GEORGIA POWER - Submittal for PLANT MCINTOSH

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):

McIntosh

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):

6124

5 Complete street address of facility (physical location):

981 Old Augusta Road

Rincon, Georgia, 31326

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 25 part I, 1-14
GEORGIA POWER - Submittal for PLANT MCINTOSH

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?

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

___ other (specify in question 14 below)

NOTE: McIntosh Unit 1 was on reserve shutdown during 2009 and thus no coal was burned. One startup on 12/31/2009 involved firing of fuel oil.

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 See response to Question 10.

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

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

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

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

 that recycle materials) (%_____)

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

____ petroleum coke (% _____)

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

_X___ distillate (% _100____)

____ other (specify __________) (% _____)

____ residual or bunker C (% _____)

Page 2 of 25 part I, 1-14
GEORGIA POWER - Submittal for PLANT MCINTOSH

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

Used Oil None in 2009

Quantity/year

None in 2009

None in 2009

Permitted to burn

Yes

Yes

Yes

Actually burn

None in 2009

None in 2009

None in 2009

Page 3 of 25 part I, 1-14
GEORGIA POWER - PLANT MCINTOSH

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 165 153 89 89.76 1800 2000 1000 1005 1000 1003 distillate oil (100%) (although the 

primary fuel for the unit is coal, no 

coal was fired during 2009 - see 

response to Part I Question 10)

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

While this unit burned oil for a short period, the contract data sheet indicates that the unit was designed to burn natural gas, oil, and pulverized coal. For the vast majority of the 

life of the unit, it has burned pulverized coal; thus the responses provided herein are based on the unit's use of pulverized coal.

Design Heat Input

Confidential Business Information

Present Maximum Heat Input

Confidential Business Information

MWe Gross Capacity Summer

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

MWe Net Capacity Summer

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

Original Design Gross Efficiency

Taken directly from the original contract boiler data sheet.

Present Operating Gross Efficiency 

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

Page 4 of 25 part I, 15
GEORGIA POWER - PLANT MCINTOSH

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

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 an actual retirement date for Plant McIntosh Unit 1. 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 25 part I, 15
GEORGIA POWER - PLANT MCINTOSH

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.):

NOTE: SO3 flue gas conditioning are installed and available but have not operated since before 1/1/2005.

Boiler ID14 Type15 NOx control16 SO2 control17 PM control18 Other control19

1 wall-fired (1) overfire air (2003) Not applicable (3) cold-side electrostatic 

precipitator (ESP) (1981)

(2) flue gas conditioning - SO3 

injection (4/1997)

Not applicable

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Page 6 of 25 part I, 16
GEORGIA POWER - PLANT MCINTOSH

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

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 7 of 25 part I, 17
GEORGIA POWER - PLANT MCINTOSH

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

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 8 of 25 part I, 18
GEORGIA POWER - PLANT MCINTOSH

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

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

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

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

Company (vendor) contact information

Boiler ID24 Company (vendor) name

Page 9 of 25 part I, 19
GEORGIA POWER - PLANT MCINTOSH

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

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 10 of 25 part I, 20
GEORGIA POWER - PLANT MCINTOSH

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

stack test using Method 5 of 17; test conducted 

every 13 months, but may be deferred for 12 

months if test results from the previous annual 

tests are fifty percent or less of the limit)

Not 

applicable

Not 

applicable

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

back-calculation of daily average sulfur content 

from SO2 CEMS data and supplier certification 

statement for No. 2 oil)

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

NOx Multi-Unit Plan: Southern Company Phase II 

NOx Averaging Plan 0.46 lb/MMBtu annual 

average over all units (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.

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

Boiler ID27

Page 11 of 25 part I, 21
GEORGIA POWER - PLANT MCINTOSH

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

NOTE: All guarantees are based on and demonstrated with certain fuel and operating conditions. Guarantees do not well represent 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: 99.5 % collection efficiency 

filterable (expired in 1997)

Not 

applicable

Not 

applicable

Not applicable 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 12 of 25 part I, 22-23
GEORGIA POWER - PLANT MCINTOSH

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

PM36 PM10 PM2.5 SO2

HCl 

and/or HF HCN

Metal 

HAP37 Hg CO

Other 

organics 

(specify)

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

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

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

than 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 back-calculation of 

daily average sulfur content of coal using SO2 CEMS; fuel oil 

sulfur content monitored through vendor certification; 

exceedances of 3% limit reported quarterly; records retained 

for 5 years.

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

Not 

applicable

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 there is a permitted emission limit

Boiler ID35

Page 13 of 25 part I, 24
GEORGIA POWER - PLANT MCINTOSH

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 14 of 25 part I, 25-26
GEORGIA POWER - PLANT MCINTOSH

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: 

McIntosh

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

6124

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

Page 15 of 25 part II, 1
GEORGIA POWER - PLANT MCINTOSH

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

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

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

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

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

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

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

10,390 1 KY KNOTT, FLOYD

5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, 

HAZARD #7 TRAIN 1.52 12.68 12,931

10,172 1 KY KNOTT, FLOYD

5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, 

HAZARD #7 TRAIN 1.42 12.02 13,067

9,723 1 KY KNOTT, FLOYD

5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, 

HAZARD #7 TRAIN 1.45 11.33 13,187

10,235 1 KY KNOTT, FLOYD

5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, 

HAZARD #7 TRAIN 1.35 11.13 13,221

10,113 1 KY KNOTT, FLOYD

5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, 

HAZARD #7 TRAIN 1.19 13.46 12,842

10,004 1 KY KNOTT, FLOYD

5A, 7, 8, 9, ELKHORN 2, ELKHORN 3, 

HAZARD #7 TRAIN 1.31 12.58 13,029

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

amount fired.

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

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

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

42 If known.

43 If known.

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) 

firing fuel41

Fuel shipment 

method

Page 16 of 25 part II, 2
GEORGIA POWER - PLANT MCINTOSH

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

, as

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

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

Georgia Power collects this information on select coal shipments on a quarterly basis, but does not have this information available on a shipment by shipment basis. The information Georgia Power provides in this question cannot be 

linked to the information in Part II, Question 2 because the information comes from two separate databases. Thus the information provided in this question represents only a very small portion of our actual shipments.

Antimony Arsenic Beryllium Cadmium Chromium Cobalt Lead Manganese Selenium

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

Floyd, 

Knott

Hazard 8, Elkhorn 

#1, Elkhorn #2, 

Elkhorn #3, 

Whitesburg, 

Hazard #4 Train

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

Perry, 

Letcher

Hazard 4, Hazard 

4R, Hazard 8, 

Hazard 7 Train

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

Perry, 

Letcher

Hazard 4, Hazard 

4R, Hazard 8, 

Hazard 7 Train

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

Floyd, 

Knott

Hazard 8, Elkhorn 

#1, Elkhorn #2, 

Elkhorn #3, 

Whitesburg, 

Hazard #4 Train

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

Floyd, 

Knott

Hazard 8, Elkhorn 

#1, Elkhorn #2, 

Elkhorn #3, 

Whitesburg, 

Hazard #4 Train

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

Perry, 

Letcher

Hazard 4, Hazard 

5A, Alma Train

44 To the extent that a vendor provides these data or that a facility is required by State or local agency to analyze its fuel for HAP constituents (e.g., Cl, F), 

and any metallic HAP (e.g., Hg, Pb, As, Se, etc.), EPA wishes the responding facility to provide those fuel analyses results. Otherwise, this 12-month fuel

analysis requirement can be bypassed by the respondent.

45 Metal HAP includes compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, phosphorus, and selenium.

Fuel 

Shipment 

Method

Total amount of 

fuel represented 

by sample, tons

Sample 

ID #

State/ 

Country

County Coal Seam Nickel, 

ppm

Other trace metal HAP, ppm45

Total 

Sulfur, %

Ash 

Content, 

%

Heating 

Value, 

Btu/lb

Mercury, 

ppm

Chlorine, 

ppm

Fluorine, 

ppm

Page 17 of 25 part II, 3
GEORGIA POWER - PLANT MCINTOSH

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 25 part II, 4-6
GEORGIA POWER - PLANT MCINTOSH

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 K2O SiO2 Na2O SO3 TiO2

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

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

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

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

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

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

Sample 

ID #

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

Page 19 of 25 part II, 7
GEORGIA POWER - PLANT MCINTOSH

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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

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

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

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

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

Report 1 Unit 1 Particulate Emissions Test (February 10, 2005)

Report 2 Unit 1 Particulate Emissions Test (February 8, 2007)

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: 2/10/2005 Type: stack Constituents: PM

Report 2 Date: 2/8/2007 Type: stack Constituents: PM

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

Yes ____ No _X___ If yes, please note which reports and provide a detailed description of the location of the emissions sampling point(s).

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.

Page 20 of 25 part II, 8
GEORGIA POWER - PLANT MCINTOSH

EGU HAPs ICR, OMB Control No. 2060-0631

April 5, 2010

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.

Boiler ID Type NOx control SO2 control PM control Other control

1 wall-fired (1) overfire air (2) cold-side 

electrostatic 

precipitator

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

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

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

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

Page 21 of 25 part II, 8
GEORGIA POWER - PLANT MCINTOSH

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.

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 22 of 25 part II, 9-11
GEORGIA POWER - PLANT MCINTOSH

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 2/10/2005 See Attachment 1 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

1 2/7/2007 See Attachment 2 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

1 1/20/2010 See Attachment 3 Not applicable Not applicable Not applicable Not applicable 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 23 of 25 part II, 12
ATTACHMENT 1 - McIntosh Report 1 Test Results

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

Run 1 Run 2 Run 3

Test Date 2/10/2005 2/10/2005 2/10/2005

Run Start Time 8:45 10:05 11:40

Run End Time 9:40 11:20 12:55

Meter Volume (dacf), Vm: 53.741 55.246 55.865

Sqrt Delta P ("wc): 1.39 1.41 1.42

Sampling Time (min): 60 60 60

Barometric Pressure ("Hg), Pbar: 29.95 29.95 29.95

Delta H ("wc): 2.6 2.6 2.7

Volume in Impingers (mls), VIc: 80.0 81.3 83.2

Static Pressure ("wc), Pg: -2.10 -2.10 -2.20

Stack Pressure ("Hg), Ps: 29.80 29.80 29.79

Stack Temperature (F), Ts: 267 268 268

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

Pitot Coefficient (no units) Cp: 0.840 0.840 0.840

Meter OutletTemperature (F), Tm: 78 80 81

Stack Diameter (inches): 138 138 138

Area Stack (sq. ft.), As: 103.87 103.87 103.87

Nozzle Diameter (inches), dp: 0.212 0.212 0.212

Area Nozzle (sq. ft.), An: 0.000245 0.000245 0.000245

Percent CO2 (% dry volume): 12.8 12.7 12.9

Percent O2 (% dry volume): 6.5 6.4 6.5

Percent (N2 + CO) (% dry volume): 80.7 80.9 80.7

Particulate Collected (mg), Mn: 27.6 28.8 32.1

Molec. Wt. Dry (lb/lb-mole), Md: 30.308 30.293 30.318

Volume Water (scf), Vwstd 3.766 3.827 3.916

Meter Volume (dscf), Vmstd: 52.182 53.474 53.977

Wet Fraction (v/v), Bws: 0.067 0.067 0.068

Molec. Wt. Wet (lb/lb-mole), Ms: 29.480 29.472 29.485

Stack Gas Sampled (acf), Vma: 77.355 79.317 80.176 Averages

Stack Gas Velocity (fps), Vs: 91.08 91.87 92.61 92

Volumetric Flowrate (dscfm), Qs: 382,904 386,018 388,555 385,825

Volumetric Flowrate (acfm), Qa: 567,624 572,576 577,145 572,448

Grainloading (gr/dscf), cs: 0.0082 0.0083 0.0092 0.01

Emission Rate (lb/hour), E: 26.79 27.54 30.61 28.3

Percent Isokinetic Sampling (%), I: 96.30 97.89 98.17 97.45

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

Heat Input (mmBtu/hour): 1618.52 1640.18 1648.11 1635.60

Emission Rate (lbs/mmBtu), E: 0.017 0.017 0.019 0.017

Allowable Rate (lb/mmBtu): 0.180 0.180 0.180 0.180

Average Unit Gross Load (MW) 165 165 166 165

Particulate Emission Results Summary

McIntosh Unit 1

Page 24 of 25 Att. 1
ATTACHMENT 2 - McIntosh Report 2 Test Results

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

Run 1 Run 2 Run 3

Test Date 2/8/2007 2/8/2007 2/8/2007

Run Start Time 8:00 9:42 11:06

Run End Time 9:20 10:52 12:20

Meter Volume (dacf), Vm: 36.337 37.378 38.75

Sqrt Delta P ("wc): 1.45 1.45 1.45

Sampling Time (min): 60 60 60

Barometric Pressure ("Hg), Pbar: 30.06 30.00 30.00

Delta H ("wc): 1.3 1.3 1.3

Volume in Impingers (mls), VIc: 69.8 71.7 70.3

Static Pressure ("wc), Pg: -2.20 -2.30 -2.30

Stack Pressure ("Hg), Ps: 29.90 29.83 29.83

Stack Temperature (F), Ts: 265 269 273

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: 67 71 75

Stack Diameter (inches): 138 138 138

Area Stack (sq. ft.), As: 103.87 103.87 103.87

Nozzle Diameter (inches), dp: 0.174 0.174 0.174

Area Nozzle (sq. ft.), An: 0.000165 0.000165 0.000165

Percent CO2 (% dry volume): 13.4 13.5 13.5

Percent O2 (% dry volume): 6.1 6.2 6.1

Percent (N2 + CO) (% dry volume): 80.5 80.3 80.4

Particulate Collected (mg), Mn: 40.4 33.7 43.1

Molec. Wt. Dry (lb/lb-mole), Md: 30.388 30.408 30.404

Volume Water (scf), Vwstd 3.285 3.375 3.309

Meter Volume (dscf), Vmstd: 36.219 36.870 37.941

Wet Fraction (v/v), Bws: 0.083 0.084 0.080

Molec. Wt. Wet (lb/lb-mole), Ms: 29.358 29.367 29.409

Stack Gas Sampled (acf), Vma: 54.251 55.712 57.443 Averages

Stack Gas Velocity (fps), Vs: 94.56 94.99 95.21 95

Volumetric Flowrate (dscfm), Qs: 393,440 391,790 391,911 392,380

Volumetric Flowrate (acfm), Qa: 589,331 592,013 593,360 591,568

Grainloading (gr/dscf), cs: 0.0172 0.0141 0.0175 0.02

Emission Rate (lb/hour), E: 58.00 47.32 58.84 54.7

Percent Isokinetic Sampling (%), I: 96.57 98.72 101.56 98.95

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

Heat Input (mmBtu/hour): 1709.25 1690.58 1702.61 1700.81

Emission Rate (lbs/mmBtu), E: 0.034 0.028 0.035 0.032

Allowable Rate (lb/mmBtu): 0.180 0.180 0.180 0.180

Average Unit Gross Load (MW) 165 166 165 165

Particulate Emission Results Summary

Plant McIntosh, Unit 1

Page 25 of 25 Att. 2