0161 0.0292 0.0266

Emission Rate (lb/hour), E: 55.03 101.53 93.36

Percent Isokinetic Sampling (%), I: 99.08 100.53 100.18

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

Heat Input (mmBtu/hour): 1736.27 1748.57 1757.46

Emission Rate (lbs/mmBtu), E: 0.03 0.06 0.05

Allowable Rate (lb/mmBtu): 0.24 0.24 0.24

Particulate Emission Results Summary

Mitchell Unit 3

Page 25 of 26 Att. 2
ATTACHMENT 3 ‐ Mitchell Report 3 Test Results

Title of

Run Description Date Start Time End Time Test Load

Avg. Econ.

Gas Outlet

CO

Avg. Econ.

Gas Outlet

O2

Avg. Econ.

Gas Outlet

CO2

Avg. Econ.

Gas Outlet

Temp

Military Military MW ppm % Dry % Dry Deg F

Test 1 2/27/2008 7:40 10:00 164.01 6.1 3.41 15.2 686.2

Test 2 D Mill off 2/27/2008 11:45 13:45 100.12 5 4.96 13.75 582.3

Test 3 D Mill off 2/27/2008 14:40 16:40 79.99 4 5.31 13.41 547

Test 4 D Mill off 2/28/2008 8:00 10:00 65.07 5 5.62 13.17 517.2

Test 5 D Mill off 2/28/2008 11:30 13:30 80.01 5 5.14 13.57 557.8

Boiler Baseline Test Results Summary (In Preparation for Biomass Project)

Mitchell Unit 3

Page 26 of 26 Att. 3