Process Information

1Name 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. 2Name of legal operator of facility, if different from legal owner:

Alabama Power Company 3Address of ____ legal owner or _X__ operator:

600 North 18th Street Birmingham, AL 35291-0830 4aPlant 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 4bEIA 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 5Complete street address of facility (physical location):

4250 Porter Road Quinton, AL 35130 6Provide mailing address if different:

600 North 18th Street Birmingham, AL 35291-0830 7Name and title of contact(s) able to answer technical questions about the completed survey:

Sarah Markham, Engineer II 8Contact(s) telephone number(s):

(205) 257-6780 and e-mail address(es):

sasander@southernco.com 9Is 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

10Which 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)

11Which of the following fossil fuel or other material(s) are permitted1to 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.

12If 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.
2If 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).

3In 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").13If 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 (% _____)

14aIf "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 permitted5to burn non-fossil fuel(s) or other material(s) even if you do not actually burn them.

14bIf "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.

4If 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).

5If 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

Yes15Identification (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 ID6Original design fuel (i.e.,coal rank or type of oil)Design heat input,(MMBtu/hr)7Present maximum heatinput, (MMBtu/hr)8MWe Gross capacitysummerMWe Net CapacitysummerOriginal design grossefficiency (%, HHV)Present operating grossefficiency (%, HHV)Design steam pressure(psig)Operating steam pressure(psig)Design steam temperature(oF)Operating steamtemperature (oF)Design steam reheattemperature (oF)9Operating steam reheattemperature (oF)10Fuel11Hours/year operated12Average annual capacityfactor for the past 3 yearsApplicable NSPSEstimated year ofretirement13

1 bituminous CBI CBI 725 684 87.34 86.3 2400 2400 1000 982 1000 991subbituminous 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 994subbituminous 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 990subbituminous 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 986subbituminous 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.

6Boiler 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).

7Per fuel burned in the boiler. Report this based on higher heating value (HHV).

8Per fuel burned in the boiler. Report this based on higher heating value (HHV).

9Please indicate if more than one steam reheat cycle is utilized, and, if so, please provide information for both.

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

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

12The "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.

13This can be treated as CBI and can be submitted through the proper CBI procedure if desired.16For 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 SO3formation (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 SO3formation (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 SO3formation (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 SO3formation (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.

14Boiler 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).

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

16Examples: 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?

17Examples: 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.
18Examples: 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.
19Please 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]).

### 17For 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.

20A 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.

21Boiler 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

### 18For 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-dateType 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.

22Boiler 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).

23If additive is used, please indicate injection point.

### 19For 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.

24Boiler 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

### 20For 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 dateExpected or projected start-up date Type of control (e.g.,

sorbent and type; chemical additive)26

### Guaranteed HAP

emission reduction (%) or emission rateSorbent or additive

feed rate on which guarantee is basedCoal 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.

25Boiler 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).

26If additive is used, please indicate injection point.21For 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/A1.2 lb/MMBtu (Title V permit; 3-hr rolling average) N/A N/A N/A N/A N/A N/ANOx: 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/A1.2 lb/MMBtu (Title V permit; 3-hr rolling average) N/A N/A N/A N/A N/A N/ANOx: 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/A1.2 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/ANOx: 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/A1.2 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/ANOx: 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.

27Boiler 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).

28If 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.
29List the compliance test method utilized.

30List the compliance test method utilized.

31Metal 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

### 22For 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.

1The 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)

2These guarantees are dependent on specific operating conditions and expire 18 months after the FGDs begin operation.



### 23Was any other guarantee level sought or offered? ____ Yes

_X__ No Please elaborate.

32Boiler 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).

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

34Metal 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 ID3224For 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/AContinuous 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/AContinuous 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 ID35PM36 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/AContinuous 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/AInstall, 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/AContinuous 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/AInstall, certify, and operate a mercury emission monitoring system (Mercury CEMS) by December 31, 2008. N/A N/A

Note: "N/A" means not applicable.

35Boiler 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).
36If 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.
37Metal 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.

### 25For 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]

26Are 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.

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

Note: "N/A" means not applicable.

### Fuel Analysis39



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

James H Miller Jr 1bPlant or facility code from Part I, question 4b:

Plant Code - 6002

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

### 2For 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 % A sh 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 

### Fuel source Amount received, dry basis, short tons40

### ID # of boiler(s) firing fuel41 

### Fuel shipment method Vendor AnalysesD.B. D.B. D.B. 

### State/Country County42 

### Coal seam43 % Sulf % A sh Btu/lb 

### Fuel source Amount received, dry 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 12,070D.B. D.B. D.B. 

### State/Country County42 

### Coal seam43 % Sulf % A sh Btu/lb 

### Fuel source Amount received, dry 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 12,099D.B. D.B. D.B. 

### State/Country County42 

### Coal seam43 % Sulf % A sh Btu/lb 

### Fuel source Amount received, dry 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 12,250D.B. D.B. D.B. 

### State/Country County42 

### Coal seam43 % Sulf % A sh Btu/lb 

### Fuel source Amount received, dry 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 12,041D.B. D.B. D.B. 

### State/Country County42 

### Coal seam43 % Sulf % A sh Btu/lb 

### Fuel source Amount received, dry 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 12,043D.B. D.B. D.B. 

### State/Country County42 

### Coal seam43 % Sulf % A sh Btu/lb 

### Fuel source Amount received, dry 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 12,102D.B. D.B. D.B. 

### State/Country County42 

### Coal seam43 % Sulf % A sh Btu/lb 

### Fuel source Amount received, dry 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 12,125D.B. D.B. D.B. 

### State/Country County42 

### Coal seam43 % Sulf % A sh Btu/lb 

### Fuel source Amount received, dry 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 CANYONTRAIN 0.31 7.03 12,104 11,626 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.42 7.70 12,125 11,766 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.37 7.78 12,050 11,760 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.41 8.59 11,899 11,578 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.50 7.19 12,126 11,756 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.32 6.66 12,184 11,396 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.29 6.13 12,200 11,585 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.33 6.78 12,161 10,823 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.35 5.88 12,285 11,598 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.39 6.35 12,248 11,588 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.33 6.93 12,156 11,672 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.46 7.24 12,089 11,519 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.37 6.64 12,105 11,349 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.35 7.43 12,017 9,534 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.32 6.27 12,204 11,758 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.31 7.93 11,941 11,591 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.32 7.61 12,067 11,706 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.32 7.78 11,969 11,507 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.40 6.87 12,178 11,607 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.54 6.64 12,202 11,464 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.31 6.35 12,171 11,615 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.29 7.26 11,990 11,471 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.31 7.14 12,067 11,593 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.33 6.33 12,159 11,686 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.50 7.28 12,089 11,668 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.46 7.79 12,096D.B. D.B. D.B. 

### State/Country County42 

### Coal seam43 % Sulf % A sh Btu/lb 

### Fuel source Amount received, dry basis, short tons40

### ID # of boiler(s) firing fuel41 

### Fuel shipment method Vendor Analyses

11,582 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.35 7.45 12,056 11,523 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.44 7.41 12,079 11,551 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.34 7.23 12,121 11,694 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.39 7.47 12,064 11,675 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.38 7.30 12,117 11,555 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.40 6.36 12,199 11,658 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.38 6.65 12,145 11,586 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.34 6.95 12,138 11,801 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.40 7.62 11,860 11,678 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.37 7.03 12,120 11,645 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.41 7.39 12,071 11,763 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.49 7.45 12,100 11,595 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.49 7.33 12,127 11,737 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.31 5.70 12,261 11,704 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.43 7.89 12,035 11,553 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.33 7.55 12,050 11,644 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.38 6.92 12,155 11,556 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.32 6.28 12,200 11,575 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.41 6.57 12,177 11,535 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.41 7.15 12,165 11,651 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.53 7.78 12,099 11,771 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.33 7.80 11,942 11,635 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.45 6.96 12,193 11,578 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.40 6.53 12,313 11,678 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.29 7.00 12,088 11,793 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.45 7.33 12,018 11,845 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.49 7.99 12,075 11,678 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.28 6.43 12,151 11,631 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.47 7.46 12,057 11,511 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.44 6.73 12,120 11,697 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.38 6.63 12,109 11,761 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.42 6.39 12,174 11,454 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.42 6.43 12,177 11,522 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.38 5.63 12,292 11,638 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.35 6.99 12,106 11,723 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 0.38 7.45 12,046 11,561 1, 2, 3, 4 WY CAMPBELL WYODAC, LOWER CANYONTRAIN 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 12,015D.B. D.B. D.B. 

### State/Country County42 

### Coal seam43 % Sulf % A sh Btu/lb 

### Fuel source Amount received, dry 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 11,924D.B. D.B. D.B. 

### State/Country County42 

### Coal seam43 % Sulf % A sh Btu/lb 

### Fuel source Amount received, dry 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 11,761D.B. D.B. D.B. 

### State/Country County42 

### Coal seam43 % Sulf % A sh Btu/lb 

### Fuel source Amount received, dry 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 11,892D.B. D.B. D.B. 

### State/Country County42 

### Coal seam43 % Sulf % A sh Btu/lb 

### Fuel source Amount received, dry 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 12,048D.B. D.B. D.B. 

### State/Country County42 

### Coal seam43 % Sulf % A sh Btu/lb 

### Fuel source Amount received, dry 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 12,104D.B. D.B. D.B. 

### State/Country County42 

### Coal seam43 % Sulf % A sh Btu/lb 

### Fuel source Amount received, dry 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 12,061D.B. D.B. D.B. 

### State/Country County42 

### Coal seam43 % Sulf % A sh Btu/lb 

### Fuel source Amount received, dry 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 12,001D.B. D.B. D.B. 

### State/Country County42 

### Coal seam43 % Sulf % A sh Btu/lb 

### Fuel source Amount received, dry 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.

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

41Boiler 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).

42If known.

43If known.3For 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):

AntimonyArsenicBerylliumCadmiumChromiumCobalt Lead ManganeseSelenium 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 0.7WY 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 0.5WY 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 0.7WY 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 0.6WY 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 0.6WY 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 0.6WY 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 0.7WY 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 0.6WY 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 0.7WY 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 0.7WY 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 0.6WY Campbell & ConverseWyodak 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 0.6WY 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 0.6WY 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 0.9WY 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 0.7WY 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 0.6WY 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 0.5WY 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.

44To 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.

45Metal HAP includes compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, phosphorus, and selenium. Sample ID # State/Country County Coal SeamFuel Shipment Method Total amount of fuel represented byTotal

Sulfur, % Ash

Content, %Heating Value,

Btu/lb Mercury,

ppm Chlorine,

ppmFluorine,

ppm Nickel,

ppm Other Trace Metal HAP, ppm4Were the data provided in Part II, question 3 above, acquired pursuant to:

____ permit requirements ____ contractual obligations ____ standard operational procedures

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

5Analyses 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 6Name and address of laboratory performing analyses: Alabama Power Company, General Services Laboratory 744 Highway 87, GSC #8 Calera, AL 35040 7In 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

MoistureVolatilesAsh Fixed CarbonCarbonHydrogenNitrogenTotal SulfurOxygenBariumCopperMagnesiumSodiumVanadium Zinc Al2O3Fe2O3 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 4.290.0325 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 5.060.0130 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 4.120.0280 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 4.160.0263 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 0.1980.0738 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 3.490.0331 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 4.830.0136 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 3.830.0373 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 4.830.0104 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 3.530.0220 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 4.060.0425 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 4.000.0358 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 4.190.0190 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 Ash Mineralogy, % by wt Other Trace Metals, ppm8aWhat 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 1Unit 3 Particulate Emissions Test (May 9, 2005) Report 2Unit 4 Particulate Emissions Test (May 9, 2005) Report 3Unit 1 Particulate Emissions Test (May 2, 2006) Report 4Unit 2 Particulate Emissoins Test (May 4, 2006) Report 5Unit 3 Particulate Emissions Test (April 24, 2007) Report 6Unit 4 Particulate Emissions Test (April 24, 2007) Report 7Unit 1 Particulate Emissions Test (April 16, 2008) Report 8Unit 2 Particulate Emissions Test (April 16, 2008) Report 9Unit 3 Particulate Emissions Test (May 5, 2009) Report 10Unit 4 Particulate Emissions Test (May 5, 2009) Report 11Unit 1 Compliance Assurance Monitoring Test (May 3, 2006) Report 12Unit 2 Compliance Assurance Monitoring Test (May 5, 2006) Report 13Unit 4 Compliance Assurance Monitoring Test (April 24, 2007) Report 14Unit 1 B&W Dual Register Coal Burner Tuning (May 27 - June 4, 2009) Report 15Unit 2 B&W Wall Fired Coal Burner Tuning (May 11 - 18, 2009) Report 16Unit 3 B&W Wall Fired Coal Burner Tuning (April 22 - 29, 2009) Report 17Unit 4 B&W Wall Fired Coal Burner Tuning (April 1 - 13, 2009) Report 18Evaluation 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 19The 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)

8bPlease 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: Hg8cDo 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.

8dWere 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.

8eDo any of these test reports reflect testing during periods of startup, shutdown, and malfunction? Yes ____No _X

__If yes, please note which reports.

8fDid 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 - SO3injection (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 - SO3injection (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/AThe 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.

8gDo 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 - SO3injection (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 - SO3injection (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

### 9What 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. 10Are 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. 11Are 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.

46Where 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.

### 12For 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 5/9/2005See Attachment 1 N/A N/A N/A N/A N/A N/A 4 Report 2 5/9/2005See Attachment 2 N/A N/A N/A N/A N/A N/A 1 Report 3 5/2/2006See Attachment 3 N/A N/A N/A N/A N/A N/A 2 Report 4 5/4/2006See Attachment 4 N/A N/A N/A N/A N/A N/A 3 Report 5 4/24/2007See Attachment 5 N/A N/A N/A N/A N/A N/A 4 Report 6 4/24/2007See Attachment 6 N/A N/A N/A N/A N/A N/A 1 Report 7 4/16/2008See Attachment 7 N/A N/A N/A N/A N/A N/A 2 Report 8 4/16/2008See Attachment 8 N/A N/A N/A N/A N/A N/A 3 Report 9 5/5/2009See Attachment 9 N/A N/A N/A N/A N/A N/A 4 Report 10 5/5/2009See Attachment 10 N/A N/A N/A N/A N/A N/A 1 Report 11 5/3/2006See Attachment 11 N/A N/A N/A N/A N/A N/A 2 Report 12 5/5/2006See Attachment 12 N/A N/A N/A N/A N/A N/A 4 Report 13 4/24/2007See 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 1810/1-10/31/2006 N/A N/A N/A N/A See Attachments 18-21 N/A N/A 4 Report 1910/1-10/31/2008 N/A N/A See Attachment 25See Attachment 25See Attachments 22-24 N/A N/A
Note: "N/A" means not applicable.

47Provide 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.

48For 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).

49If 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. 50Metal 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.

51Please 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 5/9/20055/9/20055/9/2005 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 59.21054.66553.535 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 490.874490.874490.874 Avg. Sqr. Root Velocity PressureInches 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 3Average
Volume of Gas Sampled Standard Dry 58.183 53.16551.95754.435 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 2,831,2802,811,9772,747,3582,796,872 Feet Per Minute Stack Gas Flow Rate Standard Wet Cubic 1,947,9211,936,9531,890,1831,925,019 Feet Per Minute Stack Gas Flow Rate Standard Dry Cubic 1,759,9771,732,8991,691,0251,727,967 Feet Per Minute Stack Gas Flow Rate Pounds of Dry Air 131,822129,794126,658129,425 Per Minute Particulate Concentration Grains per Standard 0.00250.00200.00180.0021 Dry Cubic Foot Particulate Concentration Grains per Actual 0.00160.00120.00110.0013 Cubic Foot Particulate Emission Rate Pounds per Hour 37.9 29.7 25.8 31.1

Particulate Emission Rate Pounds per Million 0.00550.00430.00370.0045 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 5/9/20055/9/20055/9/2005 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 50.74848.12249.744 Volume of Water Collected Milliliters 124.00123.00116.00 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 490.874490.874490.874 Avg. Sqr. Root Velocity PressureInches Water 1.33801.38871.3915 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 3Average
Volume of Gas Sampled Standard Dry 51.47348.09349.72449.764 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 2,643,5332,747,0322,748,7392,713,101 Feet Per Minute Stack Gas Flow Rate Standard Wet Cubic 1,841,7111,910,0461,908,5171,886,758 Feet Per Minute Stack Gas Flow Rate Standard Dry Cubic 1,654,1441,704,8141,719,6821,692,880 Feet Per Minute Particulate Concentration Grains per Standard 0.00100.00200.00230.0018 Dry Cubic Foot Particulate Concentration Grains per Actual 0.00060.00130.00150.0011 Cubic Foot Particulate Emission Rate Pounds per Hour 14.0 29.9 34.2 26.1

Particulate Emission Rate Pounds per Million 0.00210.00450.00520.0039 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 5/2/20065/2/20065/2/2006 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 PressureDH@ 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 47.85048.300 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 490.874490.874490.874 Avg. Sqr. Root Velocity PressureInches 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 3Average
Volume of Gas Sampled Standard Dry 44.583 44.301 44.59844.494 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 2,694,6282,719,6722,748,1112,720,804 Feet Per Minute Stack Gas Flow Rate Standard Wet Cubic 1,900,2341,916,4021,922,3381,912,991 Feet Per Minute Stack Gas Flow Rate Standard Dry Cubic 1,710,6021,727,3631,719,1261,719,030 Feet Per Minute Stack Gas Flow Rate Pounds of Dry Air 128,124129,380128,763128,755 Per Minute Particulate Concentration Grains per Standard 0.0053 0.0052 0.0058 0.0054 Dry Cubic Foot Particulate Concentration Grains per Actual 0.00340.0033 0.00360.0034 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 5/4/20065/4/20065/4/2006 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 PressureDH@ Inches Water 1.74 1.74 1.74 Meter Correction Factor dimensionless 0.98660.98660.9866 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 45.82046.570 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 490.874490.874490.874 Avg. Sqr. Root Velocity PressureInches 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 3Average
Volume of Gas Sampled Standard Dry 44.551 41.96042.34942.953 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 2,641,7352,573,7032,644,9432,620,127 Feet Per Minute Stack Gas Flow Rate Standard Wet Cubic 1,864,3861,810,5311,854,6811,843,199 Feet Per Minute Stack Gas Flow Rate Standard Dry Cubic 1,634,6821,610,0491,636,4211,627,051 Feet Per Minute Stack Gas Flow Rate Pounds of Dry Air 122,438120,593122,568121,866 Per Minute Particulate Concentration Grains per Standard 0.0049 0.0041 0.0047 0.0046 Dry Cubic Foot Particulate Concentration Grains per Actual 0.00300.00260.0029 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 4/24/20074/24/20074/24/2007 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 PressureDH@ 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 490.874490.874490.874 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 3Average
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 2,841,2222,802,3562,864,1442,835,907 Feet Per Minute Stack Gas Flow Rate Standard Wet Cubic 1,892,4931,858,4061,895,4181,882,106 Feet Per Minute Stack Gas Flow Rate Standard Dry Cubic 1,650,0581,652,7771,689,0181,663,951 Feet Per Minute Stack Gas Flow Rate Pounds of Dry Air 123,589123,793126,507124,630 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 Factordimensionless 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 4/24/20074/24/20074/24/2007 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 PressureDH@ 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 490.874490.874490.874 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 3Average
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 2,725,1292,865,3712,900,8762,830,459 Feet Per Minute Stack Gas Flow Rate Standard Wet Cubic 1,881,4911,975,9521,997,6151,951,686 Feet Per Minute Stack Gas Flow Rate Standard Dry Cubic 1,699,4241,750,2321,786,4691,745,375 Feet Per Minute Stack Gas Flow Rate Pounds of Dry Air 127,287131,092133,807130,729 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 Factordimensionless 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 4/16/20084/16/20084/16/2008 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 490.874490.874490.874 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 3AVERAGE
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 2,613,2032,676,2422,717,0052,668,817 Feet Per Minute Stack Gas Flow Rate Standard Wet Cubic 1,853,3341,869,3551,882,2531,868,314 Feet Per Minute Stack Gas Flow Rate Standard Dry Cubic 1,671,6181,675,0391,679,5361,675,398 Feet Per Minute Stack Gas Flow Rate Pounds of Dry Air 125,204125,460125,797125,487 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 Checkdimensionless 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 4/16/20084/16/20084/16/2008 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 490.874490.874490.874 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 3AVERAGE
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 2,623,1082,703,1272,665,9922,664,076 Feet Per Minute Stack Gas Flow Rate Standard Wet Cubic 1,806,1961,834,9841,816,3891,819,190 Feet Per Minute Stack Gas Flow Rate Standard Dry Cubic 1,605,6441,604,0801,618,1781,609,301 Feet Per Minute Stack Gas Flow Rate Pounds of Dry Air 120,263120,146121,202120,537 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 Checkdimensionless 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 5/5/20095/5/20095/5/2009 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 58.56855.325 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 490.874490.874490.874 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 3AVERAGE
Volume of Gas Sampled Standard Dry 51.55548.62651.149 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 2,750,3352,764,9262,767,6482,760,969 Feet Per Minute Stack Gas Flow Rate Standard Wet Cubic 1,820,2781,823,0541,819,7181,821,017 Feet Per Minute Stack Gas Flow Rate Standard Dry Cubic 1,617,9071,600,0231,609,4081,609,113 Feet Per Minute Stack Gas Flow Rate Pounds of Dry Air 121,181119,842120,545120,523 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 Checkdimensionless 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 5/5/20095/5/20095/5/2009 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 59.25655.029 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 490.874490.874490.874 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 3AVERAGE
Volume of Gas Sampled Standard Dry 52.033 52.27848.217 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 2,703,4182,717,6072,708,0992,709,708 Feet Per Minute Stack Gas Flow Rate Standard Wet Cubic 1,825,4011,833,8041,825,2411,828,148 Feet Per Minute Stack Gas Flow Rate Standard Dry Cubic 1,604,7461,619,4591,614,0981,612,768 Feet Per Minute Stack Gas Flow Rate Pounds of Dry Air 120,195121,297120,896120,796 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 Checkdimensionless 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 5/3/20065/3/20065/3/2006 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 PressureDH@ 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 46.20049.28048.250 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 490.874490.874490.874 Avg. Sqr. Root Velocity PressureInches 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 3Average
Volume of Gas Sampled Standard Dry 43.56045.73143.91944.403 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 2,734,5782,773,7372,755,9232,754,746 Feet Per Minute Stack Gas Flow Rate Standard Wet Cubic 1,920,7061,940,2481,927,1481,929,367 Feet Per Minute Stack Gas Flow Rate Standard Dry Cubic 1,736,7871,726,9461,709,1671,724,300 Feet Per Minute Stack Gas Flow Rate Pounds of Dry Air 130,085129,348128,017129,150 Per Minute Particulate Concentration Grains per Standard 0.01380.01260.01400.0135 Dry Cubic Foot Particulate Concentration Grains per Actual 0.00880.00780.00870.0084 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 5/5/20065/5/20065/5/2006 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 PressureDH@ 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 44.85046.95047.350 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 490.874490.874490.874 Avg. Sqr. Root Velocity PressureInches 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 3Average
Volume of Gas Sampled Standard Dry 41.73642.55442.75342.348 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 2,622,6702,651,8522,644,3792,639,634 Feet Per Minute Stack Gas Flow Rate Standard Wet Cubic 1,832,9761,853,5781,852,3561,846,304 Feet Per Minute Stack Gas Flow Rate Standard Dry Cubic 1,614,4771,654,1441,629,8501,632,824 Feet Per Minute Stack Gas Flow Rate Pounds of Dry Air 120,924123,895122,076122,298 Per Minute Particulate Concentration Grains per Standard 0.01380.01350.01530.0142 Dry Cubic Foot Particulate Concentration Grains per Actual 0.00850.00840.00950.0088 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 4/25/20074/25/20074/25/2007 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 PressureDH@ 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 490.874490.874490.874 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 3Average
Volume of Gas Sampled Standard Dry 52.738 38.556 38.65443.316 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 2,866,2372,905,3942,892,8082,888,146 Feet Per Minute Stack Gas Flow Rate Standard Wet Cubic 1,971,1601,992,6631,974,3801,979,401 Feet Per Minute Stack Gas Flow Rate Standard Dry Cubic 1,694,4081,752,9761,769,6561,739,014 Feet Per Minute Stack Gas Flow Rate Pounds of Dry Air 126,911131,298132,547130,252 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 Factordimensionless 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 5/27/20096/4/2009 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 5/11/20095/18/2009 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 4/22/20094/29/2009 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 4/1/20094/13/2009 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 HgElem. 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/dNm3Total Hg

(mg/dNm3Total 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) DateStart TimeEnd Time Between SCEM and Sorbent Tubes Condition*Date in

2006Start TimeEnd 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 # % Hg0Oxidized Across SCR = [1 – (Hg0SCR,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 & TimeAvg. 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 HgElem. 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/dNm3at 3% O2

Comparison of Sorbent Tube and SCEM Results

Br Injection Rate Ontario HydroSorbent

Tubes SCEM % RD
(ppm in coal) Total Hg (mg/dNm3Total Hg

(mg/dNm3Total 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 -44InjectionRate (ppmBr incoal)*Date in

2008Start TimeEnd Time Ontario Hydro Results# % RD

ACI? DateStart TimeEnd 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 InletSCR OutletStack Spring 2008 Bypassed n/a n/a 35 – 57% 2006 In Service / NH318 – 28%13 – 56%57 – 66% Oct-08 In Service / NH3 -- -- 29 – 50% Spring 2008In 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 10/12/2008On (with NH3) 3.5 0.1 97% 10/13/2008 0:00 – 12:18

10/13/08 12:18 – 24:00On (with NH3) 4.9 0.1 98% 10/14/2008On (with NH3) 6.5 0.2 97% 10/15/2008On (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. HgSCEM 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. % Oxid. Test Periods SCR

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