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

__

x

__ legal owner or ____ operator:

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

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

Riverton

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 re

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

Plant Code 1239

5 Complete street address of facility (physical location):

6 Provide mailing address if different:

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

Jeff Burkett, Environmental Coordinator

8 Contact(s) telephone number(s):

417‐625‐4236

and e‐mail address(es):

jburkett@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

602 S.Joplin Ave.

Joplin, Missouri 64801

7240 SE Highway 66

Riverton, Kansas 66770

PO Box 127602 S. Joplin Ave.

Joplin, Missouri 64802
10 Which of the following fossil fuels or other material(s) are fired in any steam generating unit at this facility?

___x_ coal ___x_ oil (including pet coke) __x__ natural gas____

other (specify in question 14 below)

Note: natural gas used as a co‐firing fuel.

11 Which of the following fossil fuel or other material(s) are permitted1 to be fired in any steam generating unit at this fac

_

x

___

coal

__

X

__

oil (including pet coke) __x__ natural gas

____

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 

during the previous 12 months prior to the receipt of this ICR:2,3

____ lignite (% _____) __x__ subbituminous ( tonnage basis 82% ; BTU basis74% )____

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 p

that recycle materials) (%_____)(please specify the type or form of synfuel used ___________________________________________)

_

x

__ petroleum coke (tonnage basis 18%; BTU basis 26%)

Note: The Kansas Dept. of Health & Environment made a determination allowing the combustion of pet coke.

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

____

distillate (% _____)

____

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 n

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

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

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

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

Other Material Actually Permitted to burn burn Quantity/year
14b If "other" was checked in questions 10 or 11 above indicating that any non‐fossil fuel or other material (including, but n

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

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

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

material?

____

Yes

____

No

Explain:

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 

(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 not

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

purposes").

4 If the boiler is fired by a blend of fuel oil ranks, please specify percentage (separately, on both a volume and on a Btu basis) of each

fuel oil rank (e.g., 85% residual oil/15% distillate).

5 If necessary, a notation can be added to a utilized fuel type that is not listed in the operating permit noting the reason the fuel was

combusted (e.g., "the permitting agency allowed this fuel to be combusted for special testing and research purposes").
15 Identification (or designation) of all coal‐ and oil‐fired steam generating units (boilers) (as defined by Clean Air Act section 112(a)(8))

located at this facility.

Boiler

ID

6

Original

design

fuel

(i.

e.,

coal

rank

or

type

of

oil)

Design

heat

input,

(MMBtu/hr)7

Present

maximum

heat

input,

(MMBtu/hr)8

MWe

Gross

capacity

summer

MWe

Net

Capacity

summer

Original

design

gross

efficiency

(%,

HHV)

Present

operating

gross

efficiency

(%,

HHV)

Design

steam

pressure

(psig)

Operating

steam

pressure

(psig)

Design

steam

temperature

(oF)

Operating

steam

temperature

(oF)

Design

steam

reheat

temperature

(oF)9

Operating

steam

reheat

temperature

(oF)

10

Fuel

11

Hours/year

operated

12

39 *bituminous

coal, oil, andnatural gas

387MMBtu/hr

**426MMBtu/hr

40 MW 38 MW ***87.72 % ****87.72% 875 (psig) 900 (psig) 900 900 n/a n/a Sub‐bituminous

(tonnage basis 81% ;

BTU basis 73 %).

Petroleum coke

(tonnage basis 19%;

BTU basis 27 %)

8133.9 

40 *bituminous

coal, oil, andnatural gas

567MMBtu/hr

**600MMBtu/hr

58 MW 54 MW ***87.4%  87.4% 925 (psig) 900 (psig) 900 900 n/a n/a Sub‐bituminous

(tonnage basis 82% ;

BTU basis 74%).

Petroleum coke

(tonnage basis 18%;

BTU basis 26%)

7879.81 

** Based on normal operating conditions while combusting coal (unit has ability to co‐fire with natural gas)

***This value is the boiler efficiency only.

**** 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.

* Unit is currently not combusting original design fuel. However, no design modifications have been made to accommodate state approved fuel changes.
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 

39 Dry bottom, wall‐fired n/a n/a cold side ESP (1976)

40 Dry bottom, tangential‐fired Burner tip upgrade‐June 2006 n/a cold side ESP (1976)

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]).
17 For each boiler noted in Part I, question 15, provide the company (prime vendor) name and company contact informati

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

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

etc.).

Name Telephone Addr

39 n/a n/a n/a n/a40 n/a n/a n/a n/a

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 t

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 5

[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 1

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

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

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 de

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

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

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

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 emissi

reduction (%) or

emission rate

39 n/a n/a n/a n/a n/a 40 n/a n/a n/a n/a n/a 

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

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

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

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

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

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

Name Telephone Address

39 n/a n/a n/a n/a40 n/a n/a n/a n/a

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

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

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

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

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

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

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

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

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

"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 addit

feed rate on wh

guarantee is ba

39 n/a n/a n/a n/a n/a 40 n/a n/a n/a n/a n/a 

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 M

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 

39 0.204 lb/MMBtu (plant‐wide 3‐

hr rolling avg.‐state operating

permit)

n/a n/a 3.0 lb/MMBtu (3hr rolling avg.‐

state operating permit)

n/a n/a n/a n/a n/a 

40 0.204 lb/MMBtu (plant‐wide 3‐

hr rolling avg.‐ state operatingpermit)

n/a n/a 3.0 lb/MMBtu (3hr rolling avg‐ 

state operating permit)

n/a n/a n/a n/a n/a 

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 

39 n/a n/a n/a n/a n/a n/a n/a n/a n/a 40 n/a n/a n/a n/a n/a n/a n/a n/a n/a 

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 lim

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

PM36 PM10 PM2.5 SO2

HCl

and/or

HF

HCN

39 Monitoring: opacity as indicator of PM (CAM), operational

parameters of ESP, performance testing each pemit cycle,

Method 9.Recordkeeping: document all excursions.

Reporting: report excursions semi‐annually, report

exceedances the next business day following the discovery

of the release, with written follow up within 5 days of

discovery.

Monitoring: Using CEMS as per 40 CFR Part 75.

Recordkeeping: Using CEMS as per 40 CFR Part 75

Reporting: Deviations resulting in excess emissions to be

reported the next business day following the discovery of

the release, with written follow up within 5 days of

discovery. Deviations not resulting in excess emissions are

to be reported in writing within 10 business days following

discovery.

n/a n/a 

40 Monitoring: opacity as indicator of PM (CAM), operational

parameters of ESP, performance testing each pemit cycle,

Method 9.Recordkeeping: document all excursions.

Reporting: report excursions semi‐annually, report

exceedances the next business day following the discovery

of the release, with written follow up within 5 days of

discovery.

Monitoring: Using CEMS as per 40 CFR Part 75.

Recordkeeping: Using CEMS as per 40 CFR Part 75

Reporting: Deviations resulting in excess emissions to be

reported the next business day following the discovery of

the release, with written follow up within 5 days of

discovery. Deviations not resulting in excess emissions are

to be reported in writing within 10 business days following

discovery.

n/a n/a 

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

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

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

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

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

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

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

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

Boiler ID35
25 For the control technologies identified in Part I, questions 17 and 19, provide the cost information requested.38

Facility Name/Unit No.: n/a

Retrofit to existing boiler? n/a

Installation on a new boiler? n/a

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.

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:

Riverton

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

Plant Code 1239

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

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

*Fuel

State/Country (all

shipments are from

USA)

County42 Coal seam43 (Info not available)

Jan PC 4,676 39,40 n/a n/a truck

Sub 6,693 39,40 WY Campbell RR & truck

Sub 14,097 39,40 WY Campbell RR & truck

Feb PC 5,069 39,40 n/a n/a truck

Sub 4,038 39,40 WY Campbell RR & truck

Sub 16,144 39,40 WY Campbell RR & truck

Mar PC 5,566 39,40 n/a n/a truck

Sub 22,963 39,40 WY Campbell RR & truck

Apr PC 2,496 39,40 n/a n/a truck

Sub 8,868 39,40 WY Campbell RR & truck

May PC 3,144 39,40 n/a n/a truck

Sub 2,744 39,40 WY Campbell RR & truck

Sub 13,346 39,40 WY Campbell RR & truck

Jun PC 4,879 39,40 n/a n/a truck

Sub 7,360 39,40 WY Campbell RR & truck

Sub 14,654 39,40 WY Campbell RR & truck

Jul PC 4,989 39,40 n/a n/a truck

Sub 5,991 39,40 WY Campbell RR & truck

Sub 14,465 39,40 WY Campbell RR & truck

Aug PC 4,519 39,40 n/a n/a truck

Sub 5,928 39,40 WY Campbell RR & truck

Sub 15,654 39,40 WY Campbell RR & truck

Sep PC 3,602 39,40 n/a n/a truck

Sub 6,119 39,40 WY Campbell RR & truck

Sub 16,725 39,40 WY Campbell RR & truck

Oct PC 3,038 39,40 n/a n/a truck

Sub 9,103 39,40 WY Campbell RR & truck

Sub 13,684 39,40 WY Campbell RR & truck

Nov PC 3,061 39,40 n/a n/a truck

Sub 18,263 39,40 WY Campbell RR & truck

Sub 4,580 39,40 WY Campbell RR & truck

Dec PC 2,877 39,40 n/a n/a truck

Sub 9,099 39,40 WY Campbell RR & truck

Sub 13,820 39,40 WY Campbell RR & truck

*PC= Pet coke, Sub= sub‐bituminous coal

**The fuel analysis supplied by the vendor is as‐received on a wet‐basis and is consistent with the values reported in EIA form 923.

*** Coal is shipped via rail to our Asbury facility and trucked to the Riverton faclility. Riverton does not have rail unloading capabilities.

40 EPA recognizes that facilities have (sometimes) several months inventory and that the amount received is not necessarily the same as theamount fired.41 Boiler ID (as reported on U.S. DOE/EIA Form EIA‐860 (2007), "Annual Electric Generating Report," schedule 6, pa rt 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.

Fuel source

**Amount received,

dry basis, short tons40

ID # of boiler(s) firing

fuel41

***Fuel shipment

method
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):

Fuel

Type Sample ID #

*Total amount

of fuel

represented by

sample, tons or

gallons

(tons)

* Total sulfur, % *Ash content, %

Heating value,

Btu/lb

(not provided by

vendor)

**Heating value

received

mmbtu/ton

***Moisture

content, %

Mercury, ppm

(not provided by

vendor)

Chloride, ppm

(not provided by

vendor)

Fluorine, ppm

(not provided by

vendor)

Nickel, ppm

(not provided by

vendor)

O

t

m

H

p

(not 

by 

PC Jan 4,676 5.22 0.24 28.28 7.36 n/a n/a n/a n/a n/a

Sub 6,693 0.23 4.30 17.3 28.05 n/a n/a n/a n/a n/aSub 14,097 0.29 5.60 17.67 26.92 n/a n/a n/a n/a n/aPC Feb 5,069 4.23 0.19 27.89 9.22 n/a n/a n/a n/a n/aSub 4,038 0.23 4.30 17.34 28.10 n/a n/a n/a n/a n/aSub 16,144 0.26 4.7 17.85 26.97 n/a n/a n/a n/a n/a 

PC Mar 5,566 4.74 0.21 28.82 5.92 n/a n/a n/a n/a n/a

Sub 22,963 0.23 4.6 17.8 26.77 n/a n/a n/a n/a n/aPC Apr 2,496 4.54 0.18 28.44 7.65 n/a n/a n/a n/a n/aSub 8,868 0.23 4.63 17.8 26.77 n/a n/a n/a n/a n/aPC May 3,144 4.8 0.26 28.79 5.84 n/a n/a n/a n/a n/a

Sub 2,744 0.22 5.00 17.28 27.90 n/a n/a n/a n/a n/a

Sub 13,346 0.29 5.2 17.75 26.85 n/a n/a n/a n/a n/aPC Jun 4,879 4.29 0.27 29.24 4.78 n/a n/a n/a n/a n/a

Sub 7,360 0.19 4.70 17.24 28.25 n/a n/a n/a n/a n/a

Sub 14,654 0.33 5.8 17.53 26.99 n/a n/a n/a n/a n/aPC Jul 4,989 4.73 0.23 29.65 3.41 n/a n/a n/a n/a n/a

Sub 5,991 0.21 4.50 17.23 28.21 n/a n/a n/a n/a n/a

Sub 14,465 0.30 5.10 17.65 27.06 n/a n/a n/a n/a n/a

PC Aug 4,519 4.99 0.20 29.53 3.42 n/a n/a n/a n/a n/a

Sub 5,928 0.20 5.30 17.73 27.91 n/a n/a n/a n/a n/a

Sub 15,654 0.28 5.10 17.14 26.84 n/a n/a n/a n/a n/a

PC Sep 3,602 4.84 0.21 29.34 4.18 n/a n/a n/a n/a n/a

Sub 6,119 0.20 4.80 17.16 28.45 n/a n/a n/a n/a n/a

Sub 16,725 0.27 5.30 17.74 26.96 n/a n/a n/a n/a n/a

PC Oct 3,038 4.87 0.20 29.12 4.68 n/a n/a n/a n/a n/a

Sub 9,103 0.19 4.80 17.36 27.70 n/a n/a n/a n/a n/a

Sub 13,684 0.28 5.50 17.67 26.73 n/a n/a n/a n/a n/a

PC Nov 3,061 5.09 0.21 28.46 7.48 n/a n/a n/a n/a n/a

Sub 18,263 0.22 4.50 17.18 28.35 n/a n/a n/a n/a n/a

Sub 4,580 0.31 5.20 17.76 26.68 n/a n/a n/a n/a n/a

PC Dec 2,877 5.06 0.21 29.03 5.05 n/a n/a n/a n/a n/aSub 9,099 0.21 5.10 17 28.35 n/a n/a n/a n/a n/aSub 13,820 0.32 5.10 17.55 27.85 n/a n/a n/a n/a n/a

*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.
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 Dr., Suite 300, St. Louis, MO 63141

Oxbow Carbon & Minerals, LLC, 1601 Forum Pl. Suite 1400, West Palm Beach, FL 33401

Peabody Coal Sales, LLC. 701 Market St., St. Louis, MO 63101

____

Other (name and address)

6 Name and address of laboratory performing analyses:

Analyses is directed by fuel suppliers. Empire District Electric Company does not 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.
8a What emission test report(s), parametric monitoring data, and other data or monitoring are available for the boilers noted in Part I,

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

all pollutants, including (but not limited to) those required under Title V, compliance with State or local requirements, fulfillment of

contractual obligations, U.S. Department of Energy (DOE) programs, etc. (NOTE: EPA is not requesting copies of the test reports or data

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

Unit

PM testing 39 Date: May 20‐21, 2008

PM testing 40 Date: July 15‐16, 2008

HG testing 39 Date: December 8‐9, 2008

HG testing 40 Date: December 11, 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 hazardous

air pollutants) sampled for:

Unit39 Date: May 20‐21, 2008 Type: Stack Constituents: PM

40 Date: July 15‐16, 2008 Type: Stack Constituents: PM

39 Date: December 8‐9, 2008 Type: Stack Constituents: Hg40 Date: December 11, 2008 Type: Stack Constituents: Hg

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 poin

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

Yes

____

No

_

x

___

If yes, please not which reports and identify the other material(s) or non‐fossil fuels used.

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

Yes

____

No

__

x

__

If yes, please note which reports.

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

Yes

____

No

__x__ If yes, please list the unit's complete control configuration at time of testing in a similar format to Part I, question 

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 Scrubbe

Yes

____

No

_x___ If yes, please note which reports and, in addition to the detailed description of the location of the sampling point(

(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.
9 What type of deviation reporting is required for violations of permit requirements?

Deviations which result in emissions exceeding those allowed in the permit shall be reported the next business day

following the discovery of the release, with follow‐up written notice within five business days following discovery of the

release.Deviations which do not result in emissions exceeding those allowed in the permit shall be reported in writing within 10 business day

following the discovery of the deviation.

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 periods of deviations or malfunctions occur the following reports are generated.

Quarterly opacity excess emissions, semi‐annual monitoring, annual compliance, malfunction,

opacity monitor downtime, SO2 excess emissions, and CAM PM excursions.

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 and 

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

NOTE: CEMS mercury data are available for unit 39 beginning December 9, 2008 and are available for unit 40 beginning December 11

The data are currently not required by State or Federal regulations. Therefore, the raw data has not been subject to all quality assura

Limited quality assurance measures are in place due to the vacature of the Clean Air Mercury Rule and technology limitations.

Efforts are made to maintain the continuous mercury monitoring systems to provide valid mercury emissions data.

None of the mercury data is currently being provided to the EPA by Empire District Electric Company.

Emission units 39 and 40 have not experienced any malfunction(s) that are not captured in the start‐up or shut‐down periods contain

provided CEMS data. Since there are no mercury controls installed on these units malfunction periods of the control equipment are n

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 O

39 May 20‐21, 2008 Tested after the ESP

*0.1012 lb/MMBtu

(avg. of three 1‐hrruns)

December 8‐9, 2008

Tested after the ESP

3.69 ug/m3

(Avg. of 9 runs)

40 July 15‐16, 2008 Tested after the ESP *0.1827 lb/MMBtu (avg. of three 1‐hr runs)

"December 11, 2008

Tested after the ESP

5.44 ug/m3

(Avg. of 9 runs)

* Test results at baseline conditions

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 

Boiler ID: 39 Pollutant tested: PM 

EDE notes for review Process information Run 1 Run 2 Run 3 Run 4 Run 5 Run 6 Run 7 Run 8 Run 9 DAHS Unit Load (MW) 22.8 22.8 22.8 Est. aux. 2.5 MW

*Net Generation during

run (MWh net) 20.3 20.3 20.3 

Perf. Test summary

Flue Gas Moisture

Content (%) 8.0 7.9 7.8 

DAHS

Flue gas flow rate

(dscfm) 82.9772 83.0767 82.9684 

Perf. Test summary

Flue gas oxygen content(%, dry) 7.3 7.3 7.3 

Perf. Test summary

Flue gas carbon dioxide

content (%, dry) 12.0 12.1 12.1 

Perf. Test summary

Flue gas temperature at

sampling point (oF) 308 311 313 

DAHS

Flue gas pressure at

sampling point (atm) 29.10 29.14 29.15 

Perf. test field data

**Standard temperature(oF) 75 75 76 

Perf. Test summary

***Standard pressure(atm) 29.10 29.10 29.10 

Part II, question 12 attachment for testing 

Boiler ID: 40 Pollutant tested: PM 

EDE notes for review Process information Run 1 Run 2 Run 3 Run 4 Run 5 Run 6 Run 7 Run 8 Run 9 DAHS Unit Load (MW) 45 45 45 

*Net generation is estimated.

**Std. temp entered is ambient

***Std pressure entered is barometric
Est. aux. 2.5 MW

Net Generation during

run (MWh net) 41.5 41.5 41.5 

Perf. Test summary

Flue Gas Moisture

Content (%) 10.19 10.41 10.15 

DAHS

Flue gas flow rate

(dscfm) 124.0338 125.2661 125.1324 

Perf. Test summary

Flue gas oxygen content(%, dry) 5.2 5.2 5.2 

Perf. Test summary

Flue gas carbon dioxide

content (%, dry) 14.0 14.0 14.0 

Perf. Test summary

Flue gas temperature at

sampling point (oF) 298 302 305 

DAHS

Flue gas pressure at

sampling point (atm) 29.40 29.45 29.51 

Perf. test field data

**Standard temperature(oF) 84 85 85 

Perf. Test summary

***Standard pressure(atm) 29.27 29.27 29.27 

**Std. temp entered is ambient

***Std pressure entered is barometric

*Net generation is estimated. 
sting

Run 1 Run 2 Run 3 Run 4 Run 5 Run 6 Run 7 Run 8 Run 9

19.61 19.23 19.63 19.68 19.61 19.64 19.59 19.23 19.2517.11 16.73 17.13 17.18 17.11 17.14 17.09 16.73 16.75

8.81 9.27 9.12 9.02 8.8 9.00 8.54 8.35 9.15

69.6703 75.6773 77.6298 77.7389 76.8601 77.0419 77.3052 79.0290 78.3370

10.3 10.4 10.6 10.6 10.5 10.4 10.4 10.5 7.6

332 333 332 332 332 332 332 321 322

28.71 28.65 28.64 28.62 28.61 28.6 28.61 28.7 28.69

49 49 49 49 49 48 48 50 49

29.79 29.79 29.79 29.79 29.79 29.79 29.79 29.75 29.75

tachment for testing

Run 1 Run 2 Run 3 Run 4 Run 5 Run 6 Run 7 Run 8 Run 9

39.5 39.4 39.5 39.5 39.4 39.4 39.5 39.4 39.5

ed.

mbient

s barometric
36 35.9 36 36 35.9 35.9 36 35.9 36

8.85 8.63 8.05 8.68 9.32 9.15 8.69 8.91 8.77

120.9871 120.9100 121.5166 121.5653 121.4823 121.1062 121.6084 120.6205 121.2672

11.8 11.8 11.8 11.9 12 12 12.9 13 13.2

286 286 287 289 290 291 293 294 296

28.56 28.59 28.6 28.66 28.67 28.68 28.7 28.73 28.78

22 22 25 25 26 28 29 30 32

30.00 30.00 30.00 30.00 30.00 30.00 30.00 30.00 30.00

mbient

s barometric

ed.