Process Information

1 Name of legal owner of facility:

The Empire District Electric Company

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

3 Address of

____ legal owner or ____ operator:

602 S. Joplin Ave

Joplin, MO 64801

4a Plant Name (as reported on U.S. DOE/EIA Form‐860 (2007), "Annual Electric Generator Report", schedule 2, line 1, page 37, questio

OR Plant Name (as reported on U.S. DOE/EIA Form EIA‐923 (2008), "Power Plant Operations Report", schedule 2, page 1, question 

Asbury

4b EIA Plant Code (as reported on U.S. DOE/EIA Form‐860 (2007), schedule 2, line 1, page 37, question 2) OR Plant ID (as reported on U

DOE/EIA Form EIA‐923 (2008), schedule 2, page 1, question 2):

2076

5 Complete street address of facility (physical location):

21133 Uphill Lane

Asbury, MO 64832

6 Provide mailing address if different:

P.O. Box 127

Joplin, MO 64802

7 Name and title of contact(s) able to answer technical questions about the completed survey:

Rebecca Heffren, Environmental Coordinator

8 Contact(s) telephone number(s):

417.625.6152 (Office)

and e‐mail address(es):

rheffren@empiredistrict.com

9 Is this facility considered to be owned or operated by a small entity as defined by the Regulatory Flexibility Act?

____

Yes X No

____

Don't know

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

__

X

__

coal

__X__ oil (including pet coke) ____ natural gas

__

X

__

other (specify in question 14 below)
11 Which of the following fossil fuel or other material(s) are permitted1 to be fired in any steam generating unit at this facility?

___X_ coal __X__ oil (including pet coke) ____ natural gas___X_ other (specify in question 14 below)

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

during the previous 12 months prior to the receipt of this ICR:2,3____ lignite (% _____) __X__ subbituminous (% 88.7 mass, 85.1% Btu ___)__

X

__

bituminous (% 9.2 mass, 11.5%Btu ___ ____ 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 ___________________________________________)

__X__ petroleum coke (1.6%mass, 2.5% Btu____)*

* Petroleum Coke is not listed in current permit, however a letter from the State of Missouri dated 8/21/2003 allows the use of pet

Pet Coke is included in the description of the Asbury unit in the permit draft language of the pending State of Missouri permit.

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

__X__ distillate (% 100_____)____

other (specify __________) (% _____)

____

residual or bunker C (% _____)

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

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

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

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

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

We are not permitted to burn non‐fossil fuels or other materials. We are allowed to burn up to 2% TDF annually.

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

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

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

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

Other Material

TIRE‐DERIVED FUEL

Quantity/year

0.5% mass

Permitted to burn

20,000 TONS annually

Actually burn

3776.35 TONS (2009)
material?

____

Yes

__x__ No

Explain:The decision would be evaluated based on any changes to the the regulation at that time. TDF is currently regulated.

1 "Permitted" in this context, refers to the fuels that the permit anticipates will be combusted at the facility.2 If the boiler is fired by a blend of coal ranks, please specify percentage (separately, on both a mass and on a Btu basis) of each coal rank(e.g., 85% subbituminuous/15% bituminous).3 In reference to footnote 1, if necessary, a notation can be added to a utilized fuel type that is not listed in the operating permit noting

the reason the fuel type was combusted (e.g., "the permitting agency allowed this fuel to be combusted for special testing and research

purposes").4 If the boiler is fired by a blend of fuel oil ranks, please specify percentage (separately, on both a volume and on a Btu basis) of eachfuel oil rank (e.g., 85% residual oil/15% distillate).5 If necessary, a notation can be added to a utilized fuel type that is not listed in the operating permit noting the reason the fuel wascombusted (e.g., "the permitting agency allowed this fuel to be combusted for special testing and research purposes").
15 Identification (or designation) of all coal‐ and oil‐fired steam generating units (boilers) (as defined by Clean Air Act section 112(a)(8))

located at this facility.

Boiler ID6

Original design fuel (i

.e

.,

coal

rank or type

of oil)

Design heat input, (MMBtu/hr)7

Present

maximum heat

input, (MMBtu/hr)8 MWe Gross capacity summer MWe Net Capacity summer Original design gross efficiency (%, HHV) Present operating gross efficiency (%, HHV)

Design

steam

pressure (psig)

Operating steam

pressure

(psig)

Design

steam temperature (oF)

Operating steam temperature (oF) De

tempera

1 *BITUMINOUS 2730

MMBtu/hr

2730 **224.5 **207 87.10% ***86.93% 2450 2215 1005 1005 

DeletedGenerator

Information

*Unit is currently not combusting original design fuel. However, no design modifications have been made to accommodate state approv**Based on 2009 Capability Test, will vary with operating conditions.

***Present operating gross electricity calculated on similar fuel. We have not performed any efficiency testing.

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

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

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

7 Per fuel burned in the boiler. Report this based on higher heating value (HHV).8 Per fuel burned in the boiler. Report this based on higher heating value (HHV).9 Please indicate if more than one steam reheat cycle is utilized, and, if so, please provide information for both.10 Please indicate if more than one steam reheat cycle is utilized, and, if so, please provide information for both.11 Indicate the fuels utilized for the indicated boiler, and percentages, as indicated in questions 11 ‐ 13.12 The "hours/year operated" would be the average of the actual number of hours the unit operated in 1 year based on the last 3 years of operation.13 This can be treated as CBI and can be submitted through the proper CBI procedure if desired.
steam

reheat F)10

Fuel11

Hours/year

operated12

Average

annual (net)capacity

factor for the

past 3 years

Applicable NSPS Estimated year of retirement13

1005 SUB 88.7%mass

85.1% Btu

7139 72.78 Grandfathered Unknown

BIT 9.2%mass11.5% BtuDFO <1%PC 1.6%mass2.5%BtuTDF 0.5%mass

s.
16 For each boiler noted in Part I, question 15, provide the following information for each current emission control device installe

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

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

Boiler ID14 Type15 NOx control16 SO2 control17 PM control18 

1 Cyclone 2) SCR 2/2008 4)cold‐side ESP 

Catalyst‐honeycomb ceramic original install 6/1970

Reductant ‐ AnhydrousAmmonia

additional cold‐side ESP

install 6/1978

1) OFA‐5/1999

additional OFA install 2003

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

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

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

15 Examples: tangential‐fired; cyclone; wall‐fired; circulating fluidized bed (CFB)16 Examples: low‐NOx burners; selective catalytic reduction (SCR); selective non‐catalytic reduction (SNCR); over‐fire air (OFA). Include

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

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

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

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

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

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

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

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

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

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

new installation. Also include any pollutants controlled by this technology (e.g., control technology [pollutant controlled]).
NA

17 For each boiler noted in Part I, question 15, provide the company (prime vendor) name and company contact information for eac

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

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

etc.).

Name Telephone Address

NA NA NA NA NA

Company (vendor) contact information Boiler ID21 Company (vendor) name

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

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

demonstrate the technology's HAP removal performance.

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

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

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

18 For the control technologies identified in Part I, question 17, provide the date of actual start‐up of the demonstration (if the control

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

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

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

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 start‐

up date

Demonstration

activity projected

start‐up date

Demonstration

activity end‐date or

projected end‐date

Type of control (e.g.,

sorbent and type;

chemical additive23)

Desired HAP emission

reduction (%) or

emission rate

C

NA NA NA NA NA NA NA

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

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

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

23 If additive is used, please indicate injection point.
NA

19 For each boiler noted in Part I, question 15, provide the company (prime vendor) name and company contact information for eac

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

for the purpose of provide a non‐demonstration, full‐scale operating system.

Name Telephone Address

NA NA NA NA NA

Company (vendor) contact information Boiler ID24 Company (vendor) name

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

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

OR Generator ID (as reported on U.S. DOE/EIA Form EIA‐923 (2008), "Power Plant Operations Report," schedule 5, part A, page 8).
20 For the control technologies identified in Part I, question 19, provide the date of actual start‐up (if the control is currently operating), 

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

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

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

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

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

"inlet" and "outlet" are).

Boiler ID25 Actual start‐up date

Expected or

projected start‐up

date

Type of control (e.g.,

sorbent and type;

chemical additive)26

Guaranteed HAP

emission reduction

(%) or emission rate

Sorbent or additive

feed rate on which

guarantee is based

C

w

NA NA NA NA NA NA NA

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

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

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

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

PM28 PM10(29) PM2.5(30) SO2 HCl and/or HF HCN Metal HAP31 Hg CO 

1 *491.7lb/MMBTu of HI

Mo State Operating Permit

12lb/MMBtu of

HI/AVERAGED FOR

CONSECUTIVE 3 hr. TIME

PERIOD Mo State

*This number has been changed in our pending Missouri State operating permit to 0.23 lb/MMBTu**In abeyance as long as CAIR is in place.

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

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

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

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

Also include the compliance test method utilized.

29 List the compliance test method utilized.30 List the compliance test method utilized.31 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, phosphorus, and selenium;

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

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

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

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

1

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

Please elaborate.

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

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

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

33 If the boiler has separate guaranteed emission rate for filterable and condensable PM, respectively, please indicate those separate emission rates.34 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, cobalt, lead, manganese, nickel, phosphorus, and selenium;

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

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

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

PM36 PM10 PM2.5 SO2

1 Required ESP operation when emission unit is in operation Install, calibrate, maintain, and operate a CEMS for 

SOx.

Monitor 4 parameters to indicate ESP performance Daily calibration checks will be conducted with on t

with known concentrations of SOx gas.

Activate timely corrective action during excursions Conduct an annual RATA.

Alarms to indicate failures are monitored. Record the daily monitoring system calibration che

on the CEMS

Continuous inspection of operations included in operation

and maintenance plan

Report quarterly any exceedances to MODNR

Appropriate corrective actions taken on the occurrence of an

abnormal condition

Semi‐annual compliance report ‐ include the correc

operation of the daily calibration checks, or any tha

done. Include RATA tests done, and all test results w

report

Appropriate spare parts inventory kept Quarterly XML EDR submittal

Records of throughput, emission factors, and actual emissions

of PM emitted into the atmosphere from this unit are kept. Compliance with Federal and State of Missouri perm

requirements

Compliance with State of Missouri permit requirements.

Hold SO2 allowances, retire them when used.

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

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

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

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

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

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

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

Required monitoring, recordkeeping, and reporting requirements for each pollutant for w

Boiler ID35
Metal

HAP37 Hg CO

Other

organics

(specify)

ion limit
25 For the control technologies identified in Part I, questions 17 and 19, provide the cost information requested.38

NAFacility Name/Unit No.:

Retrofit to existing boiler?Installation on a new boiler?

Total Capital Investment:  ‐ $Total Operating Costs: $ ‐ (Include base year for operating costs [e.g., 2006]

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

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

Ultra‐low sulfur oil is used.

38 This can be treated as CBI and can be submitted through the proper CBI procedure if desired.
Fuel Analysis39

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

Asbury

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

2076

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

*FuelType

State/Country (all

coal is from the

United States)

County42 Coal seam43

SUB 46,081 1 WY CAMPBELL UNKNOWN RRSUB 21,879 1 WY CAMPBELL UNKNOWN RRBIT 1,817 1 KS BOURBON UNKNOWN TRSUB 44,154 1 WY CAMPBELL UNKNOWN RR

SUB 11,045 1 WY CAMPBELL UNKNOWN RRBIT 4,441 1 KS BOURBON UNKNOWN TRSUB 7,050 1 WY CAMPBELL UNKNOWN RRPC 1,429 1 TRBIT 5,259 1 KS BOURBON UNKNOWN TRPC 1,166 1 TRBIT 7,634 1 KS BOURBON UNKNOWN TRSUB 60,302 1 WY CAMPBELL UNKNOWN RRSUB 12,399 1 WY CAMPBELL UNKNOWN RRBIT 5,317 1 KS BOURBON UNKNOWN TRPC 904 1 TRBIT 1,343 1 KS CRAWFORD UNKNOWN TRSUB 45,649 1 WY CAMPBELL UNKNOWN RRSUB 22,927 1 WY CAMPBELL UNKNOWN RRPC 1,222 1 TRBIT 6,896 1 KS BOURBON UNKNOWN TRSUB 60,178 1 WY CAMPBELL UNKNOWN RRSUB 24,923 1 WY CAMPBELL UNKNOWN RRPC 1,174 1 TRBIT 7,313 1 KS BOURBON UNKNOWN TRSUB 59,715 1 WY CAMPBELL UNKNOWN RRSUB 22,613 1 WY CAMPBELL UNKNOWN RRPC 1,053 1 TRBIT 6,761 1 KS BOURBON UNKNOWN TRSUB 59,504 1 WY CAMPBELL UNKNOWN RRSUB 21,769 1 WY CAMPBELL UNKNOWN RRPC 929 1 TRBIT 6,337 1 KS BOURBON UNKNOWN TRSUB 31,965 1 WY CAMPBELL UNKNOWN RRSUB 21,263 1 WY CAMPBELL UNKNOWN RRBIT 6,265 1 KS BOURBON UNKNOWN TRBIT 1,413 1 KS CRAWFORD UNKNOWN TRPC 1,503 1 TR

Fuel source

ID # of

boiler(s)

firing

fuel41

Fuel

shipment

method

**Amount

received,

dry basis,

short tons

or gallons 40
SUB 10,660 1 WY CAMPBELL UNKNOWN RR

SUB 42,508 1 WY CAMPBELL UNKNOWN RRBIT 6,013 1 KS BOURBON UNKNOWN TRPC 1,224 1 TRSUB 31,854 1 WY CAMPBELL UNKNOWN RR

SUB 20,974 1 WY CAMPBELL UNKNOWN RRPC 1,316 1 TRBIT 3,888 1 KS BOURBON UNKNOWN TR

762,029

DFO 0 1DFO 21,588 1 TRDFO 22,554 1 TRDFO 22,344 1 TRDFO 21,714 1 TRDFO 22,596 1 TR

110,796

*SUB=Sub‐bituminous, BIT=bituminous, PC= Pet Coke, DFO=Distillate Fuel Oil

**The fuel analysis received from vendor is as received wet‐basis. The values submitted in this ICR are consistent with the values reported in the EIA 923.

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

amount fired.

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

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

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

42 If known.43 If known.
3 For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information44, as

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

FuelType

Sample ID#

*Total sulfur, % *Ash content, % Heating value, Btu/lb

**Heating Value

received,

MMBtu/ton or

barrel

***Moisture

Content, % Mercury, ppm Chloride, ppm Fluorine, ppm Nickel, ppm

Other trace

metal HAP,

ppm

45

Not Provided byVendor

Not Provided byVendor

Not Provided by

Vendor

Not Provided by

Vendor

Not Provided by

Vendor

Not Provided

by Vendor

SUB Jan 46,081 0.29 5.6 17.67 26.92%SUB 21,879 0.23 4.3 17.3 28.05%BIT 1,817 3.78 14.3 21.64 10.39%SUB Feb 44,154 0.23 4.3 17.34 26.97%SUB 11,045 4.01 12.1 23.54 28.10%BIT 4,441 0.26 4.7 17.85 7.95%SUB March 7,050 0.23 4.6 17.8 26.77%PC 1,429 4.78 0.2 28.85 5.95%BIT 5,259 4.28 12.4 23.1 9.01%PC April 1,166 4.58 0.2 28.5 7.44%BIT 7,634 3.92 12.3 23.29 17.34%SUB May 60,302 0.29 5.2 17.75 26.85%SUB 12,399 0.22 5 17.28 27.90%BIT 5,317 3.81 13.5 23.33 7.43%PC 904 4.84 0.2 28.65 6.27%BIT 1,343 3.46 13.9 25.18 N/ASUB June 45,649 0.33 5.8 17.53 26.99%SUB 22,927 0.19 4.7 17.24 28.25%PC 1,222 4.3 0.3 29.33 4.49%BIT 6,896 3.68 13.8 23.04 7.83%SUB July 60,178 0.3 5.1 17.65 27.02%SUB 24,923 0.21 4.5 17.23 28.21%PC 1,174 4.73 0.2 29.66 3.40%BIT 7,313 3.64 14.5 22.78 8.08%SUB August 59,715 0.28 5.1 17.14 26.84%SUB 22,613 0.2 5.3 17.73 29.71%PC 1,053 4.98 0.2 29.54 3.40%BIT 6,761 4.21 14.7 23.26 7.24%SUB Sept 59,504 0.27 5.3 17.74 26.96%SUB 21,769 0.2 4.8 17.16 28.45%PC 929 4.84 0.2 29.35 4.17%BIT 6,337 4.24 12 24.32 6.49%SUB Oct 31,965 0.28 5.5 17.67 26.73%SUB 21,263 0.19 4.8 17.36 27.70%BIT 6,265 3.7 14.2 23 8.17%BIT 1,413 3.77 12.9 24.76 4.27%PC 1,503 4.84 0.2 29.12 4.62%SUB Nov 10,660 0.31 5.2 17.76 26.68%SUB 42,508 0.22 4.6 17.18 28.35%BIT 6,013 3.63 15.2 22.84 8.22%PC 1,224 5.06 0.2 28.66 7.08%SUB Dec 31,854 0.32 5.1 17.55 27.85%SUB 20,974 0.21 5.1 17 28.35%PC 1,316 5.05 0.2 29.11 4.91%BIT 3,888 3.91 14.9 23.11 7.84%

762,029

DFO MAR 21,588 N/A N/A 5.855 N/ADFO MAY 22,554 N/A N/A 5.855 N/ADFO AUG 22,344 N/A N/A 5.855 N/ADFO OCT 21,714 N/A N/A 5.8 N/ADFO NOV 22,596 0.1 N/A 5.855 N/A

110,796

*The fuel analysis received from vendor is as received wet‐basis. The values submitted in this ICR are consistent with the values reported in the EIA 923.

**The heating value received MMBtu/ton column is added by Empire District Electric Company. The heating values are provided by the vendor as MMBtu/ton wet‐basis, not Btu/lb dry‐basis.

***The moisture percent column is added by Empire District Electric Company

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

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

analysis requirement can be bypassed by the respondent.

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

*Total amount of

fuel represented

by sample, tons

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

____ permit requirements__x__ contractual obligations__x__ standard operational procedures____

other (please specify ______________________________)

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

_X___ Fuel supplier (name and address)

Arch Coal Sales Company, Inc; 1 City Place Drive, Suite 300; St. Louis, MO 63141

Peabody COALSALES, LLC; 701 Market St.; St. Louis, MO 63101Phoenix Coal Sales, Inc; PO Box 498; Vinita, OK 74301International Chemical Company; Southbridge Office Park; 1887 East 71st Street; Tulsa, OK 74136Oxbow Carbon & Minerals, LLC; 1601 Forum Place, Suite 1400; West Palm Beach, FL 33401

____

Other (name and address)

6 Name and address of laboratory performing analyses:

Analysis is directed by fuel/coal suppliers. We don't have the laboratory information.

7 In addition to the analyses required in Part II, question 3 above, for samples for which analyses of chlorine and/or any of 

conducted, please provide copies of any analyses conducted over the preceding 12 calendar months for (a) complete pro

analyses, (b) additional trace metals, and (c) the mineralogy of the ash that are readily available for the oil(s) or coal(s) lis

2 above. The Agency is requesting these data only as they may already be available; no additional sampling or analyses a

these data.Copies of additional lab analysis are attached.
Insert Additional Analysis

PDF Files attached "SGS Mineral Samples"
8a What emission test report(s), parametric monitoring data, and other data or monitoring are available for the boilers noted in Part I,

question 15, for tests conducted since January 1, 2005. Please consider reports prepared for all testing and monitoring programs, fo

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 d

at this time; however we may request actual copies in the future.) Use additional pages as necessary.

SCR Performance Guarantee Testing, February 2008

8b Please indicate the date(s) and types (e.g., stack, fuel, parametric, etc.) of the test(s) and the constituents (including criteria and haza

air pollutants) sampled for:

Date: February, 2008 Type: SCR Testing Constituents: NOx &SO2/SO3 

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

Yes

____

No _x___ If yes, please note which reports and provide a detailed description of the location of the emissions sampling p

8d Were any of these test reports conducted when use of other material(s) or non‐fossil fuels were fired in the boiler?

Yes _x___ No ____ If yes, please note which reports and identify the other material(s) or non‐fossil fuels used.

TDF may have been included in the fuel mix during the SCR testing.

8e Do any of these test reports reflect testing during periods of startup, shutdown, and malfunction?

Yes

____

No

__

x

__

If yes, please note which reports.

8f Did the unit's control configuration differ from that shown in Part I, question 16, at the time of these test results?

Yes

____

No __x__ If yes, please list the unit's complete control configuration at time of testing in a similar format to Part I, quest

8g Do any of these test reports reflect testing at a location before a post combustion SO2 emission control device (e.g., FGD, SDA, Dry Sc

Yes

____

No __X__ If yes, please note which reports and, in addition to the detailed description of the location of the sampling po

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

percentage of total scrubber flue gas flow). Note by diagram where sampling ports were located in relation to the bypass ductwork.
9 What type of deviation reporting is required for violations of permit requirements?

Report to State of Missouri :

Quarterly & Semi Annual Excess Emissions

Monitor Down Time

10 Are deviation reports available for malfunctions or other periods of noncompliance with permit terms and conditions?

Yes

__

x

__

No ___ If yes, please note which reports.

If malfunctions or other periods of noncompliance occur, the State of Missouri is notified according to permit terms and conditions o

Opacity Monitor DowntimeOpacity Excess EmissionsQuarterly, Semi‐Annual Compliance Report

SO2 Exceedances

11 Are continuous emissions monitoring system (CEMS) data available (e.g., mercury, continuous opacity monitoring systems) that are n

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 a

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

Non‐ quality assured CEMS mercury data is available for part of 2009. Issues with the analyzers have produced limited data.

The data is not required by State or Federal regulation, therefore the limited amount of raw data has not been subject

to all quality procedures.

46 Where units are monitored by CEMs (either following CAMR, State, or NIST QA/QC procedures), and where data are available, EPA requests

that this CEM data by submitted by the respondent. The respondent should also mark the periods of start up, shut down and malfunction events 
12 For each boiler noted in Part I, question 15, provide the following information:

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

1

February 27‐29,

2008 NA

See Part II,question 12

Additional for

testinginformation NA NA NA NA 

47 Provide emission test data for all tests conducted since January 1, 2005. Please indicate test data acquired both before and after

any control device. Use additional pages as necessary. EPA may, at some future date, request a copy of one or more emission test reports.

Data generated to fulfill both Federal and State requirements must be provided. Note that data generated pursuant to CAA Title V

must be maintained and available for 5 years. Also include averaging times and measurement units for all pollutants.

48 For each emissions test run the respondent should provide the following process information: Unit Load (MW), Net generation during run (MWh net),

Flue gas moisture content (%), Flue gas flow rate (dscfm or Nm3/hr), Flue gas oxygen content (%, dry), Flue gas carbon dioxide content (%, dry), Flue gas

temperature at sampling point (oF), Flue gas pressure at sampling point (atm), Standard temperature (oF), Standard pressure (atm).

49 If emission testing recorded the emissions of filterable and condensable PM, separately, please include those separate emission results.

Also, please include separate emission results for total PM, PM10, and PM2.5.

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

indicate emission level for all metal HAP for which an emission test has been conducted.

51 Please provide separate results for total Hg, elemental Hg, oxidized Hg, and particulate Hg, as available. If the emissions testing recorded

the amount of unburned carbon in fly ash (as reflected by the "Loss of Ignition" [L.O.I]) at the time of any Hg testing, please include these data.

Boiler ID

Emissions test results (indicate format of emission data)47,48
Part II, question 12 attachment for testing

This performance testing was conducted for the purpose of meeting contractual obligations.

Boiler ID: 1

Pollutanttested: NOX & SO2/SO3

Processinformation Run 1 Run 2 Run 3

Unit Load (MW) 205 205 205Net Generation

during run (MWhnet) NA NA NA

Flue Gas Moisture

Content (%) 12.15% 11.13% 11.94%

Flue gas flow rate

(dscfm or Nm3/hr) 447373 447373 447373

Flue gas oxygencontent (%, dry) 2.10% 2.10% 2.10%

Flue gas carbon

dioxide content (%,

dry) 17.00% 17.00% 17.00%

Flue gastemperature at

sampling point (oF) 715oF 715oF 715oF

Flue gas pressure

at sampling point

(atm) 30.71 30.93 30.93

*Standardtemperature (oF) 62oF 61oF 49oF*Standard pressure(atm) 29.2 29.21 29.27NOx Removal%

uncorrected for O2

or CO2 90.5 92.5 92.1

SO2 SO3 OxidationRate 0.19 0.33 0.43Ammonia Slip

ppmvd corrected

to 3% O2 1.1 0.67 0.94

*Average ambient

temperature and

pressure duringtest runs wereused.