Process Information

1 Name of legal owner of facility:

Mississippi Power Company

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

Same as above.

3 Address of

_

X

_ legal owner or __X__ operator:

P.O. Box 4079

Gulfport, MS 39502‐4079

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):Jack Watson

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):

2049

5 Complete street address of facility (physical location):

10406 Lorraine RoadGulfport, MS 39502‐4079

6 Provide mailing address if different:

P.O. Box 4079

Gulfport, MS 39502‐4079

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

____

oil (including pet coke) _X_ 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) _X_ 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 (% _____)

PLANT JACK WATSON ICR PART I SURVEY
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

_N/A_ distillate (% _____)_N/A_ other (specify __________) (% _____)_N/A_ residual or bunker C (% _____)

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 andRecovery 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 the 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").

Petroleum contaminated soil Y Y 110 Tons/Qtr 3 2009Boiler chemical cleaning wastes (non‐haz) Y N N/A

Quantity/year

N/A

2259 Tons/2009

Other Material

Used oilClean wood wastes

Actually burn

N

Y

Permitted to burn

YY

PLANT JACK WATSON ICR PART I SURVEY
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

Original design fuel (i.e.,

coal rank or type of oil)

Design heat input,

(MMBtu/hr)

7

Present maximum heat

input, (MMBtu/hr)

8

MWe Gross capacity

summer

MWe Net Capacity

summer

Original design gross

efficiency (%, HHV)

Present operating gross

efficiency (%, HHV)

Design steam pressure

(psig)

Operating steam pressure

(psig)

Design steam temperature (o

F)

Operating steam

temperature(

o

F)

Design steam reheat

temperature(

o

F)

9

Operating steam reheat

temperature(

o

F)10

4 bituminous CBI CBI 250 230 88.9 87.6 2400 2400 1000 998 1000 984 Coal, natural gas, used oil, pe

cleaning wastes (non‐haz), & with an electrostatic precipit

burners and an over‐fire air d

5 bituminous CBI CBI 500 476 89.01 88.03 2400 2400 1000 998 1000 979 Coal, natural gas, petroleum 

wastes (non‐haz), & woodwa

electrostatic precipitator and 

and an over‐fire air delivery 

NOTES

"N/A" means not available.Original design fuel. Based on the original contract boiler data sheet; only the primary fuel is listed if multiple fuels were included on the data sheet.

Design heat input (MMBtu/hr). Indicates the minimum level of heat input required to achieve maximum steam flow, based on the design of the unit (i.e., design efficiency, design temperature, and design 

Present maximum heat input (MMBtu/hr). Based on the calculated heat input at gross normal full load as a function of the December 2009 gross heat input equation, which takes into account a minimum 

operating data. This response does not account for changes over time in the condition of the unit, heat rate, heat or moisture content of the coal, ambient conditions, or operation of the unit at valves‐wid

MWe Gross Capacity Summer. Identifies the gross normal full load as of May 2009. Mississippi Power does not change unit capacities from season to season.

MWe Net Capacity Summer. Identifies the net normal full load as of May 2009; taken directly from the 2009 installed and authorized document. Mississippi Power does not change unit capacities from se

Original design gross efficiency (%, HHV). Taken directly from the original contract boiler data sheet.

Present operating gross efficiency (%, HHV). 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 stat

Design steam pressure (psig). Based on the thermal design of the unit as represented on the turbine heat balance sheet.

Operating steam pressure (psig). 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 steamtemperature 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. Based on the average service hours operated during the last three years (January 2007 to December 2009), as reported to NERC through the GADS reporting system.Average annual capacity factor for the past three years. Calculated using each year's gross generation divided by that year's average gross normal full load. The average annual capacity factor for each of 

together to obtain this response.NSPS. Where no NSPS is identified, the unit is not currently subject to any NSPS.Retirement. Mississippi Power has not committed to actual retirement dates for Watson Units 4‐5. Mississippi Power continually evaluates retirement scenarios with respect to its generating units for a va

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 Comm

indicative of the unit's actual retirement date.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.

PLANT JACK WATSON ICR PART I SURVEY
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

4 wall‐fired low‐NOx burners & OFA N/A cold‐side ESP ‐ 07/20/681 N/A

5 wall‐fired low‐NOx burners & OFA N/A cold‐side ESP ‐ 05/31/731 flue‐gas conditioning

1

‐ SoCo ESP Database

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]).

PLANT JACK WATSON ICR PART I SURVEY
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 installedfor the purpose of participating in a control technology demonstration project20 (e.g., U.S. Department of Energy program, consent decree,

etc.).

Name Telephone Address

4 N/A N/A N/A N/A

5 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

PLANT JACK WATSON ICR PART I SURVEY
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 equivalentemission rate), and (2) the basis for calculating the percent reduction (i.e., where the "inlet" and "outlet" are).

Boiler ID22

Demonstration

activity actual start‐

up date

Demonstration

activity projected

start‐up date

Demonstration

activity end‐date or

projected end‐date

Type of control (e.g.,

sorbent and type;

chemical additive23)

Desired HAP emission

reduction (%) or

emission rate

Coal rank(s) in use

4 N/A N/A N/A N/A N/A N/A5 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.

PLANT JACK WATSON ICR PART I SURVEY
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

4 N/A N/A N/A N/A

5 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

PLANT JACK WATSON ICR PART I SURVEY
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

4 N/A N/A N/A N/A N/A N/A5 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.

PLANT JACK WATSON ICR PART I SURVEY
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 

4 TVOP: Section 3.B.1. For emission points 4, the maximum

permissible emission of ash and/or PM when burning fossil fuels

shall not exceed an emission rate as determined by the relationship

E=0.8808*I‐0.1667; where E is the emission rate in pounds per million

BTU per hour heat input, and I is the heat input in millions of BTU

per hour, or 0.239 lb/MMBtu.

Same as PM N/A TVOP Section 3.B.2. Emission point 4, the

maximum dishcarge of sulfur oxides (SO2) from

any fuel burning installation in which the fuel isburned primarily to porduce heat or power by

indirect heat transfer shall not exceed 4.8 pounds

(measured as sulfur dioxide) per million BTU heatinput or as otherwise specified herein.

N/A N/A N/A N/

5 TVOP: Section 3.B.1. For emission points 5, the maximum

permissible emission of ash and/or PM when burning fossil fuels

shall not exceed an emission rate as determined by the relationshipE=0.8808*I‐0.1667; where E is the emission rate in pounds per million

BTU per hour heat input, and I is the heat input in millions of BTU

per hour, or 0.212 lb/MMBtu.

Same as PM N/A TVOP Section 3.B.2. Emission point 5, the

maximum dishcarge of sulfur oxides (SO2) from

any fuel burning installation in which the fuel isburned primarily to porduce heat or power by

indirect heat transfer shall not exceed 4.8 pounds

(measured as sulfur dioxide) per million BTU heatinput or as otherwise specified herein.

N/A N/A N/A N/

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 limi

Boiler ID27

PLANT JACK WATSON ICR PART I SURVEY
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 

4 0.12 (guarantee exp N/A N/A N/A N/A N/A N/A N/A N/A 5 99.5% collection effi N/A N/A N/A N/A N/A N/A N/A N/A 

Note: "N/A" means not applicable.

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

Please elaborate.

N/A ‐ not applicable.

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

PLANT JACK WATSON ICR PART I SURVEY
24 For each boiler noted in Part I, question15, provide the following information:

PM36 PM10 PM2.5 SO2

HCl

and/or

HF

HCN

M

HA

4 TVOP: Sect5.B.4. For emission points 4 & 5, the permittee

shall demonstrate compliance with the PM and CO emission

limits by performing a stack test biennially using EPAReference Methods 1‐5 and 10, respectively, or approvedequivalents. Stack testing shall be performed under normaloperating conditions and while operating at or near capacity.

The initial stack test shall be performed within eighteen (18)

months of the permit issuance date, and then tests shall be

conducted biennially thereafter by December 31st of the

respective year.

See PM N/A TVOP: Sect.5.B.2. For emission points 4 & 5, the permittee

shall install, calibrate, maintain, and operate a continuous

emission monitoring system (e.g., CEMS and COMS)for the

purpose of measuring SO2 emissions, NOx emissions, eitheroxygen (O2) or carbon dioxide (CO2), and Opacity, unless

complying with another standard or requirement meets the

requirements of this standard. The permitee shall monitor,

test, and keep records of the emission identified above in

accordance with 40 CFR Part 75. The permittee shall

maintain all measurements, data, reports, testing, and other

information required in 40 CFR Part 75.54 for each affected

unit. The permittee shall utilize Part 75 data for SO2 and NOx

emission reporting by monitoring the parameters andmaintaining the CEMS in accordance with 40 CFR Part 75. The

annual RATA shall be conducted and submitted in accordance

with the requirements of 40 CFR Part 75, Reference Methods6 & 7, respectively.

N/A N/A N

5 TVOP: Sect5.B.4. For emission points 4 & 5, the permittee

shall demonstrate compliance with the PM and CO emission

limits by performing a stack test biennially using EPAReference Methods 1‐5 and 10, respectively, or approved

equivalents. Stack testing shall be performed under normaloperating conditions and while operating at or near capacity.

The initial stack test shall be performed within eighteen (18)

months of the permit issuance date, and then tests shall be

conducted biennially thereafter by December 31st of the

respective year.

See PM N/A TVOP: Sect.5.B.2. For emission points 4 & 5, the permittee

shall install, calibrate, maintain, and operate a continuous

emission monitoring system (e.g., CEMS and COMS)for the

purpose of measuring SO2 emissions, NOx emissions, eitheroxygen (O2) or carbon dioxide (CO2), and Opacity, unless

complying with another standard or requirement meets the

requirements of this standard. The permitee shall monitor,

test, and keep records of the emission identified above in

accordance with 40 CFR Part 75. The permittee shall

maintain all measurements, data, reports, testing, and other

information required in 40 CFR Part 75.54 for each affected

unit. The permittee shall utilize Part 75 data for SO2 and NOx

emission reporting by monitoring the parameters andmaintaining the CEMS in accordance with 40 CFR Part 75. The

annual RATA shall be conducted and submitted in accordance

with the requirements of 40 CFR Part 75, Reference Methods

6 & 7, respectively.

N/A N/A N

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 per

Boiler ID35

PLANT JACK WATSON ICR PART I SURVEY
25 For the control technologies identified in Part I, questions 17 and 19, provide the cost information requested.38

Facility Name/Unit No.: N/ARetrofit 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.

PLANT JACK WATSON ICR PART I SURVEY
Fuel Analysis39

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

Jack Watson

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

2049

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

PLANT JACK WATSON ICR PART II SURVEY
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.

State/Country County42 Coal seam43 % Sulf % Ash Btu

69,017 4, 5 COLOMBIA N/A LA JAGUA SHIP 0.8 8.5 1

68,385 4, 5 COLOMBIA N/A LA JAGUA SHIP 0.63 7.78 1

72,948 4, 5 COLOMBIA N/A LA JAGUA SHIP 0.63 8.1 1

75,592 4, 5 COLOMBIA N/A LA JAGUA SHIP 0.58 8.76 1

69,330 4, 5 COLOMBIA N/A LA JAGUA SHIP 0.58 8.94 1

69,748 4, 5 COLOMBIA N/A LA JAGUA SHIP 0.64 9.38 1

70,335 4, 5 COLOMBIA N/A GRAN MADRE SHIP 0.65 8.49 1

76,805 4, 5 COLOMBIA N/A VARIOUS SHIP 0.68 11.15 1

65,481 4, 5 COLOMBIA N/A VARIOUS SHIP 0.66 9.02 1

68,951 4, 5 COLOMBIA N/A VARIOUS SHIP 0.74 10.45 1

81,573 4, 5 COLOMBIA N/A GRAN MADRE SHIP 0.47 8.23 1

70,103 4, 5 COLOMBIA N/A GRAN MADRE SHIP 0.52 7.21 1

82,057 4, 5 COLOMBIA N/A GRAN MADRE SHIP 0.69 8.06 1

82,097 4, 5 COLOMBIA N/A GRAN MADRE SHIP 0.69 8.06 1

81,016 4, 5 COLOMBIA N/A GRAN MADRE SHIP 0.52 7.34 1

80,538 4, 5 COLOMBIA N/A GRAN MADRE SHIP 0.56 7.73 1

69,585 4, 5 COLOMBIA N/A GRAN MADRE SHIP 0.65 7.98 1

83,140 4, 5 COLOMBIA N/A GRAN MADRE SHIP 0.58 8.08 1

Note: "N/A" means not available.

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

what was burned in the preceding 12 calendar months. Multiple seams may be listed to account for the flexibility written into the purchase orders. Actual ship

have originated from each seam listed.

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, dry Fuel source

basis, short tons40

ID # of boiler(s) firing

fuel41

Fuel shipment

method

Vendor Analyses

PLANT JACK WATSON ICR PART II SURVEY
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):

Antimony Arsenic Beryllium Cadmium Chromium Cobalt Lead Manganese 

09‐700 3,151 0.68 7.89 12,825 0.068 42 71 6.7 1.3 5.5 0.5 0.18 6.6 2.7 2.2 25

09‐704 3,184 0.85 8.7 13,073 0.060 273 113 8.8 1.7 4.7 0.7 0.14 9.9 3.5 3.9 5309‐705 3,148 0.63 9.14 13,009 0.047 200 74 8.1 <1 1.9 0.5 0.11 11.4 2.8 3.6 52

09‐709 3,155 0.9 8.28 13,322 0.073 213 67 6.9 1.4 4.0 0.6 0.07 9.9 2.4 3.1 40

09‐708 3,066 0.64 9.21 13,057 0.050 190 88 6.9 <1 1.9 0.5 0.07 10.2 2.5 2.9 5909‐711 76,170 0.68 9.91 12,841 0.073 31 67 8.3 1.3 5.1 0.7 0.22 9.7 3.0 4.0 28

09‐712 3,176 0.53 7.54 12,845 0.061 55 76 5.5 <1 2.8 0.4 0.17 7.1 2.0 3.1 2209‐716 1,682 0.65 9 12,971 0.070 56 60 6.5 1.3 4.3 0.6 0.10 7.3 2.6 2.5 23

09‐717 3,276 0.63 9.01 12,633 0.077 54 71 7.3 1.4 4.3 0.6 0.13 7.5 2.8 2.6 28

09‐718 74,537 0.7 9.93 12,930 0.052 207 52 8.4 <1 2.5 0.3 0.13 13.1 2.7 3.4 53

09‐720 1,748 0.77 10.41 12,444 0.079 64 81 8.5 1.9 4.9 0.6 0.26 9.8 3.5 4.2 52

09‐721 3,295 0.46 7.72 12,807 0.044 43 45 5.9 1.3 2.0 0.5 0.12 6.4 2.4 3.7 27

09‐723 84,877 0.57 9.13 12,864 0.065 32 53 7.9 1.6 4.7 0.7 0.22 9.3 3.4 3.8 43

09‐725 3,229 0.62 9.45 12,727 0.055 38 52 8.5 1.7 5.1 0.7 0.27 9.5 3.7 3.9 46

09‐726 78,256 0.73 9.59 13,075 0.038 187 54 7.3 <1 2.8 0.3 0.12 12.5 2.8 3.6 53

09‐729 93,867 0.56 8.63 12,767 0.047 37 35 7.6 2.0 5.2 0.7 0.13 8.8 3.1 3.3 24

09‐728 77,969 0.57 9.67 12,731 0.080 33 43 8.7 1.7 4.2 0.6 0.13 9.8 3.3 3.4 41

Note: Mississippi Power collects this information on select coal shipments, but does not have this information available on a shipment by shipment basis. The information Mississippi Power provides in this response cannot be linked to the information Thus, the information provided in this response represents only a very small portion of our actual shipments.

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

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

analysis requirement can be bypassed by the respondent.

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

Total amount of

fuel represented by

sample, tons

Sample ID # 

Nickel, ppm Other trace metal HAP, ppm45 Total Sulfur, % Ash Content, % Heating Value, Btu/lb Mercury, ppm Chlorine, ppm Fluorine, ppm

PLANT JACK WATSON ICR PART II SURVEY
4 Were the data provided in Part II, question 3 above, acquired pursuant to:

_

X

__ permit requirements

_

X

__

contractual obligations

_

X

__

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.

Total

Moisture Volatiles Ash Fixed Carbon Carbon Hydrogen Nitrogen Total Sulfur Oxygen Barium Copper Magnesium Sodium Vanadium Zinc Al2O3 Fe2O3 

09‐700 13.83 38.29 7.89 53.82 74.37 4.91 1.43 0.68 10.72 260 6.7 0.073 0.103 22.6 10.1 20.34 9.

09‐704 16.12 36.84 8.7 54.46 76.29 4.62 1.6 0.85 7.94 100 7.1 0.080 0.052 26.2 21.4 20.53 9.09‐705 13.55 36.84 9.14 54.02 76.25 4.65 1.48 0.63 7.85 80 7.2 0.109 0.077 28.2 19.2 21.32 7.

09‐709 10.76 37.31 8.28 54.41 75.5 5.05 1.64 0.9 8.63 80 6.6 0.077 0.041 24.8 13.6 21.47 9.

09‐708 15.35 36.83 9.21 53.96 73.79 4.74 1.43 0.64 10.19 90 5.9 0.115 0.076 25.6 17.6 19.45 8.

09‐711 10.55 37.43 9.91 52.66 73.5 4.92 1.36 0.68 9.63 190 7.7 0.064 0.051 26.8 15.9 19.48 6.

09‐712 15.84 40.77 7.54 51.69 73.95 4.96 1.46 0.53 11.56 240 6.6 0.074 0.100 19.5 10.5 20.56 7.

09‐716 11.73 37.55 9 53.45 73.97 4.89 1.28 0.65 10.21 170 6.2 0.055 0.045 21.8 12.0 18.23 6

09‐717 13.22 37.96 9.01 53.03 72.98 4.82 1.15 0.63 11.41 250 6.9 0.081 0.121 23.7 11.8 20.48 7.

09‐718 12.86 36.66 9.93 53.41 73.62 4.94 1.43 0.7 9.38 100 6.9 0.121 0.081 30.8 17.9 20.16 7.

09‐720 12.34 37.39 10.41 52.2 71.79 4.73 1.45 0.77 10.85 210 7.6 0.092 0.079 27.9 16.0 19.11 8.

09‐721 14.35 38.75 7.72 53.53 73.66 4.97 1.01 0.46 12.18 220 5.5 0.072 0.100 18.1 7.7 18.22 6.

09‐723 10.83 38.42 9.13 52.45 73.49 5.13 1.4 0.57 10.28 210 8.0 0.068 0.060 26.8 15.7 18.2 7.

09‐725 13.19 37.78 9.45 52.77 72.85 4.89 1.52 0.62 10.67 210 7.7 0.072 0.075 27.4 14.2 18.22 7

09‐726 11.76 36.73 9.59 53.68 73.33 4.98 1.56 0.73 9.81 90 6.3 0.110 0.070 28.4 18.0 19.67 7

09‐729 13.34 38.5 8.63 52.87 71.63 4.79 1.43 0.56 12.96 240 7.6 0.074 0.118 24.5 11.5 21.34 6.

09‐728 10.96 37.39 9.67 52.94 72.11 5.02 1.36 0.57 11.27 220 6.4 0.070 0.072 26.8 13.6 18.14 6.

Sample ID

#

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

PLANT JACK WATSON ICR PART II SURVEY
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 ofcontractual 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 4 Carbon Monoxide Compliance Test ‐ March 18, 2009

Report 2 Unit 5 Carbon Monoxide Compliance Test ‐ July 7, 2008

Report 3 Units 4 and 5 Compliance Particulate Emissions Report ‐ July 2006

Report 4 Units 4 and 5 Compliance Particulate Emissions Report ‐ July 2008

Report 5 Unit 4 RATA Test Report ‐ June 20‐21, 2005Report 6 Unit 4 RATA Test Report ‐ June 26, 2006Report 7 Unit 4 RATA Test Report ‐ June 19, 2007

Report 8 Unit 4 RATA Test Report ‐ June 3, 2008Report 9 Unit 4 RATA Test Report ‐ June 30, 2009

Report 10 Unit 5 RATA Test Report ‐ August 2, 2005Report 11 Unit 5 RATA Test Report ‐ July 17, 2006Report 12 Unit 5 RATA Test Report ‐ July 26, 2007

Report 13 Unit 5 RATA Test Report ‐ June 4, 2008Report 14 Unit 5 RATA Test Report ‐ June 29, 2009Report 15 Unit 4 SCR Baseline Test Report ‐ October 13‐22, 2009

Report 16 Unit 5 SCR Baseline Test Report ‐ November 11‐13, 2009

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: 18‐Mar‐09 Type: Stack Constituents: CO

Report 2 Date: 7‐Jul‐08 Type: Stack Constituents: CO

Report 3 Date: Jul‐06 Type: Stack Constituents: PM

Report 4 Date: Jul‐08 Type: Stack Constituents: PM

Report 5 Date: June 20‐21, 2005 Type: Stack Constituents: SO2

Report 6 Date: 26‐Jun‐06 Type: Stack Constituents: SO2

Report 7 Date: 19‐Jun‐07 Type: Stack Constituents: SO2

Report 8 Date: 3‐Jun‐08 Type: Stack Constituents: SO2

Report 9 Date: 30‐Jun‐09 Type: Stack Constituents: SO2

Report 10 Date: 2‐Aug‐05 Type: Stack Constituents: SO2

Report 11 Date: 17‐Jul‐06 Type: Stack Constituents: SO2

Report 12 Date: 26‐Jul‐07 Type: Stack Constituents: SO2

Report 13 Date: 4‐Jun‐08 Type: Stack Constituents: SO2

Report 14 Date: 29‐Jun‐09 Type: Stack Constituents: SO2

Report 15 Date: October 13‐22, 2009 Type: Duct Constituents: CO, CO2, & NOx

Report 16 Date: November 11‐13, 2009 Type: Duct Constituents: CO, CO2, & NOx

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

Yes

__

X

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

Reports 15 & 16 ‐ tests performed at the economizer outlet.

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 done prior to LNB/OFA on both units 4 and 5. Previous LNBs did not include OFA.

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.

PLANT JACK WATSON ICR PART II SURVEY
9 What type of deviation reporting is required for violations of permit requirements?

Excess emission reports via TVOP Section 1.24.

CAM excursions reports via TVOP Section 5.C.6.

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.

Upset reports via TVOP Section 1.24.Semi‐annual reports via TVOP Section 5.A.4 & 5.C.6.Note: A malfunction is not necessarily a period of noncompliance with permit terms and conditions. Not all reported deviations are considered violations of pe

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.

Opacity ‐ quarterly COMS reports submitted to the MS Dept of Environmental Quality describing excess emissions.

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.

PLANT JACK WATSON ICR PART II SURVEY
12 For each boiler noted in Part I, question 15, provide the following information:

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

4 7/20/2006 0.052 lbs/mmBtu‐Att 3 N/A N/A N/A N/A 

4 7/28/2008 0.040 lbs/mmBtu‐Att 4 N/A N/A N/A N/A 

4 3/18/2009 N/A N/A N/A N/A N/A 0.057 lbs/m

4 6/20‐21/2005 N/A 0.932 lbs/mmBtu (RATA) N/A N/A N/A 

4 6/26/2006 N/A 1.086 lbs/mmBtu (RATA) N/A N/A N/A 4 6/19/2007 N/A 0.779 lbs/mmBtu (RATA) N/A N/A N/A 

4 6/3/2008 N/A 1.0368 lbs/mmBtu (RATA) N/A N/A N/A 

4 6/30/2009 N/A 0.942 lbs/mmBtu (RATA) N/A N/A N/A 4 10/13‐22/2009 N/A N/A N/A N/A N/A See 

5 7/21/2006 0.061 lbs/mmBtu‐Att 6 N/A N/A N/A N/A 

5 7/29/2008 0.052 lbs/ mmBtu‐Att 7 N/A N/A N/A N/A 

5 6/13/2008 N/A N/A N/A N/A N/A 0.0676 lbs/m

5 8/2/2005 N/A 1.0745 lbs/mmBtu (RATA) N/A N/A N/A 

5 7/17/2006 N/A 1.1153 lbs/mmBtu (RATA) N/A N/A N/A 5 7/26/2007 N/A 1.0028 lbs/mmBtu (RATA) N/A N/A N/A 

5 6/4/2008 N/A 1.0595 lbs/mmBtu (RATA) N/A N/A N/A 

5 6/29/2009 N/A 0.8786 lbs/mmBtu (RATA) N/A N/A N/A 

5 11/11‐13/2009 N/A N/A N/A N/A N/A See 

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 Vmust 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

PLANT JACK WATSON ICR PART II SURVEY
ATTACHMENT 1 ‐ Watson Report 15 Test Results

Title of

Run Description Date Start Time End Time Test Load

Avg. Econ

Gas Outlet

CO

Avg. Econ

Gas Outlet

O2

Avg. Econ

Gas Outlet

CO2

Avg. Econ

Gas Outlet

Temp

Military Military MW ppmc % dry % dry DEGF

Test 1 R1 Int. Load 10/13/2009 8:37 9:13 200 41 4.605 12.942 628.8

Test 1 R2 Int. Load 10/13/2009 10:25 11:02 200 33 4.68 12.859 634.5

Test 2 R1 Peak Load 10/13/2009 13:18 13:54 270.3 162 4.14 13.422 702.5

Test 2 R1 Peak Load 10/13/2009 14:40 15:18 270.3 351 3.595 13.801 704.35

Test 3 R1 Min. Load 10/14/2009 8:20 8:56 120 31 6.27 11.486 564

Test 3 R2 Min. Load 10/14/2009 9:42 10:20 120 26 6.38 11.38 567.7

Test 4 600° F Econ 10/14/2009 13:00 14:00 165 48 5.075 12.445 603.6Test 5 FL, 1/3 OFA 10/14/2009 15:37 16:37 250 154 5.275 13.652 698.4Test 6 FL, All OFA 10/14/2009 17:07 18:07 250 17 4.055 14.754 684.4

Test 7 FL, No O2 Bias 10/15/2009 10:00 12:00 250.1 15 4.935 14.149 680.8

Test 8 FL, Max O2 10/15/2009 13:19 14:19 250 4 5.675 13.387 694.95

Test 9 FL, ‐1% O2 Bias 10/15/2009 15:43 16:43 250 25 3.985 14.918 675.35

Test 10 FL, 2/3 OFA 10/20/2009 9:49 11:49 250 35 4.43 14.56 674.8Test 11 FL, 1/3 OFA 10/20/2009 15:01 16:01 250.1 144 4.165 14.543 671.3Test 12 OFA Closed 10/20/2009 16:09 17:09 250 73.914 4.635 14.172 676.2

Test 13 FL, 1/3 OFA 10/21/2009 9:25 10:25 250.2 61.506 4.265 14.8 663.4Test 14 FL, 1/3 100, 2/3 25% 10/21/2009 10:46 11:46 250.1 26.697 4.13 14.876 667.05

Test 15 Int. Load 10/22/2009 8:58 9:58 160 26.366 5.115 14.065 585.15

Test 16 FL, OFA Closed 10/22/2009 12:55 13:55 250 437.269 4.06 14.829 676.95Test 17 FL, 2/3 50% 10/22/2009 14:27 15:10 250.1 50.849 4.19 14.688 681.15

SCR BASELINE TEST RESULTS

MISSISSIPPI POWER COMPANY

JACK WATSON

UNIT 4

PLANT JACK WATSON ICR PART II SURVEY
ATTACHMENT 2 ‐ Watson Report 16 Test Results

Title of

Run Description Date Start Time End Time Test Load

Avg. Econ

Gas Outlet

CO

Avg. Econ

Gas Outlet

O2

Avg. Econ

Gas Outlet

CO2

Avg. Econ

Gas Outlet

Temp

Military Military MW ppmc % dry % dry DEGF

1 Full Load Baseline 11/11/2009 8:22 9:07 500 205 4.96 14.19 698

2 Full Load Baseline Retest 11/11/2009 10:23 11:08 500 194 4.89 14.19 701

3 Full Load After Burner Tuning 11/11/2009 13:25 14:10 500 209 4.84 14.15 705

4 Full Load Increase O2 +1/2% 11/11/2009 15:04 15:49 500 44 5.72 13.4 718

5 Full Load Decrease O2 1/2% 11/11/2009 16:41 17:26 500 652 4.32 14.63 702

6 Temp vs. Load Test 11/12/2009 8:40 9:25 265 13 8.94 10.53 607

7 Mid Load Test 11/12/2009 10:40 11:30 340 17 6.99 12.27 632

8 Econ Gas Out Temp = 600 F vs. Load Test 11/12/2009 12:48 13:33 285 21 6.71 12.47 595

9 Low Load Test 11/12/2009 14:15 15:00 220 14 8.32 11.03 570

10 VWO Test 11/12/2009 17:19 18:04 525 165 5.66 13.42 71211 Full Load OFA Test 11/13/2009 10:16 11:01 500 562 5.19 14 71212 Full Load OFA Test 11/13/2009 12:00 12:45 500 327 5.13 13.98 71313 Full Load OFA Test 11/13/2009 13:32 14:17 500 325 5.98 13.21 721

SCR BASELINE TEST RESULTS

MISSISSIPPI POWER COMPANY

JACK WATSON

UNIT 5

PLANT JACK WATSON ICR PART II SURVEY
ATTACHMENT 3 ‐ Watson Report 3 Test Results

PLANT JACK WATSON ICR PART II SURVEY
ATTACHMENT 4 ‐ Watson Report 4 Test Results

PLANT JACK WATSON ICR PART II SURVEY
ATTACHMENT 5 ‐ Watson Report 1 Test Results

PLANT JACK WATSON ICR PART II SURVEY
ATTACHMENT 6 ‐ Watson Report 3 Test Results

PLANT JACK WATSON ICR PART II SURVEY
ATTACHMENT 7 ‐ Watson Report 4 Test Results

PLANT JACK WATSON ICR PART II SURVEY
ATTACHMENT 8 ‐ Watson Test Results

PLANT JACK WATSON ICR PART II SURVEY