Process Information

1 Name of legal owner of facility:

Mississippi Power Company (50%) and Gulf Power Company (50%)

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

Mississippi Power Company

3 Address of

___ 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):Victor J Daniel Jr

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):

6073

5 Complete street address of facility (physical location):

13201 Highway 63 North

Moss Point, MS 39562‐6489

6 Provide mailing address if different:

Same as above

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) _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 (% _____) _X_ subbituminous (% _44_)_

X

_

bituminous (% _56_) ____ 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 VICTOR J DANIEL JR 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

_

X*

_

distillate (% ____)

_

X

_

other (specify ‐ used oil) (% _< 1__)

____

residual or bunker C (% _____)

*

 ‐ start‐up

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").

Boiler chemical cleaning wastes Y N N/A

Petroleum contaminated soil Y N N/A

Quantity/year

6740 gallons/2009

N/A

Other Material

Used oilClean wood wastes

Actually burn

Y

N

Permitted to burn

YY

PLANT VICTOR J DANIEL JR 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

Fuel11

1 bituminous CBI CBI 537 510 89.17 88.27 2400 2396 1000 1000 1000 978 Bituminous and subbitimious coal, #2 fu

oil, used oil, natural gas,petroleum

contaminated soil (non‐haz), boilercleaning waste, wood waste, and #6 fue

oil and is equipped with an electrostatic

precipitator.

2 bituminous CBI CBI 536 510 89.17 88 2400 2401 1000 999 1000 976 Bituminous and subbitimious coal, #2 fu

oil, used oil, natural gas,petroleum

contaminated soil (non‐haz), boilercleaning waste, wood waste, and #6 fue

oil and is equipped with an electrostatic

precipitator.

Note: "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 pressure).

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 of twelve m

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‐wide‐open or em

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 season to seaso

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 status is indicate

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 the three yea

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 variety of plan

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, 

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 VICTOR J DANIEL JR 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

1 tangential‐fired low‐NOx burners‐2010 N/A ESP ‐ 09/06/77 (cold‐side

conversion 1998) ESP DB

flue gas conditioning ‐ 2000

2 tangential‐fired low‐NOx burners‐2008 N/A ESP ‐ 06/01/81 (cold‐side

conversion 1998) ESP DB

flue gas conditioning ‐ 2000

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 VICTOR J DANIEL JR 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

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

PLANT VICTOR J DANIEL JR 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

1 N/A N/A N/A N/A N/A N/A2 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 VICTOR J DANIEL JR 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

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

PLANT VICTOR J DANIEL JR 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

1 N/A N/A N/A N/A N/A N/A2 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 VICTOR J DANIEL JR 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 

1 TVOP 3.B.1. 0.1 lb/MMBtu; Emission points

1 & 2 are subject to the New SourcePerformance Standards (NSPS), Subpart D,

including the requirements of Section

60.42(a)(1) and (2) for particulate matter,

Section 60.43(a)(2) for sulfur dioxide, and

Section 60.44(a)(3) for nitrogen oxides.

N/A N/A TVOP 3.B.1. 1.2 lb/MMBtu;

Emission points 1 & 2 are

subject to the New SourcePerformance Standards

(NSPS), Subpart D, including

the requirements of Section

60.42(a)(1) and (2) forparticulate matter, Section

60.43(a)(2) for sulfur dioxide,and Section 60.44(a)(3) fornitrogen oxides.

N/A N/A N/A N/

2 TVOP 3.B.1. 0.1 lb/MMBtu; Emission points

1 & 2 are subject to the New SourcePerformance Standards (NSPS), Subpart D,

including the requirements of Section

60.42(a)(1) and (2) for particulate matter,Section 60.43(a)(2) for sulfur dioxide, and

Section 60.44(a)(3) for nitrogen oxides.

N/A N/A TVOP 3.B.1. 1.2 lb/MMBtu;

Emission points 1 & 2 aresubject to the New Source

Performance Standards

(NSPS), Subpart D, including

the requirements of Section

60.42(a)(1) and (2) for

particulate matter, Section

60.43(a)(2) for sulfur dioxide,and Section 60.44(a)(3) fornitrogen oxides.

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.* Boiler ID 1 CO ‐ PSD Permit 0.153 Lb/MMBtu based on a 3‐hour block average and 3660 tons/year

* Boiler ID 2 CO ‐ PSD Permit 0.153 Lb/MMBtu based on a 3‐hour block average and 3660 tons/year* Boiler ID 1 CO ‐ PSD Permit issued January 4, 2010

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

Boiler ID27

PLANT VICTOR J DANIEL JR 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 

1 0.015 lb/mmBtu (guarantee expires 1999) N/A N/A N/A N/A N/A N/A 2 0.015 lb/mmBtu (guarantee expires 2002) 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 emis

Boiler ID32

PLANT VICTOR J DANIEL JR 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

Metal

HAP37 Hg CO

1 TVOP 5.B.3. For emission

points 1 & 2, the permittee

shall demonstrate complaincewith the particulae matter

emission limits by performing

a stack test biennially usingEPA Reference Methods 1‐5,

or approved equivalents.

N/A N/A TVOP‐Sect.5.B.2. For emission points

1 & 2, the permittee shall install,calibrate, maintain, and operate acontinuous emissions monitoringsystem (e.g., COMS, CEMS) for thepurpose of measuring the opacity of

emissions, sulfur dioxide emissions,nitrogen oxides emissions, and

eithere oxygen or carbon dioxide,unless complying with another

standard or requirement meets therequirements of this standard. 40

CFR Part 60; CEMS, 40 CFR Part 75.

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

PSD‐Construction Pe

2 TVOP 5.B.3. For emission

points 1 & 2, the permittee

shall demonstrate compliance

with the particulae matter

emission limits by performing

a stack test biennially usingEPA Reference Methods 1‐5,

or approved equivalents.

N/A N/A TVOP‐Sect.5.B.2. For emission points

1 & 2, the permittee shall install,calibrate, maintain, and operate acontinuous emissions monitoringsystem (e.g., COMS, CEMS) for the

purpose of measuring the opacity of

emissions, sulfur dioxide emissions,nitrogen oxides emissions, and

eithere oxygen or carbon dioxide,unless complying with anotherstandard or requirement meets therequirements of this standard. 40

CFR Part 60; CEMS, 40 CFR Part 75.

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

PSD‐Construction Pe

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 lim

Boiler ID35

PLANT VICTOR J DANIEL JR 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/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.

PLANT VICTOR J DANIEL JR ICR PART I SURVEY
Fuel Analysis39

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

Victor J Daniel, Jr

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

6073

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

PLANT VICTOR J DANIEL JR 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.B.

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

11,060 1, 2 CO GUNNISON D SEAM TRAIN 0.49 9.82 13,173

11,257 1, 2 CO GUNNISON D SEAM TRAIN 0.59 10.48 12,870

11,335 1, 2 CO GUNNISON D SEAM TRAIN 0.5 8.84 13,136

10,986 1, 2 CO GUNNISON D SEAM TRAIN 0.51 9.06 13,067

11,390 1, 2 CO GUNNISON D SEAM TRAIN 0.51 10.18 12,905

11,127 1, 2 CO GUNNISON D SEAM TRAIN 0.5 8.16 13,20111,197 1, 2 CO GUNNISON D SEAM TRAIN 0.57 9.38 12,939

10,835 1, 2 CO GUNNISON D SEAM TRAIN 0.49 9.61 12,948

11,041 1, 2 CO GUNNISON D SEAM TRAIN 0.53 10.63 12,915

11,233 1, 2 CO GUNNISON D SEAM TRAIN 0.54 10.75 12,823

10,928 1, 2 CO GUNNISON D SEAM TRAIN 0.51 10.28 12,910

10,845 1, 2 CO GUNNISON D SEAM TRAIN 0.54 13.75 12,436

10,969 1, 2 CO GUNNISON D SEAM TRAIN 0.54 12 12,728

11,263 1, 2 CO GUNNISON D SEAM TRAIN 0.52 10.49 12,975

10,918 1, 2 CO GUNNISON D SEAM TRAIN 0.56 9.26 13,143

10,665 1, 2 CO GUNNISON D SEAM TRAIN 0.57 12.41 12,606

11,274 1, 2 CO GUNNISON D SEAM TRAIN 0.53 11.72 12,711

10,859 1, 2 CO GUNNISON D SEAM TRAIN 0.55 10.32 12,946

11,092 1, 2 CO GUNNISON D SEAM TRAIN 0.53 10.79 12,874

11,152 1, 2 CO GUNNISON D SEAM TRAIN 0.53 9.72 12,977

10,909 1, 2 CO GUNNISON D SEAM TRAIN 0.49 10.92 12,858

11,204 1, 2 CO GUNNISON D SEAM TRAIN 0.53 10.33 13,018

11,170 1, 2 CO GUNNISON D SEAM TRAIN 0.51 10.66 12,896

10,817 1, 2 CO GUNNISON D SEAM TRAIN 0.52 9.53 13,079

10,965 1, 2 CO GUNNISON D SEAM TRAIN 0.51 9.56 13,049

11,314 1, 2 CO GUNNISON D SEAM TRAIN 0.52 10.28 12,888

10,902 1, 2 CO GUNNISON D SEAM TRAIN 0.53 11.34 12,784

11,331 1, 2 CO GUNNISON D SEAM TRAIN 0.49 10.52 12,924

11,368 1, 2 CO GUNNISON D SEAM TRAIN 0.52 10.23 12,879

11,247 1, 2 CO GUNNISON D SEAM TRAIN 0.56 9.74 13,057

10,996 1, 2 CO GUNNISON D SEAM TRAIN 0.55 7.94 13,254

11,453 1, 2 CO GUNNISON D SEAM TRAIN 0.56 7.53 13,423

10,945 1, 2 CO GUNNISON D SEAM TRAIN 0.54 7.87 13,305

11,239 1, 2 CO GUNNISON D SEAM TRAIN 0.5 7.47 13,358

11,367 1, 2 CO GUNNISON D SEAM TRAIN 0.53 8.21 13,261

10,813 1, 2 CO GUNNISON D SEAM TRAIN 0.54 8.04 13,349

11,256 1, 2 CO GUNNISON D SEAM TRAIN 0.52 9.65 13,043

11,371 1, 2 CO GUNNISON D SEAM TRAIN 0.53 10.01 12,969

11,163 1, 2 CO GUNNISON D SEAM TRAIN 0.48 8.91 13,344

11,204 1, 2 CO GUNNISON D SEAM TRAIN 0.47 8.95 13,303

11,359 1, 2 CO GUNNISON D SEAM TRAIN 0.44 7.63 13,528

11,123 1, 2 CO GUNNISON D SEAM TRAIN 0.45 6.38 13,774

11,448 1, 2 CO GUNNISON D SEAM TRAIN 0.45 9.61 13,217

11,357 1, 2 CO GUNNISON D SEAM TRAIN 0.45 8.68 13,321

11,309 1, 2 CO GUNNISON D SEAM TRAIN 0.45 9.09 13,311

11,208 1, 2 CO GUNNISON D SEAM TRAIN 0.44 9.49 13,298

11,140 1, 2 CO GUNNISON D SEAM TRAIN 0.44 10.45 12,959

11,120 1, 2 CO GUNNISON D SEAM TRAIN 0.44 11 13,012

11,231 1, 2 CO GUNNISON D SEAM TRAIN 0.44 14.29 12,489

10,568 1, 2 CO ROUTT WADGE TRAIN 0.55 12.66 12,304

10,612 1, 2 CO ROUTT WADGE TRAIN 0.55 11.89 12,435

10,813 1, 2 CO ROUTT WADGE TRAIN 0.55 12.58 12,317

11,706 1, 2 CO ROUTT WADGE TRAIN 0.59 12.01 12,396

11,092 1, 2 CO ROUTT WADGE TRAIN 0.53 13.46 12,475

10,950 1, 2 CO ROUTT WADGE TRAIN 0.52 12.53 12,325

10,983 1, 2 CO ROUTT WADGE TRAIN 0.53 12.28 12,300

10,927 1, 2 CO ROUTT WADGE TRAIN 0.48 13.33 12,206

10,671 1, 2 CO ROUTT WADGE TRAIN 0.51 11.74 12,422

10,910 1, 2 CO ROUTT WADGE TRAIN 0.55 11.19 12,539

10,922 1, 2 CO ROUTT WADGE TRAIN 0.53 12.15 12,319

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) firing

fuel41

Fuel shipment

method

PLANT VICTOR J DANIEL JR ICR PART II SURVEY
D.B. D.B. D.B.

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

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) firing

fuel41

Fuel shipment

method

11,052 1, 2 CO ROUTT WADGE TRAIN 0.53 12.33 12,369

11,004 1, 2 CO ROUTT WADGE TRAIN 0.52 12.16 12,370

10,871 1, 2 CO ROUTT WADGE TRAIN 0.54 12.47 12,270

10,326 1, 2 CO ROUTT WADGE TRAIN 0.54 11.88 12,419

11,040 1, 2 CO ROUTT WADGE TRAIN 0.55 11.79 12,467

10,950 1, 2 CO ROUTT WADGE TRAIN 0.56 11.67 12,509

10,806 1, 2 CO ROUTT WADGE TRAIN 0.55 11.59 12,467

10,675 1, 2 CO ROUTT WADGE TRAIN 0.59 11.2 12,549

10,933 1, 2 CO ROUTT WADGE TRAIN 0.59 11.73 12,490

11,050 1, 2 CO ROUTT WADGE TRAIN 0.58 12.75 12,241

11,065 1, 2 CO ROUTT WADGE TRAIN 0.55 10.94 12,585

11,325 1, 2 CO ROUTT WADGE TRAIN 0.53 11.38 12,461

10,859 1, 2 CO ROUTT WADGE TRAIN 0.52 11.36 12,409

10,952 1, 2 CO ROUTT WADGE TRAIN 0.51 11.35 12,471

10,614 1, 2 CO ROUTT WADGE TRAIN 0.53 11.56 12,455

10,828 1, 2 CO ROUTT WADGE TRAIN 0.51 12.28 12,344

11,203 1, 2 CO ROUTT WADGE TRAIN 0.52 12.59 12,304

11,014 1, 2 CO ROUTT WADGE TRAIN 0.51 11.66 12,480

11,046 1, 2 CO ROUTT WADGE TRAIN 0.54 11.48 12,524

10,921 1, 2 CO ROUTT WADGE TRAIN 0.51 11.7 12,419

10,691 1, 2 CO ROUTT WADGE TRAIN 0.47 11.87 12,408

10,667 1, 2 CO ROUTT WADGE TRAIN 0.47 11.91 12,443

11,015 1, 2 CO ROUTT WADGE TRAIN 0.52 11.18 12,472

10,924 1, 2 CO ROUTT WADGE TRAIN 0.52 11.78 12,457

11,218 1, 2 CO ROUTT WADGE TRAIN 0.53 11.49 12,533

11,057 1, 2 CO ROUTT WADGE TRAIN 0.54 11.22 12,507

9,283 1, 2 WY CAMPBELL WYODAK TRAIN 0.26 6.1 12,057

9,431 1, 2 WY CAMPBELL WYODAK TRAIN 0.29 6.11 12,116

9,390 1, 2 WY CAMPBELL WYODAK TRAIN 0.27 6.71 12,000

9,858 1, 2 WY CAMPBELL WYODAK TRAIN 0.29 7.02 11,939

9,873 1, 2 WY CAMPBELL WYODAK TRAIN 0.29 5.97 12,084

9,528 1, 2 WY CAMPBELL WYODAK TRAIN 0.29 6.74 11,980

9,763 1, 2 WY CAMPBELL WYODAK TRAIN 0.35 6.54 12,027

9,356 1, 2 WY CAMPBELL WYODAK TRAIN 0.28 6.52 12,082

9,958 1, 2 WY CAMPBELL WYODAK TRAIN 0.3 7.52 11,901

9,996 1, 2 WY CAMPBELL WYODAK TRAIN 0.27 6.11 12,134

9,953 1, 2 WY CAMPBELL WYODAK TRAIN 0.27 6.33 12,102

9,819 1, 2 WY CAMPBELL WYODAK TRAIN 0.27 5.61 12,200

10,542 1, 2 WY CAMPBELL WYODAK TRAIN 0.28 6.54 12,015

9,555 1, 2 WY CAMPBELL WYODAK TRAIN 0.27 6.33 12,044

9,933 1, 2 WY CAMPBELL WYODAK TRAIN 0.26 6.77 12,028

10,012 1, 2 WY CAMPBELL WYODAK TRAIN 0.3 6.69 12,009

9,671 1, 2 WY CAMPBELL WYODAK TRAIN 0.33 6.44 11,990

9,811 1, 2 WY CAMPBELL WYODAK TRAIN 0.29 5.89 12,015

10,011 1, 2 WY CAMPBELL WYODAK TRAIN 0.3 6.97 11,948

9,986 1, 2 WY CAMPBELL WYODAK TRAIN 0.3 6.8 11,906

10,059 1, 2 WY CAMPBELL WYODAK TRAIN 0.3 6.18 12,068

9,968 1, 2 WY CAMPBELL WYODAK TRAIN 0.31 6.34 12,017

10,038 1, 2 WY CAMPBELL WYODAK TRAIN 0.31 6.69 11,952

10,040 1, 2 WY CAMPBELL WYODAK TRAIN 0.33 6.29 11,986

9,992 1, 2 WY CAMPBELL WYODAK TRAIN 0.27 6.56 11,996

9,867 1, 2 WY CAMPBELL WYODAK TRAIN 0.28 6.8 11,990

8,673 1, 2 WY CAMPBELL WYODAK TRAIN 0.24 6.68 12,037

9,871 1, 2 WY CAMPBELL WYODAK TRAIN 0.27 6.29 12,024

9,962 1, 2 WY CAMPBELL WYODAK TRAIN 0.32 7.07 11,900

9,949 1, 2 WY CAMPBELL WYODAK TRAIN 0.26 6.26 12,132

9,996 1, 2 WY CAMPBELL WYODAK TRAIN 0.29 6.67 12,001

10,027 1, 2 WY CAMPBELL WYODAK TRAIN 0.3 6.16 11,991

10,054 1, 2 WY CAMPBELL WYODAK TRAIN 0.3 6.17 12,013

10,002 1, 2 WY CAMPBELL WYODAK TRAIN 0.28 6.7 12,032

10,130 1, 2 WY CAMPBELL WYODAK TRAIN 0.33 5.88 12,117

9,990 1, 2 WY CAMPBELL WYODAK TRAIN 0.32 6.2 12,035

PLANT VICTOR J DANIEL JR ICR PART II SURVEY
D.B. D.B. D.B.

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

Vendor Analyses

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) firing

fuel41

Fuel shipment

method

10,058 1, 2 WY CAMPBELL WYODAK TRAIN 0.27 6.31 12,044

9,988 1, 2 WY CAMPBELL WYODAK TRAIN 0.3 6.9 11,931

9,928 1, 2 WY CAMPBELL WYODAK TRAIN 0.26 6.32 12,010

10,076 1, 2 WY CAMPBELL WYODAK TRAIN 0.28 6.05 12,075

10,031 1, 2 WY CAMPBELL WYODAK TRAIN 0.29 6.72 11,947

10,006 1, 2 WY CAMPBELL WYODAK TRAIN 0.31 6.29 12,031

10,062 1, 2 WY CAMPBELL WYODAK TRAIN 0.3 6.03 12,040

9,965 1, 2 WY CAMPBELL WYODAK TRAIN 0.29 6.77 11,914

10,075 1, 2 WY CAMPBELL WYODAK TRAIN 0.25 6.4 12,056

9,939 1, 2 WY CAMPBELL WYODAK TRAIN 0.29 6.26 12,054

10,047 1, 2 WY CAMPBELL WYODAK TRAIN 0.25 6.05 12,135

9,891 1, 2 WY CAMPBELL WYODAK TRAIN 0.28 6.01 11,959

9,799 1, 2 WY CAMPBELL WYODAK TRAIN 0.28 6.61 11,903

9,732 1, 2 WY CAMPBELL WYODAK TRAIN 0.26 6.32 12,065

10,141 1, 2 WY CAMPBELL WYODAK TRAIN 0.28 5.96 12,160

9,828 1, 2 WY CAMPBELL WYODAK TRAIN 0.29 6.67 11,990

9,959 1, 2 WY CAMPBELL WYODAK TRAIN 0.28 6.16 12,035

9,930 1, 2 WY CAMPBELL WYODAK TRAIN 0.27 6.24 12,015

9,865 1, 2 WY CAMPBELL WYODAK TRAIN 0.28 6.59 12,041

9,856 1, 2 WY CAMPBELL WYODAK TRAIN 0.34 6.73 11,969

9,410 1, 2 WY CAMPBELL WYODAK TRAIN 0.3 6.54 11,985

8,905 1, 2 WY CAMPBELL WYODAK TRAIN 0.26 6.25 12,142

10,006 1, 2 WY CAMPBELL WYODAK TRAIN 0.3 6.31 12,092

9,946 1, 2 WY CAMPBELL WYODAK TRAIN 0.29 5.95 12,058

10,165 1, 2 WY CAMPBELL WYODAK TRAIN 0.25 5.86 12,165

10,010 1, 2 WY CAMPBELL WYODAK TRAIN 0.3 6.37 12,006

9,958 1, 2 WY CAMPBELL WYODAK TRAIN 0.32 5.99 12,085

9,895 1, 2 WY CAMPBELL WYODAK TRAIN 0.29 6.1 12,080

9,995 1, 2 WY CAMPBELL WYODAK TRAIN 0.31 6.39 12,169

9,837 1, 2 WY CAMPBELL WYODAK TRAIN 0.3 6.1 12,033

9,887 1, 2 WY CAMPBELL WYODAK TRAIN 0.26 6.29 11,999

13,821 1, 2 WY CAMPBELL WYODAK TRAIN

9,330 1, 2 WY CAMPBELL WYODAK TRAIN 0.27 6.51 12,172

9,222 1, 2 WY CAMPBELL WYODAK TRAIN 0.29 6.48 12,064

10,049 1, 2 WY CAMPBELL WYODAK TRAIN 0.3 6.19 12,064

8,492 1, 2 WY CAMPBELL WYODAK TRAIN 0.28 6.85 11,990

69,441 1, 2 COLOMBIA N/A GRAN MADRE SHIP 0.72 7.94 12,85469,505 1, 2 COLOMBIA N/A GRAN MADRE SHIP 0.69 9.52 12,60370,345 1, 2 COLOMBIA N/A GRAN MADRE SHIP 0.73 8.72 12,63981,722 1, 2 COLOMBIA N/A GRAN MADRE SHIP 0.71 8.96 12,67870,206 1, 2 COLOMBIA N/A GRAN MADRE SHIP 0.54 9.13 12,64882,002 1, 2 COLOMBIA N/A GRAN MADRE SHIP 0.63 7.17 12,986

Note: "N/A" means not available.

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.

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

the preceeding 12 calendar months is what was burned in the preceeding 12 calendar months.

PLANT VICTOR J DANIEL JR ICR PART II SURVEY
State/Country County42 Coal seam43

14,826 1, 2 Mississippi/USA N/A N/A Truck

7,403 1, 2 Mississippi/USA N/A N/A Truck

14,868 1, 2 Mississippi/USA N/A N/A Truck

14,872 1, 2 Mississippi/USA N/A N/A Truck

7,448 1, 2 Mississippi/USA N/A N/A Truck

7,448 1, 2 Mississippi/USA N/A N/A Truck

7,434 1, 2 Mississippi/USA N/A N/A Truck

7,400 1, 2 Mississippi/USA N/A N/A Truck

7,410 1, 2 Mississippi/USA N/A N/A Truck

14,854 1, 2 Mississippi/USA N/A N/A Truck

7,434 1, 2 Mississippi/USA N/A N/A Truck

29,708 1, 2 Mississippi/USA N/A N/A Truck

14,834 1, 2 Mississippi/USA N/A N/A Truck

14,725 1, 2 Mississippi/USA N/A N/A Truck

22,145 1, 2 Mississippi/USA N/A N/A Truck

12,393 1, 2 Mississippi/USA N/A N/A Truck

22,184 1, 2 Mississippi/USA N/A N/A Truck

7,358 1, 2 Mississippi/USA N/A N/A Truck

22,093 1, 2 Mississippi/USA N/A N/A Truck

7,400 1, 2 Mississippi/USA N/A N/A Truck

14,732 1, 2 Mississippi/USA N/A N/A Truck

7,366 1, 2 Mississippi/USA N/A N/A Truck

7,373 1, 2 Mississippi/USA N/A N/A Truck

14,666 1, 2 Mississippi/USA N/A N/A Truck

7,345 1, 2 Mississippi/USA N/A N/A Truck

22,063 1, 2 Mississippi/USA N/A N/A Truck

14,608 1, 2 Mississippi/USA N/A N/A Truck

14,614 1, 2 Mississippi/USA N/A N/A Truck

14,622 1, 2 Mississippi/USA N/A N/A Truck

7,331 1, 2 Mississippi/USA N/A N/A Truck

7,318 1, 2 Mississippi/USA N/A N/A Truck

7,318 1, 2 Mississippi/USA N/A N/A Truck

14,814 1, 2 Mississippi/USA N/A N/A Truck

14,826 1, 2 Mississippi/USA N/A N/A Truck

14,842 1, 2 Mississippi/USA N/A N/A Truck

14,834 1, 2 Mississippi/USA N/A N/A Truck

14,834 1, 2 Mississippi/USA N/A N/A Truck

Note: "N/A" means not available.

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

the preceeding 12 calendar months is what was burned in the preceeding 12 calendar months.

FUEL OIL SHIPMENTS

Amount received,

gallons40

ID # of boiler(s) firing

fuel41

Fuel source Fuel shipment

method

PLANT VICTOR J DANIEL JR ICR PART II SURVEY
3 For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information 44, as

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

Antimony Arsenic Beryllium Cadmium Chromium Cobalt Lead 

09‐306 11,746 0.55 10.55 12,773 0.028 76 59 4.0 <1 0.9 0.7 0.06 5.3 2.3 6.0 

09‐706 79,854 0.75 9.61 12,618 0.089 40 68 7.8 1.8 6.1 0.8 0.26 8.3 3.0 3.1 

09‐302 14,519 0.28 6 11,962 0.065 60 67 3.0 <1 0.5 0.4 0.05 3.9 2.5 3.1 

09‐318 11,875 0.53 12.1 12,398 0.045 47 65 2.5 <1 0.6 0.8 <0.02 4.1 1.9 6.4 

09‐319 12,281 0.57 9.66 12,894 0.030 131 56 3.7 <1 1.0 0.6 0.03 5.0 2.1 5.4 

09‐714 80,478 0.75 8.78 12,643 0.095 48 59 9.7 2.3 6.4 0.8 0.25 8.9 3.9 3.1 

09‐312 14,588 0.28 5.95 12,055 ND ND 32 3.5 ND 0.3 0.3 ND 3.1 2.9 2.4 

09‐325 16,045 0.27 6.5 12,079 0.079 37 48 2.8 <1 0.5 0.4 <0.02 2.9 2.5 2.2 

09‐333 12,286 0.53 10.91 13,086 0.033 231 57 4.0 <1 1.0 0.7 0.03 5.9 2.2 5.6 

09‐334 12,310 0.56 11.79 12,437 0.059 43 96 2.8 <1 0.8 0.6 0.06 4.4 2.0 6.4 

09‐722 93,664 0.72 9.06 12,604 0.090 39 48 7.8 1.3 4.7 0.5 0.23 8.3 2.7 4.2 

09‐337 11,901 0.46 11.79 12,406 0.052 31 61 2.0 <1 1.0 0.7 0.03 4.3 2.3 7.1 

09‐338 12,197 0.46 9.97 13,087 0.032 266 56 4.1 <1 1.1 0.6 0.05 6.4 2.9 6.5 

09‐343 14,718 0.37 6.36 11,990 ND 88 62 3.7 ND 0.5 0.4 ND 3.3 3.3 2.9 

Note: "ND" means non‐detect.

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 

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 VICTOR J DANIEL JR 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 

09‐306 8.8 38.09 10.55 51.36 74.14 4.84 1.54 0.55 8.38 240 8.5 0.081 0.050 15.5 11.0 27.37 5.0

09‐706 12.34 38.19 9.61 52.2 74.11 4.51 1.42 0.75 9.6 250 8.1 0.081 0.139 25.9 15.0 21.18 7.4

09‐302 26.54 44.79 6 49.21 69.39 4.45 0.86 0.28 19.03 361 11.0 0.206 0.083 13.5 6.9 15 4.509‐318 10.22 37.34 12.1 50.56 69.57 4.9 1.73 0.53 11.17 350 6.0 0.094 0.092 9.3 7.9 24.85 3.409‐319 8.81 37.86 9.66 52.48 72.92 5.03 1.64 0.57 10.18 250 8.2 0.075 0.051 14.2 14.4 25.88 6.209‐714 12.4 38.68 8.78 52.54 73.12 4.93 1.49 0.75 10.93 250 8.1 0.076 0.110 31.0 13.3 19.88 8.9

09‐312 28.27 44.91 5.95 49.14 70.27 4.6 0.99 0.28 17.9 346 11.3 0.198 0.074 11.9 9.0 15.4 5.309‐325 27.29 43.79 6.5 49.71 69.81 4.79 0.65 0.27 17.98 340 10.3 0.189 0.074 11.2 7.4 17.12 5.009‐333 7.58 36.91 10.91 52.18 73.35 5.03 1.34 0.53 8.84 240 9.0 0.079 0.074 15.5 10.6 23.62 5.009‐334 10.27 37.09 11.79 51.12 70.39 4.96 1.85 0.56 10.45 320 5.8 0.078 0.110 10.0 7.6 26.25 3.2

09‐722 11.78 38.07 9.06 52.87 72.78 4.96 1.06 0.72 11.42 240 7.5 0.082 0.102 24.6 12.9 19.61 7.909‐337 10.36 37.14 11.79 51.07 69.85 4.96 1.82 0.46 11.12 330 5.3 0.079 0.093 9.6 8.4 26.39 3.109‐338 7.8 37.33 9.97 52.7 73.85 5.15 1.71 0.46 8.86 220 9.9 0.078 0.071 17.6 13.6 24.33 5.309‐343 28.18 44.34 6.36 49.31 68.87 4.53 1.09 0.37 18.77 375 11.1 0.209 0.071 12.9 8.9 15.3 4

Note: "ND" means non‐detect.

Sample ID

#

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

PLANT VICTOR J DANIEL JR 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, forall 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.

Report1 Unit 1 Nitric Oxides & Sulfur Dioxide Emissions Report ‐ Septemeber 20‐21, 2005

Report2 Unit 1 Sulfur Dioxide & Nitric Oxides Emissions Report ‐ August 29, 2006

Report3 Unit 1 Sulfur Dioxide & Nitric Oxides Emissions Report ‐ October 13, 2008

Report4 Unit 1 Particulate Emissions Test Report ‐ May 19, 2009Report5 Unit 2 Nitric Oxides & Sulfur Dioxide Emissions Report ‐ September 19‐20, 2005

Report6 Unit 2 Sulfur Dioxide & Nitric Oxides Emissions Report ‐ August 30, 2006

Report7 Unit 2 Sulfur Dioxide & Nitric Oxides Emissions Report ‐ September 5, 2008

Report8 Report8 Unit 2 Particulate Particulate Emissions Emissions Test Report ‐ June 5, 2009Report9 Unit 1 CO Test Report ‐ January 24‐26, 2006Report10 Unit 2 CO Test Report ‐ January 21‐22, 2009Report11 Evaluation of Hg Control using Sorben Injection ‐ April 23 ‐ May 21, 2005

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: September 20‐21, 2005 Type: Stack Constituents: NOx&SO2

Report 2 Date: 29‐Aug‐06 Type: Stack Constituents: SO2&NOxReport 3 Date: 13‐Oct‐08 Type: Stack Constituents: SO2&NOx

Report 4 Date: 19‐May‐09 Type: Stack Constituents: PM

Report 5 Date: September 19‐20, 2005 Type: Stack Constituents: NOx&SO2

Report 6 Date: 30‐Aug‐06 Type: Stack Constituents: SO2&NOx

Report 7 Report 7 Date: 5 Sep 08 5‐Sep‐08 Type: Stack Constituents: Constituents: SO2&NOx SO2&NOx

Report 8 Date: 5‐Jun‐09 Type: Stack Constituents: PM

Report 9 Date: 01/24‐26/2006 Type: Duct Constituents: CO, CO2 & NOx

Report 10 Date: 01/21‐22/2009 Type: Duct Constituents: CO, CO2 & NOx

Report 11 Date: April 23‐May21, 2005 Type: Parametric Constituents: Mercury

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 9 & 10 ‐ tests performed at the economizer outlet.

Report 11 ‐ test performed prior to ESP.

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.

PLANT VICTOR J DANIEL JR ICR PART II SURVEY
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.

Yes ‐ due to installation of Low NOx burners on Daniel unit 2 first, and then, on Daniel unit 1.

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

__

X

__

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

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

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

Hg testing was performed upstream of ESP for Plant Daniel unit 1 during April and May 2005.

PLANT VICTOR J DANIEL JR 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.8.

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.C.8.Note: A malfunction is not necessarily a period of noncompliance with permit terms and conditions.

Note: Not all reported deviations are considered violations of permit requirements.

11 Are continuous emissions monitoring system (CEMS) data available (e.g., mercury, continuous opacity monitoring systems) that are not

already being provided to the U.S. EPA, even if from short‐term testing?

Yes

_

X_ No ____ If yes46, please note for which pollutants CEMS data are available and the period of time (both total period and calendar

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

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 VICTOR J DANIEL JR 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 CO 

1 5/19/2009 0.0085 lbs/mmBtu‐Att 7 N/A N/A N/A N/A N/A 1 9/20‐21/2005 N/A 0.672 lbs/mmBtu‐Att 4 N/A N/A N/A N/A 

1 8/29/2006 N/A 0.748 lbs/mmBtu‐Att 5 N/A N/A N/A N/A 

1 10/13/2008 N/A 0.608 lbs/mmBtu‐Att 6 N/A N/A N/A N/A 

1 1/24‐26/2006 N/A N/A N/A N/A N/A See Attach. 2 6/5/2009 0.0088 lbs/mmBtu‐Att 11 N/A N/A N/A N/A N/A 2 9/20‐21‐2005 N/A 0.740 lbs/mmBtu‐Att 8 N/A N/A N/A N/A 

2 8/30/2006 N/A 0.820 lbs/mmBtu‐Att 9 N/A N/A N/A N/A 

2 9/5/2008 N/A 0.865 lbs/mmBtu‐Att 10 N/A N/A N/A N/A 

2 1/21‐22/2009 N/A N/A N/A N/A N/A See Attach. 2 

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.

40 CFR Part 60 Appendix A Reference Methods 1, 2, 3A, 4 & 17.

PM test results via an average of 3 one‐hour runs.

40 CFR Part 60 Appendix A Reference Methods 3A, 6C & 7E

SO2 test results via data extracted from RATA test data.

Boiler ID

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

PLANT VICTOR J DANIEL JR ICR PART II SURVEY
ATTACHMENT 1 ‐ Daniel Report 9 Test Results

Title of

Run Description Date Start Time End Time Gross Load

Avg. Econ.

Gas Outlet

CO

Avg. Econ.

Gas Outlet

O2

Avg. Econ.

Gas Outlet

CO2

Avg. Econ.

Gas Outlet

Temp

Military Military MW ppm % Dry % Dry Deg F

Test02 full load, horizontal burner tilts 1/24/2006 10:42 11:42 533.4 222 2.6 16.38 632.6

Test03 full load, horizontal burner tilts 1/24/2006 14:35 15:35 533.4 386 2.37 16.5 637.4

Test04 full load, CCOFA @ 50% 1/25/2006 9:00 10:00 534.1 18 3.5 15.58 637.7

Test06 intermediate load 1/25/2006 12:59 13:59 370.2 76 3.35 15.63 577.1Test07 minimum load 1/25/2006 15:07 16:07 200.2 1 5.26 13.7 492.5

Test08 full load, CCOFA @ 50% 1/26/2006 11:00 11:50 535.2 851 2.15 16.61 628.7

Test10 intermediate load 1/26/2006 13:27 14:27 369.9 0 3.95 14.95 575.7Test11 minimum load 1/26/2006 15:39 16:30 201.1 0 5.24 13.75 498.9

Test12 full load, horizontal burner tilts 1/26/2006 17:55 18:50 530.1 233 2.71 16.05 631.6

SCR BASELINE TEST RESULTS

MISSISSIPPI POWER COMPANY

VICTOR J DANIEL JR.

UNIT 1

PLANT VICTOR J DANIEL JR ICR PART II SURVEY
ATTACHMENT 2 ‐ Daniel Report 10 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

31 Full Load 1/21/2009 14:06 14:54 532 47 3.02 15.92 71632 Full Load 1/21/2009 15:01 15:11 533 69 2.96 15.94 71633 Full Load 1/21/2009 15:14 16:02 533 61 2.93 16.01 71634 Full Load 1/21/2009 16:11 16:21 533 55 2.98 15.93 71735 Full Load 1/21/2009 16:25 17:13 534 41 3 15.94 71837 Full Load 1/21/2009 17:19 18:07 534 50 3.02 15.94 71938 Int. Load 1/22/2009 17:23 18:11 301 15 3.91 15.14 612

39 Int. Load 1/22/2009 18:17 18:27 300 13 3.92 15.11 613

40 Int. Load 1/22/2009 18:30 19:18 300 8 4.1 14.97 614

41 Int. Load 1/22/2009 19:23 19:33 301 8 4.07 14.99 615

42 Int. Load 1/22/2009 19:37 20:25 302 8 4.17 14.92 617

43 Int. Load 1/22/2009 20:28 21:16 301 8 4.16 14.94 617

LNB GUARANTEE TEST RESULTS

MISSISSIPPI POWER COMPANY

VICTOR J DANIEL JR.

UNIT 2

PLANT VICTOR J DANIEL JR ICR PART II SURVEY
ATTACHMENT 3 ‐ Daniel Report 11 Test Results

EVALUATION OF MERCURY CONTROL USING SORBENT INJECTION

MISSISSIPPI POWER COMPANY

VICTOR J DANIEL JR

Typical Average

VICTOR J DANIEL JR.

UNIT 1

Table 1. Coal Analyses

Parameter Units Typical West Elk Typical Twenty Mile Typical Black Thunder Typical Antelope Average Blend 60%/40%

HHV Btu/lb 14,700 12,340 11,898 12,005 11,256Moisture wt% 0 00 09.6Carbon wt% 80.7 72.2 65.3 70.1 65.4Hydrogen wt% 5 5 5.9 4.9 4.3Nitrogen wt% 1.9 1.8 1.1 1.1 4.4Oxygen wt% 8.9 10.3 16.5 16.5 7.2Sulfur wt% 0 5. 0 61 . 0 6. 0 3. 0 5.Ash wt% 3 10.2 10.6 7.2 8.7Mercury μg/g 0.02 0.03 0.08 0.06 0.034Chlorine wt% 0.05 <0.005 0.03 0.01 <0.001

Date Time Blend HgT μg/Nm3 Hg0 μg/Nm3 Hg0 % Hg2+ % HgT μg/Nm3 Hg0 μg/Nm3 Hg0 % Hg2+ %

4/23/05 20 00 60%/40% 3 41 2 42 71 29 3 21 2 2 69 31

Table 5. Mercury Speciation Data

ESP Inlet ESP Outlet

4/23/05 20:00 60%/40% 3.41 2.42 71 29 3.21 2.2 69 314/24/05 13:00 60%/40% 2.83 1.82 64 36 3.44 1.87 54 464/24/05 20:00 60%/40% 2.55 1.59 62 38 3.87 1.93 50 504/25/05 5:00 60%/40% 2.5 1.63 65 35 3.1 1.58 51 494/30/05 4/30/05 5:00 60%/40% 60%/40% 1.97 1.06 54 46 n/a n/a n/a n/a5/5/05 12:00 60%/40% 5.08 3.65 72 28 n/a n/a n/a n/a5/8/05 8:00 60%/40% 4.81 3.86 80 20 n/a n/a n/a n/a5/9/05 8:00 60%/40% 4.67 2.78 60 40 n/a n/a n/a n/a5/15/05 8:00 80%/20% 3.89 2.5 64 36 n/a n/a n/a n/a5/17/05 8:00 80%/20% 3.58 2.18 61 39 n/a n/a n/a n/a

Inlet Outlet

Table 6. Snap Shots of Native Capture Results

Date/Time Coal Blend Bituminous Coal SO3 Injection Mercury ESP Capture Inlet

μg/Nm3

Outlet

μg/Nm3

4/25 60%/40% Twenty Mile 6 3.7 3.5 5%4/26, 1700 60%/40% Twenty Mile 6 4.8 3.5 27%4/26, 2030 60%/40% Twenty Mile 6 4.1 3.4 17%

Date/Time Coal Blend Bituminous Coal

ppm %

4/27, 1100 60%/40% Twenty Mile 6 4.3 4.1 5%5/1, 0600 60%/40% Twenty Mile 0 3.1 1.5 52%5/1, 2300 60%/40% Twenty Mile 0 4.1 1.4 66%5/8, 0312 60%/40% Twenty Mile 0 5.5 3.1 44%5/8, 1035 60%/40% 60%/40% Twenty Mile 0 5 2 1. 59%5/9, 0000 60%/40% West Elk 0 4.4 1.1 75%5/9, 1600 60%/40% West Elk 0 5.3 0.8 85%5/13, 0200 80%/20% Twenty Mile 0 3.3 0.8 75%5/13, 0600 80%/20% Twenty Mile 0 3.1 0.9 71%5/13, 1200 80%/20% Twenty Mile 0 3 1.4 53%5/13, 2300 80%/20% Twenty Mile 0 4.7 3.3 30%5/14, 1000 80%/20% Twenty Mile 0 3.3 1.8 45%

*Inlet mercury on 5/1 and after is measured upstream of the APH

PLANT VICTOR J DANIEL JR ICR PART II SURVEY
ATTACHMENT 3 ‐ Daniel Report 11 Test Results

Injection SO3 Injection Inlet Mercury Outlet Approximate

Table 8. Parametric Test Results: DARCO Hg, 60%/40% Blend

Date Concentration

lb/Mmacf

SO3 Injection

ppm

Inlet Mercury

μg/Nm3 Mercury μg/Nm3 Removal ESP %

4/28/05 3 6 43.6 104/28/05 5 6 4.2 3.3 214/29/05 9 6 3.9 3.3 154/29/05 12 6 3.9 2.5 364/30/05 9 6 2.8 2 29

Table 9. Parametric Test Results: DARCO Hg‐LH, 60%/40% Blend

Date

Injection

Concentration

lb/Mmacf

SO3 Injection

ppm

Inlet Mercury

μg/Nm3

Outlet

Mercury

μg/Nm3

Approximate

Removal ESP

%

5/2/05 3 0 4.9 1.6 675/3/05 5 6 4.6 3.2 305/3/05 5 0 4.6 1.5 675/4/05 10 6 4.7 2.1 555/4/05 10 3 4.7 1.5 685/4/05 10 0 4.7 0.8 835/5/05 3 6 5 2. 3 2. 385/5/05 3 3 5.1 2.8 455/5/05 3 0 5.1 2.1 595/5/05 7.5 0 5 1.5 705/21/05 3++ 0 4.8 1.3 735/21/05 5++ 0 4.5 0.5 895/21/05 9++ 0 4.7 0.1 98

++Data taken during the in‐flight test, conducted at the end of the program with a modified injection configuration.

Table 10. Parametric Test Results: DARCO Hg‐LH 80%/20% Blend

Date

Injection

Concentration

lb/Mmacf

SO3 Injection

ppm

Inlet Mercury

μg/Nm3

Outlet

Mercury

μg/Nm3

Approximate

Removal ESP

%

5/15/05 3 0 4.1 1 76

/ /

Table 10. Parametric Test Results: DARCO Hg‐LH, 80%/20% Blend

5/16/05 5 0 4.3 0.7 845/17/05 7.5 0 3.7 0.8 785/17/05 10 0 4.1 0.9 785/17/05 10 6 4.1 1.5 63

Date

Injection

Concentration

lb/Mmacf

SO3 Injection

ppm

Inlet Mercury

μg/Nm3

Outlet

Mercury

μg/Nm3

Approximate

Removal ESP

%

/ /

Table 11. Parametric Test Results: DARCO Hg, 80%/20% Blend

5/18/05 3 6 3.8 2.4 375/18/05 3 0 42 505/18/05 5 0 4.2 1.8 575/18/05 5 6 4.4 2.2 505/19/05 10 6 3 8. 1.8 535/19/05 10 0 4.2 1.4 675/19/05 7.5 0 4.4 1.3 70

Table 14. Snap Shot Results from Constant Rate Injection Test at 5

Point Background SO3

ppm

ESP Inlet

Mercury

(μg/Nm3, 3%

)1

ESP Outlet

Mercury

(μg/Nm3, 3%

)1

Capture

lb/MMacf Injection

O2)1 O2)1

5/6/2005 0.25 4.66 1.36 72%

5/7/2005 0.24 4.79 1.49 69%

5/8/2005 0.24 4.82 1.43 70%

5/9/2005 0.24 4.83 0.82 83%

5/10/2005 0.24 5.22 1.04 81%5/11/2005 0.2 3.24 0.42 87%

1Results presented are from the SCEMs

PLANT VICTOR J DANIEL JR ICR PART II SURVEY
ATTACHMENT 3 ‐ Daniel Report 11 Test Results

Table 15. Relative Performances of Twenty Mile and West Elk Coals with 5 lb/MMacf Injection

May 8 May 8 May 8 May 9 May 8 May 9 May 9 May 9

312 1035 1435 2330 2108 1 807 1556

μg/Nm3 5.49 4.98 4.89 5.07 4.12 4.36 4.66 5.33

Twenty Mile West Elk

DateTimeInlet MercuryTest Side

μg/Nm3 1 1.38 1.29 1.34 0.83 0.82 0.73 0.7% 82 72 74 74 80 81 84 87μg/Nm3 3.05 2.05 2.09 2.28 0.85 1.11 0.91 0.81

Control SideTest Side

Outlet Mercury

Mercury Capture

Outlet Mercury

% 44 59 57 55 79 75 80 85% 38 13 17 19 1 6 4 2

APH Inlet ESP Inlet ESP Outlet

Mercury Capture

Improvement Due to Sorbent Injection

Table 16. Summary Data from In‐Flight Capture Test

Time

SO3 Injection

ppm

Sorbent Injection

lb/Mmacf

APH Inlet

Mercury

μg/Nm3

ESP Inlet

Mercury

μg/Nm3

ESP Outlet

Mercury

μg/Nm3

In‐Flight

Capture %

ESP Capture

%

Overall

Capture %

0000‐0345 6 0 4.6 4.1 3.1 11 22 330345‐1012 0 0 4.1 3.5 2.6 15 22 371012‐1205 0 3 4.8 1.4 1.3 71 2 731205‐1315 0 0 4.6 2.5 2.1 46 9 551315‐1554 0 5 4.5 0.6 0.5 87 2 891554‐1755 0 9 4.7 0.2 0.1 96 2 981755 1230 1755‐1230 0 04 5. 2 7. 240 16 561230‐0900 6 0 5.2 4.2 2.9 19 25 44

PLANT VICTOR J DANIEL JR ICR PART II SURVEY
ATTACHMENT 3 ‐ Daniel Report 11 Test Results

Coal Hg Inlet Hg Inlet Hg STM Absolute Relative

Table 19. Comparison of Inlet Mercury Levels by Coal, SCEM, and STM

Date Test Phase Fuel Blend Coal Hg lb/Tbtu SCEM lb/Tbtu Inlet Hg STM lb/Tbtu Consistency lb/Tbtu Relative Consistency

4/28/2005 Parametric,

DARCO Hg, 3&5

lb/MMacf

60%/40% 4.3 4.01 0.3 7%

lb/MMacf

4/29/2005 Parametric,

DARCO HgInjection, 10lb/MMacf

60%/40% 4.01 3.3 0.7 18%

4/29/2005 Parametric,

DARCO HgInjection, 10lb/MMacf

60%/40% 4.01 4.5 0.5 11%

5/7/2005 5/7/2005 Constant Constant Rate, 60%/40% 4 4 4 3 0 1 2%

DARCO Hg‐LH, 5

lb/MMacf

60%/40% 4.4 4.3 0.1 2%

5/8/2005 Constant Rate, 60%/40% 4.3 4.2 0.1 2%

DARCO Hg‐LH, 5

lb/MMacf

5/13/2005 Baseline 80%/20% 3.8 3.3 0.5 13%

1Note that SCEM data from before 5/8/05 was taken at the air preheater outlet

Date Test Phase Fuel Blend Inlet Hg SCEM lb/Tbtu Inlet Hg STM lb/Tbtu Absolute Consistency lb/Tbtu Relative Consistency

Table 20. Comparison of Outlet Mercury Levels by SCEM and STM

lb/Tbtu lb/Tbtu

4/27/2005 Baseline 60%/40% 3.4 3.5 0.1 3%4/27/2005 Baseline 60%/40% 3.4 3.3 0.1 3%5/9/2005 Constant Rate,

DARCO Hg‐LH, 5

60%/40% 0.8 0.4 0.4 50%

lb/MMacf

5/9/2005 Constant Rate,

DARCO Hg‐LH, 5

lb/MMacf

60%/40% 0.8 0.4 0.4 50%

5/11/2005 Constant Rate,

DARCO Hg‐LH, 5

lb/MMacf

60%/40% 0.3 0.2 0.1 33%

5/11/2005 5/11/2005 Constant Constant Rate, 60%/40% 0 3 0 2 0 1 33%

DARCO Hg‐LH, 5

lb/MMacf

60%/40% 0.3 0.2 0.1 33%

5/14/2005 Baseline 80%/20% 2.1 1.3 0.8 38%5/14/2005 5/14/2005 Baseline Baseline 80%/20% 80%/20% 2 1. 1 5. 0 6. 29%5/16/2005 Hg‐LH Injection 80%/20% 2.1 1.9 0.2 10%5/16/2005 Hg‐LH Injection 80%/20% 2.1 1.9 0.2 10%

Load Range Opacity Range Opacity Average Opacity Range Opacity A erage Differential (CRI Base)

Table 24. Unit 6 Opacity With and Without Sorbent Injection

Baseline Data Constant Rate Injection

oad a ge Opac ty a ge Opac ty e age Opac ty a ge Average (CRI‐Base)

530 to 540 MW 3.5 – 8.3 5.2 3.8 – 8.3 6.0 +0.8

PLANT VICTOR J DANIEL JR ICR PART II SURVEY
ATTACHMENT 4 ‐ Daniel Report 1 Test Results

PLANT VICTOR J DANIEL JR ICR PART II SURVEY
ATTACHMENT 5 ‐ Daniel Report 2 Test Results

PLANT VICTOR J DANIEL JR ICR PART II SURVEY
ATTACHMENT 6 ‐ Daniel Report 3 Test Results

PLANT VICTOR J DANIEL JR ICR PART II SURVEY
ATTACHMENT 7 ‐ Daniel Report 4 Test Results

PLANT VICTOR J DANIEL JR ICR PART II SURVEY
ATTACHMENT 8 ‐ Daniel Report 5 Test Results

PLANT VICTOR J DANIEL JR ICR PART II SURVEY
ATTACHMENT 9 ‐ Daniel Report 6 Test Results

PLANT VICTOR J DANIEL JR ICR PART II SURVEY
ATTACHMENT 10 ‐ Daniel Report 7 Test Results

PLANT VICTOR J DANIEL JR ICR PART II SURVEY
ATTACHMENT 11 ‐ Daniel Report 7 Test Results

PLANT VICTOR J DANIEL JR ICR PART II SURVEY