Process Information

1 Name of legal owner of facility:

Gulf Power Company

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

Gulf Power Company

3 Address of ___ legal owner or ____ operator:

One Energy Place

Pensacola, FL 32520 - 0100

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):

Scholz

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):

642

5 Complete street address of facility (physical location):

1460 Gulf Power Road

Sneads, FL 32460

6 Provide mailing address if different:

One Energy Place

Pensacola, FL 32520 - 0345

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

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

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

_X_ other (specify in question 14 below)

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

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

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

_X_ other (specify in question 14 below)

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

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

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

_X__ bituminous (% _100_) ____ anthracite (% _____)

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

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

 that recycle materials) (%_____)

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

____ petroleum coke (% _____)

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

_X__ distillate (% 70.4_)

_X__ other (specify on spec used oil_) (% _29.6)

____ residual or bunker C (% _____)

Note: total of 1436 gallons
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 _X__ Neither

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

On Specification Used Oil which 

meets 40 CFR 279 and less than 50 

ppm PCB for energy recovery 

purposes.

On Site Generated Oil Contaminated 

Soil which meets 40 CFR 279 and less 

than 50 PCB for energy recovery 

purposes.

Boiler cleaning wastes that are not 

hazardous as defined in 40 CFR Part 

261, Subpart B.

No boiler cleaning wastes were 

burned in 2009

Quantity/year

425 gallons

No Oil Contaminated Soil was 

burned in 2009.

Permitted to burn

Yes; Scholz 1-2 are 

permitted to burn at 

each unit's permitted 

heat input for oil but 

not to exceed 50,000 

gallons/yr per unit

Yes; Scholz 1-2 are 

permitted to burn at 

each unit's permitted 

heat input for oil but 

not to exceed 50,000 

gallons/yr per unit

Yes; Scholz 1-2 are 

permitted to burn non 

hazardous boiler 

cleaning wastes not to 

exceed 50 gallons per 

minute.

Actually burn

Yes

No

No
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. Boiler ID

6

coal rank or type of oil) Original design fuel (i.e., 

r

Design heat input, 

(MMBtu/hr)7, q

Present maximum heat 

input, (MMBtu/hr)8,p

MWe Gross capacity

summer o

MWe Net Capacity

summer 

n

efficiency (%, HHV) 

Original design gross 

m

Present operating gross 

efficiency (%, HHV) 

l

Design steam pressure 

(psig) 

k

Operating steam pressure 

(psig) 

j

Design steam temperature 

(

oF) I 

Operating steam 

temperature (

oF) 

h

Design steam reheat 

temperature (

oF)9, g

Operating steam reheat 

temperature (

oF)10, f

Fuel11, e

Hours/year operated12, dAverage annual capacity 

factor for the past 3 years 

c

Applicable NSPS b Estimated year of 

retirement13, a

1 bituminous CBI CBI 49 46 88 N/A 850 863 900 N/A N/A N/A bituminus coal, 

No. 2 fuel oil, onspec used oil, 

boiler cleaning 

waste. 

CBI CBI none N/A

2 bituminous CBI CBI 49 46 88 N/A 850 854 900 N/A N/A N/A bituminus coal, 

No. 2 fuel oil, onspec used oil, 

boiler cleaning 

waste. 

CBI CBI none N/A

Notes

"N/A" means not available.

a Gulf Power has not committed to actual retirement dates for Plant Scholz. Gulf 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 

 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. 

b

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

c CBI

d CBI

e

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

f

 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).

g

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

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

i

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

j

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

k

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

l

 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.

m

 Taken directly from the original contract boiler data sheet.

n

 Identifies the net normal full load as of May 2009; taken directly from the 2009 installed and authorized document. Gulf Power does not change unit capacities from season to season.

o

 Identifies the gross normal full load as of May 2009. Gulf Power does not change unit capacities season from season.

p CBI

q CBI

r

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

 response (Part I, No. 11), which indicates that the design fuel simply means the fuel for which the boiler is optimized to operate at maximum possible efficiency, 

 but that the boiler was designed to handle and burn a range of fuels.

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.
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.):

Boiler ID14 Type15 NOx control16 SO2 control17 PM control18 Other control19

1 wall - fired N/A N/A 1) Cold side ESP (01/1974) N/A

2 wall - fired N/A N/A 1) Cold side ESP Upgrade 

(12/2007)

N/A

Note: "N/A" means 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]).
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 N/A N/A N/A N/A

2 N/A N/A N/A N/A

Note: "N/A" means 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
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 N/A N/A N/A N/A N/A N/A

2 N/A N/A N/A N/A N/A N/A

Note: "N/A" means 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.
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 N/A N/A N/A N/A

2 N/A N/A N/A N/A

Note: "N/A" means 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
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 N/A N/A N/A N/A N/A N/A

2 N/A N/A N/A N/A N/A N/A

Note: "N/A" means 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.
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 Steady-State 0.10 lb/mmbtu 

Soot-blow 0.30 lb/mmbtu 

Title V permit; annual test 

Reference Method by 5 or 17

N/A N/A Solid Fuel (Coal) @ 6.17 

lb/mmbtu on 24-hr daily 

average ; Liquid Fuel (Oil) @ 

2.75 lb/mmbtu on 3 hr; #2 & 

On-Spec Used Oil not to 

exceed 0.5% by weight; Title 

V Permit.

N/A N/A N/A N/A N/A N/A N/A

2 Steady-State 0.10 lb/mmbtu 

Soot-blow 0.30 lb/mmbtu 

Title V permit; annual test 

Reference Method by 5 or 17

N/A N/A Solid Fuel (Coal) @ 6.17 

lb/mmbtu on 24-hr daily 

average ; Liquid Fuel (Oil) @ 

2.75 lb/mmbtu on 3 hr; #2 & 

On-Spec Used Oil not to 

exceed 0.5% by weight; Title 

V Permit.

N/A N/A N/A N/A N/A N/A N/A

Note: "N/A" means not applicable.

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

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

Other organics 

(specify)

Other 

pollutant 

(specify)

1 CS-ESP: 99.8% collection efficiency 1 N/A N/A N/A N/A N/A N/A N/A N/A

2 CS-ESP: 99.8% collection efficiency 2 N/A N/A N/A N/A N/A N/A N/A N/A

Note: "N/A" means not applicable.

1

 Cold Side ESP guarantee expired 1975

2

 Cold Side ESP guarantee expired 1975

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
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 Particulate emission tests for steady state and soot blow are 

conducted annually. Results are required to be reported to 

FDEP within forty five days of completion of testing. FDEP 

must be notified at least 14 days in advance of all emission 

tests. Compliance Assurance Monitoring (CAM) reports for 

Particulate are reported on a semi-annual basis. All records 

must be maintained for 5 years.

N/A N/A Sulfur Dioxide emissions tests are conducted annually. Results 

are required to be reported to FDEP within forty five days of 

completion of testing. FDEP must be notified at least 14 days 

in advance of all emission tests. Daily compliance is 

determined by fuel sampling or by continuous emission 

monitoring systems certified under 40 CFR Part 75. Excess 

Emissions are required on a quarterly basis to FDEP. All 

records must be maintained for 5 years. 

N/A N/A N/A N/A N/A N/A

2 Particulate emission tests for steady state and soot blow are 

conducted annually. Results are required to be reported to 

FDEP within forty five days of completion of testing. FDEP 

must be notified at least 14 days in advance of all emission 

tests. Compliance Assurance Monitoring (CAM) reports for 

Particulate are reported on a semi-annual basis. All records 

must be maintained for 5 years.

N/A N/A Sulfur Dioxide emissions tests are conducted annually. Results 

are required to be reported to FDEP within forty five days of 

completion of testing. FDEP must be notified at least 14 days 

in advance of all emission tests. Daily compliance is 

determined by fuel sampling or by continuous emission 

monitoring systems certified under 40 CFR Part 75. Excess 

Emissions are required on a quarterly basis to FDEP. All 

records must be maintained for 5 years. 

N/A N/A N/A N/A N/A N/A

Note: "N/A" means 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
25 For the control technologies identified in Part I, questions 17 and 19, provide the cost information requested.38

Facility Name/Unit No.: N/A

Retrofit to existing boiler? 

Installation on a new boiler?

Total Capital Investment: $ -

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

Note: "N/A" means not applicable.

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.
Fuel Analysis39

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

Scholz

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

Plant Code- 642

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

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

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

9,825 1, 2 KY LETCHER HAZARD, ROXANA TRAIN 0.91 14.06 12,759

9,599 1, 2 KY LETCHER HAZARD, ROXANA TRAIN 1 10.29 13,414

State/Country County42 Coal seam43

7,462 1, 2 Georgia/USA N/A N/A Truck

Note: The information being provided is on a shipment by shipment basis. Gulf Power cannot guarantee that what was shipped in the preceding 12 calendar months is 

what was burned in the preceding 12 calendar months. 

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.

Amount received, 

gallons40

ID # of boiler(s) firing 

fuel41

Fuel source Fuel shipment 

method

Vendor Analyses

FUEL OIL SHIPMENTS

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) firing 

fuel41

Fuel Shipment

Method
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):

Sample ID #

Total amount of 

fuel represented 

by sample, gallons

Total Sulfur, % Ash content, % Heating Value, 

Btu/lb Mercury, ppm Chlorine, ppm Fluorine, ppm Nickel, ppm

Other trace 

metal HAP, 

ppm

45

N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A

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

____ permit requirements

____ contractual obligations

____ standard operational procedures

_X__ other (please specify to support R&D projects, plant performance, and TRI reporting)

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

____ Fuel supplier (name and address)

_X__ Other (name and address)

Analytical services are conducted by Alabama Power Company's in-house laboratory.

Alabama Power Company, General Services Laboratory

744 Highway 87, GSC #8

Calera, AL 35040

6 Name and address of laboratory performing analyses:

Alabama Power Company, General Services Laboratory

744 Highway 87, GSC #8

Calera, AL 35040

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.

N/A
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 8/17/2005 SO2 Unit 1 Test

Report 2 8/17/2005 Particulate Soot Blow Test

Report 3 8/18/2005 Particulate Steady State Test `

Report 4 Unit 2 8/18/2005 SO2 Unit 2 Test

Report 5 8/23/2005 Particulate Soot Blow Test

Report 6 8/24/2005 Particulate Steady State Test

Report 7 Unit 1 8/15/2006 Particulate Soot Blow Test

Report 8 8/16/2006 Particulate Steady State Test

Report 9 Unit 2 8/15/2006 Particulate Soot Blow Test

Report 10 8/15/2006 Particulate Steady State Test

Report 11 Unit 1/2 8/16/2006 SO2 Unit 1/2 Test

Report 12 Unit 1 8/14/2007 Particulate Soot Blow Test

Report 13 8/14/2007 Particulate Steady State Test

Report 14 Unit 2 8/14/2007 Particulate Soot Blow Test

Report 15 8/14/2007 Particulate Steady State Test

Report 16 Unit 1/2 8/14/2007 SO2 Unit 1/2 Test

Report 17 Unit 1 8/12/2008 Particulate Soot Blow Test

Report 18 8/12/2008 Particulate Steady State Test

Report 19 Unit 2 8/11/2008 Particulate Soot Blow Test

Report 20 8/12/2008 Particulate Steady State Test

Report 21 Unit 1/2 8/13/2008 SO2 Unit 1/2 Test

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: 8/17/2005 Type: Duct Constituents: SO2

Report 2 Date: 8/17/2005 Type: Duct Constituents: PM

Report 3 Date: 8/18/2005 Type: Duct Constituents: PM

Report 4 Date: 8/18/2005 Type: Duct Constituents: SO2

Report 5 Date: 8/23/2005 Type: Duct Constituents: PM

Report 6 Date: 8/24/2005 Type: Duct Constituents: PM

Report 7 Date: 8/15/2006 Type: Duct Constituents: PM

Report 8 Date: 8/16/2006 Type: Duct Constituents: PM

Report 9 Date: 8/15/2006 Type: Duct Constituents: PM

Report 10 Date: 8/15/2006 Type: Duct Constituents: PM

Report 11 Date: 8/16/2006 Type: Stack Constituents: SO2

Report 12 Date: 8/14/2007 Type: Duct Constituents: PM

Report 13 Date: 8/14/2007 Type: Duct Constituents: PM

Report 14 Date: 8/14/2007 Type: Duct Constituents: PM

Report 15 Date: 8/14/2007 Type: Duct Constituents: PM

Report 16 Date: 8/14/2007 Type: Stack Constituents: SO2

Report 17 Date: 8/12/2008 Type: Duct Constituents: PM

Report 18 Date: 8/12/2008 Type: Duct Constituents: PM

Report 19 Date: 8/11/2008 Type: Duct Constituents: PM

Report 20 Date: 8/12/2008 Type: Duct Constituents: PM

Report 21 Date: 8/13/2008 Type: Stack Constituents: SO2
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.

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.

All tests presented in Test Reports 1-16 were conducted with the same control configuration as outlined in the table 8f-1 below: 

Table 8f-1

Boiler ID14 Type15 NOx control16 SO2 control17 PM control18 Other control19

1 wall - fired N/A N/A 1) Cold side ESP 

(01/1974)

N/A

2 wall - fired N/A N/A 1) Cold side ESP 

(01/1974)

N/A

Note: "N/A" means not applicable.

All tests presented in Test Reports 17-21 were conducted with the same control configuration as outlined in the table 8f-2 below: 

Table 8f-2

Boiler ID14 Type15 NOx control16 SO2 control17 PM control18 Other control19

1 wall - fired N/A N/A 1) Cold side ESP 

(01/1974)

N/A

2 wall - fired N/A N/A 1) Cold side ESP 

Upgrade 

(12/2007)

N/A

Note: "N/A" means not applicable.

8g Do any of these test reports reflect testing at a location upstream of 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.
9 What type of deviation reporting is required for violations of permit requirements?

Deviations which constitute a violation from permit conditions shall be reported immediately to FDEP. Immediately 

shall mean the same workday (i.e. 8:00 am to 5:00 pm), or first business day after the incident,excluding weekends and holidays.

This report shall contain a description of and cause of noncompliance; and the period of noncompliance, including dates and times; 

weekends and holidays. This report shall contain a description of and cause of noncompliance; and the period of noncompliance,

including dates and times; or if not corrected, the anticipated time the noncompliance is expected to continue, and steps being 

taken to reduce, eliminate, and prevent the recurrence of the noncompliance. The permittee shall be responsible for any and 

all damages which may result and may be subjext to enforcement action by the Department for penalties or revocation of the permit. 

Deviations which do not constitute a violation as allowable excess emissions are reported quarterly or semi-annual under 

the Excess Emissions, Semi-annual Monitoring and Annual Title V Certification Reports. 

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.

Deviations from any permit condition is reported in the Semi-annual monitoring reports submitted to FDEP. 

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.

01/01/05 - 12/31/09 Unit 1: Continuous Opacity Monitoring Information is available upon request

01/01/05 - 12/31/09 Unit 2: Continuous Opacity Monitoring Information is available upon request

1

 Gulf Power considers CEMS data "available" only if it is maintained and subject to quality assurance/quality control

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

Test Report Date of test PM49 SO2 HCl/HF/HCN Metal HAP50 Hg51 CO Other organics 

(specify)

Unit 1 Report 1 8/17/2005 N/A See Attachment 1 N/A N/A N/A N/A N/A

Report 2 8/17/2005 See Attachment 2 N/A N/A N/A N/A N/A N/A

Report 3 8/18/2005 See Attachment 3 N/A N/A N/A N/A N/A N/A

Unit 2 Report 4 8/18/2005 N/A See Attachment 4 N/A N/A N/A N/A N/A

Report 5 8/23/2005 See Attachment 5 N/A N/A N/A N/A N/A N/A

Report 6 8/24/2005 See Attachment 6 N/A N/A N/A N/A N/A N/A

Unit 1 Report 7 8/15/2006 See Attachment 7 N/A N/A N/A N/A N/A N/A

Report 8 8/16/2006 See Attachment 8 N/A N/A N/A N/A N/A N/A

Unit 2 Report 9 8/15/2006 See Attachment 9 N/A N/A N/A N/A N/A N/A

Report 10 8/15/2006 See Attachment 10 N/A N/A N/A N/A N/A N/A

Unit 1/2 Report 11 8/16/2006 N/A See Attachment 11 N/A N/A N/A N/A N/A

Unit 1 Report 12 8/14/2007 See Attachment 12 N/A N/A N/A N/A N/A N/A

Report 13 8/14/2007 See Attachment 13 N/A N/A N/A N/A N/A N/A

Unit 2 Report 14 8/14/2007 See Attachment 14 N/A N/A N/A N/A N/A N/A

Report 15 8/14/2007 See Attachment 15 N/A N/A N/A N/A N/A N/A

Unit 1/2 Report 16 8/14/2007 N/A See Attachment 16 N/A N/A N/A N/A N/A

Unit 1 Report 17 8/12/2008 See Attachment 17 N/A N/A N/A N/A N/A N/A

Report 18 8/12/2008 See Attachment 18 N/A N/A N/A N/A N/A N/A

Unit 2 Report 19 8/11/2008 See Attachment 19 N/A N/A N/A N/A N/A N/A

Report 20 8/12/2008 See Attachment 20 N/A N/A N/A N/A N/A N/A

Unit 1/2 Report 21 8/13/2008 N/A See Attachment 21 N/A N/A N/A N/A N/A

Note: "N/A" means 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
ATTACHMENT 1 - Scholz Report 1 Test Results

2005 SO2 Emissions Test

Run Number

Date- Start 

Time

Date- Stop 

Time

Average Emissions 

(lbs/mmBTU SO2)

1 8/17/05- 13:05 8/17/05- 14:05 1.5

2 8/17/05- 14:36 8/17/05- 15:36 1.47

3 8/17/05- 16:01 8/17/05- 17:01 1.48

1.49

Scholz Unit 1 2005 High Load ~ 46 MWs

Average:
ATTACHMENT 2 - Scholz Report 2 Test Results

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 8/17/2005 8/17/2005 8/17/2005

Sampling Time -Start Military 0655 0826 0956

Sampling Time -Stop Military 0803 0934 1102

Oxygen F Factor SDCF/MMBtu 9780 9780 9780

Stack Static Pressure Inches Water 0.30 0.30 0.30

Barometric Pressure Inches Mercury 30.00 30.00 30.00

Meter Correction Factor dimensionless 1.025 1.025 1.025

Oxygen Concentration Mole Percent O2 7.8 7.5 7.4

Carbon Dioxide Concentration Mole Percent CO2 11.0 11.0 11.0

Volume of Gas Metered Actual Cubic Feet 37.250 36.269 37.231

Volume of Water Collected Milliliters 71 68 67

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.265 0.265 0.265

Weight of Solids Collected Milligrams 19.4 19.2 19.6

Area of Stack Square Feet 86.4032 86.4032 86.4032

Avg. Sqr. Root Velocity Pressure Inches Water 0.6361 0.6158 0.6310

Average Orifice Pressure (H) Inches Water 1.8 1.7 1.7

Average Stack Temperature Degrees F 292.5 298.6 299.5

Average Meter Temperature Degrees F 79.0 81.6 85.7

RUN 1 RUN 2 RUN 3 Average

Volume of Gas Sampled Standard Dry 37.672 36.494 37.190 37.118

 Cubic Feet 

Molecular Wt. of Stack Gas LB/LB-MOLE 29.088 29.088 29.114 29.096

Water vapor in Stack Gas Percent 8.1 8.1 7.8 8.0

Average Stack Gas Velocity Feet per second 42.40 41.21 42.23 41.94

Stack Gas Flow Rate Actual Cubic 219,786 213,621 218,930 217,446

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 154,706 149,163 152,689 152,186

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 142,100 137,135 140,753 139,996

 Feet Per Minute

Particulate Concentration Grains per Standard 0.00793 0.00810 0.00812 0.00805

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.00513 0.00520 0.00522 0.00518

 Cubic Foot

Particulate Emission Rate Pounds per Hour 9.66 9.52 9.79 9.66

Particulate Emission Rate Pounds per Million 0.0177 0.0177 0.0176 0.0176

Allowable Particulate Emission Rate Btu (O2 F Factor) 0.3 0.3 0.3 0.3

Heat Input (O2 F Factor) Million Btu per Hour 546 539 558 548

Isokinetic Rate Percent 99.7 100.0 99.3 99.7

Calculations

TABLE I. SUMMARY OF PARTICULATE EMISSIONS TEST RESULTS

GULF POWER COMPANY

PLANT SCHOLZ - UNIT 1

SOOT BLOWING OPERATIONS
ATTACHMENT 3 - Scholz Report 3 Test Results

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 8/18/2005 8/18/2005 8/18/2005

Sampling Time -Start Military 0634 0800 0924

Sampling Time -Stop Military 0741 0905 1029

Oxygen F Factor SDCF/MMBtu 9780 9780 9780

Stack Static Pressure Inches Water 0.30 0.30 0.30

Barometric Pressure Inches Mercury 30.05 30.05 30.05

Meter Correction Factor dimensionless 1.025 1.025 1.025

Oxygen Concentration Mole Percent O2 7.3 7.5 7.7

Carbon Dioxide Concentration Mole Percent CO2 10.5 10.5 11.0

Volume of Gas Metered Actual Cubic Feet 36.463 37.367 37.457

Volume of Water Collected Milliliters 62.0 65.0 66.0

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.265 0.265 0.265

Weight of Solids Collected Milligrams 13.4 14.0 31.9

Area of Stack Square Feet 86.4032 86.4032 86.4032

Avg. Sqr. Root Velocity Pressure Inches Water 0.6158 0.6302 0.6325

Average Orifice Pressure (H) Inches Water 1.6 1.7 1.7

Average Stack Temperature Degrees F 297.9 301.8 304.7

Average Meter Temperature Degrees F 77.7 82.5 86.5

RUN 1 RUN 2 RUN 3 Average

Volume of Gas Sampled Standard Dry 37.018 37.605 37.421 37.348

 Cubic Feet 

Molecular Wt. of Stack Gas LB/LB-MOLE 29.097 29.079 29.143 29.106

Water vapor in Stack Gas Percent 7.3 7.5 7.7 7.5

Average Stack Gas Velocity Feet per second 41.15 42.23 42.42 41.93

Stack Gas Flow Rate Actual Cubic 213,314 218,937 219,925 217,392

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 149,328 152,493 152,593 151,471

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 138,416 141,019 140,896 140,110

 Feet Per Minute

Particulate Concentration Grains per Standard 0.00557 0.00573 0.01313 0.00815

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.00362 0.00369 0.00841 0.00524

 Cubic Foot

Particulate Emission Rate Pounds per Hour 6.61 6.93 15.85 9.80

Particulate Emission Rate Pounds per Million 0.0120 0.0125 0.0290 0.0178

Allowable Particulate Emission Rate Btu (O2 F Factor) 0.1 0.1 0.1 0.1

Heat Input (O2 F Factor) Million Btu per Hour 553 555 546 551

Isokinetic Rate Percent 100.5 100.2 99.8 100.2

Calculations

TABLE I. SUMMARY OF PARTICULATE EMISSIONS TEST RESULTS

GULF POWER COMPANY

PLANT SCHOLZ - UNIT 1

STEADY STATE OPERATIONS
ATTACHMENT 4 - Scholz Report 4 Test Results

2005 SO2 Emissions Test

Run Number

Date- Start 

Time

Date- Stop 

Time

Average Emissions 

(lbs/mmBTU SO2)

1 08/18/05- 10:48

08/18/05- 

11:48 1.43

2 08/18/05- 12:17

08/18/05- 

13:17 1.4

3 08/18/05- 13:48

08/18/05- 

14:48 1.38

1.4

Scholz Unit 2 2005 High Load ~ 46 MWs

Average:
ATTACHMENT 5 - Scholz Report 5 Test Results

Title of Run RUN 1 RUN 2 RUN 4

Date Month/Day/Year 8/23/2005 8/23/2005 8/23/2005

Sampling Time -Start Military 0644 0818 1135

Sampling Time -Stop Military 0753 0926 1240

Number of Ports dimensionless 6 6 6

Number of Points per Port dimensionless 5 5 5

Oxygen F Factor SDCF/MMBtu 9,780 9,780 9,780

Stack Static Pressure Inches Water 0.55 0.55 0.55

Barometric Pressure Inches Mercury 30.15 30.15 30.15

Meter Correction Factor dimensionless 1.025 1.025 1.025

Oxygen Concentration Mole Percent O2 7.1 7.0 6.9

Carbon Dioxide Concentration Mole Percent CO2 12.0 12.0 12.0

Volume of Gas Metered Actual Cubic Feet 38.100 34.800 34.020

Volume of Water Collected Milliliters 62.00 69.00 63.00

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.255 0.255 0.247

Weight of Solids Collected Milligrams 29.1 24.6 23.6

Area of Stack Square Feet 89.333 89.333 89.333

Avg. Sqr. Root Velocity Pressure Inches Water 0.6841 0.6943 0.6946

Average Orifice Pressure (H) Inches Water 1.7 1.8 1.6

Average Stack Temperature Degrees F 303 321 313

Average Meter Temperature Degrees F 79 86 94

RUN 1 RUN 2 RUN 4 Average

Volume of Gas Sampled Standard Dry 38.687 34.948 33.653 35.762

 Cubic Feet 

Molecular Wt. of Stack Gas LB/LB-MOLE 29.35 29.16 29.21 29.24

Water vapor in Stack Gas Percent 7.0 8.5 8.1 7.9

Average Stack Gas Velocity Feet per second 45.6 47.0 46.7 46.4

Stack Gas Flow Rate Actual Cubic 244,356 251,705 250,238 248,766

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 170,502 171,590 172,481 171,524

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 158,542 156,999 158,514 158,018

 Feet Per Minute

Stack Gas Flow Rate Pounds of Dry Air 11,875 11,759 11,873 11,836

Per Minute

Stack Gas Flow Rate Thousands of Standard 2,841,693 2,859,826 2,874,691 2,858,736

Wet Cubic Feet per Minute

Particulate Concentration Grains per Standard 0.0116 0.0108 0.0108 0.0111

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.0075 0.0068 0.0068 0.0070

 Cubic Foot

Particulate Emission Rate Pounds per Hour 15.7 14.6 14.7 15.0

Particulate Emission Rate Pounds per Million 0.025 0.023 0.023 0.023

Allowable Btu (O2 F Factor) 0.3 0.3 0.3 0.3

Heat Input (O2 F Factor) Million Btu per Hour 642 641 651 645

Isokinetic Rate Percent 102.4 93.4 95.0 96.9

Calculations

TABLE I. PARTICULATE EMISSIONS TEST RESULTS

GULF POWER COMPANY

PLANT SCHOLZ - UNIT 2

SOOT BLOWING
ATTACHMENT 6 - Scholz Report 6 Test Results

Title of Run RUN 1 RUN 2 RUN 4

Date Month/Day/Year 8/24/2005 8/24/2005 8/24/2005

Sampling Time -Start Military 0628 0759 0926

Sampling Time -Stop Military 0738 0905 1033

Number of Ports dimensionless 6 6 6

Number of Points per Port dimensionless 5 5 5

Oxygen F Factor SDCF/MMBtu 9,780 9,780 9,780

Stack Static Pressure Inches Water 0.55 0.55 0.55

Barometric Pressure Inches Mercury 30.00 30.00 30.00

Meter Correction Factor dimensionless 1.025 1.025 1.025

Oxygen Concentration Mole Percent O2 6.5 7.1 6.9

Carbon Dioxide Concentration Mole Percent CO2 12.0 12.0 12.0

Volume of Gas Metered Actual Cubic Feet 36.700 35.000 35.700

Volume of Water Collected Milliliters 65.00 60.00 58.00

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.256 0.250 0.248

Weight of Solids Collected Milligrams 20.8 18.6 20.5

Area of Stack Square Feet 89.333 89.333 89.333

Avg. Sqr. Root Velocity Pressure Inches Water 0.6744 0.7134 0.7079

Average Orifice Pressure (H) Inches Water 1.8 1.7 1.7

Average Stack Temperature Degrees F 323 326 322

Average Meter Temperature Degrees F 80 85 89

RUN 1 RUN 2 RUN 4 Average

Volume of Gas Sampled Standard Dry 37.034 35.009 35.417 35.820

 Cubic Feet 

Molecular Wt. of Stack Gas LB/LB-MOLE 29.25 29.29 29.32 29.29

Water vapor in Stack Gas Percent 7.6 7.5 7.2 7.4

Average Stack Gas Velocity Feet per second 45.7 48.4 47.9 47.3

Stack Gas Flow Rate Actual Cubic 245,038 259,429 256,743 253,737

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 165,818 174,990 173,932 171,580

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 153,165 161,928 161,484 158,859

 Feet Per Minute

Stack Gas Flow Rate Pounds of Dry Air 11,472 12,128 12,095 11,899

Per Minute

Stack Gas Flow Rate Thousands of Standard 2,763,639 2,916,504 2,898,860 2,859,668

Wet Cubic Feet per Minute

Particulate Concentration Grains per Standard 0.0086 0.0082 0.0089 0.0086

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.0054 0.0051 0.0056 0.0054

 Cubic Foot

Particulate Emission Rate Pounds per Hour 11.4 11.4 12.3 11.7

Particulate Emission Rate Pounds per Million 0.018 0.017 0.019 0.018

Allowable Btu (O2 F Factor) 0.1 0.1 0.1 0.1

Heat Input (O2 F Factor) Million Btu per Hour 647 656 664 656

Isokinetic Rate Percent 100.7 94.4 97.3 97.5

Calculations

TABLE I. PARTICULATE EMISSIONS TEST RESULTS

GULF POWER COMPANY

PLANT SCHOLZ - UNIT 2

STEADY STATE
ATTACHMENT 7 - Scholz Report 7 Test Results

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 8/15/2006 8/15/2006 8/15/2006

Sampling Time -Start Military 0712 0901 1048

Sampling Time -Stop Military 0815 1005 1151

Number of Ports dimensionless 6 6 6

Number of Points per Port dimensionless 5 5 5

Oxygen F Factor SDCF/MMBtu 9,780 9,780 9,780

Stack Static Pressure Inches Water 0.30 0.30 0.30

Barometric Pressure Inches Mercury 30.20 30.20 30.20

Standard Orifice Pressure H@ Inches Water 2.418 2.418 2.418

Meter Correction Factor dimensionless 0.939 0.939 0.939

Oxygen Concentration Mole Percent O2 8.5 8.5 9

Carbon Dioxide Concentration Mole Percent CO2 11 11 10.5

Volume of Gas Metered Actual Cubic Feet 39.955 41.190 42.887

Volume of Water Collected Milliliters 64 67 74

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.255 0.255 0.255

Weight of Solids Collected Milligrams 12.2 7.6 32.9

Area of Stack Square Feet 86.403 86.403 86.403

Avg. Sqr. Root Velocity Pressure Inches Water 0.6911 0.7072 0.7304

Average Orifice Pressure (H) Inches Water 1.885 1.978 2.139

Average Stack Temperature Degrees F 297 297 299

Average Meter Temperature Degrees F 80 85 89

RUN 1 RUN 2 RUN 3 AVERAGE

Volume of Gas Sampled Standard Dry 37.196 38.028 39.338 38.187

 Cubic Feet 

Molecular Wt. of Stack Gas (dry) LB/LB-MOLE 30.10 30.10 30.04 30.08

Water vapor in Stack Gas Percent 7.5 7.7 8.1 7.8

Average Stack Gas Velocity Feet per second 46.0 47.1 48.7 47.3

Stack Gas Flow Rate Actual Cubic 238,285 243,925 252,704 244,971

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 167,840 171,775 177,574 172,396

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 155,265 158,621 163,130 159,005

 Feet Per Minute

Stack Gas Flow Rate Pounds of Dry Air 11,629 11,881 12,218 11,909

Per Minute

Particulate Concentration Grains per Standard 0.0051 0.0031 0.0129 0.0070

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.0033 0.0020 0.0083 0.0045

 Cubic Foot

Particulate Emission Rate Pounds per Hour 6.7 4.2 18.0 9.6

Particulate Emission Rate Pounds per Million 0.012 0.007 0.032 0.017

Allowable Btu (O2 F Factor) 0.3 0.3 0.3 0.3

Heat Input (O2 F Factor) Million Btu per Hour 565 577 570 571

Isokinetic Rate Percent 97.3 97.3 97.9 97.5

Post Test Meter Correction Factor dimensionless 0.981 0.979 0.982 0.980

Percent Difference Allowed 5% 4.2 4.0 4.3 4.1

Calculations

TABLE I. PARTICULATE EMISSIONS TEST RESULTS

GULF POWER COMPANY

PLANT SCHOLZ, UNIT 1

SOOT BLOWING
ATTACHMENT 8 - Scholz Report 8 Test Results

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 8/16/2006 8/16/2006 8/16/2006

Sampling Time -Start Military 0707 0835 1000

Sampling Time -Stop Military 0809 0939 1103

Number of Ports dimensionless 6 6 6

Number of Points per Port dimensionless 5 5 5

Oxygen F Factor SDCF/MMBtu 9,780 9,780 9,780

Stack Static Pressure Inches Water 0.30 0.30 0.30

Barometric Pressure Inches Mercury 30.12 30.12 30.12

Standard Orifice Pressure H@ Inches Water 2.418 2.418 2.418

Meter Correction Factor dimensionless 0.939 0.939 0.939

Oxygen Concentration Mole Percent O2 9.5 9 9

Carbon Dioxide Concentration Mole Percent CO2 10.5 10.5 11

Volume of Gas Metered Actual Cubic Feet 40.672 42.072 42.595

Volume of Water Collected Milliliters 60 67 71

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.255 0.255 0.255

Weight of Solids Collected Milligrams 8.0 10.9 9.8

Area of Stack Square Feet 86.403 86.403 86.403

Avg. Sqr. Root Velocity Pressure Inches Water 0.7200 0.7239 0.7305

Average Orifice Pressure (H) Inches Water 2.004 2.029 2.061

Average Stack Temperature Degrees F 296 303 305

Average Meter Temperature Degrees F 68 68 71

RUN 1 RUN 2 RUN 3 AVERAGE

Volume of Gas Sampled Standard Dry 38.672 39.976 40.254 39.634

 Cubic Feet 

Molecular Wt. of Stack Gas (dry) LB/LB-MOLE 30.06 30.04 30.12 30.07

Water vapor in Stack Gas Percent 6.8 7.3 7.7 7.3

Average Stack Gas Velocity Feet per second 47.9 48.4 48.9 48.4

Stack Gas Flow Rate Actual Cubic 248,173 251,022 253,587 250,927

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 174,642 174,987 176,189 175,273

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 162,756 162,192 162,683 162,544

 Feet Per Minute

Stack Gas Flow Rate Pounds of Dry Air 12,190 12,148 12,185 12,175

Per Minute

Particulate Concentration Grains per Standard 0.0032 0.0042 0.0037 0.0037

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.0021 0.0027 0.0024 0.0024

 Cubic Foot

Particulate Emission Rate Pounds per Hour 4.4 5.8 5.2 5.2

Particulate Emission Rate Pounds per Million 0.0082 0.0103 0.0092 0.0092

Allowable Btu (O2 F Factor) 0.1 0.1 0.1 0.1

Heat Input (O2 F Factor) Million Btu per Hour 545 567 568 560

Isokinetic Rate Percent 96.5 100.1 100.5 99.0

Post Test Meter Correction Factor dimensionless 0.984 0.957 0.954 0.965

Percent Difference Allowed 5% 4.5 1.8 1.5 2.6

Calculations

TABLE I. PARTICULATE EMISSIONS TEST RESULTS

GULF POWER COMPANY

PLANT SCHOLZ, UNIT 1

STEADY STATE
ATTACHMENT 9 - Scholz Report 9 Test Results

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 8/15/2006 8/15/2006 8/15/2006

Sampling Time -Start Military 0712 0901 1048

Sampling Time -Stop Military 0815 1005 1157

Number of Ports dimensionless 6 6 6

Number of Points per Port dimensionless 5 5 5

Oxygen F Factor SDCF/MMBtu 9,780 9,780 9,780

Stack Static Pressure Inches Water 0.50 0.50 0.50

Barometric Pressure Inches Mercury 30.20 30.20 30.20

Standard Orifice Pressure H@ Inches Water 1.939 1.939 1.939

Meter Correction Factor dimensionless 0.981 0.981 0.981

Oxygen Concentration Mole Percent O2 10.5 10 10

Carbon Dioxide Concentration Mole Percent CO2 10.5 11 11

Volume of Gas Metered Actual Cubic Feet 41.600 41.900 42.350

Volume of Water Collected Milliliters 79 82 85

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.260 0.260 0.260

Weight of Solids Collected Milligrams 15.5 20.1 44.9

Area of Stack Square Feet 89.333 89.333 89.333

Avg. Sqr. Root Velocity Pressure Inches Water 0.7203 0.7171 0.7207

Average Orifice Pressure (H) Inches Water 1.811 1.782 1.821

Average Stack Temperature Degrees F 317 318 318

Average Meter Temperature Degrees F 82 87 91

RUN 1 RUN 2 RUN 3 AVERAGE

Volume of Gas Sampled Standard Dry 40.343 40.205 40.353 40.300

 Cubic Feet 

Molecular Wt. of Stack Gas (dry) LB/LB-MOLE 30.10 30.16 30.16 30.14

Water vapor in Stack Gas Percent 8.4 8.8 9.0 8.7

Average Stack Gas Velocity Feet per second 48.6 48.4 48.7 48.6

Stack Gas Flow Rate Actual Cubic 260,603 259,475 260,916 260,332

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 178,905 177,971 178,982 178,619

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 163,807 162,382 162,837 163,008

 Feet Per Minute

Stack Gas Flow Rate Pounds of Dry Air 12,269 12,162 12,196 12,209

Per Minute

Particulate Concentration Grains per Standard 0.0059 0.0077 0.0171 0.0103

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.0037 0.0048 0.0107 0.0064

 Cubic Foot

Particulate Emission Rate Pounds per Hour 8.3 10.7 23.9 14.3

Particulate Emission Rate Pounds per Million 0.017 0.021 0.046 0.028

Allowable Btu (O2 F Factor) 0.3 0.3 0.3 0.3

Heat Input (O2 F Factor) Million Btu per Hour 500 520 521 514

Isokinetic Rate Percent 99.4 100.0 100.1 99.8

Post Test Meter Correction Factor dimensionless 1.033 1.021 1.025 1.026

Percent Difference Allowed 5% 5.2 4.0 4.4 4.5

Calculations

TABLE I. PARTICULATE EMISSIONS TEST RESULTS

GULF POWER COMPANY

PLANT SCHOLZ, UNIT 2

SOOT BLOWING
ATTACHMENT 10 - Scholz Report 10 Test Results

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 8/15/2006 8/15/2006 8/15/2006

Sampling Time -Start Military 1303 1442 1609

Sampling Time -Stop Military 1406 1534 1710

Number of Ports dimensionless 6 6 6

Number of Points per Port dimensionless 5 5 5

Oxygen F Factor SDCF/MMBtu 9,780 9,780 9,780

Stack Static Pressure Inches Water 0.50 0.50 0.50

Barometric Pressure Inches Mercury 30.20 30.20 30.20

Standard Orifice Pressure H@ Inches Water 1.939 1.939 1.939

Meter Correction Factor dimensionless 0.981 0.981 0.981

Oxygen Concentration Mole Percent O2 10 9.5 9.5

Carbon Dioxide Concentration Mole Percent CO2 11 11.5 11.5

Volume of Gas Metered Actual Cubic Feet 44.600 41.555 41.500

Volume of Water Collected Milliliters 87 79 76

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.260 0.260 0.260

Weight of Solids Collected Milligrams 30.0 12.6 14.5

Area of Stack Square Feet 89.333 89.333 89.333

Avg. Sqr. Root Velocity Pressure Inches Water 0.7603 0.7065 0.7032

Average Orifice Pressure (H) Inches Water 2.0 1.8 1.7

Average Stack Temperature Degrees F 318 324 326

Average Meter Temperature Degrees F 94 96 95

RUN 1 RUN 2 RUN 3 AVERAGE

Volume of Gas Sampled Standard Dry 42.300 39.235 39.252 40.262

 Cubic Feet 

Molecular Wt. of Stack Gas (dry) LB/LB-MOLE 30.16 30.22 30.22 30.20

Water vapor in Stack Gas Percent 8.8 8.7 8.4 8.6

Average Stack Gas Velocity Feet per second 51.4 47.8 47.6 48.9

Stack Gas Flow Rate Actual Cubic 275,236 256,431 255,252 262,306

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 188,643 174,424 173,335 178,801

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 171,992 159,324 158,857 163,391

 Feet Per Minute

Stack Gas Flow Rate Pounds of Dry Air 12,882 11,933 11,898 12,238

Per Minute

Particulate Concentration Grains per Standard 0.0109 0.0049 0.0057 0.0072

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.0068 0.0031 0.0035 0.0045

 Cubic Foot

Particulate Emission Rate Pounds per Hour 16.1 6.8 7.7 10.2

Particulate Emission Rate Pounds per Million 0.029 0.013 0.015 0.019

Allowable Btu (O2 F Factor) 0.1 0.1 0.1 0.1

Heat Input (O2 F Factor) Million Btu per Hour 550 533 532 538

Isokinetic Rate Percent 99.3 99.4 99.8 99.5

Post Test Meter Correction Factor dimensionless 1.028 1.034 1.024 1.029

Percent Difference Allowed 5% 4.7 5.3 4.3 4.8

Calculations

TABLE I. PARTICULATE EMISSIONS TEST RESULTS

GULF POWER COMPANY

PLANT SCHOLZ, UNIT 2

STEADY STATE
ATTACHMENT 11 - Scholz Report 11 Test Results

Carbon Sulfur

F Factor Dioxide Sulfur Dioxide

Start Stop Carbon Dioxide ( Dry) Dioxide Emissions

TEST Time Time ( Dry) (measured) Emissions (CO2 F factor)

Military Military (SDCF/MMbtu) (Percent) (ppm-dry) (Lbs/MMbtu)

RUN 1 7:07 8:07 1,800 10.8 833.2 2.3012

RUN 2 8:24 9:24 1,800 10.5 842.4 2.4057

RUN 3 9:38 10:38 1,800 10.3 860.0 2.5035

Average 1,800 10.5 845.2 2.4035

Allowable 6.17

Wednesday, August 16, 2006

TABLE I. SULFUR DIOXIDE AND 

GULF POWER COMPANY

PLANT SCHOLZ 

UNITS 1 AND 2 - HIGH LOAD ~ 95 MWs
ATTACHMENT 12 - Scholz Report 12 Test Results

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 8/14/2007 8/14/2007 8/14/2007

Sampling Time -Start Military 0638 0843 1047

Sampling Time -Stop Military 0803 0953 1159

Number of Ports dimensionless 6 6 6

Number of Points per Port dimensionless 5 5 5

Oxygen F Factor SDCF/MMBtu 9,780 9,780 9,780

Stack Static Pressure Inches Water 0.35 0.35 0.35

Barometric Pressure Inches Mercury 29.91 29.91 29.91

Standard Orifice Pressure H@ Inches Water 2.418 2.418 2.418

Meter Correction Factor dimensionless 0.939 0.939 0.939

Oxygen Concentration Mole Percent O2 5.5 5.4 5.8

Carbon Dioxide Concentration Mole Percent CO2 12.0 12.0 12.0

Volume of Gas Metered Actual Cubic Feet 37.155 36.955 36.100

Volume of Water Collected Milliliters 80 80 81

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.256 0.250 0.250

Weight of Solids Collected Milligrams 20.1 15.9 23.4

Area of Stack Square Feet 89.333 89.333 89.333

Avg. Sqr. Root Velocity Pressure Inches Water 0.6344 0.6563 0.6325

Average Orifice Pressure (H) Inches Water 1.7 1.6 1.5

Average Stack Temperature Degrees F 305 317 316

Average Meter Temperature Degrees F 85 96 100

Calculations

RUN 1 RUN 2 RUN 3 AVERAGE

Volume of Gas Sampled Standard Dry 33.923 33.093 32.092 33.036

 Cubic Feet 

Molecular Wt. of Stack Gas (dry) LB/LB-MOLE 30.14 30.14 30.15 30.14

Water vapor in Stack Gas Percent 10.0 10.2 10.6 10.3

Average Stack Gas Velocity Feet per second 42.8 44.7 43.0 43.5

Stack Gas Flow Rate Actual Cubic 229,441 239,361 230,644 233,148

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 158,432 162,728 157,011 159,391

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 142,603 146,104 140,338 143,015

 Feet Per Minute

Stack Gas Flow Rate Pounds of Dry Air 10,681 10,943 10,511 10,712

Per Minute

Particulate Concentration Grains per Standard 0.009 0.007 0.011 0.009

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.006 0.005 0.007 0.006

 Cubic Foot

Particulate Emission Rate Pounds per Hour 11.2 9.3 13.5 11.309

Particulate Emission Rate Pounds per Million 0.017 0.014 0.022 0.018

Allowable Btu (O2 F Factor) 0.3 0.3 0.3 0.3

Heat Input (O2 F Factor) Million Btu per Hour 645 665 622 644

Isokinetic Rate Percent 99.1 98.9 99.9 99.3

TABLE I. PARTICULATE EMISSIONS TEST RESULTS

GULF POWER COMPANY

PLANT SCHOLZ - UNIT 1

SOOT BLOWING
ATTACHMENT 13 - Scholz Report 13 Test Results

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 8/14/2007 8/14/2007 8/14/2007

Sampling Time -Start Military 1345 1531 1703

Sampling Time -Stop Military 1458 1641 1812

Number of Ports dimensionless 6 6 6

Number of Points per Port dimensionless 5 5 5

Oxygen F Factor SDCF/MMBtu 9,780 9,780 9,780

Stack Static Pressure Inches Water 0.35 0.35 0.35

Barometric Pressure Inches Mercury 29.91 29.91 29.91

Standard Orifice Pressure H@ Inches Water 2.418 2.418 2.418

Meter Correction Factor dimensionless 0.939 0.939 0.939

Oxygen Concentration Mole Percent O2 6.0 7.5 6.8

Carbon Dioxide Concentration Mole Percent CO2 12.0 11.5 11.5

Volume of Gas Metered Actual Cubic Feet 37.030 38.137 35.954

Volume of Water Collected Milliliters 72 75 65

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.250 0.256 0.250

Weight of Solids Collected Milligrams 11.4 12.9 10.2

Area of Stack Square Feet 89.333 89.333 89.333

Avg. Sqr. Root Velocity Pressure Inches Water 0.6503 0.6530 0.6376

Average Orifice Pressure (H) Inches Water 1.6 1.8 1.5

Average Stack Temperature Degrees F 316 317 316

Average Meter Temperature Degrees F 99 100 93

Calculations

RUN 1 RUN 2 RUN 3 AVERAGE

Volume of Gas Sampled Standard Dry 32.994 33.911 32.379 33.095

 Cubic Feet 

Molecular Wt. of Stack Gas (dry) LB/LB-MOLE 30.16 30.14 30.11 30.14

Water vapor in Stack Gas Percent 9.3 9.4 8.6 9.1

Average Stack Gas Velocity Feet per second 44.1 44.4 43.2 43.9

Stack Gas Flow Rate Actual Cubic 236,464 237,820 231,681 235,322

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 160,980 161,577 157,731 160,096

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 145,985 146,342 144,113 145,480

 Feet Per Minute

Stack Gas Flow Rate Pounds of Dry Air 10,934 10,961 10,794 10,896

Per Minute

Particulate Concentration Grains per Standard 0.005 0.006 0.005 0.005

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.003 0.004 0.003 0.003

 Cubic Foot

Particulate Emission Rate Pounds per Hour 6.7 7.3 6.0 6.7

Particulate Emission Rate Pounds per Million 0.010 0.013 0.010 0.011

Allowable Btu (O2 F Factor) 0.1 0.1 0.1 0.1

Heat Input (O2 F Factor) Million Btu per Hour 638 576 596 604

Isokinetic Rate Percent 98.7 96.5 98.1 97.8

TABLE I. PARTICULATE EMISSIONS TEST RESULTS

GULF POWER COMPANY

PLANT SCHOLZ - UNIT 1

STEADY STATE
ATTACHMENT 14 - Scholz Report 14 Test Results

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 8/14/2007 8/14/2007 8/14/2007

Sampling Time -Start Military 0638 0843 1047

Sampling Time -Stop Military 0803 0953 1159

Number of Ports dimensionless 6 6 6

Number of Points per Port dimensionless 5 5 5

Oxygen F Factor SDCF/MMBtu 9,780 9,780 9,780

Stack Static Pressure Inches Water 0.50 0.50 0.50

Barometric Pressure Inches Mercury 29.91 29.91 29.91

Standard Orifice Pressure H@ Inches Water 1.939 1.939 1.939

Meter Correction Factor dimensionless 0.981 0.981 0.981

Oxygen Concentration Mole Percent O2 6.8 6.2 6.5

Carbon Dioxide Concentration Mole Percent CO2 12.5 11.5 12.0

Volume of Gas Metered Actual Cubic Feet 47.407 41.447 42.997

Volume of Water Collected Milliliters 89 73 73

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.276 0.252 0.256

Weight of Solids Collected Milligrams 27.8 27.3 25.9

Area of Stack Square Feet 86.403 86.403 86.403

Avg. Sqr. Root Velocity Pressure Inches Water 0.7282 0.7458 0.7480

Average Orifice Pressure (H) Inches Water 2.3 1.7 1.8

Average Stack Temperature Degrees F 319 324 326

Average Meter Temperature Degrees F 86 93 99

Calculations

RUN 1 RUN 2 RUN 3 AVERAGE

Volume of Gas Sampled Standard Dry 45.182 38.999 40.033 41.405

 Cubic Feet 

Molecular Wt. of Stack Gas (dry) LB/LB-MOLE 30.27 30.09 30.18 30.18

Water vapor in Stack Gas Percent 8.5 8.1 7.9 8.2

Average Stack Gas Velocity Feet per second 49.3 50.8 50.9 50.3

Stack Gas Flow Rate Actual Cubic 255,666 263,293 263,814 260,924

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 173,446 177,389 177,446 176,094

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 158,728 163,025 163,419 161,724

 Feet Per Minute

Stack Gas Flow Rate Pounds of Dry Air 11,889 12,211 12,240 12,113

Per Minute

Particulate Concentration Grains per Standard 0.009 0.011 0.010 0.010

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.006 0.007 0.006 0.006

 Cubic Foot

Particulate Emission Rate Pounds per Hour 12.9 15.1 14.0 13.971

Particulate Emission Rate Pounds per Million 0.020 0.021 0.020 0.020

Allowable Btu (O2 F Factor) 0.3 0.3 0.3 0.3

Heat Input (O2 F Factor) Million Btu per Hour 657 703 691 684

Isokinetic Rate Percent 98.6 99.4 98.7 98.9

Post Test Meter Correction Check (Yqa) dimensionless 1.03 1.02 1.02 1.022

Percent Difference Allowed 5% Average 4.4 3.8 4.0 4.1

TABLE I. PARTICULATE EMISSIONS TEST RESULTS

GULF POWER COMPANY

PLANT SCHOLZ - UNIT 2

SOOT BLOWING
ATTACHMENT 15 - Scholz Report 15 Test Results

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 8/14/2007 8/14/2007 8/14/2007

Sampling Time -Start Military 1345 1531 1703

Sampling Time -Stop Military 1458 1641 1812

Number of Ports dimensionless 6 6 6

Number of Points per Port dimensionless 5 5 5

Oxygen F Factor SDCF/MMBtu 9,780 9,780 9,780

Stack Static Pressure Inches Water 0.50 0.50 0.50

Barometric Pressure Inches Mercury 29.91 29.91 29.91

Standard Orifice Pressure H@ Inches Water 1.939 1.939 1.939

Meter Correction Factor dimensionless 0.981 0.98 0.98

Oxygen Concentration Mole Percent O2 7.1 7.8 6.9

Carbon Dioxide Concentration Mole Percent CO2 12.0 11.5 11.5

Volume of Gas Metered Actual Cubic Feet 48.868 42.912 41.795

Volume of Water Collected Milliliters 78 69 69

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.276 0.252 0.256

Weight of Solids Collected Milligrams 37.1 37.1 29.3

Area of Stack Square Feet 86.403 86.403 86.403

Avg. Sqr. Root Velocity Pressure Inches Water 0.7407 0.7697 0.7280

Average Orifice Pressure (H) Inches Water 2.4 1.8 1.7

Average Stack Temperature Degrees F 326 328 327

Average Meter Temperature Degrees F 99 99 96

Calculations

RUN 1 RUN 2 RUN 3 AVERAGE

Volume of Gas Sampled Standard Dry 45.551 39.943 39.122 41.539

 Cubic Feet 

Molecular Wt. of Stack Gas (dry) LB/LB-MOLE 30.20 30.15 30.12 30.16

Water vapor in Stack Gas Percent 7.5 7.5 7.7 7.5

Average Stack Gas Velocity Feet per second 50.4 52.4 49.6 50.8

Stack Gas Flow Rate Actual Cubic 261,039 271,781 257,122 263,314

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 175,386 182,240 172,601 176,742

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 162,304 168,536 159,370 163,404

 Feet Per Minute

Stack Gas Flow Rate Pounds of Dry Air 12,157 12,623 11,937 12,239

Per Minute

Particulate Concentration Grains per Standard 0.013 0.014 0.012 0.013

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.008 0.009 0.007 0.008

 Cubic Foot

Particulate Emission Rate Pounds per Hour 17.4 20.7 15.8 17.956

Particulate Emission Rate Pounds per Million 0.027 0.032 0.024 0.027

Allowable Btu (O2 F Factor) 0.1 0.1 0.1 0.1

Heat Input (O2 F Factor) Million Btu per Hour 657 648 655 653

Isokinetic Rate Percent 97.3 98.5 98.9 98.2

Post Test Meter Correction Check (Yqa) dimensionless 1.03 1.02 1.01 1.02

Percent Difference Allowed 5% Average 4.7 3.4 2.8 3.6

TABLE I. PARTICULATE EMISSIONS TEST RESULTS

GULF POWER COMPANY

PLANT SCHOLZ - UNIT 2

STEADY STATE
ATTACHMENT 16 - Scholz Report 16 Test Results

Scholz Units 1 and 2 SO2 Test 2007 - Combined Stack

Run Date Start Time End Time Load RM-6C

Number MW lbm/mmbtu

1 8/14/2007 6:29 7:29 98 1.87

2 8/14/2007 9:05 10:05 98 1.83

3 8/14/2007 7:45 8:45 98 1.86

Avg 1.85
ATTACHMENT 17 - Scholz Report 17 Test Results

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 8/12/2008 8/12/2008 8/12/2008

Sampling Time -Start Military 1320 1520 1658

Sampling Time -Stop Military 1434 1632 1812

Number of Ports dimensionless 6 6 6

Number of Points per Port dimensionless 5 5 5

Oxygen F Factor SDCF/MMBtu 9,780 9,780 9,780

Stack Static Pressure Inches Water 0.40 0.40 0.40

Barometric Pressure Inches Mercury 29.90 29.90 29.90

Standard Orifice Pressure H@ Inches Water 2.211 2.211 2.211

Meter Correction Factor dimensionless 0.927 0.927 0.927

Oxygen Concentration Mole Percent O2 7.5 8.0 8.0

Carbon Dioxide Concentration Mole Percent CO2 11.0 10.5 10.5

Volume of Gas Metered Actual Cubic Feet 46.085 41.675 44.950

Volume of Water Collected Milliliters 70 63 70

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.275 0.260 0.275

Weight of Solids Collected Milligrams 25.6 19.2 20.5

Area of Stack Square Feet 89.333 89.333 89.333

Avg. Sqr. Root Velocity Pressure Inches Water 0.6552 0.6654 0.6491

Average Orifice Pressure (H) Inches Water 2.0 1.7 2.0

Average Stack Temperature Degrees F 305 307 306

Average Meter Temperature Degrees F 85 84 83

Calculations

RUN 1 RUN 2 RUN 3 AVERAGE

Volume of Gas Sampled Standard Dry 41.577 37.643 40.698 39.973

 Cubic Feet 

Molecular Wt. of Stack Gas (dry) LB/LB-MOLE 30.06 30.00 30.00 30.02

Water vapor in Stack Gas Percent 7.3 7.3 7.5 7.4

Average Stack Gas Velocity Feet per second 44.0 44.8 43.7 44.2

Stack Gas Flow Rate Actual Cubic 236,027 240,206 234,298 236,843

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 162,875 165,384 161,435 163,231

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 150,915 153,307 149,344 151,189

 Feet Per Minute

Stack Gas Flow Rate Pounds of Dry Air 11,304 11,483 11,186 11,324

Per Minute

Particulate Concentration Grains per Standard 0.0095 0.0079 0.0078 0.0084

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.0061 0.0050 0.0049 0.0053

 Cubic Foot

Particulate Emission Rate Pounds per Hour 12.3 10.3 9.9 10.8

Particulate Emission Rate Pounds per Million 0.021 0.018 0.018 0.019

Allowable Btu (O2 F Factor) 0.3 0.3 0.3 0.3

Heat Input (O2 F Factor) Million Btu per Hour 594 581 566 580

Isokinetic Rate Percent 99.4 99.1 98.3 99.0

Post Test Meter Correction Check dimensionless 0.936 0.939 0.948 0.941

Percent Difference Allowed 5% Average 0.9 1.2 2.1 1.4

TABLE I. PARTICULATE EMISSIONS TEST RESULTS

GULF POWER COMPANY

PLANT SCHOLZ - UNIT 1

SOOT BLOWING
ATTACHMENT 18 - Scholz Report 18 Test Results

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 8/12/2008 8/12/2008 8/12/2008

Sampling Time -Start Military 0720 0853 1045

Sampling Time -Stop Military 0832 1003 1201

Number of Ports dimensionless 6 6 6

Number of Points per Port dimensionless 5 5 5

Oxygen F Factor SDCF/MMBtu 9,780 9,780 9,780

Stack Static Pressure Inches Water 0.40 0.40 0.40

Barometric Pressure Inches Mercury 29.85 29.85 29.85

Standard Orifice Pressure H@ Inches Water 2.211 2.211 2.211

Meter Correction Factor dimensionless 0.927 0.927 0.927

Oxygen Concentration Mole Percent O2 7.0 7.0 7.5

Carbon Dioxide Concentration Mole Percent CO2 10.5 10.5 10.5

Volume of Gas Metered Actual Cubic Feet 45.733 41.173 46.546

Volume of Water Collected Milliliters 74 71 89

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.275 0.260 0.275

Weight of Solids Collected Milligrams 18.0 23.7 27.2

Area of Stack Square Feet 89.333 89.333 89.333

Avg. Sqr. Root Velocity Pressure Inches Water 0.6554 0.6598 0.6645

Average Orifice Pressure (H) Inches Water 2.0 1.6 2.1

Average Stack Temperature Degrees F 304 306 308

Average Meter Temperature Degrees F 73 77 75

Calculations

RUN 1 RUN 2 RUN 3 AVERAGE

Volume of Gas Sampled Standard Dry 42.080 37.590 42.687 40.786

 Cubic Feet 

Molecular Wt. of Stack Gas (dry) LB/LB-MOLE 29.96 29.96 29.98 29.97

Water vapor in Stack Gas Percent 7.6 8.2 8.9 8.2

Average Stack Gas Velocity Feet per second 44.1 44.6 45.0 44.6

Stack Gas Flow Rate Actual Cubic 236,607 238,861 241,063 238,844

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 163,337 164,312 165,560 164,403

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 150,850 150,896 150,764 150,837

 Feet Per Minute

Stack Gas Flow Rate Pounds of Dry Air 11,299 11,302 11,292 11,298

Per Minute

Particulate Concentration Grains per Standard 0.0066 0.0097 0.0098 0.0087

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.0042 0.0061 0.0061 0.0055

 Cubic Foot

Particulate Emission Rate Pounds per Hour 8.5 12.6 12.7 11.3

Particulate Emission Rate Pounds per Million 0.014 0.020 0.021 0.019

Allowable Btu (O2 F Factor) 0.1 0.1 0.1 0.1

Heat Input (O2 F Factor) Million Btu per Hour 615 616 593 608

Isokinetic Rate Percent 100.7 100.6 102.2 101.1

Post Test Meter Correction Check dimensionless 0.930 0.934 0.928 0.931

Percent Difference Allowed 5% Average 0.3 0.7 0.1 0.4

TABLE I. PARTICULATE EMISSIONS TEST RESULTS

GULF POWER COMPANY

PLANT SCHOLZ - UNIT 1

STEADY STATE
ATTACHMENT 19 - Scholz Report 19 Test Results

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 8/11/2008 8/11/2008 8/11/2008

Sampling Time -Start Military 1320 1520 1658

Sampling Time -Stop Military 1434 1632 1812

Number of Ports dimensionless 6 6 6

Number of Points per Port dimensionless 5 5 5

Oxygen F Factor SDCF/MMBtu 9,780 9,780 9,780

Stack Static Pressure Inches Water 0.50 0.50 0.50

Barometric Pressure Inches Mercury 29.90 29.90 29.90

Standard Orifice Pressure H@ Inches Water 1.939 1.939 1.939

Meter Correction Factor dimensionless 0.981 0.981 0.981

Oxygen Concentration Mole Percent O2 6.5 7.0 7.0

Carbon Dioxide Concentration Mole Percent CO2 11.0 11.0 10.5

Volume of Gas Metered Actual Cubic Feet 41.240 41.908 41.752

Volume of Water Collected Milliliters 67.5 72.0 73.0

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.250 0.255 0.255

Weight of Solids Collected Milligrams 17.5 12.8 13.1

Area of Stack Square Feet 86.403 86.403 86.403

Avg. Sqr. Root Velocity Pressure Inches Water 0.7434 0.7327 0.7315

Average Orifice Pressure (H) Inches Water 1.6 1.6 1.6

Average Stack Temperature Degrees F 332 334 333

Average Meter Temperature Degrees F 87 86 86

Calculations

RUN 1 RUN 2 RUN 3 AVERAGE

Volume of Gas Sampled Standard Dry 39.185 39.936 39.769 39.630

 Cubic Feet 

Molecular Wt. of Stack Gas (dry) LB/LB-MOLE 30.02 30.04 29.96 30.01

Water vapor in Stack Gas Percent 7.5 7.8 8.0 7.8

Average Stack Gas Velocity Feet per second 50.9 50.2 50.2 50.4

Stack Gas Flow Rate Actual Cubic 263,714 260,278 260,176 261,389

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 175,901 173,237 173,271 174,136

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 162,708 159,686 159,491 160,628

 Feet Per Minute

Stack Gas Flow Rate Pounds of Dry Air 12,187 11,960 11,946 12,031

Per Minute

Particulate Concentration Grains per Standard 0.007 0.005 0.005 0.006

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.004 0.003 0.003 0.003

 Cubic Foot

Particulate Emission Rate Pounds per Hour 9.6 6.8 6.9 7.8

Particulate Emission Rate Pounds per Million 0.014 0.010 0.011 0.012

Allowable Btu (O2 F Factor) 0.3 0.3 0.3 0.3

Heat Input (O2 F Factor) Million Btu per Hour 688 652 651 663

Isokinetic Rate Percent 101.7 101.5 101.2 101.5

Post Test Meter Correction Check dimensionless 0.99 0.99 0.99 0.99

Percent Difference Allowed 5% Average 0.5 0.7 0.9 0.7

TABLE I. PARTICULATE EMISSIONS TEST RESULTS

GULF POWER COMPANY

PLANT SCHOLZ - UNIT 2

SOOT BLOWING
ATTACHMENT 20 - Scholz Report 20 Test Results

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 8/12/2008 8/12/2008 8/12/2008

Sampling Time -Start Military 0720 0853 1045

Sampling Time -Stop Military 0832 1003 1201

Number of Ports dimensionless 6 6 6

Number of Points per Port dimensionless 5 5 5

Oxygen F Factor SDCF/MMBtu 9,780 9,780 9,780

Stack Static Pressure Inches Water 0.50 0.50 0.50

Barometric Pressure Inches Mercury 29.85 29.85 29.85

Standard Orifice Pressure H@ Inches Water 1.939 1.939 1.939

Meter Correction Factor dimensionless 0.981 0.981 0.981

Oxygen Concentration Mole Percent O2 7.0 7.0 7.5

Carbon Dioxide Concentration Mole Percent CO2 10.5 10.5 11.0

Volume of Gas Metered Actual Cubic Feet 41.332 40.460 41.476

Volume of Water Collected Milliliters 64 63 84

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.255 0.250 0.255

Weight of Solids Collected Milligrams 8.6 9.7 11.1

Area of Stack Square Feet 86.403 86.403 86.403

Avg. Sqr. Root Velocity Pressure Inches Water 0.7318 0.7357 0.7279

Average Orifice Pressure (H) Inches Water 1.6 1.5 1.6

Average Stack Temperature Degrees F 329 331 336

Average Meter Temperature Degrees F 77 81 78

Calculations

RUN 1 RUN 2 RUN 3 AVERAGE

Volume of Gas Sampled Standard Dry 39.967 38.811 40.025 39.601

 Cubic Feet 

Molecular Wt. of Stack Gas (dry) LB/LB-MOLE 29.96 29.96 30.06 29.99

Water vapor in Stack Gas Percent 7.0 7.0 9.0 7.7

Average Stack Gas Velocity Feet per second 50.0 50.4 50.1 50.2

Stack Gas Flow Rate Actual Cubic 259,384 261,059 259,712 260,052

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 173,278 174,022 172,101 173,134

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 161,133 161,761 156,628 159,841

 Feet Per Minute

Stack Gas Flow Rate Pounds of Dry Air 12,069 12,116 11,731 11,972

Per Minute

Particulate Concentration Grains per Standard 0.0033 0.0038 0.0043 0.0038

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.0021 0.0024 0.0026 0.0023

 Cubic Foot

Particulate Emission Rate Pounds per Hour 4.6 5.3 5.7 5.2

Particulate Emission Rate Pounds per Million 0.007 0.008 0.009 0.008

Allowable Btu (O2 F Factor) 0.1 0.1 0.1 0.1

Heat Input (O2 F Factor) Million Btu per Hour 657 660 616 645

Isokinetic Rate Percent 100.7 101.3 103.7 101.9

Post Test Meter Correction Check dimensionless 0.983 0.979 0.979 0.981

Percent Difference Allowed 5% Average 0.2 -0.2 -0.2 0.0

TABLE I. PARTICULATE EMISSIONS TEST RESULTS

GULF POWER COMPANY

PLANT SCHOLZ - UNIT 2

STEADY STATE
ATTACHMENT 21 - Scholz Report 21 Test Results

Scholz Units 1 and 2 SO2 Test 2008 - Combined Stack 

Run Date Start Time End Time Load RM-6C

Number MW lbm/mmbtu

1 8/13/2008 6:20 7:20 96 1.40

2 8/13/2008 7:53 8:53 96 1.30

3 8/13/2008 9:45 10:45 96 1.40

Avg 1.37