Process Information

1 Name of legal owner of facility:

PowerSouth owns 8.16% of Units 1 and 2. Alabama Power Company owns the remainder of Units 1 and 2 and all of Units 3 and 4.

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

Alabama Power Company

3 Address of ____ legal owner or _X__ operator:

600 North 18th Street

Birmingham, AL 35291-0830

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):

James H Miller 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):

Plant Code - 6002

5 Complete street address of facility (physical location):

4250 Porter Road

Quinton, AL 35130

6 Provide mailing address if different:

600 North 18th Street

Birmingham, AL 35291-0830

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) _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)

Note: These are the anticipated fuels; however, the permit and design are not necessarily restricted to these fuels.

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 (% _100_)

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

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

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

 that recycle materials) (%_____)

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

____ petroleum coke (% _____)

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

_X__ distillate (% _100__)

____ other (specify __________) (% _____)

____ residual or bunker C (% _____)

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

plastics, treated wood, rubber belting or gaskets, whole tires, tire-derived fuel, boiler cleaning solutions, animal wastes, etc.) is 

either utilized or permitted to be used, please indicate below what materials are combusted in the boiler and in what quantities

(specify whether this quantity is on a weight percentage or heat [Btu] basis). Also indicate (yes/no) whether you are permitted5 to 

burn non-fossil fuel(s) or other material(s) even if you do not actually burn them.

14b If "other" was checked in questions 10 or 11 above indicating that any non-fossil fuel or other material (including, but not limited to,

plastics, treated wood, rubber belting or gaskets, whole tires, tire-derived fuel, boiler cleaning solutions, animal wastes, etc.) is 

either utilized or permitted to be used, were such material to be classified as "solid waste" under the Resource Conservation and 

Recovery Act and, thus make the utilizing unit subject to CAA section 129, would you continue to utilize (i.e., use as a fuel) the 

material? ____ Yes ____ No _X__ Neither

Explain: Until the regulations are finalized, we cannot determine with certainty whether we would use these other materials or not.

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").

Quantity/year

519,825 gallons

476,162.5 gallons used oilcontaminated waste was burned; no 

used oil was burned

Other Material

Boiler cleaning wastes which are not 

hazardous wastes as defined in 40 

CFR Part 261, Subpart B may be 

combusted in the units for energy 

recovery.

Used oil which is not hazardous 

waste as defined in 40 CFR Part 279, 

and which is generated at Alabama 

Power facilities in the state of 

Alabama may be combusted in the 

units for energy recovery. This 

includes non-hazardous waste 

residue which is contaminated with 

used oil and used oil which is 

generated by Alabama Power 

employees who are household used 

oil generators.

Actually burn

Yes

Yes

Permitted to burn

Yes

Yes
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 

(

oF)

temperature (

Operating steam 

oF)

Design steam reheat 

temperature (

oF)

9

Operating steam reheat 

temperature (

oF)10

Fuel11

Hours/year operated12

Average annual capacity 

factor for the past 3 years

Applicable NSPS

Estimated year of 

retirement13

1 bituminous CBI CBI 725 684 87.34 86.3 2400 2400 1000 982 1000 991 subbituminous 

coal, natural gas, 

used oilcontaminated 

waste, boiler 

cleaning waste

CBI CBI Subpart D not 

available

2 bituminous CBI CBI 716 686 87.34 86.62 2400 2400 1000 987 1000 994 subbituminous 

coal, natural gas, 

No. 2 fuel oil, 

used oilcontaminated 

waste, boiler 

cleaning waste

CBI CBI Subpart D not 

available

3 bituminous CBI CBI 716 690 87.34 86.12 2400 2400 1000 984 1000 990 subbituminous 

coal, natural gas, 

used oilcontaminated 

waste

CBI CBI Subpart D not 

available

4 bituminous CBI CBI 723 691 87.34 86.22 2400 2401 1000 988 1000 986 subbituminous 

coal, natural gas, 

used oilcontaminated 

waste

CBI CBI Subpart D not 

available

NOTES

Original design fuel. Based on the original contract boiler data sheet; only the primary fuel is listed if multiple fuels were included on the data sheet. See also text to previous response (Part I, No. 11), which indicates that 

the design fuel simply means the fuel for which the boiler is optimized to operate at maximum possible efficiency, but that the boiler was designed to handle and burn a range of fuels.

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

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 indicated.

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

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

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

Retirement. Alabama Power has not committed to actual retirement dates for Miller Units 1 - 4. Alabama Power continually evaluates retirement scenarios with respect to its generating units for a variety of planning purposes, 

taking into account a wide range of variables. While the company assumes financial "retirement dates" for accounting purposes, for example, for depreciation schedules or for FERC or Public Service Commission uses, these dates are not

indicative of the unit's actual retirement date.

6

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

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

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

7

 Per fuel burned in the boiler. Report this based on higher heating value (HHV).

8

 Per fuel burned in the boiler. Report this based on higher heating value (HHV).

9

 Please indicate if more than one steam reheat cycle is utilized, and, if so, please provide information for both.

10 Please indicate if more than one steam reheat cycle is utilized, and, if so, please provide information for both.

11 Indicate the fuels utilized for the indicated boiler, and percentages, as indicated in questions 11 - 13.

12 The "hours/year operated" would be the average of the actual number of hours the unit operated in 1 year based on the last 3 years of operation.

13 This can be treated as CBI and can be submitted through the proper CBI procedure if desired.
16 For each boiler noted in Part I, question 15, provide the following information for each current emission control device installed

and operating and/or planned (please designate the order of the emission controls - 1 for the first control following the boiler, 2

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

Boiler ID14 Type15 NOx control16 SO2 control17 PM control18 Other control19

1 wall-fired/dry bottom (1) low-NOx burners 

(10/12/1978)

(2) SCR (05/09/2005) - the SCR 

uses a titania-vanadia based 

ceramic catalyst and 

anhydrous ammonia as the 

reductant; the catalyst is not 

specifically designed to 

reduce SO3 formation

(5) calcium-based wet flue gas 

desulfurization (planned April 

2011)

(3) flue gas conditioning - SO3 

injection (05/1999)

(4) hot-side ESP was originally 

installed (10/12/1978) but 

was converted to a cold-side 

ESP (05/1999)

N/A

2 wall-fired/dry bottom (1) low-NOx burners 

(05/01/1985)

(2) SCR (05/01/2005) - the SCR 

uses a titania-vanadia based 

ceramic catalyst and 

anhydrous ammonia as the 

reductant; the catalyst is not 

specifically designed to 

reduce SO3 formation

(5) calcium-based wet flue gas 

desulfurization (planned 

04/07/2010)

(3) flue gas conditioning - SO3 

injection (05/1999)

(4) hot-side ESP was originally 

installed (05/01/1985) but 

was converted to a cold-side 

ESP (03/1999)

N/A

3 wall-fired/dry bottom (1) low-NOx burners 

(05/01/1989)

(2) SCR (03/18/2003) - the SCR 

uses a titania-vanadia based 

ceramic catalyst and 

anhydrous ammonia as the 

reductant; the catalyst is not 

specifically designed to 

reduce SO3 formation

(4) calcium-based wet flue gas 

desulfurization (12/16/2009)

(3) cold-side ESP (05/01/1989) N/A

4 wall-fired/dry bottom (1) low-NOx burners 

(03/05/1991)

(2) SCR (03/28/2003) - the SCR 

uses a titania-vanadia based 

ceramic catalyst and 

anhydrous ammonia as the 

reductant; the catalyst is not 

specifically designed to 

reduce SO3 formation

(4) calcium-based wet flue gas 

desulfurization (01/16/2010)

(3) cold-side ESP (03/01/1991) N/A

Note: "N/A" means not applicable.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

new installation. Also include any pollutants controlled by this technology (e.g., control technology [pollutant controlled]).
17 For each boiler noted in Part I, question 15, provide the company (prime vendor) name and company contact information for each

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

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

etc.).

Name Telephone Address

1 N/A N/A N/A N/A

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

3 N/A N/A N/A N/A

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

Note: "N/A" means not applicable.

20 A control technology demonstration project is defined as a U.S. Government (e.g., U.S. Department of Energy program) sponsored

(in whole or in part) project or mandate (e.g., as a result of a consent decree) that adds a HAP control technology to a facility's unit to

demonstrate the technology's HAP removal performance.

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

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

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

Company (vendor) contact information Boiler ID21 Company (vendor) name
18 For the control technologies identified in Part I, question 17, provide the date of actual start-up of the demonstration (if the control

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

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

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

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

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

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

Boiler ID22

Demonstration 

activity actual startup date

Demonstration 

activity projected 

start-up date

Demonstration 

activity end-date or 

projected end-date

Type of control (e.g., 

sorbent and type; 

chemical additive23)

Desired HAP emission 

reduction (%) or 

emission rate

Coal rank(s) in use

1 N/A N/A N/A N/A N/A N/A

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

3 N/A N/A N/A N/A N/A N/A

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

Note: "N/A" means not applicable.

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

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

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

23 If additive is used, please indicate injection point.
19 For each boiler noted in Part I, question 15, provide the company (prime vendor) name and company contact information for each

HAP-specific (e.g., mercury, hydrogen chloride) 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

3 N/A N/A N/A N/A

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

Note: "N/A" means not applicable.

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

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

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

Company (vendor) contact information

Boiler ID24 Company (vendor) name
20 For the control technologies identified in Part I, question 19, provide the date of actual start-up (if the control is currently operating), the

date of expected or projected start-up, the type of HAP control installed (e.g., sorbent and type; pre-construction boiler chemical additive;

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

guarantee is based, and the coal rank(s) upon which the guarantee is based. Please specify the format of the guarantee (e.g., lb/MWh,

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

rate would be (and specify the format of the equivalent emission rate), and (2) the basis for calculating the percent reduction (i.e., where the

"inlet" and "outlet" are).

Boiler ID25 Actual start-up date Expected or projected 

start-up date

Type of control (e.g., 

sorbent and type; 

chemical additive)26

Guaranteed HAP 

emission reduction 

(%) or emission rate

Sorbent or additive 

feed rate on which 

guarantee is based

Coal rank(s) upon 

which guarantee is 

based

1 N/A N/A N/A N/A N/A N/A

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

3 N/A N/A N/A N/A N/A N/A

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

Note: "N/A" means not applicable.

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

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

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

26 If additive is used, please indicate injection point.
21 For each boiler noted in Part I, question 15, provide the following information:

PM28 PM10

(29) PM2.5(30) SO2

HCl and/or 

HF

HCN

Metal 

HAP31 Hg CO

Other 

organics 

(specify)

Other pollutant 

(specify)

1 0.10 lb/MMBtu

(Title V permit; biennial 

Reference Method 5 or 17 

before installation of the FGD 

and Reference Method 5B 

after installation of the FGD)

N/A N/A 1.2 lb/MMBtu

(Title V permit; 3-hr rolling 

average)

N/A N/A N/A N/A N/A N/A NOx: 0.70 lb/MMBtu

(Title V permit; 7-day 

rolling average)

NOx: 0.21 lb/MMBtu

(Title V permit; 30-day 

Btu-weighted average 

between the units at 

James H Miller Jr and 

Gorgas during ozone 

season)

2 0.10 lb/MMBtu

(Title V permit; biennial 

Reference Method 5 or 17 

before installation of the FGD 

and Reference Method 5B 

after installation of the FGD)

N/A N/A 1.2 lb/MMBtu

(Title V permit; 3-hr rolling 

average)

N/A N/A N/A N/A N/A N/A NOx: 0.70 lb/MMBtu

(Title V permit; 7-day 

rolling average)

NOx: 0.21 lb/MMBtu

(Title V permit; 30-day 

Btu-weighted average 

between the units at 

James H Miller Jr and 

Gorgas during ozone 

season)

3 0.030 lb/MMBtu at the boiler 

stack exit

(Title V permit; Reference 

Method 5 or 17 before 

installation of the FGD and 

Reference Method 5B after 

installation of the FGD)

N/A N/A 1.2 lb/MMBtu

(Title V permit; 3-hr rolling 

average);

30-day rolling average 

removal efficiency of 95% 

with <1% sulfur coal and 90% 

with >1% sulfur coal (Title V 

permit)

N/A N/A N/A N/A N/A N/A NOx: 0.100 lb/MMBtu

(Title V permit; 30-day 

rolling average); 

NOx: 0.100 lb/MMBtu 

(Title V permit; 365-day 

rolling average)

NOx: 0.21 lb/MMBtu

(Title V permit; 30-day 

Btu-weighted average 

between the units at 

James H Miller Jr and 

Gorgas during ozone 

season)

4 0.030 lb/MMBtu at the boiler 

stack exit

(Title V permit; Reference 

Method 5 or 17 before 

installation of the FGD and 

Reference Method 5B after 

installation of the FGD)

N/A N/A 1.2 lb/MMBtu

(Title V permit; 3-hr rolling 

average);

30-day rolling average 

removal efficiency of 95% 

with <1% sulfur coal and 90% 

with >1% sulfur coal (Title V 

permit)

N/A N/A N/A N/A N/A N/A NOx: 0.100 lb/MMBtu

(Title V permit; 30-day 

rolling average); 

NOx: 0.100 lb/MMBtu 

(Title V permit; 365-day 

rolling average)

NOx: 0.21 lb/MMBtu

(Title V permit; 30-day 

Btu-weighted average 

between the units at 

James H Miller Jr and 

Gorgas during ozone 

season)

Note: "N/A" means not applicable.

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

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

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

28 If the boiler has separate permitted emission limits for filterable and condensable PM, respectively, please indicate those separate limits. 

Also include the compliance test method utilized.

29 List the compliance test method utilized.

30 List the compliance test method utilized.

31 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, phosphorus, and selenium;

indicate permit level for all metal HAP for which a permit level has been developed.

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

Boiler ID27
22 For each boiler noted in Part I, question 15, provide the following information:

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

Other organics 

(specify)

Other 

pollutant 

(specify)

1

ESP: 99.4% collection 

efficiency guarantee 

(expired in 1979); FGD: 

CBI

N/A N/A FGD: 98% instantaneous 

removal efficiency to meet 

a 95% 30-day rolling 

average removal 

efficiency1,2

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

2

ESP: 99.4% collection 

efficiency guarantee 

(expired in 1985); FGD: 

CBI

N/A N/A FGD: 98% instantaneous 

removal efficiency to meet 

a 95% 30-day rolling 

average removal 

efficiency1,2

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

3

ESP: 99.7% collection 

efficiency guarantee 

(expired in 1998); FGD: 

CBI

N/A N/A FGD: 98% instantaneous 

removal efficiency to meet 

a 95% 30-day rolling 

average removal 

efficiency2

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

4

ESP: 99.7% collection 

efficiency guarantee 

(expired in 1991); FGD: 

CBI

N/A N/A FGD: 98% instantaneous 

removal efficiency to meet 

a 95% 30-day rolling 

average removal 

efficiency2

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

Note: "N/A" means not applicable.

1

 The SO2 guarantees for the Units 1 and 2 FGDs will become effective with the startup of the FGD systems (see Part I, Question 16 for installation dates)

2

 These guarantees are dependent on specific operating conditions and expire 18 months after the FGDs begin operation.

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

Please elaborate.

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

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

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

33 If the boiler has separate guaranteed emission rate for filterable and condensable PM, respectively, please indicate those separate emission rates.

34 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, cobalt, lead, manganese, nickel, phosphorus, and selenium; 

indicate permit level for all metal HAP for which a permit level has been developed.

Most recent guaranteed emission rate for each pollutant for which there is a permitted emission limit

Boiler ID32
24 For each boiler noted in Part I, question15, provide the following information:

PM36 PM10 PM2.5 SO2

HCl 

and/or 

HF

HCN

Metal 

HAP37 Hg CO

Other 

organics 

(specify)

1 Biennial particulate testing shall be completed during the second quarter (April - June) of each 

calendar year unless otherwise approved by the Department. One copy of the test results shall be 

forwarded to the Department within 3 weeks after completion of the tests. The Department must 

be notified at least 10 working days in advance of all emissions tests to be completed. Submission 

of an annual PM test schedule with periodic updates as changes occur shall satisfy the 10 day 

notification requirement. Heat input data collected from the unit's CEMS while testing, shall be 

utilized to determine the final PM emissions rate in pounds per million BTU.

Beginning on the 1st day of the first full calendar quarter following the effective date of the permit 

(April 1, 2010), the permittee shall conduct Compliance Assurance Monitoring (CAM) for 

particulate matter in accordance with the procedures included in the CAM Plan submitted to the 

Department and appended to the permit.

All records must be maintained for 5 years.

N/A N/A Continuous Emissions Monitoring System (CEMS) shall be 

installed and operated at locations approved by the Director 

to measure the sulfur dioxide emissions from each affected 

unit. The CEMS shall meet all specifications and procedures in 

40 CFR 75 and will be certified and maintained in accordance 

with 40 CRF 75. In addition, each of the CEMS shall undergo a 

relative accuracy test audit (RATA) in accordance with 40 CFR 

75 and at times approved by the Director. A summary 

emissions report shall be submitted to the Department within 

30 days of the end of each calendar quarter.

Deviations from permit requirements shall be reported within 

2 working days of such deviations, including those attributable 

to upset conditions as defined in the permit, the probable 

cause of said deviations, and any corrective actions or 

preventive measures that were taken. All records must be 

maintained for 5 years.

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

2 Biennial particulate testing shall be completed during the second quarter (April - June) of each 

calendar year unless otherwise approved by the Department. One copy of the test results shall be 

forwarded to the Department within 3 weeks after completion of the tests. The Department must 

be notified at least 10 working days in advance of all emissions tests to be completed. Submission 

of an annual PM test schedule with periodic updates as changes occur shall satisfy the 10 day 

notification requirement. Heat input data collected from the unit's CEMS while testing, shall be 

utilized to determine the final PM emissions rate in pounds per million BTU.

Beginning on the 1st day of the first full calendar quarter following the effective date of the permit 

(April 1, 2010), the permittee shall conduct Compliance Assurance Monitoring (CAM) for 

particulate matter in accordance with the procedures included in the CAM Plan submitted to the 

Department and appended to the permit.

All records must be maintained for 5 years.

N/A N/A Continuous Emissions Monitoring System (CEMS) shall be 

installed and operated at locations approved by the Director 

to measure the sulfur dioxide emissions from each affected 

unit. The CEMS shall meet all specifications and procedures in 

40 CFR 75 and will be certified and maintained in accordance 

with 40 CRF 75. In addition, each of the CEMS shall undergo a 

relative accuracy test audit (RATA) in accordance with 40 CFR 

75 and at times approved by the Director. A summary 

emissions report shall be submitted to the Department within 

30 days of the end of each calendar quarter.

Deviations from permit requirements shall be reported within 

2 working days of such deviations, including those attributable 

to upset conditions as defined in the permit, the probable 

cause of said deviations, and any corrective actions or 

preventive measures that were taken. All records must be 

maintained for 5 years.

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

Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a permitted emission limit

Boiler ID35
PM36 PM10 PM2.5 SO2

HCl 

and/or 

HF

HCN

Metal 

HAP37 Hg CO

Other 

organics 

(specify)

Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a permitted emission limit

Boiler ID35

3 Compliance with the PM emission rate shall be determined by a stack test in 2011 and every year 

thereafter; however if the performance test shows that the PM Emission Rate is equal or less than 

0.015 lb/MMBtu, the test may be conducted every other year, so long as a PM Emission Rate of 

0.015 lb/MMBtu is maintained. One copy of the test results shall be forwarded to the Department 

within 3 weeks after completion of the tests. The Department must be notified at least 10 

working days in advance of all emissions tests to be completed. Submission of an annual PM test 

schedule with periodic updates as changes occur shall satisfy the 10 day notification requirement. 

Heat input data collected from the unit's CEMS while testing, shall be utilized to determine the 

final PM emissions rate in pounds per million BTU.

Beginning on the 1st day of the first full calendar quarter following the effective date of the permit 

(April 1, 2010), the permittee shall conduct Compliance Assurance Monitoring (CAM) for 

particulate matter in accordance with the procedures included in the CAM Plan submitted to the 

Department and appended to the permit.

All records must be maintained for 5 years.

N/A N/A Continuous Emissions Monitoring System (CEMS) shall be 

installed and operated at locations approved by the Director 

to measure the sulfur dioxide emissions from each affected 

unit. The CEMS shall meet all specifications and procedures in 

40 CFR 75 and will be certified and maintained in accordance 

with 40 CRF 75. In addition, each of the CEMS shall undergo a 

relative accuracy test audit (RATA) in accordance with 40 CFR 

75 and at times approved by the Director. A summary 

emissions report shall be submitted to the Department within 

30 days of the end of each calendar quarter.

Deviations from permit requirements shall be reported within 

2 working days of such deviations, including those attributable 

to upset conditions as defined in the permit, the probable 

cause of said deviations, and any corrective actions or 

preventive measures that were taken. All records must be 

maintained for 5 years.

N/A N/A N/A Install, certify, and 

operate a mercury 

emission 

monitoring system 

(Mercury CEMS) by 

December 31, 

2008.

N/A N/A

4 Compliance with the PM emission rate shall be determined by a stack test in 2011 and every year 

thereafter; however if the performance test shows that the PM Emission Rate is equal or less than 

0.015 lb/MMBtu, the test may be conducted every other year, so long as a PM Emission Rate of 

0.015 lb/MMBtu is maintained. One copy of the test results shall be forwarded to the Department 

within 3 weeks after completion of the tests. The Department must be notified at least 10 

working days in advance of all emissions tests to be completed. Submission of an annual PM test 

schedule with periodic updates as changes occur shall satisfy the 10 day notification requirement. 

Heat input data collected from the unit's CEMS while testing, shall be utilized to determine the 

final PM emissions rate in pounds per million BTU.

Beginning on the 1st day of the first full calendar quarter following the effective date of the permit 

(April 1, 2010), the permittee shall conduct Compliance Assurance Monitoring (CAM) for 

particulate matter in accordance with the procedures included in the CAM Plan submitted to the 

Department and appended to the permit.

All records must be maintained for 5 years.

N/A N/A Continuous Emissions Monitoring System (CEMS) shall be 

installed and operated at locations approved by the Director 

to measure the sulfur dioxide emissions from each affected 

unit. The CEMS shall meet all specifications and procedures in 

40 CFR 75 and will be certified and maintained in accordance 

with 40 CRF 75. In addition, each of the CEMS shall undergo a 

relative accuracy test audit (RATA) in accordance with 40 CFR 

75 and at times approved by the Director. A summary 

emissions report shall be submitted to the Department within 

30 days of the end of each calendar quarter.

Deviations from permit requirements shall be reported within 

2 working days of such deviations, including those attributable 

to upset conditions as defined in the permit, the probable 

cause of said deviations, and any corrective actions or 

preventive measures that were taken. All records must be 

maintained for 5 years.

N/A N/A N/A Install, certify, and 

operate a mercury 

emission 

monitoring system 

(Mercury CEMS) by 

December 31, 

2008.

N/A N/A

Note: "N/A" means not applicable.

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

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

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

36 If the boiler's monitoring, recordkeeping, and reporting requirements require your company to monitoring, keep records, and report filterable

and condensable PM separately, please describe the separate actions required.

37 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, phosphorus, and selenium;

indicate permit level for all metal HAP for which a permit level has been developed.
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 Operating Costs: $ - (Include base year for operating costs [e.g., 2006]

26 Are any other means of emission control (for any pollutant) employed on any boiler noted in Part I, question 15 (e.g., low-ash coal,

coal or oil with low trace constituents, etc.)? Please specify.

Plant Miller switched to subbituminous Powder River Basin coal for compliance with the Acid Rain SO2 and NOx programs.

38 This can be treated as CBI and can be submitted through the proper CBI procedure if desired.

Note: "N/A" means not applicable.
Fuel Analysis39

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

James H Miller Jr

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

Plant Code - 6002

39 The respondent should reply to this ICR with separate pages 18 through 24 (Part II) for each of their facilities.
2 For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information,

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

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

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

11,460 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.05 12,053

11,515 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.19 12,087

11,581 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 5.86 12,189

11,487 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 7.08 11,939

11,413 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 5.80 12,191

11,516 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 5.91 12,139

11,653 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.05 12,137

11,492 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 7.29 11,903

10,541 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 7.29 11,903

11,542 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.21 12,031

11,564 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.27 12,074

9,976 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 5.83 12,117

11,412 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 7.00 11,984

11,598 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.69 11,970

11,461 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.21 12,087

11,550 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 N/A 12,101

11,538 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.87 12,057

11,469 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.68 11,972

11,632 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 5.95 12,026

11,450 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.00 12,082

11,356 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 7.14 11,905

11,484 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.48 12,008

11,605 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.38 12,021

10,106 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.86 11,979

11,300 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.22 12,077

11,585 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 7.20 11,929

11,419 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.17 12,108

11,628 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.33 6.13 12,050

11,430 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 5.79 12,086

11,313 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.46 12,034

11,608 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.04 12,051

11,499 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.63 12,028

11,306 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.83 11,975

11,715 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.37 12,033

11,629 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 6.44 12,003

11,584 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.88 11,940

11,651 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 7.44 11,881

11,430 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 6.71 11,951

11,448 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 5.86 12,058

11,612 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.33 6.32 12,001

11,527 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.36 12,013

11,546 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 5.82 12,105

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) firing 

fuel41

Fuel shipment 

method

Vendor Analyses
D.B. D.B. D.B.

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

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) firing 

fuel41

Fuel shipment 

method

Vendor Analyses

11,598 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.20 12,048

11,554 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 6.22 12,086

11,528 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.12 12,098

11,565 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.98 11,972

11,527 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 6.12 12,080

11,507 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.50 11,976

11,551 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.35 6.20 12,028

11,565 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.36 12,060

11,456 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.95 12,097

11,452 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 6.44 11,987

11,435 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.64 12,003

11,566 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.52 12,019

11,634 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.37 12,025

11,480 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.35 12,108

11,404 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.09 12,053

10,754 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.05 12,095

11,485 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.30 12,093

11,715 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 6.51 12,012

11,452 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.12 12,110

11,547 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.43 12,074

11,551 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.33 11,993

11,589 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.34 12,029

11,600 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.05 12,092

11,595 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 6.45 12,053

11,524 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.05 12,085

11,516 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.66 12,000

11,525 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 6.19 12,054

11,591 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 6.30 12,029

11,526 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.39 12,038

11,534 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.42 12,044

11,444 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.32 12,014

11,614 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.47 11,993

11,710 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.55 12,020

11,707 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.27 12,094

11,678 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 7.03 11,911

11,669 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.97 12,126

11,667 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.34 6.21 12,027

11,532 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 6.40 12,024

11,682 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.34 12,101

11,546 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.39 12,092

11,471 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.17 12,077

11,447 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.38 12,031

11,622 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.89 12,114

11,560 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.19 12,070
D.B. D.B. D.B.

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

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) firing 

fuel41

Fuel shipment 

method

Vendor Analyses

11,516 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.04 12,157

11,615 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.15 12,133

11,357 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 6.42 12,007

11,634 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.90 11,862

11,406 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.43 12,001

11,576 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.28 12,072

11,557 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.41 12,021

11,598 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.91 11,967

11,636 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 6.65 11,972

11,530 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.30 12,069

11,652 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.23 12,093

11,476 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.35 12,040

11,641 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.13 12,058

11,519 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.10 12,081

11,581 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.69 12,132

11,658 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.46 12,049

11,684 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.28 12,079

11,586 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 6.22 12,052

11,513 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.59 12,063

11,500 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.88 11,993

11,527 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.28 12,087

11,499 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.81 11,969

11,735 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.87 11,999

11,494 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.93 11,966

11,495 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.07 12,093

11,526 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.10 11,989

11,595 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.24 6.01 11,970

11,454 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.42 11,996

11,550 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 6.32 12,048

11,624 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.64 11,996

11,542 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 7.03 11,965

11,381 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.93 11,999

11,522 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.45 12,028

11,552 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.40 12,035

11,492 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 7.05 11,922

11,432 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.33 12,069

11,516 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.15 12,053

11,521 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 6.64 12,026

11,649 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.85 12,025

11,454 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.40 12,066

11,439 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.60 12,015

11,749 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.34 6.55 11,998

11,432 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 5.99 12,144

11,443 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.16 12,099
D.B. D.B. D.B.

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

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) firing 

fuel41

Fuel shipment 

method

Vendor Analyses

11,550 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.11 12,054

11,548 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.95 12,027

11,519 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.18 12,006

11,569 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.27 11,973

11,520 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 6.20 12,053

11,731 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.06 12,125

11,581 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 6.40 12,042

11,534 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.50 12,045

11,830 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 7.20 11,952

11,499 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.75 12,087

11,516 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 6.02 12,133

11,342 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.48 12,051

11,542 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.40 12,096

11,477 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.24 12,078

11,577 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.04 12,100

11,567 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 7.06 11,959

11,521 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.51 12,096

11,517 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 6.61 12,009

11,559 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 6.50 12,051

11,374 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 6.37 12,049

11,628 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.26 12,050

11,430 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.23 12,026

11,624 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.15 12,081

11,647 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.48 12,012

11,643 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.49 11,997

11,536 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 6.17 12,057

11,488 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.17 12,064

11,399 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 6.07 12,003

11,585 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.02 12,086

11,521 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.27 12,033

11,571 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 5.90 12,065

11,520 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.10 12,078

11,503 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.28 12,063

11,403 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 6.10 12,051

11,467 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.32 11,996

11,557 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.22 12,117

11,526 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.24 12,056

11,464 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.28 12,170

11,442 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.25 6.39 12,021

11,342 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 6.50 11,975

11,452 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.47 11,998

11,384 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.56 11,975

11,573 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.71 12,032

11,643 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.53 6.81 12,250
D.B. D.B. D.B.

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

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) firing 

fuel41

Fuel shipment 

method

Vendor Analyses

11,581 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.63 7.78 12,102

11,517 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.38 6.09 12,314

11,629 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.64 7.35 12,189

11,225 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.63 6.85 12,249

11,572 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.40 6.14 12,301

11,537 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.42 7.59 12,096

11,476 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.50 7.16 12,096

11,542 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.64 7.89 12,102

11,634 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.58 7.37 12,203

11,537 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.62 7.89 12,135

11,647 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.59 7.03 12,245

11,448 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.43 6.52 12,199

11,371 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.50 7.00 12,160

11,608 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.58 7.15 12,201

11,682 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.57 7.06 12,211

11,563 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.62 7.72 12,131

11,598 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.40 6.41 12,215

11,491 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.63 8.42 12,000

11,672 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.63 8.59 11,952

11,232 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.66 8.08 12,046

10,648 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.45 6.60 12,242

11,495 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.43 6.42 12,215

11,640 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.58 6.87 12,205

11,418 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.42 6.32 12,291

11,418 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.45 6.61 12,232

11,552 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.66 8.27 12,043

11,491 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.64 8.10 12,052

10,961 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.60 8.45 12,015

11,431 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.50 8.13 12,024

11,603 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.67 8.22 12,062

11,496 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.44 6.99 12,148

11,529 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.69 8.01 12,060

11,631 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.64 8.01 12,099

11,505 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.49 7.37 12,083

11,551 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.64 7.72 12,118

11,565 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.61 7.48 12,095

11,579 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.48 6.70 12,165

11,677 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.62 7.37 12,172

11,570 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.68 7.51 12,133

11,606 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.64 7.22 12,151

11,656 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.61 7.51 12,155

11,528 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.61 7.17 12,218

11,472 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.65 7.14 12,208

11,584 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.65 8.02 12,041
D.B. D.B. D.B.

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

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) firing 

fuel41

Fuel shipment 

method

Vendor Analyses

11,454 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.67 7.54 12,124

11,403 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.63 7.95 12,033

11,597 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.47 7.16 12,099

11,511 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.67 7.74 12,099

11,477 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.44 7.04 12,113

11,608 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.51 7.02 12,099

11,391 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.65 7.61 12,077

11,502 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.70 8.02 12,042

11,343 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.64 7.65 12,104

11,458 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.50 7.15 12,055

11,362 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.69 7.40 12,087

11,475 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.63 7.84 12,045

11,397 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.61 7.29 12,112

11,498 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.72 8.94 11,904

11,196 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.69 8.09 11,983

11,487 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.69 7.87 12,032

11,452 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.71 7.98 11,970

11,084 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.67 7.57 12,144

10,322 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.63 7.32 12,136

11,472 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.69 7.60 12,113

11,538 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.46 6.53 12,197

11,556 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.55 7.66 12,010

11,439 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.68 7.83 12,080

11,441 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.45 7.31 12,064

11,504 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.58 7.27 12,168

11,506 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.42 6.44 12,153

11,499 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.63 7.34 12,155

11,495 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.47 6.79 12,158

11,580 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.71 8.05 12,052

11,381 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.62 7.14 12,165

11,622 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.58 7.36 12,111

11,605 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.48 6.54 12,256

11,511 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.63 7.69 12,087

11,670 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.61 8.94 11,897

11,419 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.42 7.30 12,069

11,582 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.62 7.36 12,114

11,608 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.61 7.46 12,085

11,487 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.47 6.85 12,153

9,188 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.45 6.93 12,150

11,524 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.63 8.00 12,053

11,589 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.64 7.61 12,110

11,469 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.46 7.03 12,111

11,528 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.64 8.44 11,961

10,644 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.61 7.70 12,043
D.B. D.B. D.B.

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

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) firing 

fuel41

Fuel shipment 

method

Vendor Analyses

11,621 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.65 7.72 12,068

11,527 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.70 7.85 12,060

11,583 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.64 7.53 12,128

11,580 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.65 7.69 12,084

11,476 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.66 7.87 12,067

11,591 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.58 7.06 12,193

11,741 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.69 7.68 12,102

11,582 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.50 7.10 12,131

11,555 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.57 7.13 12,160

11,551 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.65 7.87 12,051

11,476 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.68 7.61 12,056

11,582 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.56 6.80 12,199

11,527 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.71 7.58 12,066

11,541 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.63 7.26 12,120

11,497 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.62 7.50 12,077

11,564 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.62 7.80 12,070

11,498 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.68 7.90 12,068

11,604 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.65 8.25 12,029

11,456 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.69 8.20 12,027

11,561 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.57 7.36 12,201

11,449 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.68 7.50 12,102

11,486 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.58 7.38 12,155

11,590 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.53 7.14 12,123

11,579 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.45 6.72 12,179

9,394 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.46 7.57 12,082

11,631 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.57 7.80 12,029

11,582 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.60 8.07 12,004

11,523 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.65 7.63 12,158

11,470 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.46 6.64 12,220

11,637 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.57 7.09 12,139

11,502 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.50 6.81 12,173

11,431 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.64 7.65 12,112

11,532 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.70 7.61 12,159

11,574 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.62 7.21 12,147

11,472 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.46 6.33 12,220

11,540 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.70 7.51 12,064

11,672 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.64 7.38 12,092

11,644 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.63 7.39 12,117

11,577 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.48 6.78 12,159

11,640 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.69 7.93 12,069

11,543 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.58 8.13 11,993

11,594 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.64 7.94 12,017

11,584 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.68 7.51 12,081

11,566 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.62 7.52 12,102
D.B. D.B. D.B.

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

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) firing 

fuel41

Fuel shipment 

method

Vendor Analyses

11,593 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.64 7.81 12,063

11,479 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.71 7.69 12,187

11,475 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.48 7.46 12,102

11,437 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.62 7.58 12,076

11,255 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.43 7.48 12,030

11,541 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.44 6.44 12,195

11,511 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.67 7.63 12,109

11,526 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.45 6.60 12,145

11,438 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.45 7.42 12,053

11,480 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.70 7.92 12,041

11,457 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.42 6.62 12,189

11,618 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.55 7.52 12,108

11,866 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.62 7.41 12,114

11,431 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.46 6.37 12,215

11,339 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.40 6.39 12,218

11,486 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.42 6.53 12,222

11,504 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.44 6.81 12,187

11,478 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.43 6.53 12,242

11,555 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.59 7.21 12,168

11,656 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.43 6.67 12,198

11,441 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.45 6.94 12,134

11,577 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.64 7.31 12,138

11,708 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.51 6.68 12,182

11,487 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.42 6.47 12,242

11,520 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.67 7.47 12,136

11,366 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.47 7.28 12,109

11,446 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.48 7.58 12,080

11,342 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.48 6.91 12,150

11,372 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.47 7.52 12,048

11,450 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.65 7.33 12,141

11,421 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.47 6.73 12,135

11,524 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.45 6.84 12,160

11,561 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.45 6.60 12,172

11,542 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.60 7.13 12,131

11,529 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.59 7.44 12,081

11,602 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.61 7.39 12,153

11,455 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.59 7.25 12,125

11,558 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.60 7.69 12,049

11,467 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.61 7.86 12,063

11,458 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.65 7.45 12,089

11,635 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.68 8.09 12,024

11,518 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.60 7.32 12,120

11,494 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.62 7.49 12,108

11,522 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.63 7.34 12,125
D.B. D.B. D.B.

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

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) firing 

fuel41

Fuel shipment 

method

Vendor Analyses

11,479 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.44 7.40 12,099

11,656 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.56 7.32 12,107

11,627 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.61 7.98 12,048

11,590 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.45 6.99 12,056

11,577 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.59 7.77 12,024

11,533 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.60 7.12 12,135

11,578 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.60 7.55 12,126

11,573 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.60 8.09 12,072

11,597 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.52 7.05 12,137

11,526 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.55 7.51 12,141

11,467 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.51 7.22 12,120

11,512 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.61 7.18 12,159

11,440 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.39 6.03 12,311

11,402 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.60 7.10 12,260

11,380 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.43 6.47 12,288

11,575 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.52 7.45 12,130

11,561 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.57 6.83 12,244

11,538 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.55 7.63 12,099

11,757 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.31 7.03 12,104

11,626 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.42 7.70 12,125

11,766 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.37 7.78 12,050

11,760 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.41 8.59 11,899

11,578 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.50 7.19 12,126

11,756 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.32 6.66 12,184

11,396 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.29 6.13 12,200

11,585 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.33 6.78 12,161

10,823 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.35 5.88 12,285

11,598 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.39 6.35 12,248

11,588 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.33 6.93 12,156

11,672 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.46 7.24 12,089

11,519 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.37 6.64 12,105

11,349 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.35 7.43 12,017

9,534 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.32 6.27 12,204

11,758 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.31 7.93 11,941

11,591 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.32 7.61 12,067

11,706 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.32 7.78 11,969

11,507 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.40 6.87 12,178

11,607 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.54 6.64 12,202

11,464 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.31 6.35 12,171

11,615 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.29 7.26 11,990

11,471 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.31 7.14 12,067

11,593 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.33 6.33 12,159

11,686 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.50 7.28 12,089

11,668 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.46 7.79 12,096
D.B. D.B. D.B.

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

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) firing 

fuel41

Fuel shipment 

method

Vendor Analyses

11,582 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.35 7.45 12,056

11,523 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.44 7.41 12,079

11,551 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.34 7.23 12,121

11,694 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.39 7.47 12,064

11,675 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.38 7.30 12,117

11,555 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.40 6.36 12,199

11,658 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.38 6.65 12,145

11,586 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.34 6.95 12,138

11,801 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.40 7.62 11,860

11,678 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.37 7.03 12,120

11,645 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.41 7.39 12,071

11,763 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.49 7.45 12,100

11,595 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.49 7.33 12,127

11,737 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.31 5.70 12,261

11,704 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.43 7.89 12,035

11,553 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.33 7.55 12,050

11,644 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.38 6.92 12,155

11,556 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.32 6.28 12,200

11,575 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.41 6.57 12,177

11,535 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.41 7.15 12,165

11,651 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.53 7.78 12,099

11,771 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.33 7.80 11,942

11,635 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.45 6.96 12,193

11,578 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.40 6.53 12,313

11,678 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.29 7.00 12,088

11,793 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.45 7.33 12,018

11,845 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.49 7.99 12,075

11,678 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.28 6.43 12,151

11,631 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.47 7.46 12,057

11,511 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.44 6.73 12,120

11,697 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.38 6.63 12,109

11,761 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.42 6.39 12,174

11,454 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.42 6.43 12,177

11,522 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.38 5.63 12,292

11,638 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.35 6.99 12,106

11,723 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.38 7.45 12,046

11,561 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYON TRAIN 0.38 7.19 12,097

11,408 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.44 8.40 12,062

11,508 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.54 7.97 12,047

11,571 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.64 8.16 12,051

11,954 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.32 7.33 11,952

11,759 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.28 6.85 12,076

11,803 1, 2, 3, 4 WY CONVERSE CANYON TRAIN N/A 7.86 11,893

11,746 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.33 6.88 12,015
D.B. D.B. D.B.

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

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) firing 

fuel41

Fuel shipment 

method

Vendor Analyses

11,867 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.30 7.99 11,876

11,817 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.29 7.42 11,929

11,824 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.27 7.49 11,949

11,989 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.31 7.62 11,932

11,915 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.39 6.15 12,129

11,884 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 6.47 12,079

11,914 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 6.43 12,053

11,779 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 6.19 12,088

11,895 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.41 6.74 12,075

12,125 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.39 8.01 11,863

11,984 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 7.38 11,999

11,822 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.39 8.02 11,910

11,762 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.31 8.19 11,824

11,637 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.30 8.62 11,764

11,860 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.30 7.20 11,963

11,797 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.32 8.11 11,789

11,804 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.28 7.82 11,850

11,697 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.26 8.13 11,815

11,575 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.29 7.77 11,787

11,782 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.28 7.81 11,779

12,009 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 6.88 11,988

11,847 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 7.25 11,918

11,899 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 7.81 11,872

11,818 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 7.83 11,900

11,906 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 7.10 11,978

11,887 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 7.48 11,898

11,979 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 7.43 11,899

11,974 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 6.71 12,023

11,843 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.28 7.22 12,037

11,821 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.25 7.12 11,996

11,777 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.31 8.37 11,879

11,738 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 7.28 11,975

11,815 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 7.07 11,983

11,652 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.44 6.94 11,960

11,832 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 7.40 11,925

11,795 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.33 6.82 12,023

11,727 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 6.14 12,138

10,820 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 7.63 11,886

11,820 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 6.84 12,009

11,988 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.39 7.56 11,893

11,927 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.42 8.04 11,877

11,923 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 7.85 11,892

11,791 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 7.42 11,976

11,565 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.33 7.40 11,924
D.B. D.B. D.B.

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

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) firing 

fuel41

Fuel shipment 

method

Vendor Analyses

11,870 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.39 7.13 11,925

11,675 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.39 7.03 11,930

11,787 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.42 6.41 12,013

11,851 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.40 6.77 11,939

11,707 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 7.36 11,963

11,835 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 7.32 11,925

11,964 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.32 7.93 11,842

11,800 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.28 8.46 11,773

11,863 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.32 7.23 11,962

11,857 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 6.72 12,020

11,820 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.39 6.61 12,008

11,934 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.39 8.60 11,765

11,758 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.32 8.08 11,832

11,815 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.33 8.97 11,738

11,810 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.33 7.55 11,982

11,727 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 7.56 11,960

11,870 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 8.05 11,872

11,796 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 6.64 12,042

11,745 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 6.60 12,020

11,854 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 6.54 12,055

11,807 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.40 6.81 11,944

11,795 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 7.60 11,854

11,961 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.39 7.14 11,928

11,853 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 7.92 11,845

12,018 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.33 8.44 11,772

11,830 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.31 8.32 11,800

11,861 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 8.91 11,735

11,932 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.33 8.44 11,772

11,915 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 8.08 11,781

11,853 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 7.10 11,966

12,014 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 7.24 11,920

11,735 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.33 6.50 12,081

11,814 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 7.48 11,956

11,490 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.30 8.10 11,832

11,779 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.30 7.61 11,925

11,716 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.27 6.78 12,008

11,668 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.29 6.99 11,988

11,717 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 7.32 11,910

11,842 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 6.65 12,014

11,936 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 6.99 11,959

12,026 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.39 8.73 11,781

11,794 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 8.32 11,838

11,249 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 6.84 12,012

11,858 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 8.64 11,761
D.B. D.B. D.B.

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

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) firing 

fuel41

Fuel shipment 

method

Vendor Analyses

11,848 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 7.78 11,856

12,106 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 7.65 11,914

11,968 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 7.52 11,943

11,799 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 7.91 11,859

11,668 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 8.10 11,860

11,816 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 7.44 11,970

11,762 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.31 8.25 11,879

9,991 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 6.91 12,068

12,004 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 6.74 12,042

11,835 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 6.60 12,050

11,831 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.33 7.94 11,806

11,928 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.33 7.90 11,864

11,611 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.31 7.69 11,830

11,669 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.32 7.63 11,908

11,741 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 7.93 11,921

11,564 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.33 7.10 11,977

11,849 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 6.63 11,983

11,960 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 7.24 11,920

11,869 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 7.58 11,866

11,933 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 6.68 12,048

11,917 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 8.21 11,839

11,797 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.31 6.84 12,024

11,810 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 7.60 11,880

11,919 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.39 8.84 11,691

11,960 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.41 7.72 11,866

11,988 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.39 9.24 11,684

11,984 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.31 8.06 11,790

11,880 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.31 8.06 11,790

11,888 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 7.13 11,938

11,927 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.32 7.62 11,870

9,603 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.27 7.26 11,890

11,810 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.25 7.65 11,850

11,744 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.28 7.44 11,844

11,578 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.27 6.95 11,925

11,872 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.27 7.07 12,031

10,770 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.29 6.36 12,060

11,838 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.29 7.28 12,009

11,856 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.33 7.65 11,923

11,721 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.31 7.05 11,997

11,911 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.30 6.90 12,025

11,940 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 6.19 12,122

11,827 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.32 6.79 12,037

11,876 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 7.69 11,906

11,901 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 8.08 11,892
D.B. D.B. D.B.

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

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) firing 

fuel41

Fuel shipment 

method

Vendor Analyses

11,719 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.29 7.09 12,022

11,960 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.33 7.25 11,953

11,841 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 7.91 11,865

11,976 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 7.17 11,962

11,988 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 7.03 11,907

11,892 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 7.31 11,894

11,800 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 7.00 11,920

11,809 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.27 7.43 11,982

11,833 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.28 7.43 11,918

11,692 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.30 6.83 12,000

11,879 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.30 6.84 11,996

11,909 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 6.18 12,136

11,887 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 6.49 12,069

11,820 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 6.48 12,055

11,788 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 7.49 11,944

11,870 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.40 7.01 11,949

11,951 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 8.11 11,814

11,890 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.39 6.03 12,126

11,895 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 5.99 12,129

11,924 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 6.58 12,088

11,874 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.39 6.60 12,028

11,908 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 6.57 12,030

11,864 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 6.23 12,084

11,951 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 6.58 12,006

12,002 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 6.50 12,024

11,891 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 6.85 12,024

11,902 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 7.54 11,938

11,772 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 7.16 11,974

11,869 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.39 6.96 11,982

11,961 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.40 6.46 12,050

11,999 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.40 6.51 12,049

11,862 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.40 6.32 11,997

11,190 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.32 6.66 12,053

11,850 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 7.62 11,838

11,898 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.41 7.21 12,062

11,842 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.40 6.18 12,061

11,976 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.31 6.72 12,018

11,836 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 8.29 11,818

11,728 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 7.53 11,890

11,821 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.32 7.60 11,893

11,828 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 8.81 11,717

11,831 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.32 6.62 12,037

11,773 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.33 6.77 12,010

11,786 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.36 6.58 12,048
D.B. D.B. D.B.

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

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) firing 

fuel41

Fuel shipment 

method

Vendor Analyses

11,799 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 7.25 11,949

11,801 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.45 7.37 11,952

11,987 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.42 7.36 11,974

11,853 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.41 7.79 11,892

11,871 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.43 7.32 11,921

12,018 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 7.55 11,970

11,927 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 7.21 12,003

11,853 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.37 8.22 11,839

11,937 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.34 7.72 11,885

11,873 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.31 8.32 11,837

11,785 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.38 7.32 11,982

11,800 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.33 7.93 11,892

11,910 1, 2, 3, 4 WY CONVERSE CANYON TRAIN 0.35 8.68 11,802

11,600 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.40 7.78 12,108

11,629 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.62 7.75 12,078

11,601 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.62 7.98 12,048

11,668 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.33 7.61 12,072

11,713 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.39 7.33 12,080

11,733 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.51 8.82 11,882

11,563 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.36 8.19 12,012

11,574 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.38 6.83 12,195

11,691 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.50 12,204

11,598 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.33 6.41 12,177

11,686 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.38 6.31 12,215

11,488 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.39 6.53 12,259

11,630 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.48 6.01 12,278

11,611 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.55 8.11 12,082

11,671 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.39 6.57 12,138

11,679 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN N/A 8.44 11,962

11,510 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 6.91 12,075

11,614 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.37 7.08 12,087

11,520 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.44 6.99 12,137

11,391 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.47 7.22 12,143

11,473 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.53 7.18 12,134

11,458 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.64 7.49 12,140

11,423 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.64 7.53 12,129

11,529 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.44 6.92 12,165

12,053 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.46 7.09 12,127

11,607 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.88 12,077

11,518 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.20 12,028

11,430 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.40 12,063

11,639 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.57 11,939

11,662 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.11 12,116

11,535 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 6.52 12,104
D.B. D.B. D.B.

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

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) firing 

fuel41

Fuel shipment 

method

Vendor Analyses

11,317 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.20 12,005

11,548 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.32 12,119

11,755 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.50 12,018

11,511 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.33 12,056

11,598 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 6.26 12,031

11,433 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.34 11,986

11,604 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.41 12,026

11,542 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.34 6.67 12,040

11,227 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 7.03 11,916

11,552 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.33 5.94 12,078

11,343 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.58 12,016

11,384 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.38 12,042

11,248 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.59 11,918

11,406 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.33 12,073

11,468 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 7.11 11,933

11,555 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.54 12,030

9,572 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.71 11,956

11,329 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.27 6.28 12,020

11,517 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.35 12,064

11,435 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.59 12,001

11,401 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.58 11,987

11,435 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.43 12,017

11,378 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.50 11,991

11,405 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.82 11,941

11,442 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 5.98 12,053

11,357 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.31 12,040

11,520 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.73 11,960

11,438 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.33 12,038

11,482 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.35 6.36 12,091

11,422 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.05 12,080

11,714 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 5.94 12,021

11,477 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 6.67 11,965

11,513 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.66 12,006

11,473 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.25 12,004

11,548 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.33 6.74 11,994

11,520 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.31 6.46 12,000

11,505 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 6.19 12,046

11,494 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.43 12,050

11,442 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.31 12,046

11,183 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.29 6.29 12,005

11,276 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 6.48 12,061

11,271 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.32 6.93 11,961

11,431 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.30 7.04 11,958

11,713 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.26 6.23 12,061
D.B. D.B. D.B.

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

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) firing 

fuel41

Fuel shipment 

method

Vendor Analyses

11,544 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.28 6.36 11,982

11,485 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.55 7.18 12,114

11,631 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.64 7.85 12,058

11,558 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN N/A 7.33 12,137

11,359 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.49 7.43 11,945

11,402 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.65 7.60 12,117

11,429 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.67 7.76 12,069

11,378 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.60 8.06 11,980

11,409 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.41 6.80 12,124

11,448 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.42 7.63 12,034

11,543 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.48 7.38 12,075

11,396 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.51 6.68 12,153

11,469 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.67 7.26 12,151

11,379 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.64 7.41 12,149

11,622 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.86 9.04 11,980

11,477 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.61 7.46 12,064

11,566 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 1.02 9.30 12,019

11,346 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.66 7.24 12,129

11,120 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.56 7.27 12,141

11,410 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.54 6.91 12,164

11,590 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.63 7.49 12,078

11,457 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.57 6.96 12,154

11,515 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.56 7.06 12,167

11,527 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.59 7.27 12,100

11,522 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.63 7.52 12,110

11,177 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.47 6.75 12,156

11,633 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.63 7.52 12,080

11,491 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.66 6.91 12,177

11,596 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.56 7.50 12,098

11,531 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.44 6.91 12,157

11,511 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.60 8.02 11,998

11,509 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.49 6.98 12,221

11,472 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.64 7.79 12,077

11,410 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.59 7.37 12,120

11,639 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.40 7.09 12,095

11,527 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.62 7.26 12,173

11,471 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.63 7.31 12,155

11,621 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.47 6.91 12,177

11,502 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.45 7.07 12,213

11,486 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.44 7.04 12,172

11,324 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.36 6.26 12,263

11,507 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.60 7.03 12,133

11,634 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.60 6.99 12,170

11,531 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.39 7.97 12,001
D.B. D.B. D.B.

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

Amount received, dry Fuel source

basis, short tons40

ID # of boiler(s) firing 

fuel41

Fuel shipment 

method

Vendor Analyses

11,501 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.62 7.66 12,120

11,514 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.45 6.85 12,218

11,674 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.37 6.83 12,142

11,649 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.58 7.35 12,185

11,577 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.76 7.55 12,169

11,454 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.47 6.86 12,205

11,316 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.42 6.74 12,186

11,487 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.62 8.14 12,060

11,317 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.69 7.64 12,119

11,483 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.53 8.11 12,033

11,513 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.49 7.20 12,093

11,469 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.51 7.18 12,107

11,508 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.50 6.42 12,201

11,601 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.63 7.57 12,085

11,151 1, 2, 3, 4 WY CAMPBELL WYODAK TRAIN 0.40 6.27 12,223

Note: "N/A" means not available.

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

09-304 14,592 0.45 6.65 12,211 0.085 37 39 3.5 <1 0.7 0.3 0.02 3.2 2.2 2.4 13.7 0.7 WY Campbell Wyodak Train

09-313 14,629 0.32 6.91 11,971 0.082 43 48 4.1 <1 0.3 0.3 <0.02 3.5 3.0 2.4 5.7 0.5 WY Campbell Wyodak Train

09-315 16,007 0.44 7.2 12,090 0.102 37 ND 3.2 <1 0.4 0.3 <0.02 4.1 2.2 2.6 12.8 0.7 WY Campbell Wyodak Train

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 8.5 0.6 WY Campbell Wyodak Train

09-305 14,629 0.34 6.26 12,038 0.058 60 60 3.4 <1 0.4 0.3 0.05 3.4 2.8 2.5 9.4 0.6 WY Campbell, Converse Wyodak Train

09-308 16,008 0.31 6.84 12,105 0.057 37 64 2.9 <1 0.4 0.3 0.02 3.0 2.3 2.6 11.4 0.6 WY Campbell Wyodak Train

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 6.7 0.7 WY Campbell Wyodak Train

09-324 16,054 0.43 7.52 12,074 0.085 39 36 4.8 <1 0.9 0.3 <0.02 4.7 2.6 2.2 15.7 0.6 WY Campbell Wyodak Train

09-325 16,045 0.27 6.50 12,079 0.079 37 48 2.8 <1 0.5 0.4 <0.02 2.9 2.5 2.2 5.6 0.7 WY Campbell Wyodak Train

09-326 16,058 0.48 7.30 12,084 0.131 44 25 4.8 <1 1.1 0.4 <0.02 4.5 2.9 2.4 17.2 0.7 WY Campbell Wyodak Train

09-327 16,001 0.37 7.14 11,968 0.076 37 33 4.6 <1 0.8 0.3 <0.02 3.4 3.3 2.9 4.7 0.6 WY Campbell & Converse Wyodak Train

09-311 15,835 0.32 7.74 11,968 0.072 33 64 3.8 <1 0.8 0.3 <0.02 4.8 2.5 2.8 10.8 0.6 WY Campbell Wyodak Train

09-340 15,884 0.45 7.08 12,105 0.080 32 39 4.9 ND 0.9 0.1 0.03 4.6 2.9 2.9 19.0 0.6 WY Campbell Wyodak Train

09-344 16,021 0.43 6.48 12,093 0.079 29 ND 5.0 <1 1.1 0.2 0.02 3.5 2.8 2.5 14.7 0.9 WY Campbell Wyodak Train

09-345 15,975 0.27 6.76 12,129 0.063 32 41 3.5 <1 0.6 0.1 <0.02 3.7 2.7 2.7 8.1 0.7 WY Campbell Wyodak Train

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 6.8 0.6 WY Campbell Wyodak Train

09-347 14,688 0.41 7.17 11,923 ND ND 49 2.9 ND 0.5 0.2 ND 3.2 2.7 2.9 12.3 0.5 WY Campbell Wyodak Train

Note: "ND" means non-detect.

Note: Alabama Power collects this information on select coal shipments, but does not have this information available on a shipment by shipment basis. The information Alabama Power provides in this response cannot be linked to the information in Part II, Question 2 because the information comes from two separate databases.

Thus, the information provided in this 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.

Sample ID # State/Country County Coal Seam

Fuel Shipment 

Method

Total amount of 

fuel represented by 

Total 

Sulfur, %

Ash 

Content, %

Heating Value, 

Btu/lb

Mercury, 

ppm

Chlorine, 

ppm

Fluorine, 

ppm

Nickel, 

ppm

Other Trace Metal HAP, ppm
4 Were the data provided in Part II, question 3 above, acquired pursuant to:

____ permit requirements

____ contractual obligations

____ standard operational procedures

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

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

____ Fuel supplier (name and address)

_X__ Other (name and address)

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

Alabama Power Company, General Services Laboratory

744 Highway 87, GSC #8

Calera, AL 35040

6 Name and address of laboratory performing analyses:

Alabama Power Company, General Services Laboratory

744 Highway 87, GSC #8

Calera, AL 35040

7 In addition to the analyses required in Part II, question 3 above, for samples for which analyses of chlorine and/or any of the HAP metals were 

conducted, please provide copies of any analyses conducted over the preceding 12 calendar months for (a) complete proximate and ultimate 

analyses, (b) additional trace metals, and (c) the mineralogy of the ash that are readily available for the oil(s) or coal(s) listed in Part II, question

2 above. The Agency is requesting these data only as they may already be available; no additional sampling or analyses are required to provide

these data.

Total 

Moisture Volatiles Ash Fixed Carbon Carbon Hydrogen Nitrogen Total Sulfur Oxygen Barium Copper Magnesium Sodium Vanadium Zinc Al2O3 Fe2O3 CaO MgO MnO2 P2O5 K2O SiO2 Na2O SO3 TiO2

09-304 26.85 45.01 6.65 48.34 72.61 4.42 1.04 0.45 14.83 330 12.2 0.172 0.087 13.8 15.2 15.56 6.84 23.55 4.29 0.0325 0.96 0.20 26.09 1.76 18.77 1.13

09-313 26.08 43.52 6.91 49.57 70.56 4.77 1.03 0.32 16.41 390 9.8 0.211 0.063 12.2 19.1 15.71 5.76 20.61 5.06 0.0130 1.23 0.53 36.25 1.23 11.55 1.07

09-315 27.96 44.53 7.20 48.27 70.59 4.75 1.02 0.44 16.00 370 13.2 0.179 0.078 15.1 8.9 17.99 6.14 21.47 4.12 0.0280 1.17 0.31 30.92 1.47 14.62 1.24

09-302 26.54 44.79 6.00 49.21 69.39 4.45 0.86 0.28 19.03 361 11.0 0.206 0.083 13.5 6.9 15.00 4.54 18.20 4.24 ND 1.29 ND 35.60 1.28 15.10 1.11

09-305 26.91 45.12 6.26 48.62 72.40 4.45 1.16 0.34 15.39 302 10.6 0.217 0.078 12.9 15 14.30 5.75 18.30 4.62 ND 0.60 ND 32.30 1.24 15.20 1.01

09-308 26.92 44.86 6.84 48.30 72.77 4.48 0.84 0.31 14.76 320 11.2 0.172 0.057 12.8 7.3 15.41 5.08 20.96 4.16 0.0263 0.78 0.43 36.52 1.12 14.00 1.10

09-312 28.27 44.91 5.95 49.14 70.27 4.60 0.99 0.28 17.90 346 11.3 0.198 0.0738 11.9 9.0 15.40 5.33 21.80 5.17 ND 1.29 ND 35.20 1.53 12.40 1.35

09-324 26.81 43.71 7.52 48.77 69.66 4.88 0.71 0.43 16.80 300 12.2 0.158 0.059 16.4 10.8 17.88 5.81 17.75 3.49 0.0331 0.78 0.55 35.78 1.07 15.41 1.15

09-325 27.29 43.79 6.50 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 5.07 20.27 4.83 0.0136 1.11 0.40 35.15 1.53 12.51 1.13

09-326 27.80 44.25 7.30 48.45 69.22 4.83 0.88 0.48 17.29 340 14.2 0.169 0.077 17.7 13.7 16.64 5.87 20.31 3.83 0.0373 0.98 0.35 31.34 1.42 16.93 1.13

09-327 26.57 42.74 7.14 50.12 69.41 4.73 0.98 0.37 17.37 380 9.5 0.208 0.057 10.8 12.5 16.55 4.88 19.32 4.83 0.0104 1.26 0.42 34.62 1.08 14.81 0.97

09-311 26.64 43.37 7.74 48.89 70.26 4.79 0.87 0.32 16.02 280 9.8 0.165 0.054 15.0 10.8 16.92 5.22 16.65 3.53 0.0220 0.49 0.67 42.99 0.95 10.76 1.16

09-340 27.97 44.56 7.08 48.36 69.57 4.95 1.15 0.45 16.80 360 13.9 0.173 0.076 17.2 11.8 17.61 5.93 21.92 4.06 0.0425 1.33 0.25 30.01 1.44 15.75 1.20

09-344 27.71 44.32 6.48 49.20 69.90 4.92 1.06 0.43 17.21 300 11.6 0.156 0.058 14.1 9.8 15.65 6.60 21.74 4.00 0.0358 1.02 0.28 31.78 1.20 15.82 1.18

09-345 26.95 43.29 6.76 49.95 69.90 4.87 1.08 0.27 17.12 300 11.1 0.171 0.055 13.6 9.3 16.17 5.24 20.36 4.19 0.0190 0.64 0.50 39.64 1.11 10.50 1.22

09-343 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 15.30 4.70 20.40 4.96 ND 1.22 ND 33.60 1.55 9.47 1.13

09-347 26.57 43.07 7.17 49.76 68.26 4.45 1.10 0.41 18.61 479 9.7 0.219 0.069 12.2 6.4 12.80 4.53 18.70 4.39 ND 1.29 ND 37.90 1.28 11.20 1.01

Note: "ND" means non-detect.

Sample ID 

#

Proximate Analyses, % by wt Ultimate Analyses, % by wt Other Trace Metals, ppm Ash Mineralogy, % by wt
8a What emission test report(s), parametric monitoring data, and other data or monitoring are available for the boilers noted in Part I,

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

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

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

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

Report 1 Unit 3 Particulate Emissions Test (May 9, 2005)

Report 2 Unit 4 Particulate Emissions Test (May 9, 2005)

Report 3 Unit 1 Particulate Emissions Test (May 2, 2006)

Report 4 Unit 2 Particulate Emissoins Test (May 4, 2006)

Report 5 Unit 3 Particulate Emissions Test (April 24, 2007)

Report 6 Unit 4 Particulate Emissions Test (April 24, 2007)

Report 7 Unit 1 Particulate Emissions Test (April 16, 2008)

Report 8 Unit 2 Particulate Emissions Test (April 16, 2008)

Report 9 Unit 3 Particulate Emissions Test (May 5, 2009)

Report 10 Unit 4 Particulate Emissions Test (May 5, 2009)

Report 11 Unit 1 Compliance Assurance Monitoring Test (May 3, 2006)

Report 12 Unit 2 Compliance Assurance Monitoring Test (May 5, 2006)

Report 13 Unit 4 Compliance Assurance Monitoring Test (April 24, 2007)

Report 14 Unit 1 B&W Dual Register Coal Burner Tuning (May 27 - June 4, 2009)

Report 15 Unit 2 B&W Wall Fired Coal Burner Tuning (May 11 - 18, 2009)

Report 16 Unit 3 B&W Wall Fired Coal Burner Tuning (April 22 - 29, 2009)

Report 17 Unit 4 B&W Wall Fired Coal Burner Tuning (April 1 - 13, 2009)

Report 18 Evaluation of Calcium Bromide for Mercury Emissions Control at Southern Company's Plant Miller

Unit 4 (October 2006) - conducted in coordination with the Electric Power Research Institute (EPRI)

Report 19 The Evaluation of Furnace Calicum Bromide and FGD Activated Carbon Injection for Mercury Emissions 

Control at Southern Company's Plant Miller Unit 4 (October 2008) - conducted in coordination with the Electric 

Power Research Institute (EPRI)

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: 5/9/2005 Type: stack Constituents: PM

Report 2 Date: 5/9/2005 Type: stack Constituents: PM

Report 3 Date: 5/2/2006 Type: stack Constituents: PM

Report 4 Date: 5/4/2006 Type: stack Constituents: PM

Report 5 Date: 4/24/2007 Type: stack Constituents: PM

Report 6 Date: 4/24/2007 Type: stack Constituents: PM

Report 7 Date: 4/16/2008 Type: stack Constituents: PM

Report 8 Date: 4/16/2008 Type: stack Constituents: PM

Report 9 Date: 5/5/2009 Type: stack Constituents: PM

Report 10 Date: 5/5/2009 Type: stack Constituents: PM

Report 11 Date: 5/3/2006 Type: stack Constituents: PM

Report 12 Date: 5/5/2006 Type: stack Constituents: PM

Report 13 Date: 4/24/2007 Type: stack Constituents: PM

Report 14 Date: 5/27-6/4/2009 Type: duct Constituents: CO, NOx, CO2

Report 15 Date: 5/11-5/18/2009 Type: duct Constituents: CO, NOx, CO2

Report 16 Date: 4/22-4/29/2009 Type: duct Constituents: CO, NOx, CO2

Report 17 Date: 4/1-4/13/2009 Type: duct Constituents: CO, NOx, CO2

Report 18 Date: 10/1-10/31/2006 Type: parametric Constituents: Hg

Report 19 Date: 10/1-10/31/2008 Type: parametric Constituents: Hg
8c Do any of these test reports reflect testing at a location before 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 14, 15, 16, and 17 contain test data for CO which was measured at the economizer outlet.

Report 18 contains Hg test data measured at the SCR inlet, SCR outlet, ESP inlet, and ESP 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.

The control configurations shown below are representative of the conditions present during Reports 1, 2, 3, 4, 9, 10, 11, 13, 14, 15, 16, 17, 

18 and 19 (no FGD).

Boiler ID

1

2

3

4

Note: "N/A" means not applicable.

PM control Other control

wall-fired/dry bottom (3) flue gas conditioning 

- SO3 injection 

(05/1999)

(4) hot-side ESP was 

originally installed 

(10/12/1978) but was 

converted to a cold-side 

ESP (05/1999)

N/A

N/A

N/A

Type NOx control SO2 control

wall-fired/dry bottom

wall-fired/dry bottom

(1) low-NOx burners (10/12/1978)

(2) SCR (05/09/2005) - the SCR 

uses a titania-vanadia based 

ceramic catalyst and anhydrous 

ammonia as the reductant; the 

catalyst is not specifically 

designed to reduce SO3 formation

(1) low-NOx burners (05/01/1985)

(2) SCR (05/01/2005) - the SCR 

uses a titania-vanadia based 

ceramic catalyst and anhydrous 

ammonia as the reductant; the 

catalyst is not specifically 

designed to reduce SO3 formation

(1) low-NOx burners (05/01/1989)

(2) SCR (03/18/2003) - the SCR 

uses a titania-vanadia based 

ceramic catalyst and anhydrous 

ammonia as the reductant; the 

catalyst is not specifically 

designed to reduce SO3 formation

wall-fired/dry bottom (1) low-NOx burners (03/05/1991)

(2) SCR (03/28/2003) - the SCR 

uses a titania-vanadia based 

ceramic catalyst and anhydrous 

ammonia as the reductant; the 

catalyst is not specifically 

designed to reduce SO3 formation

N/A (3) cold-side ESP 

(03/01/1991)

N/A

(3) flue gas conditioning 

- SO3 injection 

(05/1999)

(4) hot-side ESP was 

originally installed 

(05/01/1985) but was 

converted to a cold-side 

ESP (03/1999)

(3) cold-side ESP 

(05/01/1989)

N/A

N/A

N/A
The control configurations shown below are representative of the conditions present during Reports 5, 6, 7, and 8 (no FGD, no SCRs in operation).

Boiler ID

1

2

3

4

Note: "N/A" means not applicable.

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

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

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

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

Type NOx control SO2 control PM control Other control

wall-fired/dry bottom (1) low-NOx burners (10/12/1978) N/A (2) flue gas conditioning 

- SO3 injection 

(05/1999)

(3) hot-side ESP was 

originally installed 

(10/12/1978) but was 

converted to a cold-side 

ESP (05/1999)

N/A

wall-fired/dry bottom (1) low-NOx burners (05/01/1985) N/A (2) flue gas conditioning 

- SO3 injection 

(05/1999)

(3) hot-side ESP was 

originally installed 

(05/01/1985) but was 

converted to a cold-side 

ESP (03/1999)

N/A

wall-fired/dry bottom (1) low-NOx burners (05/01/1989) N/A (2) cold-side ESP 

(05/01/1989)

N/A

wall-fired/dry bottom (1) low-NOx burners (03/05/1991) N/A (2) cold-side ESP 

(03/01/1991)

N/A
9 What type of deviation reporting is required for violations of permit requirements?

Deviations from permit requirements shall be reported within 2 working days of such deviations, including those attributable

to upset conditions as defined in the permit, the probable cause of said deviations, and any corrective actions or preventive 

measures that were taken.

The date, time, duration, magnitude, cause and corrective action taken for each excess emission are also included in the monthly

and quarterly reports submitted to the Jefferson County Department of Health.

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

10 Are deviation reports available for malfunctions or other periods of noncompliance with permit terms and conditions?

Yes _X__ No ____ If yes, please note which reports.

Deviation cause and corrective action reports are included in each of the monthly and quarterly reports submitted to the Jefferson 

County Department of Health.

Additionally, all deviations from permit terms and conditions are reported in the annual Title V compliance certifications,

submitted to both the Jefferson County Department of Health and EPA.

Note: A malfunction is not necessarily a period of non-compliance with permit terms and conditions. Not all reported deviations 

are considered violations of permit requirements.

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

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

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

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

Mercury CEMS data are available1 for the following periods of time:

Unit 1: April 25, 2008 - June 17, 2009

Unit 2: April 29, 2008 - June 17, 2009

Unit 3: August 5, 2008 - December 31, 2009

Unit 4: November 20, 2008 - December 31, 2009

COMS data are available for the following periods of time:

Unit 1: December 1, 1993 - December 31, 2009

Unit 2: December 1, 1993 - December 31, 2009

Unit 3: Bypass Stack: December 1, 1993 - December 31, 2009

FGD: December 14, 2009 - December 31, 2009

Unit 4: December 1, 1993 - December 31, 2009

1

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

procedures that meet the requirements of 40 CFR Part 75.

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 CEMS data be submitted by the respondent. The respondent should also mark the periods of start up, shut down and malfunction events (SSM) in the data sets.
12 For each boiler noted in Part I, question 15, provide the following information:

Test 

Report

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

(specify)

3 Report 1 5/9/2005 See Attachment 1 N/A N/A N/A N/A N/A N/A

4 Report 2 5/9/2005 See Attachment 2 N/A N/A N/A N/A N/A N/A

1 Report 3 5/2/2006 See Attachment 3 N/A N/A N/A N/A N/A N/A

2 Report 4 5/4/2006 See Attachment 4 N/A N/A N/A N/A N/A N/A

3 Report 5 4/24/2007 See Attachment 5 N/A N/A N/A N/A N/A N/A

4 Report 6 4/24/2007 See Attachment 6 N/A N/A N/A N/A N/A N/A

1 Report 7 4/16/2008 See Attachment 7 N/A N/A N/A N/A N/A N/A

2 Report 8 4/16/2008 See Attachment 8 N/A N/A N/A N/A N/A N/A

3 Report 9 5/5/2009 See Attachment 9 N/A N/A N/A N/A N/A N/A

4 Report 10 5/5/2009 See Attachment 10 N/A N/A N/A N/A N/A N/A

1 Report 11 5/3/2006 See Attachment 11 N/A N/A N/A N/A N/A N/A

2 Report 12 5/5/2006 See Attachment 12 N/A N/A N/A N/A N/A N/A

4 Report 13 4/24/2007 See Attachment 13 N/A N/A N/A N/A N/A N/A

1 Report 14 5/27-6-4/2009 N/A N/A N/A N/A N/A See Attachment 14 N/A

2 Report 15 5/11-5/18/2009 N/A N/A N/A N/A N/A See Attachment 15 N/A

3 Report 16 4/22-4/29/2009 N/A N/A N/A N/A N/A See Attachment 16 N/A

4 Report 17 4/1-4/13/2009 N/A N/A N/A N/A N/A See Attachment 17 N/A

4 Report 18 10/1-10/31/2006 N/A N/A N/A N/A See Attachments 18-21 N/A N/A

4 Report 19 10/1-10/31/2008 N/A N/A See Attachment 25 See Attachment 25 See Attachments 22-24 N/A N/A

Note: "N/A" means not applicable.

47 Provide emission test data for all tests conducted since January 1, 2005. Please indicate test data acquired both before and after

any control device. Use additional pages as necessary. EPA may, at some future date, request a copy of one or more emission test reports.

Data generated to fulfill both Federal and State requirements must be provided. Note that data generated pursuant to CAA Title V

must be maintained and available for 5 years. Also include averaging times and measurement units for all pollutants.

48 For each emissions test run the respondent should provide the following process information: Unit Load (MW), Net generation during run (MWh net),

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

temperature at sampling point (oF), Flue gas pressure at sampling point (atm), Standard temperature (oF), Standard pressure (atm).

49 If emission testing recorded the emissions of filterable and condensable PM, separately, please include those separate emission results. 

Also, please include separate emission results for total PM, PM10, and PM2.5.

50 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, phosphorus, and selenium;

indicate emission level for all metal HAP for which an emission test has been conducted.

51 Please provide separate results for total Hg, elemental Hg, oxidized Hg, and particulate Hg, as available. If the emissions testing recorded

the amount of unburned carbon in fly ash (as reflected by the "Loss of Ignition" [L.O.I]) at the time of any Hg testing, please include these data.

Boiler ID

Emissions test results (indicate format of emission data)47,48
ATTACHMENT 1 - Miller Report 1 Test Results

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 5/9/2005 5/9/2005 5/9/2005

Sampling Time -Start Military 1245 1410 1540

Sampling Time -Stop Military 1348 1515 1643

Number of Ports dimensionless 4 4 4

Number of Points per Port dimensionless 3 3 3

Heat Input Million Btu per Hour 6,913 6,975 7,004

Stack Static Pressure Inches Water -2.80 -2.80 -2.80

Barometric Pressure Inches Mercury 30.16 30.16 30.16

Meter Correction Factor dimensionless 1.011 1.011 1.011

Oxygen Concentration Mole Percent O2 6.0 6.0 7.5

Carbon Dioxide Concentration Mole Percent CO2 12.0 14.0 14.0

Volume of Gas Metered Actual Cubic Feet 59.210 54.665 53.535

Volume of Water Collected Milliliters 132.00 133.00 130.00

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.217 0.214 0.215

Weight of Solids Collected Milligrams 9.5 6.9 6.0

Area of Stack Square Feet 490.874 490.874 490.874

Avg. Sqr. Root Velocity Pressure Inches Water 1.4235 1.4190 1.3868

Average Orifice Pressure (DH) Inches Water 2.9 2.7 2.6

Average Stack Temperature Degrees F 308 307 308

Average Meter Temperature Degrees F 92 97 98

Average Generation MW 708 708 708

3 Runs

RUN 1 RUN 2 RUN 3 Average

Volume of Gas Sampled Standard Dry 58.183 53.165 51.957 54.435

 Cubic Feet 

Molecular Wt. of Stack Gas LB/LB-MOLE 28.99 29.17 29.22 29.12

Water vapor in Stack Gas Percent 9.6 10.5 10.5 10.2

Average Stack Gas Velocity Feet per second 96.1 95.5 93.3 95.0

Stack Gas Flow Rate Actual Cubic 2,831,280 2,811,977 2,747,358 2,796,872

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 1,947,921 1,936,953 1,890,183 1,925,019

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 1,759,977 1,732,899 1,691,025 1,727,967

 Feet Per Minute

Stack Gas Flow Rate Pounds of Dry Air 131,822 129,794 126,658 129,425

Per Minute

Particulate Concentration Grains per Standard 0.0025 0.0020 0.0018 0.0021

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.0016 0.0012 0.0011 0.0013

 Cubic Foot

Particulate Emission Rate Pounds per Hour 37.9 29.7 25.8 31.1

Particulate Emission Rate Pounds per Million 0.0055 0.0043 0.0037 0.0045

 Btu (Heat Input)

Isokinetic Rate Percent 105.3 100.5 99.7 101.8

TABLE I. SUMMARY OF PARTICULATE EMISSIONS TEST RESULTS

ALABAMA POWER COMPANY

MILLER STEAM PLANT, UNIT 3

5/9/2005

Calculations
ATTACHMENT 2 - Miller Report 2 Test Results 

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 5/9/2005 5/9/2005 5/9/2005

Sampling Time -Start Military 1245 1410 1540

Sampling Time -Stop Military 1345 1510 1640

Number of Ports dimensionless 4 4 4

Number of Points per Port dimensionless 3 3 3

Heat Input Million Btu per Hour 6,598 6,609 6,619

Stack Static Pressure Inches Water -2.00 -2.00 -2.00

Barometric Pressure Inches Mercury 30.16 30.16 30.16

Meter Correction Factor dimensionless 1.051 1.051 1.051

Oxygen Concentration Mole Percent O2 5.5 6.0 5.5

Carbon Dioxide Concentration Mole Percent CO2 12.8 13.0 13.3

Volume of Gas Metered Actual Cubic Feet 50.748 48.122 49.744

Volume of Water Collected Milliliters 124.00 123.00 116.00

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.217 0.206 0.215

Weight of Solids Collected Milligrams 3.3 6.4 7.5

Area of Stack Square Feet 490.874 490.874 490.874

Avg. Sqr. Root Velocity Pressure Inches Water 1.3380 1.3887 1.3915

Average Orifice Pressure (DH) Inches Water 3.2 2.7 3.1

Average Stack Temperature Degrees F 300 302 303

Average Meter Temperature Degrees F 96 104 104

Average Generation MW 709 709 709

3 Runs

RUN 1 RUN 2 RUN 3 Average

Volume of Gas Sampled Standard Dry 51.473 48.093 49.724 49.764

 Cubic Feet 

Molecular Wt. of Stack Gas LB/LB-MOLE 29.01 29.00 29.12 29.04

Water vapor in Stack Gas Percent 10.2 10.7 9.9 10.3

Average Stack Gas Velocity Feet per second 89.8 93.3 93.3 92.1

Stack Gas Flow Rate Actual Cubic 2,643,533 2,747,032 2,748,739 2,713,101

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 1,841,711 1,910,046 1,908,517 1,886,758

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 1,654,144 1,704,814 1,719,682 1,692,880

 Feet Per Minute

Particulate Concentration Grains per Standard 0.0010 0.0020 0.0023 0.0018

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.0006 0.0013 0.0015 0.0011

 Cubic Foot

Particulate Emission Rate Pounds per Hour 14.0 29.9 34.2 26.1

Particulate Emission Rate Pounds per Million 0.0021 0.0045 0.0052 0.0039

 Btu (Heat Input)

Isokinetic Rate Percent 99.1 99.7 93.8 97.5

TABLE I. SUMMARY OF PARTICULATE EMISSIONS TEST RESULTS

ALABAMA POWER COMPANY

MILLER STEAM PLANT, UNIT 4

5/9/2005

Calculations
ATTACHMENT 3 - Miller Report 3 Test Results 

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 5/2/2006 5/2/2006 5/2/2006

Sampling Time -Start Military 0845 0957 1109

Sampling Time -Stop Military 0951 1102 1212

Number of Ports dimensionless 4 4 4

Number of Points per Port dimensionless 3 3 3

Heat Input Million Btu per Hour 7,649 7,617 7,622

Stack Static Pressure Inches Water -2.00 -2.00 -2.00

Barometric Pressure Inches Mercury 30.10 30.10 30.10

Standard Orifice Pressure DH@ Inches Water 1.74 1.74 1.74

Meter Correction Factor dimensionless 0.99 0.99 0.99

Oxygen Concentration Mole Percent O2 7.5 7.0 7.0

Carbon Dioxide Concentration Mole Percent CO2 12 12 12

Volume of Gas Metered Actual Cubic Feet 46.415 47.850 48.300

Volume of Water Collected Milliliters 105 103 112

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.200 0.200 0.200

Weight of Solids Collected Milligrams 15.4 14.9 16.7

Area of Stack Square Feet 490.874 490.874 490.874

Avg. Sqr. Root Velocity Pressure Inches Water 1.37 1.38 1.39

Average Orifice Pressure (DH) Inches Water 2.0 2.1 2.1

Average Stack Temperature Degrees F 289 290 296

Average Meter Temperature Degrees F 88 109 111

Average Generation MW 708 708 708

RUN 1 RUN 2 RUN 3 Average

Volume of Gas Sampled Standard Dry 44.583 44.301 44.598 44.494

 Cubic Feet 

Molecular Wt. of Stack Gas (dry) LB/LB-MOLE 29.00 29.00 28.91 28.97

Water vapor in Stack Gas Percent 10.0 9.9 10.6 10.1

Average Stack Gas Velocity Feet per second 91.5 92.3 93.3 92.4

Stack Gas Flow Rate Actual Cubic 2,694,628 2,719,672 2,748,111 2,720,804

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 1,900,234 1,916,402 1,922,338 1,912,991

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 1,710,602 1,727,363 1,719,126 1,719,030

 Feet Per Minute

Stack Gas Flow Rate Pounds of Dry Air 128,124 129,380 128,763 128,755

Per Minute

Particulate Concentration Grains per Standard 0.0053 0.0052 0.0058 0.0054

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.0034 0.0033 0.0036 0.0034

 Cubic Foot

Particulate Emission Rate Pounds per Hour 78.0 76.7 85.0 79.9

Particulate Emission Rate Pounds per Million 0.010 0.010 0.011 0.010

Allowable Btu (Heat Input) 0.10 0.10 0.10 0.10

Isokinetic Rate Percent 97.7 96.2 97.3 97.0

TABLE I. PARTICULATE EMISSIONS TEST RESULTS

ALABAMA POWER COMPANY

MILLER STEAM PLANT

UNIT 1

Calculations
ATTACHMENT 4 - Miller Report 4 Test Results

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 5/4/2006 5/4/2006 5/4/2006

Sampling Time -Start Military 0752 0906 1017

Sampling Time -Stop Military 0858 1010 1121

Number of Ports dimensionless 4 4 4

Number of Points per Port dimensionless 3 3 3

Heat Input Million Btu per Hour 7,043 7,060 7,069

Stack Static Pressure Inches Water -2.00 -2.00 -2.00

Barometric Pressure Inches Mercury 30.12 30.12 30.12

Standard Orifice Pressure DH@ Inches Water 1.74 1.74 1.74

Meter Correction Factor dimensionless 0.9866 0.9866 0.9866

Oxygen Concentration Mole Percent O2 7.0 7.5 7.0

Carbon Dioxide Concentration Mole Percent CO2 12.0 12.0 12.0

Volume of Gas Metered Actual Cubic Feet 47.385 45.820 46.570

Volume of Water Collected Milliliters 133 111 120

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.200 0.200 0.200

Weight of Solids Collected Milligrams 14.2 11.3 12.8

Area of Stack Square Feet 490.874 490.874 490.874

Avg. Sqr. Root Velocity Pressure Inches Water 1.338 1.306 1.337

Average Orifice Pressure (DH) Inches Water 1.9 1.9 2.0

Average Stack Temperature Degrees F 289 292 294

Average Meter Temperature Degrees F 101 115 120

Average Generation MW 711 711 711

RUN 1 RUN 2 RUN 3 Average

Volume of Gas Sampled Standard Dry 44.551 41.960 42.349 42.953

 Cubic Feet 

Molecular Wt. of Stack Gas (dry) LB/LB-MOLE 28.70 28.87 28.76 28.78

Water vapor in Stack Gas Percent 12.3 11.1 11.8 11.7

Average Stack Gas Velocity Feet per second 89.7 87.4 89.8 89.0

Stack Gas Flow Rate Actual Cubic 2,641,735 2,573,703 2,644,943 2,620,127

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 1,864,386 1,810,531 1,854,681 1,843,199

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 1,634,682 1,610,049 1,636,421 1,627,051

 Feet Per Minute

Stack Gas Flow Rate Pounds of Dry Air 122,438 120,593 122,568 121,866

Per Minute

Particulate Concentration Grains per Standard 0.0049 0.0041 0.0047 0.0046

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.0030 0.0026 0.0029 0.0028

 Cubic Foot

Particulate Emission Rate Pounds per Hour 68.8 57.2 65.3 63.8

Particulate Emission Rate Pounds per Million 0.010 0.008 0.009 0.009

Allowable Btu (Heat Input) 0.10 0.10 0.10 0.10

Isokinetic Rate Percent 102.2 97.7 97.0 99.0

TABLE I. PARTICULATE EMISSIONS TEST RESULTS

ALABAMA POWER COMPANY

MILLER STEAM PLANT

UNIT 2

Calculations
ATTACHMENT 5 - Miller Report 5 Test Results 

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 4/24/2007 4/24/2007 4/24/2007

Sampling Time -Start Military 1134 1248 1403

Sampling Time -Stop Military 1239 1353 1507

Number of Ports dimensionless 4 4 4

Number of Points per Port dimensionless 3 3 3

Heat Input Million Btu per Hour 7,030 7,030 7,030

Stack Static Pressure Inches Water -2.50 -2.50 -2.50

Barometric Pressure Inches Mercury 30.15 30.15 30.15

Standard Orifice Pressure DH@ Inches Water 1.858 1.858 1.858

Meter Correction Factor dimensionless 0.978 0.978 0.978

Oxygen Concentration Mole Percent O2 6.5 6.0 7.0

Carbon Dioxide Concentration Mole Percent CO2 13.0 13.0 13.0

Volume of Gas Metered Actual Cubic Feet 53.650 53.115 54.980

Volume of Water Collected Milliliters 158.00 132.00 134.00

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.213 0.211 0.212

Weight of Solids Collected Milligrams 6.13 5.43 6.11

Area of Stack Square Feet 490.874 490.874 490.874

Avg. Sqr. Root Velocity Pressure Inches Water 1.4000 1.3826 1.4130

Average Orifice Pressure (DH) Inches Water 2.7 2.6 2.8

Average Stack Temperature Degrees F 334 337 339

Average Meter Temperature Degrees F 95 97 98

Average Generation MW 719 719 719

RUN 1 RUN 2 RUN 3 Average

Volume of Gas Sampled Standard Dry 50.618 49.940 51.615 50.724

 Cubic Feet 

Molecular Wt. of Stack Gas (dry) LB/LB-MOLE 30.34 30.32 30.36 30.34

Water vapor in Stack Gas Percent 12.8 11.1 10.9 11.6

Average Stack Gas Velocity Feet per second 96.5 95.1 97.2 96.3

Stack Gas Flow Rate Actual Cubic 2,841,222 2,802,356 2,864,144 2,835,907

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 1,892,493 1,858,406 1,895,418 1,882,106

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 1,650,058 1,652,777 1,689,018 1,663,951

 Feet Per Minute

Stack Gas Flow Rate Pounds of Dry Air 123,589 123,793 126,507 124,630

Per Minute

Particulate Concentration Grains per Standard 0.002 0.002 0.002 0.002

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.001 0.001 0.001 0.001

 Cubic Foot

Particulate Emission Rate Pounds per Hour 26.4 23.7 26.4 25.5

Particulate Emission Rate Pounds per Million 0.004 0.003 0.004 0.004

Allowable Btu (Heat Input) 0.030 0.030 0.030 0.030

Isokinetic Rate Percent 101.4 101.8 102.0 101.7

Post Test Meter Correction Factor dimensionless 1.01 1.00 1.00 1.00

Percent Difference Allowed 5% 2.7 2.6 2.4 2.6

TABLE I. PARTICULATE EMISSIONS TEST RESULTS

ALABAMA POWER COMPANY

MILLER STEAM PLANT

UNIT 3

Calculations
ATTACHMENT 6 - Miller Report 6 Test Results 

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 4/24/2007 4/24/2007 4/24/2007

Sampling Time -Start Military 0744 0905 1020

Sampling Time -Stop Military 0849 1008 1123

Number of Ports dimensionless 4 4 4

Number of Points per Port dimensionless 3 3 3

Heat Input Million Btu per Hour 7,035 7,034 7,044

Stack Static Pressure Inches Water -2.25 -2.25 -2.25

Barometric Pressure Inches Mercury 30.15 30.15 30.15

Standard Orifice Pressure DH@ Inches Water 1.858 1.858 1.858

Meter Correction Factor dimensionless 0.978 0.978 0.978

Oxygen Concentration Mole Percent O2 6.0 8.0 8.0

Carbon Dioxide Concentration Mole Percent CO2 11.5 12.5 12

Volume of Gas Metered Actual Cubic Feet 53.685 56.555 57.245

Volume of Water Collected Milliliters 116.00 147.00 136.00

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.213 0.211 0.212

Weight of Solids Collected Milligrams 8.18 8.14 8.40

Area of Stack Square Feet 490.874 490.874 490.874

Avg. Sqr. Root Velocity Pressure Inches Water 1.3708 1.4405 1.4581

Average Orifice Pressure (DH) Inches Water 2.8 3.0 3.0

Average Stack Temperature Degrees F 306 307 308

Average Meter Temperature Degrees F 92 93 94

Average Generation MW 718 718 719

RUN 1 RUN 2 RUN 3 Average

Volume of Gas Sampled Standard Dry 50.965 53.652 54.162 52.927

 Cubic Feet 

Molecular Wt. of Stack Gas (dry) LB/LB-MOLE 30.08 30.32 30.24 30.21

Water vapor in Stack Gas Percent 9.7 11.4 10.6 10.6

Average Stack Gas Velocity Feet per second 92.5 97.3 98.5 96.1

Stack Gas Flow Rate Actual Cubic 2,725,129 2,865,371 2,900,876 2,830,459

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 1,881,491 1,975,952 1,997,615 1,951,686

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 1,699,424 1,750,232 1,786,469 1,745,375

 Feet Per Minute

Stack Gas Flow Rate Pounds of Dry Air 127,287 131,092 133,807 130,729

Per Minute

Particulate Concentration Grains per Standard 0.002 0.002 0.002 0.002

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.002 0.001 0.001 0.001

 Cubic Foot

Particulate Emission Rate Pounds per Hour 36.0 35.1 36.6 35.9

Particulate Emission Rate Pounds per Million 0.0051 0.0050 0.0052 0.0051

Allowable Btu (Heat Input) 0.030 0.030 0.030 0.030

Isokinetic Rate Percent 99.1 103.3 101.2 101.2

Post Test Meter Correction Factor dimensionless 1.03 1.00 1.00 1.01

Percent Difference Allowed 5% 5.2 2.1 2.5 3.2

TABLE I. PARTICULATE EMISSIONS TEST RESULTS

ALABAMA POWER COMPANY

MILLER STEAM PLANT

UNIT 4

Calculations
ATTACHMENT 7 - Miller Report 7 Test Results 

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 4/16/2008 4/16/2008 4/16/2008

Sampling Time -Start Military 0900 1037 1218

Sampling Time -Stop Military 1010 1150 1330

Number of Ports dimensionless 4 4 4

Number of Points per Port dimensionless 3 3 3

Heat Input Million Btu per Hour 6,960 7,068 7,002

Stack Static Pressure Inches Water -2.50 -2.50 -2.50

Barometric Pressure Inches Mercury 30.10 30.10 30.10

Standard Orifice Pressure DH@ Inches Water 2.206 2.206 2.206

Meter Correction Factor dimensionless 0.970 0.970 0.970

Oxygen Concentration Mole Percent O2 8.0 6.0 6.0

Carbon Dioxide Concentration Mole Percent CO2 11.0 12.0 12.0

Volume of Gas Metered Actual Cubic Feet 38.415 35.560 36.175

Volume of Water Collected Milliliters 88 85 89

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.183 0.177 0.177

Weight of Solids Collected Milligrams 9.6 9 9.1

Area of Stack Square Feet 490.874 490.874 490.874

Avg. Sqr. Root Velocity Pressure Inches Water 1.3319 1.3537 1.3676

Average Orifice Pressure (DH) Inches Water 1.5 1.4 1.4

Average Stack Temperature Degrees F 284 296 302

Average Meter Temperature Degrees F 62 73 79

Average Generation MW 718 718 718

RUN 1 RUN 2 RUN 3 AVERAGE

Volume of Gas Sampled Standard Dry 38.104 34.489 34.708 35.767

 Cubic Feet 

Molecular Wt. of Stack Gas (dry) LB/LB-MOLE 30.08 30.16 30.16 30.13

Water vapor in Stack Gas Percent 9.8 10.4 10.8 10.3

Average Stack Gas Velocity Feet per second 88.7 90.9 92.3 90.6

Stack Gas Flow Rate Actual Cubic 2,613,203 2,676,242 2,717,005 2,668,817

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 1,853,334 1,869,355 1,882,253 1,868,314

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 1,671,618 1,675,039 1,679,536 1,675,398

 Feet Per Minute

Stack Gas Flow Rate Pounds of Dry Air 125,204 125,460 125,797 125,487

Per Minute

Particulate Concentration Grains per Standard 0.004 0.004 0.004 0.004

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.002 0.003 0.002 0.002

 Cubic Foot

Particulate Emission Rate Pounds per Hour 55.6 57.7 58.1 57.1

Particulate Emission Rate Pounds per Million 0.008 0.008 0.008 0.008

Allowable Btu (Heat Input) 0.1 0.1 0.1 0.1

Isokinetic Rate Percent 102.1 98.6 98.9 99.9

Post Test Meter Correction Check dimensionless 0.95 0.99 0.99 0.97

Percent Difference Allowed 5% Average -2.5 1.7 1.7 0.3

TABLE I. PARTICULATE EMISSIONS TEST RESULTS

ALABAMA POWER COMPANY

MILLER STEAM PLANT

UNIT 1

Calculations
ATTACHMENT 8 - Miller Report 8 Test Results

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 4/16/2008 4/16/2008 4/16/2008

Sampling Time -Start Military 1008 1140 1305

Sampling Time -Stop Military 1115 1245 1414

Number of Ports dimensionless 4 4 4

Number of Points per Port dimensionless 3 3 3

Heat Input Million Btu per Hour 7,140 7,072 7,031

Stack Static Pressure Inches Water -2.00 -2.00 -2.00

Barometric Pressure Inches Mercury 30.10 30.10 30.10

Standard Orifice Pressure DH@ Inches Water 2.258 2.258 2.258

Meter Correction Factor dimensionless 0.982 0.982 0.982

Oxygen Concentration Mole Percent O2 8.0 6.0 7.0

Carbon Dioxide Concentration Mole Percent CO2 14.5 15.5 13.0

Volume of Gas Metered Actual Cubic Feet 35.920 39.300 36.942

Volume of Water Collected Milliliters 96 118.1 94

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.184 0.185 0.185

Weight of Solids Collected Milligrams 10.6 11.4 13.4

Area of Stack Square Feet 490.874 490.874 490.874

Avg. Sqr. Root Velocity Pressure Inches Water 1.3251 1.3531 1.3344

Average Orifice Pressure (DH) Inches Water 1.6 1.6 1.6

Average Stack Temperature Degrees F 308 319 316

Average Meter Temperature Degrees F 60 73 76

Average Generation MW 720 720 723

RUN 1 RUN 2 RUN 3 AVERAGE

Volume of Gas Sampled Standard Dry 36.178 38.618 36.122 36.972

 Cubic Feet 

Molecular Wt. of Stack Gas (dry) LB/LB-MOLE 30.64 30.72 30.36 30.57

Water vapor in Stack Gas Percent 11.1 12.6 10.9 11.5

Average Stack Gas Velocity Feet per second 89.1 91.8 90.5 90.5

Stack Gas Flow Rate Actual Cubic 2,623,108 2,703,127 2,665,992 2,664,076

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 1,806,196 1,834,984 1,816,389 1,819,190

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 1,605,644 1,604,080 1,618,178 1,609,301

 Feet Per Minute

Stack Gas Flow Rate Pounds of Dry Air 120,263 120,146 121,202 120,537

Per Minute

Particulate Concentration Grains per Standard 0.005 0.005 0.006 0.005

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.003 0.003 0.003 0.003

 Cubic Foot

Particulate Emission Rate Pounds per Hour 62.1 62.5 79.2 67.9

Particulate Emission Rate Pounds per Million 0.009 0.009 0.011 0.010

Allowable Btu (Heat Input) 0.1 0.1 0.1 0.1

Isokinetic Rate Percent 99.8 105.5 97.8 101.0

Post Test Meter Correction Check dimensionless 1.00 0.95 1.01 0.99

Percent Difference Allowed 5% Average 1.9 -3.1 2.5 0.4

TABLE I. PARTICULATE EMISSIONS TEST RESULTS

ALABAMA POWER COMPANY

MILLER STEAM PLANT

UNIT 2

Calculations
ATTACHMENT 9 - Miller Report 9 Test Results 

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 5/5/2009 5/5/2009 5/5/2009

Sampling Time -Start Military 0848 1009 1130

Sampling Time -Stop Military 0951 1112 1233

Number of Ports dimensionless 4 4 4

Number of Points per Port dimensionless 3 3 3

Heat Input Million Btu per Hour 6,687 6,673 6,875

Stack Static Pressure Inches Water -2.70 -2.70 -2.70

Barometric Pressure Inches Mercury 30.03 30.03 30.03

Standard Orifice Pressure DH@ Inches Water 2.211 2.211 2.211

Meter Correction Factor dimensionless 0.927 0.927 0.927

Oxygen Concentration Mole Percent O2 7.0 6.0 6.5

Carbon Dioxide Concentration Mole Percent CO2 14.5 14.5 13.5

Volume of Gas Metered Actual Cubic Feet 58.568 55.325 58.135

Volume of Water Collected Milliliters 137 144 142

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.218 0.211 0.215

Weight of Solids Collected Milligrams 4.6 5.0 3.7

Area of Stack Square Feet 490.874 490.874 490.874

Avg. Sqr. Root Velocity Pressure Inches Water 1.3612 1.3618 1.3603

Average Orifice Pressure (DH) Inches Water 3.2 2.8 3.0

Average Stack Temperature Degrees F 335 338 341

Average Meter Temperature Degrees F 103 103 103

Average Generation MW 710 709 709

RUN 1 RUN 2 RUN 3 AVERAGE

Volume of Gas Sampled Standard Dry 51.555 48.626 51.149 50.443

 Cubic Feet 

Molecular Wt. of Stack Gas (dry) LB/LB-MOLE 30.60 30.56 30.42 30.53

Water vapor in Stack Gas Percent 11.1 12.2 11.6 11.6

Average Stack Gas Velocity Feet per second 93.4 93.9 94.0 93.7

Stack Gas Flow Rate Actual Cubic 2,750,335 2,764,926 2,767,648 2,760,969

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 1,820,278 1,823,054 1,819,718 1,821,017

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 1,617,907 1,600,023 1,609,408 1,609,113

 Feet Per Minute

Stack Gas Flow Rate Pounds of Dry Air 121,181 119,842 120,545 120,523

Per Minute

Particulate Concentration Grains per Standard 0.001 0.002 0.001 0.001

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.001 0.001 0.001 0.001

 Cubic Foot

Particulate Emission Rate Pounds per Hour 19.1 21.7 15.4 18.7

Particulate Emission Rate Pounds per Million 0.003 0.003 0.002 0.003

Allowable Btu (Heat Input) 0.030 0.030 0.030 0.030

Isokinetic Rate Percent 100.6 102.4 103.1 102.0

Post Test Meter Correction Check dimensionless 0.93 0.91 0.91 0.92

Percent Difference Allowed 5% Average 0.0 -1.6 -2.0 -1.2

TABLE I. PARTICULATE EMISSIONS TEST RESULTS

ALABAMA POWER COMPANY

MILLER STEAM PLANT

UNIT 3

Calculations
ATTACHMENT 10 - Miller Report 10 Test Results 

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 5/5/2009 5/5/2009 5/5/2009

Sampling Time -Start Military 1248 1410 1529

Sampling Time -Stop Military 1351 1508 1632

Number of Ports dimensionless 4 4 4

Number of Points per Port dimensionless 3 3 3

Heat Input Million Btu per Hour 6,738 6,641 6,643

Stack Static Pressure Inches Water -2.60 -2.60 -2.60

Barometric Pressure Inches Mercury 30.01 30.01 30.01

Standard Orifice Pressure DH@ Inches Water 2.211 2.211 2.211

Meter Correction Factor dimensionless 0.927 0.927 0.927

Oxygen Concentration Mole Percent O2 5.5 5.5 6.0

Carbon Dioxide Concentration Mole Percent CO2 14.5 14.5 14.0

Volume of Gas Metered Actual Cubic Feet 59.247 59.256 55.029

Volume of Water Collected Milliliters 152 147 134

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.217 0.217 0.217

Weight of Solids Collected Milligrams 5.0 5.1 4.8

Area of Stack Square Feet 490.874 490.874 490.874

Avg. Sqr. Root Velocity Pressure Inches Water 1.3474 1.3552 1.3488

Average Orifice Pressure (DH) Inches Water 3.1 3.1 2.8

Average Stack Temperature Degrees F 319 320 321

Average Meter Temperature Degrees F 103 101 104

Average Generation MW 709 710 709

RUN 1 RUN 2 RUN 3 AVERAGE

Volume of Gas Sampled Standard Dry 52.033 52.278 48.217 50.843

 Cubic Feet 

Molecular Wt. of Stack Gas (dry) LB/LB-MOLE 30.54 30.54 30.48 30.52

Water vapor in Stack Gas Percent 12.1 11.7 11.6 11.8

Average Stack Gas Velocity Feet per second 91.8 92.3 91.9 92.0

Stack Gas Flow Rate Actual Cubic 2,703,418 2,717,607 2,708,099 2,709,708

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 1,825,401 1,833,804 1,825,241 1,828,148

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 1,604,746 1,619,459 1,614,098 1,612,768

 Feet Per Minute

Stack Gas Flow Rate Pounds of Dry Air 120,195 121,297 120,896 120,796

Per Minute

Particulate Concentration Grains per Standard 0.001 0.002 0.002 0.002

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.001 0.001 0.001 0.001

 Cubic Foot

Particulate Emission Rate Pounds per Hour 20.4 20.9 21.2 20.8

Particulate Emission Rate Pounds per Million 0.003 0.003 0.003 0.003

Allowable Btu (Heat Input) 0.030 0.030 0.030 0.030

Isokinetic Rate Percent 103.3 102.8 95.1 100.4

Post Test Meter Correction Check dimensionless 0.90 0.90 0.92 0.91

Percent Difference Allowed 5% Average -2.7 -2.4 -1.1 -2.1

TABLE I. PARTICULATE EMISSIONS TEST RESULTS

ALABAMA POWER COMPANY

MILLER STEAM PLANT

UNIT 4

Calculations
ATTACHMENT 11 - Miller Report 11 Test Results

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 5/3/2006 5/3/2006 5/3/2006

Sampling Time -Start Military 0912 1055 1205

Sampling Time -Stop Military 1016 1159 1309

Number of Ports dimensionless 4 4 4

Number of Points per Port dimensionless 3 3 3

Heat Input Million Btu per Hour 7,613 7,647 7,689

Stack Static Pressure Inches Water -2.00 -2.00 -2.00

Barometric Pressure Inches Mercury 30.07 30.07 30.07

Standard Orifice Pressure DH@ Inches Water 1.74 1.74 1.74

Meter Correction Factor dimensionless 0.99 0.99 0.99

Oxygen Concentration Mole Percent O2 7.0 7.5 7.0

Carbon Dioxide Concentration Mole Percent CO2 12.0 12.0 12.0

Volume of Gas Metered Actual Cubic Feet 46.200 49.280 48.250

Volume of Water Collected Milliliters 98 120 119

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.200 0.200 0.200

Weight of Solids Collected Milligrams 39.0 37.4 39.9

Area of Stack Square Feet 490.874 490.874 490.874

Avg. Sqr. Root Velocity Pressure Inches Water 1.390 1.404 1.393

Average Orifice Pressure (DH) Inches Water 2.1 2.2 2.1

Average Stack Temperature Degrees F 292 295 295

Average Meter Temperature Degrees F 98 107 118

RUN 1 RUN 2 RUN 3 Average

Volume of Gas Sampled Standard Dry 43.560 45.731 43.919 44.403

 Cubic Feet 

Molecular Wt. of Stack Gas (dry) LB/LB-MOLE 29.03 28.88 28.82 28.91

Water vapor in Stack Gas Percent 9.6 11.0 11.3 10.6

Average Stack Gas Velocity Feet per second 92.8 94.2 93.6 93.5

Stack Gas Flow Rate Actual Cubic 2,734,578 2,773,737 2,755,923 2,754,746

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 1,920,706 1,940,248 1,927,148 1,929,367

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 1,736,787 1,726,946 1,709,167 1,724,300

 Feet Per Minute

Stack Gas Flow Rate Pounds of Dry Air 130,085 129,348 128,017 129,150

Per Minute

Particulate Concentration Grains per Standard 0.0138 0.0126 0.0140 0.0135

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.0088 0.0078 0.0087 0.0084

 Cubic Foot

Particulate Emission Rate Pounds per Hour 205.3 186.4 205.0 198.9

Particulate Emission Rate Pounds per Million 0.027 0.024 0.027 0.026

 Btu (Heat Input)

Isokinetic Rate Percent 94.0 99.3 96.3 96.6

TABLE I. PARTICULATE EMISSIONS TEST RESULTS

ALABAMA POWER COMPANY

MILLER STEAM PLANT - UNIT 1

COMPLIANCE ASSURANCE MONITORING

Calculations
ATTACHMENT 12 - Miller Report 12 Test Results

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 5/5/2006 5/5/2006 5/5/2006

Sampling Time -Start Military 0846 0957 1107

Sampling Time -Stop Military 0949 1100 1212

Number of Ports dimensionless 4 4 4

Number of Points per Port dimensionless 3 3 3

Heat Input Million Btu per Hour 7,067 7,079 7,076

Stack Static Pressure Inches Water -2.00 -2.00 -2.00

Barometric Pressure Inches Mercury 29.75 29.75 29.75

Standard Orifice Pressure DH@ Inches Water 1.74 1.74 1.74

Meter Correction Factor dimensionless 0.99 0.99 0.99

Oxygen Concentration Mole Percent O2 7.0 7.5 7.0

Carbon Dioxide Concentration Mole Percent CO2 12.0 12.5 12.5

Volume of Gas Metered Actual Cubic Feet 44.850 46.950 47.350

Volume of Water Collected Milliliters 120 109 124

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.200 0.200 0.200

Weight of Solids Collected Milligrams 37.4 37.2 42.6

Area of Stack Square Feet 490.874 490.874 490.874

Avg. Sqr. Root Velocity Pressure Inches Water 1.323 1.344 1.337

Average Orifice Pressure (DH) Inches Water 1.9 2.0 1.8

Average Stack Temperature Degrees F 287 287 286

Average Meter Temperature Degrees F 99 114 116

RUN 1 RUN 2 RUN 3 Average

Volume of Gas Sampled Standard Dry 41.736 42.554 42.753 42.348

 Cubic Feet 

Molecular Wt. of Stack Gas (dry) LB/LB-MOLE 28.75 28.98 28.80 28.84

Water vapor in Stack Gas Percent 11.9 10.8 12.0 11.6

Average Stack Gas Velocity Feet per second 89.0 90.0 89.8 89.6

Stack Gas Flow Rate Actual Cubic 2,622,670 2,651,852 2,644,379 2,639,634

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 1,832,976 1,853,578 1,852,356 1,846,304

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 1,614,477 1,654,144 1,629,850 1,632,824

 Feet Per Minute

Stack Gas Flow Rate Pounds of Dry Air 120,924 123,895 122,076 122,298

Per Minute

Particulate Concentration Grains per Standard 0.0138 0.0135 0.0153 0.0142

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.0085 0.0084 0.0095 0.0088

 Cubic Foot

Particulate Emission Rate Pounds per Hour 191.0 190.9 214.4 198.7

Particulate Emission Rate Pounds per Million 0.027 0.027 0.030 0.028

 Btu (Heat Input)

Isokinetic Rate Percent 96.9 96.5 98.3 97.2

TABLE I. PARTICULATE EMISSIONS TEST RESULTS

ALABAMA POWER COMPANY

MILLER STEAM PLANT - UNIT 2

COMPLIANCE ASSURANCE MONITORING

Calculations
ATTACHMENT 13 - Miller Report 13 Test Results

Title of Run RUN 1 RUN 2 RUN 3

Date Month/Day/Year 4/25/2007 4/25/2007 4/25/2007

Sampling Time -Start Military 0757 1022 1250

Sampling Time -Stop Military 0901 1126 1353

Number of Ports dimensionless 4 4 4

Number of Points per Port dimensionless 3 3 3

Heat Input Million Btu per Hour 7,054 7,022 6,913

Stack Static Pressure Inches Water -2.25 -2.25 -2.25

Barometric Pressure Inches Mercury 30.00 30.00 30.00

Standard Orifice Pressure DH@ Inches Water 1.858 1.858 1.858

Meter Correction Factor dimensionless 0.978 0.978 0.978

Oxygen Concentration Mole Percent O2 6.0 7.0 6.0

Carbon Dioxide Concentration Mole Percent CO2 12.0 11.5 11.5

Volume of Gas Metered Actual Cubic Feet 56.005 40.960 41.080

Volume of Water Collected Milliliters 183.00 112.00 95.00

Sampling Time Minutes 60 60 60

Nozzle Diameter Inches 0.213 0.182 0.183

Weight of Solids Collected Milligrams 36.62 31.74 25.31

Area of Stack Square Feet 490.874 490.874 490.874

Avg. Sqr. Root Velocity Pressure Inches Water 1.4275 1.4503 1.4446

Average Orifice Pressure (DH) Inches Water 3.0 1.6 1.6

Average Stack Temperature Degrees F 305 308 311

Average Meter Temperature Degrees F 94 92 93

RUN 1 RUN 2 RUN 3 Average

Volume of Gas Sampled Standard Dry 52.738 38.556 38.654 43.316

 Cubic Feet 

Molecular Wt. of Stack Gas (dry) LB/LB-MOLE 30.16 30.12 30.08 30.12

Water vapor in Stack Gas Percent 14.0 12.0 10.4 12.1

Average Stack Gas Velocity Feet per second 97.3 98.6 98.2 98.1

Stack Gas Flow Rate Actual Cubic 2,866,237 2,905,394 2,892,808 2,888,146

 Feet Per Minute

Stack Gas Flow Rate Standard Wet Cubic 1,971,160 1,992,663 1,974,380 1,979,401

 Feet Per Minute

Stack Gas Flow Rate Standard Dry Cubic 1,694,408 1,752,976 1,769,656 1,739,014

 Feet Per Minute

Stack Gas Flow Rate Pounds of Dry Air 126,911 131,298 132,547 130,252

Per Minute

Particulate Concentration Grains per Standard 0.011 0.013 0.010 0.011

 Dry Cubic Foot

Particulate Concentration Grains per Actual 0.006 0.008 0.006 0.007

 Cubic Foot

Particulate Emission Rate Pounds per Hour 155.3 190.5 153.0 166.2

Particulate Emission Rate Pounds per Million 0.022 0.027 0.022 0.024

 Btu (Heat Input)

Isokinetic Rate Percent 102.9 99.6 97.8 100.1

Post Test Meter Correction Factor dimensionless 1.02 1.01 1.01 1.01

Percent Difference Allowed 5% 4.4 2.7 3.2 3.4

TABLE I. PARTICULATE EMISSIONS TEST RESULTS

ALABAMA POWER COMPANY

MILLER STEAM PLANT - UNIT 4

COMPLIANCE ASSURANCE MONITORING

Calculations
ATTACHMENT 14 - Miller Report 14 Test Results

Title of Run 2 15

Date 5/27/2009 6/4/2009

Start Time Military 13:39 9:53

End Time Military 14:39 10:53

Unit Load MW 719 708

Avg. Econ. Gas Outlet CO ppm 46 37

Avg. Econ. Gas Outlet O2 % Dry 4.51 4.06

Avg. Econ. Gas Outlet CO2 % Dry 15.03 15.33

COAL BURNER TUNING TEST RESULTS

ALABAMA POWER COMPANY

MILLER STEAM PLANT

UNIT 1
ATTACHMENT 15 - Miller Report 15 Test Results

Title of Run 1a 10

Date 5/11/2009 5/18/2009

Start Time Military 14:54 8:17

End Time Military 15:54 9:17

Unit Load MW 713 720

Avg. Econ. Gas Outlet CO ppm 214 43

Avg. Econ. Gas Outlet O2 % Dry 3.33 3.64

Avg. Econ. Gas Outlet CO2 % Dry 16.09 15.87

COAL BURNER TUNING TEST RESULTS

ALABAMA POWER COMPANY

MILLER STEAM PLANT

UNIT 2
ATTACHMENT 16 - Miller Report 16 Test Results

Title of Run 1 15

Date 4/22/2009 4/29/2009

Start Time Military 14:38 8:51

End Time Military 15:38 9:51

Unit Load MW 711 711

Avg. Econ. Gas Outlet CO ppm 27 91

Avg. Econ. Gas Outlet O2 % Dry 3.65 3.49

Avg. Econ. Gas Outlet CO2 % Dry 15.61 16

COAL BURNER TUNING TEST RESULTS

ALABAMA POWER COMPANY

MILLER STEAM PLANT

UNIT 3
ATTACHMENT 17 - Miller Report 17 Test Results

Title of Run 01a 17

Date 4/1/2009 4/13/2009

Start Time Military 8:47 12:37

End Time Military 9:47 13:37

Unit Load MW 711 711

Avg. Econ. Gas Outlet CO ppm 221 79

Avg. Econ. Gas Outlet O2 % Dry 3.52 3.71

Avg. Econ. Gas Outlet CO2 % Dry 15.84 15.74

COAL BURNER TUNING TEST RESULTS

ALABAMA POWER COMPANY

MILLER STEAM PLANT

UNIT 4
ATTACHMENT 18 - Miller Report 18 Test Results, Part I

EVALUATION OF CALCIUM BROMIDE FOR MERCURY CONTROL AT SOUTHERN COMPANY'S PLANT MILLER

Comparison of Ontario Hydro and SCEM Results

Total Hg 

(mg/Nm3)

Elem. Hg 

(mg/Nm3) % Oxid.

Total Hg 

(mg/Nm3)

Elem. Hg 

(mg/Nm3) % Oxid. Total Hg Elem. Hg

BL 6-Oct 10:25 12:25 9.5 4.2 56 8.6 3.5 60 -10% -18%

BL 6-Oct 12:45 14:45 11.8 4.3 64 9.8 4 59 -19% -7%

BL 6-Oct 15:02 17:02 11.9 4 67 10.1 3.4 67 -16% -16%

BR 15-Oct 9:45 11:45 7.6 0.3 96 5.8 0.7 88 -27% 80%

BR 15-Oct 13:05 15:05 7.5 0.3 96 5.2 0.7 87 -36% 80%

BR 15-Oct 15:45 17.45 7.8 0.4 95 4.7 0.6 87 -50% 40%

* BL = baseline (no bromide injection); BR = calcium bromide injection at 18 ppm Br in coal

Comparison of Sorbent Tube and SCEM Results

Ontario 

Hydro

Sorbent 

Tubes SCEM % RD

Total Hg 

(mg/dNm3

Total Hg 

(mg/dNm3

Total Hg 

(mg/dNm3

at 3% O2) at 3% O2) at 3% O2)

0 6-Oct 10:38 11:18 9.5 8.9 --- ---

0 6-Oct 13:49 14:29 11.8 8.3 10.3 21

0 7-Oct 9:44 10:24 5.9 --- ---

0 7-Oct 10:52 11:32 6.6 5.7 -14

0 7-Oct 12:02 12:42 6.4 6.5 2

328 10-Oct 15:00 15:40 8.4 --- ---

328 10-Oct 16:02 16:42 7.4 5.2 -36

165 11-Oct 11:39 12:19 6.9 6.1 -11

165 11-Oct 12:35 13:15 6.7 4.5 -40

71 12-Oct 13:30 14:10 5.9 5.6 -6

71 12-Oct 14:30 15:10 5.6 4.3 -25

33 13-Oct 13:00 13:40 6.4 5.3 -19

23 13-Oct 15:15 15:55 6.8 4.9 -32

18 15-Oct 9:45 10:25 6.7 --- ---

18 15-Oct 10:45 11:25 6.5 6.6 1

18 15-Oct 13:10 13:50 6.2 --- ---

18 15-Oct 14:20 15:00 6.7 5.3 -23

18 15-Oct 15:45 16:25 6.1 4.6 -28

18 15-Oct 16:45 17:25 6.7 --- ---

7 16-Oct 10:42 11:22 7.4 6.3 -16

0 16-Oct 16:02 16:42 9.6 9 -7

3.3 17-Oct 10:30 11:10 7.2 7.3 2

3.3 17-Oct 11:30 12:10 --- 6.2 ---

86 18-Oct 10:21 11:01 9.1 --- ---

86 18-Oct 11:21 12:01 9.2 7.9 -16

Note: The missing SCEM total mercury numbers are the result of sampling elemental mercury while the sorbent tubes 

were being collected. The missing sorbent tube value on 10/17 is the result of a lost sample.

7.6

7.5

7.8

% RD

Br Injection 

Rate

(ppm in 

coal) Date Start Time End Time

Between 

SCEM and 

Sorbent 

Tubes

Condition*

Date in 

2006 Start Time End Time

Ontario Hydro Results SCEM Results – ESP Outlet
ATTACHMENT 19 - Miller Report 18 Test Results, Part II

EVALUATION OF CALCIUM BROMIDE FOR MERCURY CONTROL AT SOUTHERN COMPANY'S PLANT MILLER

Total and Oxidized Flue Gas Mercury Concentrations (dry, at 3% O2) Measured by SCEM During Baseline Conditions

Ave. Tot. Hg Ave. Tot. Hg Ave. Tot. Hg Ave. Tot. Hg

(μg/Nm3) (μg/Nm3) (μg/Nm3) (μg/Nm3)

10/5/2006

9:00 – 19:00

10/6/2006

9:00 – 17:00

10/7/2006

9:00 – 20:00

10/8/2006

9:00 – 17:00

10/9/2006

9:00 – 17:00

10/5/06 – 

10/9/06 10.9 24 10.2 34 7.9 40 7.9 61

Vapor-Phase Mercury Removal During Baseline Conditions

Projected Hg 

Emissions

(lb Hg/trillion 

Btu)

10/5/2006

9:00 – 19:00

10/6/2006

9:00 – 17:00

10/7/2006

9:00 – 20:00

10/8/2006

9:00 – 17:00

10/9/2006

9:00 – 17:00

10/5/06 – 

10/9/06 7 16 0 28 5.2

18 14 2 31 5.7

9 -- -- 27 4

20 19 -2 33 4.8

-25 -- -- 24 5.4

11 -- -- 26 6.2

8.6 66

Test Periods

% Hg Removal 

across SCR

% Hg Removal 

across AH

% Hg Removal 

across ESP

% Hg Removal 

across 

SCR/AH/ESP 

system

12.3 15 10.1 17 8.7 40

6 59

10.8 33 8.7 32 7.1 41 7.2 57

8.2 13 7.5 58 -- --

8.2 59

12.6 17 11.2 17 -- -- 9.3 62

10.8 42 13.5 44 -- --

Test Periods

SCR Inlet SCR Outlet ESP Inlet ESP Outlet

% Hg Oxid. % Hg Oxid. % Hg Oxid. % Hg Oxid.
ATTACHMENT 20 - Miller Report 18 Test Results, Part III

EVALUATION OF CALCIUM BROMIDE FOR MERCURY CONTROL AT SOUTHERN COMPANY'S PLANT MILLER

Average Elemental Hg Concentrations Measured Across Unit 4

SCR Inlet Avg. 

Hg0

SCR Outlet Avg. 

Hg0

ESP Inlet Avg. 

Hg0

ESP Outlet Avg. 

Hg0

(mg/dNm3) (mg/dNm3) (mg/dNm3) (mg/dNm3)

Baseline 0 8.2 6.7 4.7 3.1

10/17/2006

9:00 - 15:00

10/16/2006

9:00 - 12:10

10/15/2006

10:00 - 17:56

10/13/2006

15:15 - 17:00

10/13/2006

11:58 - 14:15

10/12/2006

12:15 - 17:00

10/18/2006

8:00 - 12:20

10/17/2006

16:00 - 19:00

10/11/2006

11:12 - 16:22

10/10/2006

11:52 - 17:52

Mercury Concentrations Measured by SCEM Across SCR

Avg. Total Hg 

(μg/Nm3)*

Avg. Hg0 

(μg/Nm3)

Avg. Total Hg 

(μg/Nm3)*

Avg. Hg0 

(μg/Nm3)

Baseline 0 10.8 8.2 10.2 6.7 6% 18%

10/17/2006

9:00 - 15:00

10/16/2006

9:00 - 12:10

10/15/2006

10:00 - 17:56

10/13/2006

15:15 - 17:00

10/13/2006

11:58 - 14:15

10/12/2006

12:15 - 17:00

10/18/2006

8:00 - 12:20

10/17/2006

16:00 - 19:00

10/11/2006

11:12 - 16:22

10/10/2006

11:52 - 17:52

* As noted in previous section, there may be a bias in the measurement of total Hg by the SCEM

# % Hg0 Oxidized Across SCR = [1 – (Hg0

SCR,outlet)/(Hg0SCR,inlet) ] *100

-300%

328 9.6 0.4 5.7 1.2 41% -200%

165 10.7 0.2 6.4 0.8 40%

79%

86 8.1 3 8.7 0.4 -7% 87%

84 12 5.2 6.7 1.1 44%

90%

71 9.6 4.3 4.6 0.3 52% 93%

33 5.7 3 5.1 0.3 11%

94%

23 6.3 3.7 5.2 0.3 17% 92%

18 10.6 6.3 5 0.4 53%

78%

7 13.9 11.4 6.9 0.4 50% 96%

3 10.4 7.6 7 1.7 33%

Date & Time

Avg. Bromine 

Injection Rate

(ppm in coal)

SCR Inlet SCR Outlet Apparent % Hg 

Removal Across 

SCR*

% of Hg0 

Oxidized Across 

SCR#

165 0.2 0.8 0.4 0.5

328 0.4 1.2 0.3 0.4

84 5.2 1.1 0.4 0.4

86 3 0.4 0.6 0.6

33 3 0.3 0.4 0.4

71 4.3 0.3 0.4 0.5

18 6.3 0.4 1.7 0.7

23 3.7 0.3 0.4 0.4

1

7 11.4 0.4 1.1 0.7

Date & Time

Avg. Bromine 

Injection Rate 

(ppm in coal)

3 7.6 1.7 2.1
ATTACHMENT 21 - Miller Report 18 Test Results, Part IV

EVALUATION OF CALCIUM BROMIDE FOR MERCURY CONTROL AT SOUTHERN COMPANY'S PLANT MILLER

Hg Oxidation at the ESP Outlet

Date & Time

Avg. Bromine 

Injection Rate 

(ppm in coal)

Sorbent Tube 

Total Hg 

(mg/Nm3)

ESP Outlet Avg. 

Hg0 (mg/Nm3) % Hg Oxidation

Baseline 0 7.2 3.1 58%

10/17/2006

9:00 - 15:00

10/16/2006

9:00 - 12:10

10/15/2006

10:00 - 17:56

10/13/2006

15:15 - 17:00

10/13/2006

11:58 - 14:15

10/12/2006

12:15 - 17:00

10/18/2006

8:00 - 12:20

10/17/2006

16:00 - 19:00

10/11/2006

11:12 - 16:22

10/10/2006

11:52 - 17:52

165 6.8 0.5 92%

328 7.9 0.4 94%

84 9.1 0.4 95%

86 7.2 0.6 92%

33 6.6 0.4 94%

71 5.7 0.5 91%

18 6.5 0.7 90%

23 6.6 0.4 94%

3 7.2 1 86%

7 8.5 0.7 92%
ATTACHMENT 22 - Miller Report 19 Test Results, Part I

THE EVALUATION OF FURNACE CALCIUM BROMIDE AND FGD ACTIVATED CARBON INJECTION FOR MERCURY EMISSIONS CONTROL AT 

SOUTHERN COMPANY'S PLANT MILLER

Comparison of Ontario Hydro and SCEM Results 

Total Hg 

(mg/Nm3)

Elem. Hg 

(mg/Nm3) % Oxid.

Total Hg 

(mg/Nm3)

Elem. Hg 

(mg/Nm3) % Oxid. Total Hg Elem. Hg

BL 9-Oct 9:40 11:40 4.67 2.2 53 4.14 2.54 39 -12% 14%

BL 9-Oct 13:10 15:10 5.11 2.34 54 4.1 2.45 40 -22% 5%

BL 10-Oct 10:51 12:15 4.8 2.44 49 5.41 2.72 50 12% 11%

BL 10-Oct 13:35 15:35 5.57 2.58 54 5.75 3.2 44 3% 22%

17 12-Oct 9:05 11:05 2.76 <0.35 >87 2.38 0.16 93 -15% --

17 12-Oct 12:15 14:15 2.37 <0.34 >86 2.68 0.12 95 12% --

25 14-Oct 9:05 11:05 5.07 0.27 95 5.03 0.21 96 -1% -25%

25 14-Oct 12:25 14:25 4.47 <0.35 >92 4.18 0.17 96 -7% --

* BL = baseline (no bromide injection).

# Vapor phase mercury concentrations presented as μg/dNm3 at 3% O2

Comparison of Sorbent Tube and SCEM Results 

Br Injection 

Rate

Ontario 

Hydro

Sorbent 

Tubes SCEM % RD

(ppm in 

coal)

Total Hg 

(mg/dNm3

Total Hg 

(mg/dNm3

Total Hg 

(mg/dNm3

at 3% O2) at 3% O2) at 3% O2)

0 No 9-Oct 9:47 16:07 4.89* 5.2 4.2 -20

0 No 9-Oct 16:41 6:41 5.4 4.9 -10

0 No 10-Oct 8:20 15:47 5.19* 5.2 5.6 8

0 No 10-Oct 16:00 6:01 5.8 6.8 16

0 No 11-Oct 8:29 11:27 7.2 -- --

17 No 11-Oct 14:28 5:29 4.8 1.8 -90

17 No 12-Oct 8:00 15:00 2.57* 3.1 2.5 -18

17 No 12-Oct 15:13 6:14 3.8 2.3 -50

17, 25 No 13-Oct 7:57 15:03 5 2.7 -60

25 No 13-Oct 15:15 6:51 4.8 -- --

25 No 14-Oct 7:53 15:28 4.77* 5.7 4.6 -22

25 No 14-Oct 16:00 7:01 7.3 2.8 -88

25 No 15-Oct 7:53 15:28 9.2 6.8 -30

25 No 15-Oct 15:47 6:48 8.5 3.2 -92

25 Sump 16-Oct 9:05 17:52 3 4.4 36

25 Sump 16-Oct 18:14 8:12 3.2 -- --

25 Sump 17-Oct 8:35 16:34 4.7 5.2 10

25 Sump 17-Oct 16:54 8:31 4.4 1.4 -106

25 Sump 18-Oct 8:56 17:04 6.1 2.2 -94

25 Sump 18-Oct 17:26 8:00 4 1.5 -92

25 Sump 19-Oct 10:14 19:02 5.2 1.8 -98

25 Sump 19-Oct 19:15 7:56 5.6 1.9 -100

0 Sump 21-Oct 8:19 15:12 6.1 5.4 -12

0 Sump 21-Oct 16:39 7:35 5.6 -- --

0 Duct 22-Oct 11:33 17:12 2.4 2.5 2

0 Duct 22-Oct 17:22 7:36 5.8 -- --

0 Duct 23-Oct 10:46 13:47 6.8 4.4 -42

0 Duct 23-Oct 17:45 6:27 6.6 -- --

0 Duct 24-Oct 7:18 6:39 6.6 3.1 -72

0 Duct 25-Oct 7:10 14:22 4 2.5 -44

Injection Rate (ppm Br in coal)*

Date in 

2008 Start Time End Time

Ontario Hydro Results# % RD

ACI? Date Start Time End Time

Between 

SCEM and 

Sorbent 

Tubes

SCEM Results# 
ATTACHMENT 23 - Miller Report 19 Test Results, Part II

THE EVALUATION OF FURNACE CALCIUM BROMIDE AND FGD ACTIVATED CARBON INJECTION FOR MERCURY EMISSIONS CONTROL AT 

SOUTHERN COMPANY'S PLANT MILLER

Total and Oxidized Flue Gas Mercury Concentrations (dry, at 3% O2) Measured by EPRI SCEM During Baseline Conditions 

(SCR in service, with NH3)

Ave. Tot. 

Hg

Ave. Elem. 

Hg

(μg/Nm3) (μg/Nm3)

10/7/2008

8:00 – 17:00

10/8/2008

8:00 – 17:00

10/9/2008

8:00 – 17:00

10/10/2008

8:00 – 17:00

10/11/2008

8:00 – 12:15

Effect of SCR Operating Condition on Ranges of Mercury Oxidation Measured During Baseline

Test Date SCR Condition SCR Inlet SCR Outlet Stack

Spring 2008 Bypassed n/a n/a 35 – 57%

2006 In Service / NH3 18 – 28% 13 – 56% 57 – 66%

Oct-08 In Service / NH3-- -- 29 – 50%

Spring 2008 In Service / No NH3 5% 23 – 57% 65 – 85%

% Oxid.

On (with NH3) -- -- --

42%

On (with NH3) 4.4 3.1 29%

--

On (with NH3) 5.6 3 46%

Test Periods SCR

On (with NH3) -- 2.7

On (with NH3) 4.3 2.5
ATTACHMENT 24 - Miller Report 19 Test Results, Part III

THE EVALUATION OF FURNACE CALCIUM BROMIDE AND FGD ACTIVATED CARBON INJECTION FOR MERCURY EMISSIONS CONTROL AT 

SOUTHERN COMPANY'S PLANT MILLER

Total and Oxidized Flue Gas Mercury Concentrations (dry, at 3% O2) Measured by SCEM During Long-Term 

Injection at 17 and 25 ppm (SCR in service, with NH3)

Sorb. Trap 

Ave.

SCEM Ave. 

Elem. Hg

Tot. Hg (μg/Nm3

)

(μg/Nm3)

10/11/2008

12:15 – 24:00

10/12/2008 On (with NH3

) 3.5 0.1 97%

10/13/2008

0:00 – 12:18

10/13/08 

12:18 – 24:00 On (with NH3

) 4.9 0.1 98%

10/14/2008 On (with NH3

) 6.5 0.2 97%

10/15/2008 On (with NH3

) 8.9 0.2 98%

10/16/2008

0:00 – 9:45

10/16/2008

9:45 – 24:00

10/17/2008

0:00 – 24:00

10/18/2008

0:00 – 24:00

10/19/2008

0:00 – 17:10

Total and Oxidized Flue Gas Mercury Concentrations (dry, at 3% O2) Measured (SCR in service, with NH3)

Sorb. Trap 

Ave. Tot. Hg

 SCEM Ave. 

Elem. Hg

(μg/Nm3) (μg/Nm3

)

10/16/2008

9:45 – 24:00

10/17/2008

0:00 – 24:00

10/18/2008

0:00 – 24:00

10/19/2008

0:00 – 17:10

10/19/08 17:10 – 

24:00

On (with NH3) 5.6 0 100%

10/20/2008

0:00 – 24:00

10/21/2008

0:00 – 24:00

10/22/2008

0:00 – 10:35

On (with NH3) 4.6 0.2 96%

Bromide Injection at 25 ppm 

On (with NH3) 3.1 0.1 97%

On (with NH3) 5.2 0.1 98%

On (with NH3) 5.1 0.1 98%

(no bromide injection)

On (with NH3) -- 1.3 50%

On (with NH3) 5.6 -- --

On (with NH3) 5.9 2.4 59%

Test Periods SCR % Oxid.

Test Periods SCR % Oxid.

On (with NH3) 5.2 0.1 98%

On (with NH3) 5.1 0.1 98%

On (with NH3) 4.4 0.2 95%

On (with NH3) 4.6 0.2 96%

On (with NH3) 3.1 0.1 97%

Bromide Injection at 25 ppm

On (with NH3) 8.5 -- --

Bromide Injection at 17 ppm

On (with NH3) 4.8 0.4 92%
ATTACHMENT 25 - Miller Report 19 Test Results, Part IV

THE EVALUATION OF FURNACE CALCIUM BROMIDE AND FGD ACTIVATED CARBON INJECTION FOR MERCURY EMISSIONS CONTROL AT 

SOUTHERN COMPANY'S PLANT MILLER

Summary of Method 26 Chloride Measurements 

Date

Run Start 

Time

Run End 

Time

Average HCl 

Concentration 

(ppm in flue gas)

10/15/2008 8:20 10:20 0.57

10/15/2008 10:35 12:35 0.62

10/15/2008 13:25 15:25 0.6

Method 29 Trace Metals Concentrations (Vapor Phase + Particulate), Compared to PISCES Database Values

Baseline 25 ppm Br

Average Minimum Maximum FGD Inlet FGD Inlet

Chemical Substance (μg/dNm3) (μg/dNm3) (μg/dNm3) (μg/dNm3) (μg/dNm3)

Antimony 3.4 0.3 6 0.2 <0.2

Arsenic 0.4 0.09 0.7 <0.9 <1.2

Beryllium 0.08 0.02 0.2 <0.2 <0.2

Cadmium 0.9 0.05 4.2 0.2 0.1

Chromium 3.7 0.4 7.9 3.8 2.9

Cobalt 0.6 0.5 0.8 0.2 0.2

Lead 8.9 0.1 60.9 0.8 0.5

Manganese 5.5 1 11.2 4.6 3.2

Nickel 4 0.4 16.5 4.1 4.2

Selenium 0.7 0.05 1.4 2.0<x<3.1 1.5<x<2.7

from PISCES All concentrations at 

actual O2

(PRB with ESP) Plant Miller