1

PART I: GENERAL FACILITY INFORMATION

1. Name of legal owner of facility:

South Carolina Electric & Gas

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

Same

3. Address of __X__ legal owner or _____operator:

100 SCANA Parkway

Cayce, SC 29033

4a. Plant Name (as reported on U.S. DOE/EIA Form-860 (2007), "Annual Electric Generator Report," 

schedule 2, line 1, page 37, question 1) or Plant Name (as reported on U.S. DOE/EIA Form EIA-923 

(2008), "Power Plant Operations Report," schedule 2, page 1, question 1):

Canadys Steam

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

question 2) or Plant ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), schedule 2, page 1, 

question2):

3280

5. Complete street address of facility (physical location):

13139 Augusta Highway

Canadys, SC 29488

6. Provide mailing address is different:

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

Ken Dantzler, Engineer

8. Contact(s) telephone number(s):

(803) 217-7156

9. Is the facility considered to be owned or operated by a small entity as defined by the Regulatory 

Flexibility Act? ____ Yes __X__ No ____ Don’t know
2

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)

11. Which of the following fossil fuels 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)

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

Fuel Rank % Btu Basis % Mass Basis

Lignite

Bituminous 100 100

Sub-bituminous

Pet coke

Synfuel (including, but not limited to, briquettes, pellets, or 

extrusions which are formed by binding materials, or processes that 

recycle materials

Please specify type or form of synfuel used

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

Oil Rank % Btu Basis % Volume Basis

Distillate 100 100

Residual or bunker C

Other (specify)

 

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% subbituminous/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 volume and on a 

Btu basis) of each fuel oil rank (e.g. 85% residual oil/15% distillate).
3

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 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.

Other Material Permitted 

to burn

Actually 

burned

Quantity/year

Specification Used Oil Yes No

1% solution of ammoniated salt of ethylene 

diamine tetra acetic acid (boiler cleaning 

solution)

Yes No

Activated carbon generated from on-site 

water treatment process.

Yes No

Oily dirt, oily cotton rags, oil absorbent 

material and oil-dri provided oil absorbed 

meets Spec-oil criteria.

Yes No

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, where 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 _X__ No

Explain:

The quantities burned are so small and infrequent that it would not be worth subjecting the

source to section 129 unless the requirements do not create additional burdens beyond the 

existing requirements of SC 61-62.5 Std 3 Waste Combustion and Reduction.

 

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 type was combusted (e.g. “the permitting agency allowed this fuel to be combusted for special 

testing and research purposes”).
4

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 ID6CAN1 CAN2 CAN3

Original Design fuel (i.e. coal rank or 

type of oil) Bit. Coal, Dist. Oil Bit. Coal, Dist. Oil Bit. Coal, Dist. Oil

Design heat input, (MMBtu/hr)71161* 1161* 2091*

Present maximum heat input 

(MMBtu/hr)8 1141.5 1175.7 1824.5

MWe Gross capacity

summer

121 123 185

MWe Net capacity

Summer 105 115 180

Original design gross efficiency (%, 

HHV) 89.55 89.55 89.55

Present operating gross efficiency (%, 

HHV) 89.05 88.17 89.00

Design steam pressure

(psig) 2400 2400 2400

Operating steam pressure

(psig) 2400 2400 2400

Design steam temperature

(°F) 1050 1050 1050

Operating steam temperature

(°F) 1050 1050 1050

Design steam reheat temperature 

(°F)9 1000 1000 1000

Operating steam reheat temperature 

(°F)10 1000 1000 1000

Fuel11 100% Bit. Coal

0% #2 Oil (start-up)

0% NG

100% Bit. Coal

0% #2 Oil (start-up)

0% NG

97% Bit. Coal

3% #2 Oil (start-up)

0% NG

Hours/year operated12 5859.49 5731.56 5828.05

Average annual capacity factor for 

the past 3 years 50.5% 48.96% 57.67%

Applicable NSPS Not covered under NSPS Not covered under NSPS Not covered under NSPS

Estimated year of retirement13 CBI CBI CBI

* Rates are Nominal.

 

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Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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.
5

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

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

following the boiler, etc.):

Boiler ID14 Type15 NOx control16 Date SO2 control17 PM control18 Date Other control19

CAN1 Tang. Fired

Wet Bottom

Low NOx Burners (1) 5/1999 NA Cold Side ESP (3)

Flue Gas 

Conditioning (2)

6/1972

5/1999

NA

CAN2 Tang. Fired

Wet Bottom

Low NOx Burners (1) 5/1999 NA Cold Side ESP (3)

Flue Gas 

Conditioning (2)

12/1971

5/1999

NA

CAN3 Wall Fired

Wet Bottom

Low NOx Burners (1)

Radially Stratified Flame Core (2)

Separated Over Fire Air (3)

5/1999

12/2005

12/2005

NA Baghouse (4) 7/1998 NA

Control equipment order for each unit is listed in parenthesis.

 

14 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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, aqueous ammonia, urea, other). Also, please note if the 

catalyst is specifically designed to reduce SO3 formation.

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

control went online or planned operational date for new installation.

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

online or planned operational date for new installation.

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

dry sorbent injection or wet ESP for SO3 control; flue gas conditioning to control opacity (e.g. SO3 injection, ammonia, other); additive use for mercury control 

(e.g. bromine, scrubber additives). Include specific date that control went online or planned operational date for new installation. Also include any pollutants 

controlled by this other technology (e.g. control technology [pollutant controlled]).
6

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

Canadys Station has not participated in any HAP specific control technology demonstration project.

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

Name Telephone Address

 

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 Generator 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

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 operationg), 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) in use or fuel type upon which the demonstration was conducted. Please specify the format of 

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

reduction, provide (1) and 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 enddate

Type of control 

(e.g., sorbent and 

type; chemical 

additive23)

Desired HAP 

emission 

reduction (%) or 

emission rate

Coal rank(s) in 

use

 

22 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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
8

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

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

purpose of providing a non-demonstration, full-scale operating system.

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

Name Telephone Address

No primary HAP control technology installed for full scale operating system 

 

24 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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).
9

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

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

combustion 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) or fuel type upon which the guarantee is based. Please specify the format of the guarantee (e.g., 

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

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

reduction (i.e. where the “inlet” and “outlet” are).

Boiler ID25 Actual start-up 

date

Expected or 

projected startup date

Type of control 

(e.g., sorbent and 

type; chemical 

additive26)

Guaranteed HAP 

emission 

reduction (%) or 

emission rate

Sorbent or 

additive feed rate 

on which 

guarantee is 

based

Coal rank(s) upon 

which guarantee 

is based

 

25 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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
10

21. For each boiler noted in Part I, question 15, provide the following information:

Boiler ID27 CAN1, 

CAN2, 

CAN3

Permitted Emission Limit Averaging 

Period

Compliance Method 

(PM only)

Permit Type

PM28 0.6 lb/MMBtu

0.47 lbMMBtu (CAN3)

3 hr Annual Method 5 Title V

PM10

29

PM2.5

30

SO2 3.5 lb/MMBtu 24 hr Title V

HCl and/or HF

HCN

Metal HAP31

Hg

CO

Other organics (specify)

Other pollutant (specify)

 

27 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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 include 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 and selenium; indicate permit level for 

all metal HAP for which a permit limit is in place.
11

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

Boiler ID32 CAN1, 

CAN2, 

CAN3

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

PM33 0.6 lb/MMBtu

0.47 lbMMBtu (CAN3)

PM10

PM2.5

SO2 3.5 lb/MMBtu

HCl and/or HF

HCN

Metal HAP34

Hg

CO

Other organics (specify)

Other pollutant (specify)

23. Was any other guarantee level sought or offered? Yes ___ No ___ Please elaborate.

Control equipment was designed to meet current emission limits in place at the time of installation.

 

32 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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 rates for filterable and condensable PM, respectively, please include those separate emission rates.

34 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium; indicate permit level for 

all metal HAP for which a permit limit is in place.
12

24. For each boiler noted in Part I, question 15, provide the following information:

Boiler ID35 CAN1, CAN2, 

CAN3

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

permitted emission limit

PM36 1.Compliance with the PM emission limit shall be demonstrated through annual source testing

in accordance with SC Regulation 62.1, Section IV - "Source Tests", and Federal

requirements, when applicable. EPA Reference Test Method 5 shall be used for

determination of particulate emissions. Reference Methods 5B or 17 may be used when

allowed by 40 CFR Part 60, Subparts D and Da. PM compliance shall be determined by

averaging the test run emission rates over the test run durations as specified in the required

test protocol. For periodic monitoring purposes ifa unit exceeds 80 percent of its particulate

emission limit during a stack test, stack tests shall be scheduled and conducted every 6

months. Upon demonstration that the source is operating under 80 percent of its particulate limit, 

as shown by three consecutive semiannual stack tests, the source may resume annual

stack testing. All source test reports shall be submitted to the Manager of the Source

Evaluation Section ofthe Bureau of Air Quality no later than 30 days after the completion

of the on-site testing.

2. To meet the periodic monitoring requirement for particulate matter, the permittee shall use

a continuous opacity monitor (COM). Excluding unit startup and shutdown, if any three

hour block average opacity value exceeds the opacity standard, the permittee shall, as

appropriate, initiate an inspection of the control equipment and/or the COM system and

make the necessary repairs. If five (5) percent or greater ofCOM data (excluding startup,

shutdown, and malfunction periods, data averaged over a three hour block period) recorded

in a calendar quarter show excursions above the opacity standard, the permittee shall

perform a stack test in the following calendar quarter to demonstrate compliance with the

particulate standard. The permittee shall submit a compliance test protocol representative

 

35 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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 monitor, keep records, and report filterable and condensable 

PM separately, please describe the separate actions required.
13

Boiler ID35 CAN1, CAN2, 

CAN3

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

permitted emission limit

of operational conditions during the period in question as required by SC Regulation 62.1,

Section IV - "Source Tests" before conducting the test.

PM10 NA

PM2.5 NA

SO2 Quarterly Continuous Emissions Monitoring Reports shall be submitted to the Manager of

the Technical Management Section, Bureau of Air Quality postmarked no later than 30

calendar days after the end of the reporting period. These reports shall include the 24 hour

block average(24-one hour measurements which are summed and divided by 24) sulfur

emission rates in Ib/mmBTU, using unbiased data collected from the 40 CFR Part 75 acid

rain CEMS or from fuel sampling and analysis procedures described in Sections 5.2.1 - 5.2.3

of40 CFR Part 60, Appendix A, Reference Method 19 provided that; 1) hourly fuel samples

are collected at a location as close to the burners as possible, 2) the minimum size of each

hourly sample is 0.13 cubic feet, 3) the hourly samples are composited into one sample every

24 hour period with the composited sample thoroughly mixed and analyzed by methods

specified in Method 19,4) gross calorific value and sulfur content shall be determined on

a dry basis, and 5) the sulfur dioxide emission rate shall be calculated as follows:

 lblmmBTU = (1.9) (sulfur weightfraction)

 mmBTU/lbcoal

Sources using Reference Method 19 for determination of missing data as described in 40

CFR Part 75, Subpart D, shall comply with provisions 1-5 above except that hourly fuel

samples shall be composited into one sample every 24 hour period or for the duration ofthe

CEMS unavailability period, whichever is less.

HCl and/or HF NA

HCN NA

Metal HAP37 NA

Hg NA

CO NA

Other organics (specify) NA

Other pollutant (specify) NA

 

37 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium; indicate permit level for 

all metal HAP for which a permit limit is in place.
14

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

Facility Name/Unit No.:________________________ Retrofit to existing boiler? _______ Installation on new boiler? ______ 

Total Capital Investment $:

Total Annual Operating and Maintenance Costs: $: (Include base year for operating costs [e.g., 2006])

No control technologies

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

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

No

 

38 This can be treated as CBI and can be submitted through the proper CBI procedure if desired.
15

PART II: FUEL ANALYSIS AND EMISSION DATA

Fuel Analysis39

Each facility should provide the following information for each coal and oil shipment received during 

the preceding 12 calendar months.

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

Canadys Steam

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

3280

 

39 The respondent should reply to this ICR with separate pages 18 through 24 (Part II) for each of their facilities.
16

2, 3 & 4. For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, 

as available (indicate N/A in not available; use additional pages, as necessary):

CBI
17

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

Provided by Name Address

Supplier ICG LLC 2000 Ashland Drive

Ashland, KY 41101

Supplier JAD Coal Company, Inc. PO Box 297

Coldiron, KY 40819

Supplier Trinity Coal Marketing, LLC 1051 Main Street, Suite 100

Milton, WV 25541

Supplier Consol of Kentucky, Inc 1800 Washington Road

Pittsburg, PA 15241

Supplier Kopper Glo Fuel, Inc 10712 Farragut Hills Blvd.

Knoxville, TN 37922

Supplier Alliance Coal Corporation 152 West Valley Street

Abingdon, VA 24210

Supplier Cumberland River Energies, Inc KY Highway 38

Brookside, KY 40801

Other SCE&G – Central Lab 2102 North Lake Drive

Columbia, SC 29212

7. In addition to the analyses required in Part II, question 3 above, for samples for which 

analyses f 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.

No additional analyses have been conducted.
18

Emission Data

8a. What emission test reports(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.

Filterable & Condensable Particulate Matter and Speciated Mercury

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.

Date Unit Type Parameter

2/24/2005 CAN1 PM Filterable Particulates

3/1/2005 CAN1 PM Filterable Particulates

2/21/2006 CAN1 PM Filterable Particulates

2/21/2006 CAN1 Hg SPECIATED MERCURY

1/5/2007 CAN1 PM Filterable Particulates

12/30/2008 CAN1 PM Condensable & Filterable Particulates

3/8/2005 CAN2 PM Filterable Particulates

1/24/2006 CAN2 PM SPECIATED MERCURY

3/7/2006 CAN2 PM Filterable Particulates

3/7/2006 CAN2 PM SPECIATED MERCURY

2/23/2007 CAN2 PM Filterable Particulates

1/4/2008 CAN2 PM Filterable Particulates

1/13/2009 CAN2 PM Condensable & Filterable Particulates

1/25/2006 CAN3 Hg SPECIATED MERCURY

2/22/2006 CAN3 PM Filterable Particulates

2/22/2006 CAN3 Hg SPECIATED MERCURY

2/20/2007 CAN3 PM Filterable Particulates

2/12/2008 CAN3 PM Filterable Particulates

1/14/2009 CAN3 PM Condensable & Filterable Particulates

3/4/2009 CAN3 Hg Total Hg

8c. Do any of these test reports reflect testing at a location upstream of 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 points(s).

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 note 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.
19

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 the time of testing in a similar format to Part I, question 16.

8g. Do any of these test reports reflect testing at a location upstream of a post combustion 

SO2 emission control device (e.g., FGD, SDA, Dry Scrubber)? Yes___ No__X__ If yes, please note 

which reports and, in addition to the detailed description of the location of the sampling point(s) 

(question8c above), include detail about how much, if any, bypass of unscrubbed flue gas was 

utilized at the time of testing (including percentage of total scrubber exhaust 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?

Only COMS reports for Opacity deviations

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.

Only COMS reports
20

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

are not already being provided to the U.S. EPA or permit authority, even if from short-term testing? Yes ____ No__X__ If yes40, please 

note for which pollutants CEMS data are available and the period of time (both total period and calendar period) for which data are 

available. If CEMS data are being provided to EPA, please note to which Office the data are being provided.

NOTE: The following Hg CEMS data is provided to the State.

Average Monthly

Heat Input Emission Factor CEMS Total Monthly Total Monthly Average 

from CEMS from CEMS Operating Hg Hg Monthly Hg

Canadys 1 mmBTU uG/m3Hours Pounds Ounces #/mmBTU

May-09 211859.70 2.82 373.38 0.69 11.06 3.26133E-06

Jun-09 581097.30 3.84 720.00 2.25 36.05 3.87783E-06

Jul-09 253728.20 3.41 323.00 0.95 15.24 3.75421E-06

Aug-09 592110.20 3.04 724.00 1.92 30.80 3.25106E-06

Sep-09 255093.00 4.86 388.00 1.34 21.40 5.24233E-06

Oct-09 403604.00 3.44 650.00 1.73 27.64 4.27986E-06

Nov-09 114424.20 4.74 193.00 0.62 9.95 5.43233E-06

Dec-09 0.00 0.00 0.00 0.00 0.00 0

Jan-10 173664.80 0.14 354.00 0.03 0.54 1.95702E-07

Feb-10 175348.80 0.07 313.00 0.02 0.25 8.94073E-08

Total 9.56 152.92

 

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

data be submitted by the respondent. The respondent should also mark the periods of star up, shut down and malfunction events (SSM) in the data sets.
21

12. For each boiler noted in Part I, question 15, provide the following information:41,42 43, 44, 45

Date of 

Test

Boiler 

ID

PM SO2 HCL/HF Metal 

HAP

Hg CO Unit Flue Gas

Filt Cond Total Elemental Oxidized Load Moist Flow O2 CO2 Temp Press

STD 

Temp

STD 

Press Press

#/mmBTU #/mmBTU #/mmBTU #/mmBTU #/mmBTU #/mmBTU #/mmBTU #/mmBTU % MW % dscfm % %

o

F psia

o

F psia in Hg

2/24/2005 CAN3 0.0152 N/A N/A N/A N/A N/A N/A N/A 0 187.4 6.70 433000 6.00 13.10 289.2 14.74 60 14.7 30.0

3/1/2005 CAN1 0.2586 N/A N/A N/A N/A N/A N/A N/A 0 109.6 6.20 278000 7.70 11.20 277.5 14.77 60 14.7 30.1

3/8/2005 CAN2 0.1386 N/A N/A N/A N/A N/A N/A N/A 0 102.0 6.20 302000 9.60 10.20 275.9 14.57 60 14.7 29.7

1/24/2006 CAN2 N/A N/A N/A N/A N/A 0.00000274 0.00000127 0.00000146 N/A N/A N/A N/A N/A N/A N/A N/A 60 14.7 N/A

1/25/2006 CAN3 N/A N/A N/A N/A N/A 0.00000007 0.00000002 0.00000004 N/A N/A N/A N/A N/A N/A N/A N/A 60 14.7 N/A

2/21/2006 CAN1 0.1431 N/A N/A N/A N/A N/A N/A N/A 0 103.4 7.40 264000 7.30 11.90 277.6 14.74 60 14.7 30.0

2/21/2006 CAN1 N/A N/A N/A N/A N/A 0.00000215 0.00000081 0.00000115 N/A 103.4 7.40 264000 7.30 11.90 277.6 14.74 60 14.7 30.0

2/22/2006 CAN3 0.0028 N/A N/A N/A N/A N/A N/A N/A 0 185.6 6.70 458000 6.70 12.60 286.1 14.64 60 14.7 29.8

2/22/2006 CAN3 N/A N/A N/A N/A N/A 0.00000023 0.00000008 0.00000012 N/A 185.6 N/A N/A N/A N/A N/A N/A 60 14.7 N/A

3/7/2006 CAN2 0.0211 N/A N/A N/A N/A N/A N/A N/A 0 116.3 4.30 331000 9.80 10.20 312.5 N/A 60 14.7 N/A

3/7/2006 CAN2 N/A N/A N/A N/A N/A 0.0000039 0.00000152 0.00000237 N/A 116.3 N/A N/A N/A N/A N/A N/A 60 14.7 N/A

1/5/2007 CAN1 0.2955 N/A N/A N/A N/A N/A N/A N/A 0 108.5 6.20 271000 7.60 11.40 280.0 N/A 60 14.7 N/A

2/20/2007 CAN3 0.0030 N/A N/A N/A N/A N/A N/A N/A 0 188.9 4.70 502000 6.70 12.30 282.8 14.69 60 14.7 29.9

2/23/2007 CAN2 0.1580 N/A N/A N/A N/A N/A N/A N/A 0 112.1 7.10 321551.3333 8.55 10.63 306.0 14.70 60 14.7 29.9

1/4/2008 CAN2 0.0613 N/A N/A N/A N/A N/A N/A N/A 0 106.7 5.00 284000 9.90 9.80 276.3 14.95 60 14.7 30.4

2/12/2008 CAN3 0.0053 N/A N/A N/A N/A N/A N/A N/A 0 185.2 7.40 440000 6.70 12.10 281.0 14.63 60 14.7 29.8

12/30/2008 CAN1 0.1453 0.2033 N/A N/A N/A N/A N/A N/A 0 113.1 5.50 281000 7.60 11.40 270.2 14.81 60 14.7 30.1

1/13/2009 CAN2 0.1154 0.2073 N/A N/A N/A N/A N/A N/A 0 114.7 5.50 293000 9.30 9.70 269.7 14.74 60 14.7 30.0

1/14/2009 CAN3 0.0047 0.1387 N/A N/A N/A N/A N/A N/A 0 172.5 4.50 480000 6.70 12.10 271.9 14.80 60 14.7 30.1

3/4/2009 CAN3 N/A N/A N/A N/A N/A 0.00000004224 N/A N/A N/A N/A 9.26 N/A 8.64 10.38 265.0 N/A 60 14.7 N/A

 

41 Provide emission test data for all tests conducted since January 1, 2005. Please include 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.

42 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 (°F), Flue gas pressure at sampling point (atm), Standard temperature (°F), Standard pressure (atm).

43 If emission testing recorded the emission 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.

44 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium; indicate emission level for all metal HAP for which an emission test has been conducted.

45 Please provide separate results for total Hg, elemental Hg, oxidized Hg, and particulate Hg, as available. If the emission s testing recorded the amount of unburned carbon in fly ash (as reflected by the “Loss on Ignition” *L.O.I.+) at the time of any Hg testing, please 

include these data.

1

PART I: GENERAL FACILITY INFORMATION

1. Name of legal owner of facility:

South Carolina Electric & Gas

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

Same

3. Address of __X__ legal owner or _____operator:

100 SCANA Parkway

Cayce, SC 29033

4a. Plant Name (as reported on U.S. DOE/EIA Form-860 (2007), "Annual Electric Generator Report," 

schedule 2, line 1, page 37, question 1) or Plant Name (as reported on U.S. DOE/EIA Form EIA-923 

(2008), "Power Plant Operations Report," schedule 2, page 1, question 1):

Cope

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

question 2) or Plant ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), schedule 2, page 1, 

question2):

7210

5. Complete street address of facility (physical location):

405 Teamwork Road

Cope, SC 29038

6. Provide mailing address is different:

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

Ken Dantzler, Engineer

8. Contact(s) telephone number(s):

(803) 217-7156

9. Is the facility considered to be owned or operated by a small entity as defined by the Regulatory 

Flexibility Act? ____ Yes __X__ No ____ Don’t know
2

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

____ other (specify in question 14 below)

11. Which of the following fossil fuels 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)

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

Fuel Rank % Btu Basis % Mass Basis

Lignite

Bituminous 100 100

Sub-bituminous

Pet coke

Synfuel (including, but not limited to, briquettes, pellets, or 

extrusions which are formed by binding materials, or processes that 

recycle materials

Please specify type or form of synfuel used

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

Oil Rank % Btu Basis % Volume 

Basis

Distillate 100 100

Residual or bunker C

Other (specify)

 

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% subbituminous/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 volume and on a 

Btu basis) of each fuel oil rank (e.g. 85% residual oil/15% distillate).
3

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 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.

Other Material Permitted to 

burn

Actually 

burned

Quantity/year

Specification Used Oil Yes No

Activated Carbon generated from on-site water 

treatment process

Yes No

Oily dirt, oily cotton rags, oil absorbent 

material, and oil-dri

Yes No

Coal Synfuel:

Covol Technologies(Synthetic Binder)

Heritage HES Emulsion (AM-ELIS395)

Heritage ECS Emulsion (AM-ELIZ371)

Nalco 9838 binder(water based vinyl 

polymer)

Halren J316 v203W LN

Yes No

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, where 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 _X__ No

Explain:

The quantities burned are so small and infrequent that it would not be worth subjecting the 

source to section 129 unless the requirements do not create additional burdens beyond the 

existing requirements of SC 61-62.5 Std 3 Waste Combustion and Reduction.

 

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 type was combusted (e.g. “the permitting agency allowed this fuel to be combusted for special 

testing and research purposes”).
4

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 ID6COP1

Original Design fuel (i.e. coal rank 

or type of oil) Bit. Coal, Dist. Oil

Design heat input, (MMBtu/hr)74000*

Present maximum heat input 

(MMBtu/hr)8 4059.1

MWe Gross capacity

summer

441

MWe Net capacity

Summer 420

Original design gross efficiency 

(%, HHV) 90.74

Present operating gross efficiency 

(%, HHV) 90.77

Design steam pressure

(psig) 2400

Operating steam pressure

(psig) 2400

Design steam temperature

(°F) 1000

Operating steam temperature

(°F) 1000

Design steam reheat temperature 

(°F)9 1000

Operating steam reheat 

temperature (°F)10 1000

Fuel11 99.93% Bit. Coal

0.07% #2 Oil

0% NG

Hours/year operated12 7546.36

Average annual capacity factor 

for the past 3 years 76.77%

Applicable NSPS 40 CFR 60, Subpart Da

Estimated year of retirement13 CBI

*Rates are Nominal

 

6

Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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.
5

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

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

following the boiler, etc.):

Boiler 

ID14

Type15 NOx control16 Date SO2 control17 Date PM control18 Date Other control19

COP1 Tang. Fired

Wet Bottom

Close Coupled Overfired Air (1)

SCR (2)

 Vanadium Catalyst

 Anhydrous Ammonia 

Reagent

3/2005

1/2009

Dry Scrubber (3)

Lime-Calcium based

4/1993 Baghouse (4) 4/1993 NA

Control equipment order for each unit is listed in parenthesis.

 

14 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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, aqueous ammonia, urea, other). Also, please note if the 

catalyst is specifically designed to reduce SO3 formation.

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

control went online or planned operational date for new installation.

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

online or planned operational date for new installation.

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

dry sorbent injection or wet ESP for SO3 control; flue gas conditioning to control opacity (e.g. SO3 injection, ammonia, other); additive use for mercury control 

(e.g. bromine, scrubber additives). Include specific date that control went online or planned operational date for new installation. Also include any pollutants 

controlled by this other technology (e.g. control technology [pollutant controlled]).
6

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

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

Name Telephone Address

Cope Station has not participated in any HAP specific control technology demonstration project.

 

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 Generator 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

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 operationg), 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) in use or fuel type upon which the demonstration was conducted. Please specify the format of 

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

reduction, provide (1) and 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 enddate

Type of control 

(e.g., sorbent and 

type; chemical 

additive23)

Desired HAP 

emission 

reduction (%) or 

emission rate

Coal rank(s) in 

use

 

22 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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
8

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

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

purpose of providing a non-demonstration, full-scale operating system.

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

Name Telephone Address

No primary HAP control technology installed for full scale operating system 

 

24 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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).
9

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

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

combustion 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) or fuel type upon which the guarantee is based. Please specify the format of the guarantee (e.g., 

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

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

reduction (i.e. where the “inlet” and “outlet” are).

Boiler ID25 Actual start-up 

date

Expected or 

projected startup date

Type of control 

(e.g., sorbent and 

type; chemical 

additive26)

Guaranteed HAP 

emission 

reduction (%) or 

emission rate

Sorbent or 

additive feed rate 

on which 

guarantee is 

based

Coal rank(s) upon 

which guarantee 

is based

 

25 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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
10

21. For each boiler noted in Part I, question 15, provide the following information:

Boiler ID27 COP1 Permitted Emission Limit Averaging 

Period

Compliance Method

(PM only)

Permit Type

PM28 0.02 lb/MMBtu 3 hr Annual Method 5 Title V

PM10

29

PM2.5

30

SO2 0.25 lb/MMBtu 24 hr Title V

HCl and/or HF

HCN

Metal HAP31

Hg

CO

Other organics (specify)

Other pollutant (specify)

 

27 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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 include 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 and selenium; indicate permit level for 

all metal HAP for which a permit limit is in place.
11

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

Boiler ID32 COP1 Most recent guaranteed emission rate for each pollutant for which there is a permitted emission limit

PM33 0.02 lb/MMBtu

PM10

PM2.5

SO2

0.25 lb/MMBtu

HCl and/or HF

HCN

Metal HAP34

Hg

CO

Other organics (specify)

Other pollutant (specify)

23. Was any other guarantee level sought or offered? Yes ___ No _X__ Please elaborate.

Control equipment was designed to meet current emission limits in place at the time of installation.

 

32 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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 rates for filterable and condensable PM, respectively, please include those separate emission rates.

34 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium; indicate permit level for 

all metal HAP for which a permit limit is in place.
12

24. For each boiler noted in Part I, question 15, provide the following information:

Boiler ID35 COP1 Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a 

permitted emission limit

PM36

Compliance with the PM emission limit shall be demonstrated through annual source testing

in accordance with SC Regulation 61-62.1, Section IV - "Source Tests", and Federal '\

requirements, when applicable. This source is subject to 40CFR60 Subpart Da

and compliance with the PM emission limit is to be observed during all periods of normal

operation, including periods of soot-blowing. Annual source testing is to be conducted in

accordance with SC Regulation 61-62.5 Standard 1 Section IV D.5. and is to include soot

blowing. EPA Reference Test Method 5 shall be used for determination of particulate

emissions. Reference Methods 5B or 17 may be used when allowed by 40 CFR Part 60,

Subparts D and Da.

PM compliance shall be determined by averaging the test run emission rates over the test run

durations as specified in the required test protocol. For periodic monitoring purposes if a

unit exceeds 80 percent of its' particulate emission limit during a stack test, stack tests shall

be scheduled and conducted every 6 months. Upon demonstration that the source is operating

under 80 percent of its particulate limit, as shown by three consecutive semiannual stack

tests, the source may resume annual stack testing. All source test reports shall be submitted

to the Manager of the Source Evaluation Section of the Bureau of Air Quality no later than

30 days after the completion of the on-site testing.

A visible emission observation, in accordance with EPA Reference Test Method 9 shall be

done concurrently with required PM emissions testing. In circumstances where concurrent

 

35 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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 monitor, keep records, and report filterable and condensable 

PM separately, please describe the separate actions required.
13

Boiler ID35 COP1 Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a 

permitted emission limit

visual emission observations are biased (such as overlapping plumes, overcast skies or other

non-controllable variables described in Method 9), the facility shall perform a make-up

visible emission observation within 15 days of the PM test. The make-up observation shall

be done with the unit's operational mode (steam production, electricity generation)

comparable to that of the PM test and shall be completed no later than fifteen (15) days after

the PM test. AU.. source test reports shall be submitted to the Manager of the Source

Evaluation Section of the Bureau of Air Quality no later than 30 days after the completion of

the on-site testing.

This unit may bypass the fabric filters only while burning natural gas as fuel or during No.2

fuel oil boiler start-ups to alleviate potential damage to the fabric filters at low start-up

temperatures. The fabric filters shall operate at all times that coal is being fired except for

thirty (30) minutes during each start-up. Records of when and how long the fabric filters are

bypassed must be kept for at least five (5) years following the date of such measurement and

made available to the Bureau upon request.

PM10 NA

PM2.5 NA

SO2

Quarterly reports demonstrating compliance with the sulfur dioxide and nitrogen dioxide

limits in accordance with 40 CFR 60 Subpart Da shall be submitted to the,Manager ofthe

Technical Management Section, Bureau ofAir Quality postmarked no later than 30 calendar

days after the end of the reporting period.

The owner/operator shall maintain a file of continuous monitoring system or monitoring

device performance measurements; all continuous monitoring system performance

evaluations; all continuous monitoring system or monitoring device calibration checks;

adjustments and maintenance performed on these systems or devices in a permanent form

suitable for inspection by Department personnel for at least five (5) years following the date

of such measurement, maintenance, report and record.

HCl and/or HF NA

HCN NA
14

Boiler ID35 COP1 Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a 

permitted emission limit

Metal HAP37

Hg NA

CO NA

Other organics (specify) NA

Other pollutant (specify) NA

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

Facility Name/Unit No.:________________________ Retrofit to existing boiler? _______ Installation on new boiler? ______ 

Total Capital Investment $:

Total Annual Operating and Maintenance Costs: $: (Include base year for operating costs [e.g., 2006])

No control technologies

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

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

No

 

37 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium; indicate permit level for 

all metal HAP for which a permit limit is in place.

38 This can be treated as CBI and can be submitted through the proper CBI procedure if desired.
15

PART II: FUEL ANALYSIS AND EMISSION DATA

Fuel Analysis39

Each facility should provide the following information for each coal and oil shipment received during 

the preceding 12 calendar months.

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

Cope

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

7210

 

39 The respondent should reply to this ICR with separate pages 18 through 24 (Part II) for each of their facilities.
16

2, 3 & 4. For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, 

as available (indicate N/A in not available; use additional pages, as necessary):

CBI
17

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

Provided 

by Supplier Name Address

Supplier CONSTELLATION ENERGY COMMODITIES 

GROUP

111 Market Place, Suite 500

Baltimore, MD 21202

Supplier ALLIANCE COAL CORPORATION 152 West Valley Street

Abingdon, VA 24210

Supplier MASSEY COAL SALES COMPANY INC Massey Utility Sales Co

Richmond, VA 23219

Supplier CONSOL OF KENTUCKY INC 1800 Washington Road

Pittsburg, PA 15241

Supplier TRINITY COAL MARKETING LLC 1051 Main Street, Suite 100

Milton, WV 25541

Supplier J A D COAL COMPANY INC P.O. Box 297

Coldiron, KY 40819

Supplier B&W RESOURCES INC 637 Morton Blvd.

Hazard, KY 41701

Supplier COALSALES LLC 701 Market Street, Suite 831

St. Louis, MO 63101

Supplier CUMBERLAND RIVER ENERGIES INC KY Highway 38

Brookside, KY 40801

Supplier LOGAN & KANAWHA COAL COMPANY INC 96 Maccorkle Ave, SW

S. Charleston, WV 25303

Supplier KOPPER GLO FUEL INC 10712 Farragut Hills Blvd.

Knoxville, TN 37922

Supplier TECO COAL CORPORATION 200 Allison Blvd

Corbin, KY 40701

Supplier ICG LLC 2000 Ashland Drive

Ashland, KY 41101

Other SCE&G-Central Lab 2102 North Lake Drive

Columbia, SC 29212

7. In addition to the analyses required in Part II, question 3 above, for samples for which 

analyses f 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.

No additional analyses have been conducted.
18

Emission Data

8a. What emission test reports(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.

Filterable Particulate Matter and Speciated Mercury

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.

Date Unit Type Parameter

1/18/2005 COP1 PM Filterable Particulates

1/10/2006 COP1 Hg SPECIATED MERCURY

1/10/2006 COP1 PM Filterable Particulates

1/4/2007 COP1 PM Filterable Particulates

12/4/2008 COP1 PM Filterable Particulates

2/25/2009 COP1 HG Total Hg

10/6/2009 COP1 PM Filterable Particulates

8c. Do any of these test reports reflect testing at a location upstream of 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 points(s).

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 note 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 the time of testing in a similar format to Part I, question 16.

8g. Do any of these test reports reflect testing at a location upstream of a post combustion 

SO2 emission control device (e.g., FGD, SDA, Dry Scrubber)? Yes___ No__X__ If yes, please note 

which reports and, in addition to the detailed description of the location of the sampling point(s) 

(question8c above), include detail about how much, if any, bypass of unscrubbed flue gas was 
19

utilized at the time of testing (including percentage of total scrubber exhaust 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?

COMS reports for Opacity deviations,

SO2 and NOx for 30 day rolling average

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.

COMS reports,

30 day rolling average SO2 and NOx reports
20

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

are not already being provided to the U.S. EPA or permit authority, even if from short-term testing? Yes ____ No_X___ If yes40, please 

note for which pollutants CEMS data are available and the period of time (both total period and calendar period) for which data are 

available. If CEMS data are being provided to EPA, please note to which Office the data are being provided.

NOTE: The following Hg CEMS data is provide to the State.

Average Monthly

Heat Input Emission Factor CEMS Total Monthly Total Monthly Average 

from CEMS from CEMS Operating Hg Hg Monthly Hg

Cope 1 mmBTU uG/m3Hours Pounds Ounces #/mmBTU

May-09 1900340.30 0.18 710.00 0.35 5.67 1.8644E-07

Jun-09 2059904.30 0.0033 720.00 0.01 0.11 3.26823E-09

Jul-09 2132873.10 0.0455 744.00 0.10 1.55 4.53094E-08

Aug-09 2136703.80 0.0041 744.00 0.01 0.14 4.13296E-09

Sep-09 2091068.30 0.0491 720.00 0.10 1.64 4.90358E-08

Oct-09 2319499.60 0.24 744.00 0.56 8.88 2.39305E-07

Nov-09 2123983.00 0.26 720.00 0.54 8.56 2.51966E-07

Dec-09 2739622.90 0.24 744.00 0.63 10.16 2.31696E-07

Jan-10 2595399.50 0.09 728.00 0.22 3.56 8.56552E-08

Feb-10 2228460.50 0.17 672.00 0.38 6.06 1.7008E-07

Total 2.90 46.33

 

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

data be submitted by the respondent. The respondent should also mark the periods of star up, shut down and malfunction events (SSM) in the data sets.
21

12. For each boiler noted in Part I, question 15, provide the following information:41,42 43, 44, 45

Date of 

Test

Boiler 

ID

PM SO2 HCL/HF Metal 

HAP

Hg CO Unit Flue Gas

Filt Cond Total Elemental Oxidized Load Moist Flow O2 CO2 Temp Press STD Temp STD Press Press

#/mmBTU #/mmBTU #/mmBTU #/mmBTU #/mmBTU #/mmBTU #/mmBTU #/mmBTU % MW % dscfm % %

o

F psia

o

F psia in Hg

1/18/2005 COP1 0.0115 N/A N/A N/A N/A N/A N/A N/A 0 428.9 9.60 958000 6.50 12.50 175.0 15.03 60 14.7 30.6

1/10/2006 COP1 N/A N/A N/A N/A N/A 0.00000032 0.00000027 0.00000002 N/A 439.0 N/A N/A N/A N/A N/A N/A 60 14.7 N/A

1/10/2006 COP1 0.0122 N/A N/A N/A N/A N/A N/A N/A 0 439.0 11.20 880000 7.40 12.60 169.5 14.64 60 14.7 29.8

1/4/2007 COP1 0.0040 N/A N/A N/A N/A N/A N/A N/A 0 444.0 13.30 899000 6.50 12.30 161.9 14.64 60 14.7 29.8

12/4/2008 COP1 0.0012 N/A N/A N/A N/A N/A N/A N/A 0 430.1 11.70 944000 6.80 12.20 163.1 14.75 60 14.7 30.0

2/25/2009 COP1 N/A N/A N/A N/A N/A 0.00000002896 N/A N/A N/A 440.0 N/A N/A N/A N/A N/A N/A 60 14.7 N/A

10/6/2009 COP1 0.0016 N/A N/A N/A N/A N/A N/A N/A 0 439.7 13.10 927000 7.00 11.90 160.7 14.58 60 14.7 29.7

 

41 Provide emission test data for all tests conducted since January 1, 2005. Please include 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.

42 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 (°F), Flue gas pressure at sampling point (atm), Standard temperature (°F), Standard pressure (atm).

43 If emission testing recorded the emission 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.

44 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium; indicate emission level for all metal HAP for which an emission test has been conducted.

45 Please provide separate results for total Hg, elemental Hg, oxidized Hg, and particulate Hg, as available. If the emission s testing recorded the amount of unburned carbn in fly ash (as reflected by the “Loss on Ignition” *L.O.I.]) at the time of any Hg testing, please 

include these data.

1

PART I: GENERAL FACILITY INFORMATION

1. Name of legal owner of facility:

South Carolina Electric & Gas

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

Same

3. Address of __X__ legal owner or _____operator:

100 SCANA Parkway

Cayce, SC 29033

4a. Plant Name (as reported on U.S. DOE/EIA Form-860 (2007), "Annual Electric Generator Report," 

schedule 2, line 1, page 37, question 1) or Plant Name (as reported on U.S. DOE/EIA Form EIA-923 

(2008), "Power Plant Operations Report," schedule 2, page 1, question 1):

McMeekin

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

question 2) or Plant ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), schedule 2, page 1, 

question2):

3287

5. Complete street address of facility (physical location):

6055 Bush River Road

Columbia, SC 29212

6. Provide mailing address is different:

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

Ken Dantzler, Engineer

8. Contact(s) telephone number(s):

(803) 217-7156

9. Is the 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?
2

__X__ coal __X__oil (including pet coke) ____ natural gas

____ other (specify in question 14 below)

11. Which of the following fossil fuels 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)

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

Fuel Rank % Btu Basis % Mass Basis

Lignite

Bituminous 100 100

Sub-bituminous

Pet coke

Synfuel (including, but not limited to, briquettes, pellets, or 

extrusions which are formed by binding materials, or processes that 

recycle materials

Please specify type or form of synfuel used

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

Oil Rank % Btu Basis % Volume 

Basis

Distillate 100 100

Residual or bunker C

Other (specify)

 

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% subbituminous/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 volume and on a 

Btu basis) of each fuel oil rank (e.g. 85% residual oil/15% distillate).
3

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 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.

Other Material Permitted to 

burn

Actually 

burned

Quantity/year

Specification Used Oil Yes No

1% solution of ammoniated salt of ethylene 

diamine tetra-acetic acid (boiler cleaning 

solution)

Yes No

Activated Carbon generated from on-site water 

treatment process

Yes No

Oily dirt, oily cotton rags, oil absorbent 

material, and oil-dri

Yes No

Coal Synfuel:

Covol Technologies(Synthetic Binder)

Heritage HES Emulsion (AM-ELIS395)

Heritage ECS Emulsion (AM-ELIZ371)

Nalco 9838 binder(water based vinyl 

polymer)

Halren J316 v203W LN

Yes No

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, where 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 _X__ No

Explain:

The quantities burned are so small and infrequent that it would not be worth subjecting the 

source to section 129 unless the requirements do not create additional burdens beyond the 

existing requirements of SC 61-62.5 Std. 3 Waste Combustion and Reduction.

 

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 type was combusted (e.g. “the permitting agency allowed this fuel to be combusted for special 

testing and research purposes”).
4

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 MCM1 MCM2

Original Design fuel (i.e. coal rank or 

type of oil)

Bit. Coal

Dist. Oil

NG

Bit. Coal

Dist. Oil

NG

Design heat input, (MMBtu/hr)71134* 1134*

Present maximum heat input 

(MMBtu/hr)8 1143.5 1101.3

MWe Gross capacity

summer

135 132

MWe Net capacity

Summer 125 125

Original design gross efficiency (%, 

HHV) 89.55 89.55

Present operating gross efficiency (%, 

HHV) 89.8 89.44

Design steam pressure

(psig) 2400 2400

Operating steam pressure

(psig) 2400 2400

Design steam temperature

(°F) 1050 1050

Operating steam temperature

(°F) 1050 1050

Design steam reheat temperature 

(°F)9 1000 1000

Operating steam reheat temperature 

(°F)10 1000 1000

Fuel11 99.83% Bit. Coal

0.17% Dist. Oil

0% NG

99.88% Bit. Coal

0.12% Dist. Oil

0% NG

Hours/year operated12 7059.83 6833.23

Average annual capacity factor for 

the past 3 years 66.9% 64.11%

Applicable NSPS Not Covered Under 

NSPS

Not Covered Under 

NSPS

Estimated year of retirement13 CBI CBI

*Rates are Nominal.

 

6

Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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.
5

16. For each boiler noted in Part I, question 15, provide the following information for each current 

emission control device installed and operating and/or planned (please designate the order of the 

emission controls-1 for first control following the boiler, 2 for second control following the boiler, 

etc.):

Boiler 

ID14

Type15 NOx control16 Date SO2 control17 PM control18 Date Other 

control19

MCM1 Tang. Fired

Wet Bottom

Low NOx Burners (1)

Low NOx Optimization (2)

Seperated Overfired Air (3)

7/1999

10/2000

12/2004

None Baghouse (4) 4/1993

MCM2 Tang. Fired

Wet Bottom

Low NOx Burners (1)

Low NOx Optimization (2)

Seperated Overfired Air (3)

7/1999

10/2000

12/2004

None Baghouse (4) 11/1992

Control equipment order for each unit is listed in parenthesis.

 

14 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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); overfire 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, aqueous ammonia, urea, 

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

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

sodium-based. Include specific date that control went online or planned operational date for new installation.

18 Examples: fabric filter, cold-side electrostatic precipitator (ESP); hot-side ESP; cyclone or multiclone; venturi 

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

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

activated carbon injection (ACI); Powerspan ECO; dry sorbent injection or wet ESP for SO3 control; flue gas 

conditioning to control opacity (e.g. SO3 injection, ammonia, other); additive use for mercury control (e.g. bromine, 

scrubber additives). Include specific date that control went online or planned operational date for new installation. 

Also include any pollutants controlled by this other technology (e.g. control technology [pollutant controlled]).
6

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

company contact information for each HAP-specific (e.g., mercury, hydrogen chloride) control 

technology that you have either contracted for, are installing, or have installed for the purpose of 

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

program, consent decree, etc.).

Boiler 

ID21

Company (Vendor) 

name

Company (vendor) contact information

Name Telephone Address

McMeekin Station has not participated in any HAP specific control technology 

demonstration project.

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 operationg), the date of expected or projected startup, 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) in use or fuel type upon which the 

demonstration was conducted. Please specify the format of the target HAP emission reduction or 

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

reduction, provide (1) and 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 startup date

Demonstration 

activity enddate or 

projected enddate

Type of 

control 

(e.g., 

sorbent 

and type; 

chemical 

additive23)

Desired 

HAP 

emission 

reduction 

(%) or 

emission 

rate

Coal 

rank(s) 

in use

 

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 Generator 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).

22 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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
7

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

company contact information for each HAP (e.g., mercury, hydrogen chloride, etc.) control 

technology that you have either contracted for, are installing, or have installed for the purpose of 

providing a non-demonstration, full-scale operating system.

Boiler 

ID24

Company (Vendor) 

name

Company (vendor) contact information

Name Telephone Address

No primary HAP control technology installed for full scale operating system 

20. For the control technologies identified in Part I, question 19, provide the date of actual start-up 

(if the control is currently operating), the date of the expected or projected start-up, the type of HAP 

control installed (e.g. sorbent and type; pre-combustion boiler chemical additive, combustion 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) or fuel type upon which the guarantee is 

based. Please specify the format of the guarantee (e.g., lb/MWh, lb/TBtu, percent reduction, etc.). 

If the format of the guarantee is percent reduction, provide (1) an estimate of what an equivalent 

emission rate would be (and specify the format of the equivalent emission rate), and (2) the basis 

for calculating the percent reduction (i.e. where the “inlet” and “outlet” are).

Boiler 

ID25

Actual 

start-up 

date

Expected or 

projected 

start-up 

date

Type of 

control (e.g., 

sorbent and 

type; 

chemical 

additive26)

Guaranteed 

HAP emission 

reduction (%) 

or emission 

rate

Sorbent or 

additive 

feed rate on 

which 

guarantee is 

based

Coal rank(s) 

upon which 

guarantee is 

based

 

24 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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).

25 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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
8

21. For each boiler noted in Part I, question 15, provide the following information:

Boiler ID27 MCM1, 

MCM2

Permitted Emission Limit Averaging 

Period

Compliance Method

(PM only)

Permit Type

PM28 0.03 lb/MMBtu 3 hr Annual Method 5 Title V

PM10

29

PM2.5

30

SO2 3.5 lb/MMBtu 24 hr Title V

HCl and/or HF

HCN

Metal HAP31

Hg

CO

Other organics (specify)

Other pollutant (specify)

 

27 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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 include 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 and selenium; indicate permit level for 

all metal HAP for which a permit limit is in place.
9

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

Boiler ID32 MCM1, 

MCM2

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

PM33 0.03 lb/MMBtu

PM10

PM2.5

SO2

3.5 lb/MMBtu

HCl and/or HF

HCN

Metal HAP34

Hg

CO

Other organics (specify)

Other pollutant (specify)

23. Was any other guarantee level sought or offered? Yes ___ No __X_ Please elaborate.

Control equipment was designed to meet current emission limits in place at the time of installation.

 

32 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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 rates for filterable and condensable PM, respectively, please include those separate emission rates.

34 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium; indicate permit level for 

all metal HAP for which a permit limit is in place.
10

24. For each boiler noted in Part I, question 15, provide the following information:

Boiler ID35 MCM1, 

MCM2

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

permitted emission limit

PM36

Compliance with the PM emission limit shall be demonstrated through annual source testing

in accordance with SC Regulation 61-62.1, Section IV – “Source Tests”, and Federal

requirements, when applicable. EPA Reference Test Method 5 shall be used for

determination of particulate emissions. Reference Methods 5B or 17 may be used when

allowed by 40 CFR Part 60, Subparts D and Da. PM compliance shall be determined by

averaging the test run emission rates over the test run durations as specified in the required

test protocol. For periodic monitoring purposes if a unit exceeds 80 percent of its particulate

emission limit during a stack test, stack tests shall be scheduled and conducted every 6

months. Upon demonstration that the source is operating under 80 percent of its particulate

limit, as shown by three consecutive semiannual stack tests, the source may resume annual

stack testing. All source test reports shall be submitted to the Manager of the Source

Evaluation Section of the Bureau of Air Quality no later than 30 days after the completion of

the on-site testing.

To meet the periodic monitoring requirement for particulate matter, the permittee shall use a

continuous opacity monitor (COM). Excluding unit startup and shutdown, if any three hour

block average opacity value exceeds the opacity standard, the permittee shall, as appropriate,

initiate an inspection of the control equipment and/or the COM system and make the

necessary repairs. If five (5) percent or greater of COM data (excluding startup, shutdown,

and malfunction periods, data averaged over a three hour block period) recorded in a calendar

quarter show excursions above the opacity standard, the permittee shall perform a stack test

in the following calendar quarter to demonstrate compliance with the particulate standard.

 

35 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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 monitor, keep records, and report filterable and condensable 

PM separately, please describe the separate actions required.
11

Boiler ID35 MCM1, 

MCM2

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

permitted emission limit

The permittee shall submit a compliance test protocol representative of operational

conditions during the period in question as required by SC Regulation 61-62.1, Section IV –

“Source Tests” before conducting the test.

PM10 NA

PM2.5 NA

SO2

Quarterly Continuous Emissions Monitoring Reports shall be submitted to the Manager of

the Technical Management Section, Bureau of Air Quality postmarked no later than 30

calendar days after the end of the reporting period. These reports shall include the 24 hour

block average(24-one hour measurements which are summed and divided by 24) sulfur

emission rates in lb/106 BTU, using unbiased data collected from the 40 CFR Part 75 acid

rain CEMS or from fuel sampling and analysis procedures described in Sections 5.2.1 - 5.2.3

of 40 CFR Part 60, Appendix A, Reference Method 19 provided that; 1) hourly fuel samples

are collected at a location as close to the burners as possible, 2) the minimum size of each

hourly sample is 0.13 cubic feet, 3) the hourly samples are composited into one sample every

24 hour period with the composited sample thoroughly mixed and analyzed by methods

specified in Method 19, 4) gross calorific value and sulfur content shall be determined on a

dry basis, and 5) the sulfur dioxide emission rate shall be calculated as follows:

lb

10

6 =

 1. 9 (sulfur weight fraction)

10

6 Btu lb coal

Sources using Reference Method 19 for determination of missing data as described in 40

CFR Part 75, Subpart D, shall comply with provisions 1-5 above except that hourly fuel

samples shall be composited into one sample every 24 hour period or for the duration of the

CEMS unavailability period, whichever is less.

HCl and/or HF NA

HCN NA

Metal HAP37

 

37 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium; indicate permit level for 

all metal HAP for which a permit limit is in place.
12

Boiler ID35 MCM1, 

MCM2

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

permitted emission limit

Hg NA

CO NA

Other organics (specify) NA

Other pollutant (specify) NA

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

Facility Name/Unit No.:________________________ Retrofit to existing boiler? _______ Installation on new boiler? ______ 

Total Capital Investment $:

Total Annual Operating and Maintenance Costs: $: (Include base year for operating costs [e.g., 2006])

No control technologies

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

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

No

 

38 This can be treated as CBI and can be submitted through the proper CBI procedure if desired.
13

PART II: FUEL ANALYSIS AND EMISSION DATA

Fuel Analysis39

Each facility should provide the following information for each coal and oil shipment received during 

the preceding 12 calendar months.

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

McMeekin

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

3287

 

39 The respondent should reply to this ICR with separate pages 18 through 24 (Part II) for each of their facilities.
14

2, 3 & 4. For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, 

as available (indicate N/A in not available; use additional pages, as necessary):

CBI
15

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

Provided 

by Supplier Name Address

Supplier CONSTELLATION ENERGY COMMODITIES 

GROUP

111 Market Place, Suite 500

Baltimore, MD 21202

Supplier ALLIANCE COAL CORPORATION 152 West Valley Street

Abingdon, VA 24210

Supplier MASSEY COAL SALES COMPANY INC Massey Utility Sales Co

Richmond, VA 23219

Supplier CONSOL OF KENTUCKY INC 1800 Washington Road

Pittsburg, PA 15241

Supplier TRINITY COAL MARKETING LLC 1051 Main Street, Suite 100

Milton, WV 25541

Supplier J A D COAL COMPANY INC P.O. Box 297

Coldiron, KY 40819

Supplier B&W RESOURCES INC 637 Morton Blvd.

Hazard, KY 41701

Supplier COALSALES LLC 701 Market Street, Suite 831

St. Louis, MO 63101

Supplier CUMBERLAND RIVER ENERGIES INC KY Highway 38

Brookside, KY 40801

Supplier LOGAN & KANAWHA COAL COMPANY INC 96 Maccorkle Ave, SW

S. Charleston, WV 25303

Supplier KOPPER GLO FUEL INC 10712 Farragut Hills Blvd.

Knoxville, TN 37922

Supplier TECO COAL CORPORATION 200 Allison Blvd

Corbin, KY 40701

Supplier ICG LLC 2000 Ashland Drive

Ashland, KY 41101

Other SCE&G-Central Lab 2102 North Lake Drive

Columbia, SC 29212

7. In addition to the analyses required in Part II, question 3 above, for samples for which 

analyses f 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.

No additional analyses have been conducted.
16

Emission Data

8a. What emission test reports(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.

Filterable Particulate Matter and Speciated Mercury

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.

Date Unit Type Parameter

2/26/2005 MCM1 PM Filterable Particulates

1/17/2006 MCM1 Hg SPECIATED MERCURY

1/17/2006 MCM1 PM Filterable Particulates

1/16/2007 MCM1 PM Filterable Particulates

1/8/2008 MCM1 PM Filterable Particulates

1/20/2009 MCM1 PM Filterable Particulates

2/25/2005 MCM2 PM Filterable Particulates

1/23/2006 MCM2 Hg SPECIATED MERCURY

1/23/2006 MCM2 PM Filterable Particulates

1/18/2007 MCM2 PM Filterable Particulates

1/9/2008 MCM2 PM Filterable Particulates

1/21/2009 MCM2 PM Filterable Particulates

6/10/2009 MCM2 Hg Total Hg

1/25/2005 MCM2 PM Filterable Particulates

1/26/2005 MCM1 PM Filterable Particulates

8c. Do any of these test reports reflect testing at a location upstream of 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 points(s).

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 note 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 the time of testing in a similar format to Part I, question 16.
17

8g. Do any of these test reports reflect testing at a location upstream of a post combustion 

SO2 emission control device (e.g., FGD, SDA, Dry Scrubber)? Yes___ No__X__ If yes, please note 

which reports and, in addition to the detailed description of the location of the sampling point(s) 

(question8c above), include detail about how much, if any, bypass of unscrubbed flue gas was 

utilized at the time of testing (including percentage of total scrubber exhaust 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?

Only COMS reports for Opacity deviations

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.

COMS reports
18

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

are not already being provided to the U.S. EPA or permit authority, even if from short-term testing? Yes ____ No__X__ If yes40, please 

note for which pollutants CEMS data are available and the period of time (both total period and calendar period) for which data are 

available. If CEMS data are being provided to EPA, please note to which Office the data are being provided.

NOTE: The following Hg CEMS data is provide to the State.

Average Monthly

Heat Input Emission Factor CEMS Total Monthly Total Monthly Average 

from CEMS from CEMS Operating Hg Hg Monthly Hg

McMeekin1 mmBTU uG/m3Hours Pounds Ounces #/mmBTU

May-09 322656.90 0.37 526.02 0.14 2.22 4.29306E-07

Jun-09 473685.80 0.38 720.00 0.20 3.21 4.22907E-07

Jul-09 467866.70 0.31 744.00 0.16 2.58 3.44278E-07

Aug-09 486750.10 0.63 744.00 0.35 5.58 7.15908E-07

Sep-09 327022.30 0.20 515.00 0.08 1.20 2.29428E-07

Oct-09 581023.10 0.18 744.00 0.11 1.83 1.97291E-07

Nov-09 148580.80 0.25 270.00 0.05 0.73 3.05336E-07

Dec-09 639801.00 0.42 709.00 0.29 4.62 4.50873E-07

Jan-10 694518.80 0.33 744.00 0.24 3.85 3.4644E-07

Feb-10 621575.80 0.23 672.00 0.15 2.37 2.38083E-07

Total 1.76 28.17

 

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

data be submitted by the respondent. The respondent should also mark the periods of star up, shut down and malfunction events (SSM) in the data sets.
19

12. For each boiler noted in Part I, question 15, provide the following information:41,42 43, 44, 45

Date of 

Test

Boiler 

ID

PM SO2 HCL/HF Metal 

HAP

Hg CO Unit Flue Gas

Filt Cond Total Elemental Oxidized Load Moist Flow O2 CO2 Temp Press STD Temp STD Press Press

#/mmBTU #/mmBTU #/mmBTU #/mmBTU #/mmBTU #/mmBTU #/mmBTU #/mmBTU % MW % dscfm % %

o

F psia oF psia in Hg

1/17/2006 MCM1 N/A N/A N/A N/A N/A 0.00000101 0.00000013 0.00000089 N/A 128.4 N/A N/A N/A N/A N/A N/A 60 14.7 N/A

1/17/2006 MCM1 0.0052 N/A N/A N/A N/A N/A N/A N/A 0 128.4 5.80 280000 6.90 11.90 266.5 14.59 60 14.7 29.7

1/23/2006 MCM2 N/A N/A N/A N/A N/A 0.00000089 0.00000006 0.00000082 N/A 127.4 N/A N/A N/A N/A N/A N/A 60 14.7 N/A

1/23/2006 MCM2 0.0024 N/A N/A N/A N/A N/A N/A N/A 0 127.4 5.90 279000 7.10 11.60 253.4 14.59 60 14.7 29.7

1/25/2005 MCM2 0.0091 N/A N/A N/A N/A N/A N/A N/A 0 132.0 6.20 288000 5.80 12.40 259.4 14.62 60 14.7 29.8

1/26/2005 MCM1 0.0031 N/A N/A N/A N/A N/A N/A N/A 0 129.5 6.50 287000 6.00 12.30 277.0 14.60 60 14.7 29.7

1/16/2007 MCM1 0.0021 N/A N/A N/A N/A N/A N/A N/A 0 125.6 5.40 297000 6.90 11.60 271.7 14.57 60 14.7 29.7

1/18/2007 MCM2 0.0051 N/A N/A N/A N/A N/A N/A N/A 0 126.2 5.00 287000 6.80 11.70 245.3 14.71 60 14.7 29.9

1/8/2008 MCM1 0.0029 N/A N/A N/A N/A N/A N/A N/A 0 124.5 5.60 269000 7.00 11.60 268.7 14.61 60 14.7 29.7

1/9/2008 MCM2 0.0095 N/A N/A N/A N/A N/A N/A N/A 0 126.0 5.90 266000 7.10 11.70 266.7 14.61 60 14.7 29.7

1/20/2009 MCM1 0.0092 N/A N/A N/A N/A N/A N/A N/A 0 127.5 4.90 305000 7.30 11.50 253.8 14.62 60 14.7 29.8

1/21/2009 MCM2 0.0060 N/A N/A N/A N/A N/A N/A N/A 0 125.8 5.20 287000 6.80 11.90 247.2 14.63 60 14.7 29.8

 

41 Provide emission test data for all tests conducted since January 1, 2005. Please include 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.

42 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 (°F), Flue gas pressure at sampling point (atm), Standard temperature (°F), Standard pressure (atm).

43 If emission testing recorded the emission 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.

44 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium; indicate emission level for all metal HAP for which an emission test has been conducted.

45 Please provide separate results for total Hg, elemental Hg, oxidized Hg, and particulate Hg, as available. If the emission s testing recorded the amount of unburned carbn in fly ash (as reflected by the “Loss on Ignition” *L.O.I.+) at the time of any Hg testing, please 

include these data.

1

PART I: GENERAL FACILITY INFORMATION

1. Name of legal owner of facility:

South Carolina Electric & Gas

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

Same

3. Address of __X__ legal owner or _____operator:

100 SCANA Parkway

Cayce, SC 29033

4a. Plant Name (as reported on U.S. DOE/EIA Form-860 (2007), "Annual Electric Generator Report," 

schedule 2, line 1, page 37, question 1) or Plant Name (as reported on U.S. DOE/EIA Form EIA-923 

(2008), "Power Plant Operations Report," schedule 2, page 1, question 1):

Urquhart

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

question 2) or Plant ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), schedule 2, page 1, 

question2):

3295

5. Complete street address of facility (physical location):

100 Keith Mullis Drive

Beech Island, SC 29842

6. Provide mailing address is different:

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

Ken Dantzler, Engineer

8. Contact(s) telephone number(s):

(803) 217-7156

9. Is the facility considered to be owned or operated by a small entity as defined by the Regulatory 

Flexibility Act? ____ Yes __X__ No ____ Don’t know
2

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

this facility?

__X__ coal __X__oil (including pet coke) __X__ natural gas

__X__ other (specify in question 14 below)

11. Which of the following fossil fuels 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)

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

Fuel Rank % Btu Basis % Mass Basis

Lignite

Bituminous 100 100

Sub-bituminous

Pet coke

Synfuel (including, but not limited to, briquettes, pellets, or 

extrusions which are formed by binding materials, or processes that 

recycle materials

Please specify type or form of synfuel used

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

Oil Rank % Btu Basis % Volume 

Basis

Distillate 100 100

Residual or bunker C

Other (specify)

 

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% subbituminous/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 volume and on a 

Btu basis) of each fuel oil rank (e.g. 85% residual oil/15% distillate).
3

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 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.

Other Material Permitted to 

burn

Actually 

burned

Quantity/year

Specification Used Oil Yes Yes 66,885 gal

1% solution of ammoniated salt of ethylene 

diamine tetra-acetic acid (boiler cleaning 

solution)

Yes No

Activated Carbon generated from on-site water 

treatment process

Yes No

Oily dirt, oily cotton rags, oil absorbent 

material, and oil-dri

Yes No

Non-hazardous oil sludge from virgin fuel oil 

storage tanks located on-site

Yes No

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, where 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 _X__ No

Explain:

The quantities burned are so small and infrequent that it would not be worth subjecting the 

source to section 129 unless the requirements do not create additional burdens beyond the 

existing requirements of SC 61-62.5 Std. 3 Waste Combustion and Reduction.

 

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 type was combusted (e.g. “the permitting agency allowed this fuel to be combusted for special 

testing and research purposes”).
4

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 ID6URQ3

Original Design fuel (i.e. coal rank or 

type of oil) Bit. Coal

Design heat input, (MMBtu/hr)71100*

Present maximum heat input 

(MMBtu/hr)8 1048

MWe Gross capacity

summer

103

MWe Net capacity

Summer 95

Original design gross efficiency (%, 

HHV) 89.25

Present operating gross efficiency (%, 

HHV) 89.17

Design steam pressure

(psig) 1800

Operating steam pressure

(psig) 1800

Design steam temperature

(°F) 1000

Operating steam temperature

(°F) 1000

Design steam reheat temperature 

(°F)9 1000

Operating steam reheat temperature 

(°F)10 1000

Fuel11 99.88% Bit. Coal

0.09% Spec. Oil

0.03% Dist. Oil

0% NG

Hours/year operated12 7222.76

Average annual capacity factor for 

the past 3 years 70.48%

Applicable NSPS Not Covered Under 

NSPS

Estimated year of retirement13 CBI

*Rate is Nominal.

 

6

Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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.
5

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

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

following the boiler, etc.):

Boiler ID14 Type15 NOx control16 Date SO2 control17 PM control18 Date Other control19

URQ3 Tang. Fired

Wet Bottom

Low NOx Burners (1)

Seperated Overfired Air (2)

10/1998

3/2005

None Cold Side ESP (3) 11/1969

Control equipment order for each unit is listed in parenthesis.

 

14 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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, aqueous ammonia, urea, other). Also, please note if the 

catalyst is specifically designed to reduce SO3 formation.

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

control went online or planned operational date for new installation.

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

online or planned operational date for new installation.

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

dry sorbent injection or wet ESP for SO3 control; flue gas conditioning to control opacity (e.g. SO3 injection, ammonia, other); additive use for mercury control 

(e.g. bromine, scrubber additives). Include specific date that control went online or planned operational date for new installation. Also include any pollutants 

controlled by this other technology (e.g. control technology [pollutant controlled]).
6

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

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

Name Telephone Address

Urquhart Station (URQ#) has not participated in any HAP specific control technology demonstration project.

 

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 Generator 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

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 operationg), 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) in use or fuel type upon which the demonstration was conducted. Please specify the format of 

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

reduction, provide (1) and 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 enddate

Type of control 

(e.g., sorbent and 

type; chemical 

additive23)

Desired HAP 

emission 

reduction (%) or 

emission rate

Coal rank(s) in 

use

 

22 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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
8

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

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

purpose of providing a non-demonstration, full-scale operating system.

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

Name Telephone Address

No primary HAP control technology installed for full scale operating system 

 

24 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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).
9

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

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

combustion 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) or fuel type upon which the guarantee is based. Please specify the format of the guarantee (e.g., 

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

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

reduction (i.e. where the “inlet” and “outlet” are).

Boiler ID25 Actual start-up 

date

Expected or 

projected startup date

Type of control 

(e.g., sorbent and 

type; chemical 

additive26)

Guaranteed HAP 

emission 

reduction (%) or 

emission rate

Sorbent or 

additive feed rate 

on which 

guarantee is 

based

Coal rank(s) upon 

which guarantee 

is based

 

25 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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
10

21. For each boiler noted in Part I, question 15, provide the following information:

Boiler ID27 URQ3 Permitted Emission Limit Averaging 

Period

Compliance Method

(PM only)

Permit Type

PM28 0.6 lb/MMBtu 3 hr Annual Method 5 Title V

PM10

29

PM2.5

30

SO2 3.0 lb/MMBtu 24 hr Title V

HCl and/or HF

HCN

Metal HAP31

Hg

CO

Other organics (specify)

Other pollutant (specify)

 

27 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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 include 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 and selenium; indicate permit level for 

all metal HAP for which a permit limit is in place.
11

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

Boiler ID32 URQ3 Most recent guaranteed emission rate for each pollutant for which there is a permitted emission limit

PM33 0.6 lb/MMBtu

PM10

PM2.5

SO2

3.0 lb/MMBtu

HCl and/or HF

HCN

Metal HAP34

Hg

CO

Other organics (specify)

Other pollutant (specify)

23. Was any other guarantee level sought or offered? Yes ___ No __X_ Please elaborate.

Control equipment was designed to meet current emission limits in place at the time of installation.

 

32 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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 rates for filterable and condensable PM, respectively, please include those separate emission rates.

34 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium; indicate permit level for 

all metal HAP for which a permit limit is in place.
12

24. For each boiler noted in Part I, question 15, provide the following information:

Boiler ID35 URQ3 Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a 

permitted emission limit

PM36

Compliance with the PM emission limit shall be demonstrated through annual source testing

in accordance with SC Regulation 61-62.1, Section IV – “Source Tests”, and Federal

requirements, when applicable. EPA Reference Test Method 5 shall be used for

determination of particulate emissions. Reference Methods 5B or 17 may be used when

allowed by 40 CFR Part 60, Subparts D and Da. PM compliance shall be determined by

averaging the test run emission rates over the test run durations as specified in the required

test protocol. For periodic monitoring purposes if a unit exceeds 80 percent of its particulate

emission limit during a stack test, stack tests shall be scheduled and conducted every 6

months. Upon demonstration that the source is operating under 80 percent of its particulate

limit, as shown by three consecutive semiannual stack tests, the source may resume annual

stack testing. All source test reports shall be submitted to the Manager of the Source

Evaluation Section of the Bureau of Air Quality no later than 30 days after the completion of

the on-site testing.

To meet the periodic monitoring requirement for particulate matter, the permittee shall use a

continuous opacity monitor (COM). Excluding unit startup and shutdown, if any three hour

block average opacity value exceeds the opacity standard, the permittee shall, as appropriate,

initiate an inspection of the control equipment and/or the COM system and make the

necessary repairs. If five (5) percent or greater of COM data (excluding startup, shutdown,

and malfunction periods, data averaged over a three hour block period) recorded in a calendar

 

35 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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 monitor, keep records, and report filterable and condensable 

PM separately, please describe the separate actions required.
13

Boiler ID35 URQ3 Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a 

permitted emission limit

quarter show excursions above the opacity standard, the permittee shall perform a stack test

in the following calendar quarter to demonstrate compliance with the particulate standard.

The permittee shall submit a compliance test protocol representative of operational

conditions during the period in question as required by SC Regulation 61-62.1, Section IV –

“Source Tests” before conducting the test.

PM10 NA

PM2.5 NA

SO2

Quarterly Continuous Emissions Monitoring Reports shall be submitted to the Manager of

the Technical Management Section, Bureau of Air Quality postmarked no later than 30

calendar days after the end of the reporting period. These reports shall include the 24 hour

block average(24-one hour measurements which are summed and divided by 24) sulfur

emission rates in lb/106 BTU, using unbiased data collected from the 40 CFR Part 75 acid

rain CEMS or from fuel sampling and analysis procedures described in Sections 5.2.1 - 5.2.3

of 40 CFR Part 60, Appendix A, Reference Method 19 provided that; 1) hourly fuel samples

are collected at a location as close to the burners as possible, 2) the minimum size of each

hourly sample is 0.13 cubic feet, 3) the hourly samples are composited into one sample every

24 hour period with the composited sample thoroughly mixed and analyzed by methods

specified in Method 19, 4) gross calorific value and sulfur content shall be determined on a

dry basis, and 5) the sulfur dioxide emission rate shall be calculated as follows:

lb

10

6 =

 1. 9 (sulfur weight fraction)

10

6 Btu lb coal

Sources using Reference Method 19 for determination of missing data as described in 40

CFR Part 75, Subpart D, shall comply with provisions 1-5 above except that hourly fuel

samples shall be composited into one sample every 24 hour period or for the duration of the

CEMS unavailability period, whichever is less.

HCl and/or HF NA

HCN NA
14

Boiler ID35 URQ3 Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a 

permitted emission limit

Metal HAP37

Hg NA

CO NA

Other organics (specify) NA

Other pollutant (specify) NA

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

Facility Name/Unit No.:________________________ Retrofit to existing boiler? _______ Installation on new boiler? ______ 

Total Capital Investment $:

Total Annual Operating and Maintenance Costs: $: (Include base year for operating costs [e.g., 2006])

No control technologies

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

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

No

 

37 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium; indicate permit level for 

all metal HAP for which a permit limit is in place.

38 This can be treated as CBI and can be submitted through the proper CBI procedure if desired.
15

PART II: FUEL ANALYSIS AND EMISSION DATA

Fuel Analysis39

Each facility should provide the following information for each coal and oil shipment received during 

the preceding 12 calendar months.

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

Urquhart

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

3295

 

39 The respondent should reply to this ICR with separate pages 18 through 24 (Part II) for each of their facilities.
16

2, 3 & 4. For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, 

as available (indicate N/A in not available; use additional pages, as necessary):

CBI
17

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

Provided 

by

Supplier Name Address

Supplier CONSOL OF KENTUCKY INC 1800 Washington Road

Pittsburg, PA 15241

Supplier J A D COAL COMPANY INC P.O. Box 297

Coldiron, KY 40819

Supplier KOPPER GLO FUEL INC 10712 Farragut Hills Blvd.

Knoxville, TN 37922

Other SCE&G-Central Lab 2102 North Lake Drive

Columbia, SC 29212

7. In addition to the analyses required in Part II, question 3 above, for samples for which 

analyses f 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.

No additional analyses have been conducted.
18

Emission Data

8a. What emission test reports(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.

Filterable Particulate Matter and Speciated Mercury

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.

Date Unit Type Parameter

2/3/2005 URQ3 PM Filterable Particulates

12/6/2005 URQ3 Hg SPECIATED MERCURY

11/29/2006 URQ3 PM Filterable Particulates

11/20/2007 URQ3 PM Filterable Particulates

9/24/2008 URQ3 PM Filterable Particulates

8/11/2009 URQ3 PM Filterable Particulates

8c. Do any of these test reports reflect testing at a location upstream of 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 points(s).

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 note 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 the time of testing in a similar format to Part I, question 16.

8g. Do any of these test reports reflect testing at a location upstream of a post combustion 

SO2 emission control device (e.g., FGD, SDA, Dry Scrubber)? Yes___ No__X__ If yes, please note 

which reports and, in addition to the detailed description of the location of the sampling point(s) 

(question8c above), include detail about how much, if any, bypass of unscrubbed flue gas was 
19

utilized at the time of testing (including percentage of total scrubber exhaust 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?

Only COMS reports for Opacity deviations

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.

COMS reports
20

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

are not already being provided to the U.S. EPA or permit authority, even if from short-term testing? Yes ____ No__X__ If yes40, please 

note for which pollutants CEMS data are available and the period of time (both total period and calendar period) for which data are 

available. If CEMS data are being provided to EPA, please note to which Office the data are being provided.

NOTE: The following Hg CEMS data is provide to the State.

Average Monthly

Heat Input Emission Factor CEMS Total Monthly Total Monthly Average 

from CEMS from CEMS Operating Hg Hg Monthly Hg

Urquhart 3 mmBTU uG/m3Hours Pounds Ounces #/mmBTU

May-09 316621.80 7.78 490.25 2.56 41.00 8.09315E-06

Jun-09 492195.90 8.39 720.00 4.08 65.29 8.29004E-06

Jul-09 248953.70 6.96 413.00 1.89 30.22 7.58572E-06

Aug-09 528541.20 7.02 744.00 3.92 62.75 7.42071E-06

Sep-09 440881.80 5.55 620.00 2.66 42.58 6.0369E-06

Oct-09 540264.80 4.46 700.00 2.57 41.19 4.76495E-06

Nov-09 531287.80 6.01 720.00 3.12 49.91 5.87168E-06

Dec-09 645434.00 6.21 744.00 3.80 60.79 5.88628E-06

Jan-10 585834.00 5.48 744.00 3.17 50.70 5.40921E-06

Feb-10 458924.80 4.73 621.00 2.06 33.00 4.49404E-06

Total 29.84 477.43

 

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

data be submitted by the respondent. The respondent should also mark the periods of star up, shut down and malfunction events (SSM) in the data sets.
21

12. For each boiler noted in Part I, question 15, provide the following information:41,42 43, 44, 45

Date of 

Test

Boiler 

ID

PM SO2 HCL/HF Metal 

HAP

Hg CO Unit Flue Gas

Filt Cond Total Elemental Oxidized Load Moist Flow O2 CO2 Temp Press STD Temp STD Press Press

#/mmBTU #/mmBTU #/mmBTU #/mmBTU #/mmBTU #/mmBTU #/mmBTU #/mmBTU % MW % dscfm % %

o

F psia oF psia in Hg

2/3/2005 URQ3 0.0761 N/A N/A N/A N/A N/A N/A N/A 0 99.3 8.2 223000 6.3 12.8 273.6 14.77 60 14.7 30.06

12/6/2005 URQ3 N/A N/A N/A N/A N/A 0.00000246 0.00000108 0.00000021 N/A 97.3 N/A N/A N/A N/A N/A N/A 60 14.7 N/A

11/29/2006 URQ3 0.0903 N/A N/A N/A N/A N/A N/A N/A 0 101.7 7 218000 6.2 12.7 290.4 14.76 60 14.7 30.05

11/20/2007 URQ3 0.2671 N/A N/A N/A N/A N/A N/A N/A 0 104.3 7.2 243000 6.4 13 290.7 14.63 60 14.7 29.78

9/24/2008 URQ3 0.2058 N/A N/A N/A N/A N/A N/A N/A 0 102.4 5.5 244000 7.1 11.9 269.3 14.66 60 14.7 29.83

8/11/2009 URQ3 0.2276 N/A N/A N/A N/A N/A N/A N/A 0 99.4 6.5 247000 7.3 11.7 292.6 14.66 60 14.7 29.83

 

41 Provide emission test data for all tests conducted since January 1, 2005. Please include 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.

42 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 (°F), Flue gas pressure at sampling point (atm), Standard temperature (°F), Standard pressure (atm).

43 If emission testing recorded the emission 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.

44 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium; indicate emission level for all metal HAP for which an emission test has been conducted.

45 Please provide separate results for total Hg, elemental Hg, oxidized Hg, and particulate Hg, as available. If the emission s testing recorded the amount of unburned carbn in fly ash (as reflected by the “Loss on Ignition” *L.O.I.+) at the time of any Hg testing, please 

include these data.

1

PART I: GENERAL FACILITY INFORMATION

1. Name of legal owner of facility:

South Carolina Electric & Gas

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

Same

3. Address of __X__ legal owner or _____operator:

100 SCANA Parkway

Cayce, SC 29033

4a. Plant Name (as reported on U.S. DOE/EIA Form-860 (2007), "Annual Electric Generator Report," 

schedule 2, line 1, page 37, question 1) or Plant Name (as reported on U.S. DOE/EIA Form EIA-923 

(2008), "Power Plant Operations Report," schedule 2, page 1, question 1):

Wateree

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

question 2) or Plant ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), schedule 2, page 1, 

question2):

3297

5. Complete street address of facility (physical location):

142 Wateree Station Road

Eastover, SC 29044

6. Provide mailing address is different:

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

Ken Dantzler, Engineer

8. Contact(s) telephone number(s):

(803) 217-7156

9. Is the facility considered to be owned or operated by a small entity as defined by the Regulatory 

Flexibility Act? ____ Yes __X__ No ____ Don’t know
2

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

____ other (specify in question 14 below)

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

Fuel Rank % Btu Basis % Mass Basis

Lignite 0 0

Bituminous 100 100

Sub-bituminous 0 0

Pet coke 0 0

Synfuel (including, but not limited to, briquettes, pellets, or 

extrusions which are formed by binding materials, or processes that 

recycle materials

0 0

Please specify type or form of synfuel used

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

Oil Rank % Btu Basis % Volume 

Basis

Distillate 100 100

Residual or bunker C 0 0

Other (specify) 0 0

 

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% subbituminous/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 volume and on a 

Btu basis) of each fuel oil rank (e.g. 85% residual oil/15% distillate).
3

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 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.

Other Material Permitted to 

burn

Actually 

burned

Quantity/year

Specification Used Oil Yes No

Activated carbon generated from on-site water 

treatment process.

Yes No

Petroleum contaminated organic media Yes No

Petroleum contaminated rags Yes No

Petroleum contaminated absorbents Yes No

Vermiculite/”Oil-Dri” Yes No

Coal Synfuel:

Covol Technologies (synthetic binder)

Heritage HES Emulsion (AM-ELIZ395)

Heritage ECS Emulsion (AM-ELIZ371)

Yes No

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, where 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 _X__ No

Explain:

The quantities burned are so small and infrequent that it would not be worth subjecting the 

source to section 129 unless the requirements do not create additional burdens beyond the 

existing requirements of SC 61-62.5 Std. 3 Waste Combustion and Reduction.

 

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 type was combusted (e.g. “the permitting agency allowed this fuel to be combusted for special 

testing and research purposes”).
4

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 WAT1 WAT2

Original Design fuel (i.e. coal rank 

or type of oil)

Bit. Coal

Dist. Oil

Bit. Coal

Dist. Oil

Design heat input, (MMBtu/hr)73577.5* 3577.5*

Present maximum heat input 

(MMBtu/hr)8 3329.7 3305.1

MWe Gross capacity

summer

383 380

MWe Net capacity

Summer 350 350

Original design gross efficiency 

(%, HHV) 90.00 90.00

Present operating gross efficiency 

(%, HHV) 89.48 88.92

Design steam pressure

(psig) 3500 3500

Operating steam pressure

(psig) 3500 3500

Design steam temperature

(°F) 1000 1000

Operating steam temperature

(°F) 1000 1000

Design steam reheat temperature 

(°F)9 1000 1000

Operating steam reheat 

temperature (°F)10 1000 1000

Fuel11 99.47% Bit. Coal

0.53% Dist. Oil

99.65% Bit. Coal

0.35% Dist. Oil

Hours/year operated12 7131.5 7763.37

Average annual capacity factor 

for the past 3 years 65.58% 71.22%

Applicable NSPS Not covered under 

NSPS

Not covered under 

NSPS

Estimated year of retirement13 CBI CBI

*Rates are Nominal.

 

6

Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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.
5

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

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

following the boiler, etc.):

Boiler ID14 Type15 NOx control16 Date SO2 control17 Date PM control18 Date Other control19

WAT1 Wall Fired

Wet Bottom

Low NOx Burners (1)

SCR (2)

 Vanadium Catalyst

 Anhydrous 

Ammonia Reagent

6/1998

6/2003

Wet Scrubber (4) Baghouse (3) 5/2001

WAT2 Wall Fired

Wet Bottom

Low NOx Burners (1)

SCR (2)

 Vanadium Catalyst

 Anhydrous 

Ammonia Reagent

4/2004

Wet Scrubber (4) Baghouse (3) 7/2001

Control equipment order for each unit is listed in parenthesis.

 

14 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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, aqueous ammonia, urea, other). Also, please note if the 

catalyst is specifically designed to reduce SO3 formation.

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

control went online or planned operational date for new installation.

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

online or planned operational date for new installation.

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

dry sorbent injection or wet ESP for SO3 control; flue gas conditioning to control opacity (e.g. SO3 injection, ammonia, other); additive use for mercury control 

(e.g. bromine, scrubber additives). Include specific date that control went online or planned operational date for new installation. Also include any pollutants 

controlled by this other technology (e.g. control technology [pollutant controlled]).
6

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

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

Name Telephone Address

Wateree Station has not participated in any HAP specific control technology demonstration project.

 

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 Generator 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

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 operationg), 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) in use or fuel type upon which the demonstration was conducted. Please specify the format of 

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

reduction, provide (1) and 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 enddate

Type of control 

(e.g., sorbent and 

type; chemical 

additive23)

Desired HAP 

emission 

reduction (%) or 

emission rate

Coal rank(s) in 

use

 

22 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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
8

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

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

purpose of providing a non-demonstration, full-scale operating system.

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

Name Telephone Address

No primary HAP control technology installed for full scale operating system 

 

24 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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).
9

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

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

combustion 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) or fuel type upon which the guarantee is based. Please specify the format of the guarantee (e.g., 

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

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

reduction (i.e. where the “inlet” and “outlet” are).

Boiler ID25 Actual start-up 

date

Expected or 

projected startup date

Type of control 

(e.g., sorbent and 

type; chemical 

additive26)

Guaranteed HAP 

emission 

reduction (%) or 

emission rate

Sorbent or 

additive feed rate 

on which 

guarantee is 

based

Coal rank(s) upon 

which guarantee 

is based

 

25 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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
10

21. For each boiler noted in Part I, question 15, provide the following information:

Boiler ID27 WAT1, 

WAT2, 

Permitted Emission Limit Averaging 

Period

Compliance Method 

(PM only)

Permit Type

PM28 0.34 lb/MMBtu 3 hr Annual Method 5 Title V

PM10

29

PM2.5

30

SO2 3.5 lb/MMBtu 24 hr Title V

HCl and/or HF

HCN

Metal HAP31

Hg

CO

Other organics (specify)

Other pollutant (specify)

 

27 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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 include 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 and selenium; indicate permit level for 

all metal HAP for which a permit limit is in place.
11

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

Boiler ID32 WAT1, WAT2 Most recent guaranteed emission rate for each pollutant for which there is a permitted emission limit

PM33 0.34 lb/MMBtu

PM10

PM2.5

SO2 3.5 lb/MMBtu

HCl and/or HF

HCN

Metal HAP34

Hg

CO

Other organics (specify)

Other pollutant (specify)

23. Was any other guarantee level sought or offered? Yes ___ No __X_ Please elaborate.

Control equipment was designed to meet current emission limits in place at the time of installation.

 

32 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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 rates for filterable and condensable PM, respectively, please include those separate emission rates.

34 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium; indicate permit level for 

all metal HAP for which a permit limit is in place.
12

24. For each boiler noted in Part I, question 15, provide the following information:

Boiler ID35 WAT1, WAT2 Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a 

permitted emission limit

PM36 1. Compliance with the PM emission limit shall be demonstrated through annual source testing

in accordance with SC Regulation 62.1, Section IV - "Source Tests", and Federal

requirements, when applicable. EPA Reference Test Method 5 shall be used for

determination of particulate emissions. Reference Methods 5B or 17 may be used when

allowed by 40 CFR Part 60, Subparts D and Da. PM compliance shall be determined by

averaging the test run emission rates over the test run durations as specified in the required

test protoco1. For periodic monitoring purposes ifa unit exceeds 80 percent ofits particulate

emission limit during a stack test, stack tests shall be scheduled and conducted every 6

months. Upon demonstration that the source is operating under 80 percent ofits particulate

limit, as shown by three consecutive semiannual stack tests, the source may resume annual

stack testing. All source test reports shall be submitted to the Manager of the Source

Evaluation Section ofthe Bureau of Air Quality no later than 30 days after the completion

of the on-site testing.

2. To meet the periodic monitoring requirement for particulate matter, the permittee shall use

a continuous opacity monitor (COM). Excluding unit startup and shutdown, if any three

hour block average opacity value exceeds the opacity standard, the permittee shall, as

appropriate, initiate an inspection of the control equipment and/or the COM system and

make the necessary repairs. If five (5) percent or greater of COM data (excluding startup,

 

35 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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 monitor, keep records, and report filterable and condensable 

PM separately, please describe the separate actions required.
13

Boiler ID35 WAT1, WAT2 Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a 

permitted emission limit

shutdown, and malfunction periods, data averaged over a three hour block period) recorded

in a calendar quarter show excursions above the opacity standard, the permittee shall

perform a stack test in the following calendar quarter to demonstrate compliance with the

particulate standard. The permittee shall submit a compliance test protocol representative

of operational conditions during the period in question as required by SC Regulation 62.1,

Section IV - "Source Tests" before conducting the test.

PM10 NA

PM2.5 NA

SO2 Quarterly Continuous Emissions Monitoring Reports shall be submitted to the Manager of

the Technical Management Section, Bureau of Air Quality postmarked no later than 30

calendar days after the end of the reporting period. These reports shall include the 24 hour

block average(24-one hour measurements which are summed and divided by 24) sulfur

emission rates in Ib/mmBTU, using unbiased data collected from the 40 CFR Part 75 acid

rain CEMS or from fuel sampling and analysis procedures described in Sections 5.2.1 - 5.2.3

of40 CFR Part 60, Appendix A, Reference Method 19 provided that; 1) hourly fuel samples

are collected at a location as close to the burners as possible, 2) the minimum size of each

hourly sample is 0.13 cubic feet, 3) the hourly samples are composited into one sample every

24 hour period with the composited sample thoroughly mixed and analyzed by methods

specified in Method 19,4) gross calorific value and sulfur content shall be determined on

a dry basis, and 5) the sulfur dioxide emission rate shall be calculated as follows:

 lblmmBTU = (1.9) (sulfur weightfraction)

 mmBTU/lbcoal

Sources using Reference Method 19 for determination of missing data as described in 40

CFR Part 75, Subpart D, shall comply with provisions 1-5 above except that hourly fuel

samples shall be composited into one sample every 24 hour period or for the duration ofthe

CEMS unavailability period, whichever is less.

HCl and/or HF NA

HCN NA

Metal HAP37 NA

Hg NA

 

37 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium; indicate permit level for 

all metal HAP for which a permit limit is in place.
14

Boiler ID35 WAT1, WAT2 Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a 

permitted emission limit

CO NA

Other organics (specify) NA

Other pollutant (specify) NA

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

Facility Name/Unit No.:________________________ Retrofit to existing boiler? _______ Installation on new boiler? ______ 

Total Capital Investment $:

Total Annual Operating and Maintenance Costs: $: (Include base year for operating costs [e.g., 2006])

No control technologies

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

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

No

 

38 This can be treated as CBI and can be submitted through the proper CBI procedure if desired.
15

PART II: FUEL ANALYSIS AND EMISSION DATA

Fuel Analysis39

Each facility should provide the following information for each coal and oil shipment received during 

the preceding 12 calendar months.

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

Wateree

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

3297

 

39 The respondent should reply to this ICR with separate pages 18 through 24 (Part II) for each of their facilities.
16

2, 3 & 4. For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, 

as available (indicate N/A in not available; use additional pages, as necessary):

CBI
17

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

Provided by Supplier Name Address

Supplier J A D COAL COMPANY INC PO Box 297

Coldiron, KY 40819

Supplier ARCH COAL SALES COMPANY INC City Place One, Suite 350

St. Louis, MO 63141

Supplier ALLIANCE COAL CORPORATION 152 West Valley Street

Abingdon, VA 24210

Supplier ICG LLC 2000 Ashland Drive

Ashland, KY 41101

Supplier CONSTELLATION ENERGY COMMODITIES 

GROUP 

111 Market Place, Suite 500

Baltimore, MD 21202

Supplier MASSEY COAL SALES COMPANY INC Massey Utility Sales Co

Richmond, VA 23219

Supplier B&W RESOURCES INC 637 Morton Blvd

Hazard, KY 41701

Supplier CUMBERLAND RIVER ENERGIES INC KY Highway 38

Brookside, KY 40801

Supplier KOPPER GLO FUEL INC 10712 Farragut Hills Blvd

Knoxville, TN 37922

Supplier TECO COAL CORPORATION 200 Allison Blvd

Corbin, KY 40701

Supplier CONSOL OF KENTUCKY INC 1800 Washington Road

Pittsburg, PA 15241

Supplier LOGAN & KANAWHA COAL COMPANY INC 96 Maccorkle Ave, SW

S. Charleston, WV 25303

Supplier TRINITY COAL MARKETING LLC 1051 Main Street, Suite 100

Milton, WV 25541

Supplier COALSALES LLC 701 Market Street, Suite 831

St. Louis, MO 63101

Other SCE&G-Lab 2102 North Lake Drive

Columbia, SC 29212

7. In addition to the analyses required in Part II, question 3 above, for samples for which 

analyses f 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.

No additional analyses have been conducted.
18

Emission Data

8a. What emission test reports(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.

Filterable Particulate Matter and Speciated Mercury

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.

Date Unit Type Parameter

5/24/2005 WAT1 PM Filterable Particulates

5/23/2006 WAT1 PM Filterable Particulates

5/23/2006 WAT1 Hg SPECIATED MERCURY

7/11/2006 WAT1 NOX,SO2, 

SO3,CO2,PARTICULATE,HCL/HF,Hg

NOX,SO2, 

SO3,CO2,PARTICULATE,HCL/HF,Hg

5/23/2007 WAT1 PM Filterable Particulates

5/13/2008 WAT1 PM Filterable Particulates

12/9/2008 WAT1 SPECIATED MERCURY

12/10/2008 WAT1 SPECIATED MERCURY

2/24/2009 WAT1 Hg Total Hg

5/5/2009 WAT1 PM Filterable Particulates

7/24/2007 WAT1 Inlet Duct Nox, SO2, CO2 NOX,SO2, CO2

8/2/2005 WAT2 PM Filterable Particulates

2/24/2006 WAT2 Hg SPECIATED MERCURY

5/24/2006 WAT2 PM Filterable Particulates

7/11/2006 WAT2 NOX,SO2, 

SO3,CO2,PARTICULATE,HCL/HF,Hg

NOX,SO2, 

SO3,CO2,PARTICULATE,HCL/HF,Hg

5/22/2007 WAT2 PM Filterable Particulates

5/21/2008 WAT2 PM Filterable Particulates

2/23/2009 WAT2 Hg Total Hg

6/9/2009 WAT2 PM Filterable Particulates

7/24/2007 WAT1 NOX,SO2, CO2 NOX,SO2, CO2

12/9/2008 WAT1 Hg SPECIATED MERCURY

12/10/2008 WAT1 Hg SPECIATED MERCURY

8c. Do any of these test reports reflect testing at a location upstream of 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 points(s).

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 note which reports and identify 

the other material(s) or non-fossil fuels used.
19

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 the time of testing in a similar format to Part I, question 16.

8g. Do any of these test reports reflect testing at a location upstream of a post combustion 

SO2 emission control device (e.g., FGD, SDA, Dry Scrubber)? Yes___ No__X__ If yes, please note 

which reports and, in addition to the detailed description of the location of the sampling point(s) 

(question8c above), include detail about how much, if any, bypass of unscrubbed flue gas was 

utilized at the time of testing (including percentage of total scrubber exhaust 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?

Only COMS reports for Opacity deviations

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.

COMS reports

11. Are continuous emissions monitoring system (CEMS) data available (e.g., mercury, 

continuous opacity monitoring systems) that are not already being provided to the U.S. EPA or 

permit authority, even if from short-term testing? Yes ____ No__X__ If yes40, please note for 

which pollutants CEMS data are available and the period of time (both total period and calendar 

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

which Office the data are being provided.

 

40 Where units are monitored by CEMS (either following CAMR, State, or NIST QA/QC procedures), and where data 

are available, EPA requests that these CEMS data be submitted by the respondent. The respondent should also 

mark the periods of star up, shut down and malfunction events (SSM) in the data sets.
20

12. For each boiler noted in Part I, question 15, provide the following information:41,42 43, 44, 45

Date of 

Test

Boiler 

ID

PM SO2 HCL/HF Metal 

HAP

Hg CO Unit Flue Gas

Filt Cond Total Elemental Oxidized Load Moist Flow O2 CO2 Temp Press STD Temp STD Press Press

#/mmBTU #/mmBTU #/mmBTU #/mmBTU #/mmBTU #/mmBTU #/mmBTU #/mmBTU % MW % dscfm % %

o

F psia

o

F psia in Hg

5/24/2005 WAT1 0.0118 N/A N/A N/A N/A N/A N/A N/A 0 365.6 7.4 767000 6 13.2 330.6 14.74 60 14.7 30

8/2/2005 WAT2 0.0488 N/A N/A N/A N/A N/A N/A N/A 0 365.1 7.6 813000 7 13.1 336.6 14.70 60 14.7 29.93

2/24/2006 WAT2 N/A N/A N/A N/A N/A 0.00000167 0.00000026 0.00000138 N/A 365.2 N/A N/A N/A N/A N/A N/A 60 14.7 N/A

5/23/2006 WAT1 0.0096 N/A N/A N/A N/A N/A N/A N/A 0 364.4 6.1 775000 6.9 12.1 330.5 14.63 60 14.7 29.77

5/23/2006 WAT1 N/A N/A N/A N/A N/A 0.00000377 0.00000037 0.000000007 N/A 364.4 N/A N/A N/A N/A N/A N/A 60 14.7 N/A

5/24/2006 WAT2 0.0102 N/A N/A N/A N/A N/A N/A N/A 0 365.1 6.8 757000 7.2 11.8 333.3 14.61 60 14.7 29.74

7/11/2006 WAT1 0.00734 N/A N/A 0.0560/0.00807 N/A 0.00000157 N/A N/A N/A 363 9.57 660000 6.47 12.5 312.9 14.54 60 14.7 29.6

7/11/2006 WAT2 0.0129 N/A N/A 0.0596/0.00664 N/A 0.00000254 N/A N/A N/A 365 9.12 803000 6.1 12.9 348.6 14.57 60 14.7 29.65

5/22/2007 WAT2 0.0116 N/A N/A N/A N/A N/A N/A N/A 0 339.6 7.1 711000 7.2 11.6 330.5 14.85 60 14.7 30.23

5/23/2007 WAT1 0.0116 N/A N/A N/A N/A N/A N/A N/A 0 364.8 6.7 725000 7.2 11.7 325.5 14.76 60 14.7 30.05

7/24/2007 WAT1 N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 60 14.7 N/A

5/13/2008 WAT1 0.0122 N/A N/A N/A N/A N/A N/A N/A 0 368.9 6.4 811000 6.5 13.1 322.3 14.61 60 14.7 29.74

5/21/2008 WAT2 0.0286 N/A N/A N/A N/A N/A N/A N/A 0 373.3 6.8 738000 7.1 11.9 323 14.37 60 14.7 29.25

12/9-

10/2008 WAT1 N/A N/A N/A N/A N/A 0.00000123 N/A N/A N/A 355 5.96 N/A 6.33 13.1 310 N/A 60 14.7 N/A

2/23/2009 WAT2 N/A N/A N/A N/A N/A 0.00000182 N/A N/A N/A 350 6.78 N/A 5.65 13 350 N/A 60 14.7 N/A

2/24/2009 WAT1 N/A N/A N/A N/A N/A 0.00000338 N/A N/A N/A 369.5 13.7 N/A 6.53 305 305 N/A 60 14.7 N/A

5/5/2009 WAT1 0.0533 N/A N/A N/A N/A N/A N/A N/A 0 365.1 7.4 759000 7.4 11.9 324.4 14.64 60 14.7 29.79

6/9/2009 WAT2 0.0237 N/A N/A N/A N/A N/A N/A N/A 0 345.2 7.9 734000 7.1 11.8 330.6 14.43 60 14.7 29.37

 

41 Provide emission test data for all tests conducted since January 1, 2005. Please include 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.

42 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 (°F), Flue gas pressure at sampling point (atm), Standard temperature (°F), Standard pressure (atm).

43 If emission testing recorded the emission 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.

44 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium; indicate emission level for all metal HAP for which an emission test has been conducted.

45 Please provide separate results for total Hg, elemental Hg, oxidized Hg, and particulate Hg, as available. If the emission s testing recorded the amount of unburned carbn in fly ash (as reflected by the “Loss on Ignition” *L.O.I.+) at the time of any Hg testing, please 

include these data.
1

PART I: GENERAL FACILITY INFORMATION

1. Name of legal owner of facility:

South Carolina Generating Company

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

South Carolina Electric & Gas

3. Address of ____ legal owner or ___X__operator:

100 SCANA Parkway

Cayce, SC 29033

4a. Plant Name (as reported on U.S. DOE/EIA Form-860 (2007), "Annual Electric Generator Report," 

schedule 2, line 1, page 37, question 1) or Plant Name (as reported on U.S. DOE/EIA Form EIA-923 

(2008), "Power Plant Operations Report," schedule 2, page 1, question 1):

Williams

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

question 2) or Plant ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), schedule 2, page 1, 

question2):

3298

5. Complete street address of facility (physical location):

2242 Bushy Park Road

Goose Creek, SC 29445

6. Provide mailing address is different:

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

Ken Dantzler, Engineer

8. Contact(s) telephone number(s):

(803) 217-7156

9. Is the facility considered to be owned or operated by a small entity as defined by the Regulatory 

Flexibility Act? ____ Yes __X__ No ____ Don’t know
2

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

____ other (specify in question 14 below)

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

Fuel Rank % Btu Basis % Mass Basis

Lignite

Bituminous 100 100

Sub-bituminous

Pet coke

Synfuel (including, but not limited to, briquettes, pellets, or 

extrusions which are formed by binding materials, or processes that 

recycle materials

Please specify type or form of synfuel used

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

Oil Rank % Btu Basis % Volume 

Basis

Distillate 100 100

Residual or bunker C

Other (specify)

 

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% subbituminous/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 volume and on a 

Btu basis) of each fuel oil rank (e.g. 85% residual oil/15% distillate).
3

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 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.

Other Material Permitted to 

burn

Actually 

burned

Quantity/year

Specification Used Oil Yes No

Distillate fuel oil equivalents Yes No

Employee-generated used oil Yes No

Oil-contaminated filter media Yes No

Oil-contaminated soil or sand Yes No

Oily rags Yes Yes 37 drums (5,550 lbs)

Other oily debris Yes No

Spent oil absorbent Yes No

Coal Synfuel:

Covol Technologies(Synthetic Binder)

Halren J316 v203W LN

Heritage HES Emulsion (AM-ELIS395)

Heritage ECS Emulsion (AM-ELIZ371)

Nalco 7899

Nalco 9838 binder(water based vinyl 

polymer)

RAMSorb200 (polymer based moisture 

absorbent)

Seaco

Yes No

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, where 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 _X__ No

Explain:

The quantities burned are so small and infrequent that it would not be worth subjecting the 

source to section 129 unless the requirements do not create additional burdens beyond the 

existing requirements of SC 61-62.5 Std. 3 Waste Combustion and Reduction.

 

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 type was combusted (e.g. “the permitting agency allowed this fuel to be combusted for special 

testing and research purposes”).
4

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 WIL1

Original Design fuel (i.e. coal rank or 

type of oil)

Bunker C

Converted to Bit. Coal, Oil & Gas in 1984

Design heat input, (MMBtu/hr)75500*

Present maximum heat input 

(MMBtu/hr)8 5701.2

MWe Gross capacity

summer

654

MWe Net capacity

Summer 610

Original design gross efficiency (%, 

HHV) 90.37

Present operating gross efficiency (%, 

HHV) 88.62

Design steam pressure

(psig) 3500

Operating steam pressure

(psig) 3500

Design steam temperature

(°F) 1000

Operating steam temperature

(°F) 1000

Design steam reheat temperature 

(°F)9 1000

Operating steam reheat temperature 

(°F)10 1000

Fuel11 99.7% Bit. Coal

0.03% Dist. Oil

0% NG

Hours/year operated12 7216.56

Average annual capacity factor for 

the past 3 years 73.24%

Applicable NSPS Not covered under NSPS

Estimated year of retirement13 CBI

* Rate is Nominal.

 

6

Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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.
5

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

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

following the boiler, etc.):

Boiler 

ID14

Type15 NOx control16 Date SO2 control17 Date PM control18 Date Other control19

WIL1 Tang. Fired

Wet Bottom

Low NOx Burners (1)

Low NOx Optimization (2)

SCR (3)

 Vanadium Catalyst

 Anhydrous 

Ammonia Reagant

9/1999

12/2001

5/2004

Wet Scrubber (5)

Limestone is Calcium based

10/2009 Cold Side ESP 

(4)

1984

Control equipment order for each unit is listed in parenthesis.

 

14 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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, aqueous ammonia, urea, other). Also, please note if the 

catalyst is specifically designed to reduce SO3 formation.

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

control went online or planned operational date for new installation.

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

online or planned operational date for new installation.

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

dry sorbent injection or wet ESP for SO3 control; flue gas conditioning to control opacity (e.g. SO3 injection, ammonia, other); additive use for mercury control 

(e.g. bromine, scrubber additives). Include specific date that control went online or planned operational date for new installation. Also include any pollutants 

controlled by this other technology (e.g. control technology [pollutant controlled]).
6

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

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

Name Telephone Address

Williams Station has not participated in any HAP specific control technology demonstration project.

 

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 Generator 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

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 operationg), 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) in use or fuel type upon which the demonstration was conducted. Please specify the format of 

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

reduction, provide (1) and 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 enddate

Type of control 

(e.g., sorbent and 

type; chemical 

additive23)

Desired HAP 

emission 

reduction (%) or 

emission rate

Coal rank(s) in 

use

 

22 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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
8

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

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

purpose of providing a non-demonstration, full-scale operating system.

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

Name Telephone Address

No primary HAP control technology installed for full scale operating system 

 

24 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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).
9

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

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

combustion 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) or fuel type upon which the guarantee is based. Please specify the format of the guarantee (e.g., 

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

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

reduction (i.e. where the “inlet” and “outlet” are).

Boiler ID25 Actual start-up 

date

Expected or 

projected startup date

Type of control 

(e.g., sorbent and 

type; chemical 

additive26)

Guaranteed HAP 

emission 

reduction (%) or 

emission rate

Sorbent or 

additive feed rate 

on which 

guarantee is 

based

Coal rank(s) upon 

which guarantee 

is based

 

25 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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
10

21. For each boiler noted in Part I, question 15, provide the following information:

Boiler ID27 WIL1 Permitted Emission Limit Averaging 

Period

Compliance Method (PM 

only)

Permit Type

PM28 0.239 lb/MMBtu 3 hr Annual Method 5 Title V

PM10

29

PM2.5

30

SO2 2.3 lb/MMBtu 24 hr Title V

HCl and/or HF

HCN

Metal HAP31

Note: only applies if burning 

waste other than virgin fuel

Nickel 6.0x10-3lb/MMBtu Not 

Specified

Chemical analysis Title V

Cadmium 1.0x10-4lb/MMBtu

Chromium 7.4x10-4lb/MMBtu

Arsenic 1.7x10-3lb/MMBtu

Lead 5.0x10-3lb/MMBtu

Hg

CO

Other organics (specify)

Other pollutant (specify)

 

27 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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 include 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 and selenium; indicate permit level for 

all metal HAP for which a permit limit is in place.
11

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

Boiler ID32 WIL1 Most recent guaranteed emission rate for each pollutant for which there is a permitted emission limit

PM33 0.239 lb/MMBtu

PM10

PM2.5

SO2

2.3 lb/MMBtu

HCl and/or HF

HCN

Metal HAP34 No controls or emission rate guarantees are in place for metallic HAPs

Hg

CO

Other organics (specify)

Other pollutant (specify)

23. Was any other guarantee level sought or offered? Yes ___ No __X_ Please elaborate.

Control equipment was designed to meet current emission limits in place at the time of installation.

 

32 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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 rates for filterable and condensable PM, respectively, please include those separate emission rates.

34 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium; indicate permit level for 

all metal HAP for which a permit limit is in place.
12

24. For each boiler noted in Part I, question 15, provide the following information:

Boiler ID35 WIL1 Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a 

permitted emission limit

PM36

Testing: In accordance with SC Regulation 61-62.5 Standard 1 Section IV B, semiannual

particulate matter testing shall be performed on this source, using a site-specific test plan that

has been approved by the Bureau of Air Quality. Unless otherwise approved by the Bureau in

writing, semiannual testing shall be scheduled to occur during each 2nd and 4th quarter of the

Title V operating permit year. For purposes of this operating permit, the first Title V operating

permit year begins on the effectivity date of this permit. Subsequent Title V operating permit

years begin on the anniversary of the effectivity date. Except where approved by the Bureau

of Air Quality, particulate matter testing shall be simultaneously conducted with opacity

testing. If any applicable COMs data recorded in a quarter shows exceedances above the

opacity standard, the Bureau may require the permittee to perform additional actions to

demonstrate compliance with the particulate matter standard. Actions may include, but are not

limited to, additional particulate matter source testing.

Upon demonstration that the source is emitting less than eighty percent (80%) of its particulate

matter limit, as shown by three (3) consecutive particulate matter source tests, the requirement

for semi-annual testing is waived and the source may commence periodic source testing on an

annual frequency. The next particulate matter source test shall then be scheduled and

conducted in the following Title V operating year, but within the same quarter as the previous

particulate matter source test was conducted. Unless otherwise directed by the Bureau, a

source shall conduct a minimum of one particulate matter source test during each Title V year.

Each periodic particulate matter test is to be performed in accordance with the provisions of

R.61-62.1, Section IV, Source Tests. The site-specific test plan filed in accordance with

 

35 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator 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 monitor, keep records, and report filterable and condensable 

PM separately, please describe the separate actions required.
13

Boiler ID35 WIL1 Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a 

permitted emission limit

General Condition GC2 shall stipulate for Bureau review approval a minimum average hourly

boiler heat input rate or generator output rate at which the unit will be operated during the

course of the periodic test. In its review approval of the proposed minimum average hourly

boiler heat input rate or generator output rate, the Bureau of Air Quality may consider the

actual maximum hourly heat input the unit has achieved during the preceding 60 months in

addition to fuel test results, the margin of compliance demonstrated by the unit under test, and other factors. If any 

performance test is conducted for purposes of this condition and actual

average hourly heat input rates or generator output rates during the test are less than the

minimum average hourly heat input rate or generator output rate contained in the site-specific

test plan, the Department may impose operating restrictions on the unit’s maximum allowable

hourly heat input or generator output rate, until the facility has demonstrated compliance at a

higher heat input rate or generator output rate by means of a satisfactory performance test.

Monitoring/Record Keeping/Reporting/Other: All particulate matter test reports shall be

submitted to the Manager of the Source Evaluation Section of the Bureau of Air Quality no

later than 30 days after the completion of the on-site testing, except as allowed per provisions

of SC Regulation 61-62.1, Section IV(F)(1).

PM10 NA

PM2.5 NA

SO2

Monitoring/Record Keeping/Reporting/Other: The owner/operator shall continue to

operate CEMS for monitoring and reporting emissions of SO2. In determining Emission Rates

for SO2, the owner/operator shall use CEMS in accordance with methods specified in 40 CFR

Parts 60 and 75.

Quarterly CEMS Reports shall be submitted to the Manager of the Technical Management

Section, Bureau of Air Quality postmarked no later than 30 calendar days after the end of the

reporting period. These reports shall include the 24 hour block average (24-one hour

measurements which are summed and divided by 24) sulfur emission rates in pounds per

million Btu, using unbiased data collected from the 40 CFR Part 75 acid rain CEMS or from

fuel sampling and analysis procedures described in Sections 5.2.1 – 5.2.3 of 40 CFR Part 60,

Appendix A, Reference Method 19 provided that;

1) Hourly fuel samples are collected at a location as close to the burners as possible,

2) The minimum size of each hourly sample is 0.13 cubic feet,

3) The hourly samples are composited into one sample every 24 hour period with the

composited sample thoroughly mixed and analyzed by methods specified in Method 19,

4) Gross calorific value and sulfur content shall be determined on a dry basis, and

5) The sulfur dioxide emission rate shall be calculated as follows:
14

Boiler ID35 WIL1 Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a 

permitted emission limit

SO2 pounds per million Btu = (1.9) (sulfur weight fraction) / million Btu per pound coal

Sources using Reference Method 19 for determination of missing data as described in 40 CFR

Part 75, Subpart D, shall comply with provisions 1-5 above except that hourly fuel samples

shall be composited into one sample every 24 hour period or for the duration of the CEMS

unavailability period, whichever is less.

The maximum allowable sulfur content in the coal fuel, expressed as a 24-hour average in units of percent

by weight dry basis, shall be 1.32%. This limit shall remain in effect until the new wet limestone slurry flu

gas desulfurization scrubber becomes operational for removing SO2 emissions from the UB1 utility boiler.

The owner/operator shall measure and record the fuel sulfur content for the 24-hour period, in units of

percent by weight, dry basis. For purposes of this condition, the term “24-hour period”, shall mean the 24-

hour period between 12 midnight and the following midnight during which any coal fuel is combusted at

any time in the UB1 boiler. It is not necessary for fuel to be combusted during the entire 24-hour period.

HCl and/or HF NA

HCN NA

Metal HAP37 Total heat input shall include the Btu from all waste and virgin fuel being combusted. Furthermore, the

maximum total heat input value to be used in determining the emission limitations shall be limited to the

Btu’s necessary to maintain production. The Btu from other sources, such as afterburners, shall not be

considered in determining this total heat input value unless those auxiliary burners are fired with waste. In

the case where waste is fired in the auxiliary burners located outside of the primary combustion chamber,

only the Btu value of the fuel for the auxiliary burner which is from waste shall be added to the total heat

input value. Source testing for metals or HCl will not be required while combusting waste having no metals

or chlorine in the waste. Analysis showing these constituents to be non-detectible by reference method in

the waste is an alternative method for determining compliance with emission limits as allowed by R.61-

62.5, Standard 3, Section VIII(A).

This source is permitted to burn small quantities of waste that is generated by the owner/operator and

specified by this permit. The waste shall be burned as described in the following table:

Boiler Size 

(1x106 Btu/hr)

Waste Firing Rate

(heat input of waste / total heat input of waste and virgin 

fuel)

>10 - 50 0.1

 

37 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium; indicate permit level for 

all metal HAP for which a permit limit is in place.
15

Boiler ID35 WIL1 Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a 

permitted emission limit

>50 0.06

When burning wastes specified by this condition, this boiler is exempt from the requirements of S.C.

Regulation 61-62.5 Standard 3 except as follows:

a. There must be a valid permit for the boiler which specifies the exact waste to be burned.

b. Analysis may be required to prove that the material to be burned is one of the substances

authorized by the permit.

c. Records of the materials being burned (i.e., gallons per month or tons per month) and its firing rate

must be kept and made available to the Department upon request.

Hg NA

CO NA

Other organics (specify) NA

Other pollutant (specify) NA

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

Facility Name/Unit No.:________________________ Retrofit to existing boiler? _______ Installation on new boiler? ______ 

Total Capital Investment $:

Total Annual Operating and Maintenance Costs: $: (Include base year for operating costs [e.g., 2006])

No control technologies

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

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

No

 

38 This can be treated as CBI and can be submitted through the proper CBI procedure if desired.
16

PART II: FUEL ANALYSIS AND EMISSION DATA

Fuel Analysis39

Each facility should provide the following information for each coal and oil shipment received during 

the preceding 12 calendar months.

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

Williams

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

3298

 

39 The respondent should reply to this ICR with separate pages 18 through 24 (Part II) for each of their facilities.
17

2, 3 & 4. For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, 

as available (indicate N/A in not available; use additional pages, as necessary):

CBI
18

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

Provided 

by Supplier Name Address

Supplier TECO COAL CORPORATION 200 Allison Blvd

Corbin, KY 40701

Supplier ALLIANCE COAL CORPORATION 152 West Valley Street

Abingdon, VA 24210

Supplier MASSEY COAL SALES COMPANY INC Massey Utility Sales Co

Richmond, VA 23219

Supplier ARCH COAL SALES COMPANY INC City Place One, Suite 350

St. Louis, MO 63141

Supplier LOGAN & KANAWHA COAL COMPANY INC 96 Maccorkle Ave, SW

S. Charleston, WV 25303

Supplier GLENCORE LTD 3 Stamford Plaza

Stamford, CT 06901

Supplier COALSALES LLC 701 Market Street, Suite 831

St. Louis, MO 63101

Supplier NRG ENERGY INC 901 Marquette Ave, Suite 2300

Minneapolis, MN 55402

Supplier INTERAMERICAN COAL S.A. Bogota

Supplier CONSTELLATION ENERGY COMMODITIES 

GROUP 

111 Market Place, Suite 500

Baltimore, MD 21202

Other SCE&G-Central Lab 2102 North Lake Drive

Columbia, SC 29212

7. In addition to the analyses required in Part II, question 3 above, for samples for which 

analyses f 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.

No additional analyses have been conducted.
19

Emission Data

8a. What emission test reports(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.

Filterable Particulate Matter and Speciated Mercury

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.

Date Unit Type Parameter

11/15/2005 WIL1 PM Filterable Particulates

11/15/2005 WIL1 Hg SPECIATED MERCURY

6/27/2006 WIL1 NOX,SO2, 

SO3,CO2,PARTICULATE,HCL/HF,Hg

NOX,SO2, 

SO3,CO2,PARTICULATE,HCL/HF,Hg

9/26/2006 WIL1 PM Filterable Particulates

9/20/2007 WIL1 PM Filterable Particulates

9/16/2008 WIL1 PM Filterable Particulates

9/16/2008 WIL1 PM Condensable Particulates

12/16/2008 WIL1 Hg SPECIATED MERCURY

3/5/2009 WIL1 Hg Total Hg

7/21/2009 WIL1 PM Filterable Particulates

7/21/2009 WIL1 PM CONDENSIBLES

12/22/2009 WIL1 Hg Total Hg

12/22/2009 WIL1 Hg SPECIATED MERCURY

7/21/2009 WIL1 PM Condensable Particulates

7/11/2006 WAT2 NOX,SO2, 

SO3,CO2,PARTICULATE,HCL/HF,Hg

NOX,SO2, 

SO3,CO2,PARTICULATE,HCL/HF,Hg

8c. Do any of these test reports reflect testing at a location upstream of 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 points(s).

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 note 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.
20

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 the time of testing in a similar format to Part I, question 16.

8g. Do any of these test reports reflect testing at a location upstream of a post combustion 

SO2 emission control device (e.g., FGD, SDA, Dry Scrubber)? Yes___ No__X__ If yes, please note 

which reports and, in addition to the detailed description of the location of the sampling point(s) 

(question8c above), include detail about how much, if any, bypass of unscrubbed flue gas was 

utilized at the time of testing (including percentage of total scrubber exhaust 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?

Only COMS reports for Opacity deviations

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.

COMS reports

11. Are continuous emissions monitoring system (CEMS) data available (e.g., mercury, 

continuous opacity monitoring systems) that are not already being provided to the U.S. EPA or 

permit authority, even if from short-term testing? Yes ____ No__X__ If yes40, please note for 

which pollutants CEMS data are available and the period of time (both total period and calendar 

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

which Office the data are being provided.

 

40 Where units are monitored by CEMS (either following CAMR, State, or NIST QA/QC procedures), and where data 

are available, EPA requests that these CEMS data be submitted by the respondent. The respondent should also 

mark the periods of star up, shut down and malfunction events (SSM) in the data sets.
21

12. For each boiler noted in Part I, question 15, provide the following information:41,42 43, 44, 45

Date of 

Test

Boiler 

ID

PM SO2 HCL/HF Metal 

HAP

Hg CO Unit Flue Gas

Filt Cond Total Elemental Oxidized Load Moist Flow O2 CO2 Temp Press STD Temp STD Press Press

#/mmBTU #/mmBTU #/mmBTU #/mmBTU #/mmBTU #/mmBTU #/mmBTU #/mmBTU % MW % dscfm % %

o

F psia

o

F psia in Hg

11/15/2005 WIL1 0.018 N/A N/A N/A N/A N/A N/A N/A 0 640 6.5 1314000 5.9 13 323.7 14.70 60 14.7 29.92

11/15/2005 WIL1 N/A N/A N/A N/A N/A 0.00000113 0.00000019 0.00000078 N/A 640 N/A N/A N/A N/A N/A N/A 60 14.7 N/A

6/27/2006 WIL1 0.00689 N/A N/A 0.00562/0.0102 N/A 0.00000117 N/A N/A N/A N/A 9.27 1366000 5.82 13.2 325.3 14.50 60 14.7 29.52

9/26/2006 WIL1 0.0055 N/A N/A N/A N/A N/A N/A N/A 0 651.1 6 1415000 5.2 12.6 314.7 14.68 60 14.7 29.88

9/20/2007 WIL1 0.0053 N/A N/A N/A N/A N/A N/A N/A 0 647.4 6.6 1418000 5.4 13.2 309.3 14.71 60 14.7 29.95

9/16/2008 WIL1 0.0042 N/A N/A N/A N/A N/A N/A N/A 0 640.9 7.1 1365000 6.5 12.4 323.7 14.72 60 14.7 29.96

9/16/2008 WIL1 N/A 0.0203 N/A N/A N/A N/A N/A N/A N/A 640.9 N/A N/A N/A N/A N/A N/A 60 14.7 N/A

12/16/2008 WIL1 N/A N/A N/A N/A N/A 0.00000157 N/A N/A N/A 640.4 7.18 N/A 7.92 11.5 300.7 N/A 60 14.7 N/A

3/5/2009 WIL1 N/A N/A N/A N/A N/A 0.00000178 N/A N/A N/A N/A N/A N/A 6.48 N/A 305 N/A 60 14.7 N/A

7/21/2009 WIL1 0.014 N/A N/A N/A N/A N/A N/A N/A 0 635.1 7.9 1326000 5.6 13.2 339.6 14.70 60 14.7 29.93

7/21/2009 WIL1 N/A 0.0341 N/A N/A N/A N/A N/A N/A N/A 635.1 N/A N/A N/A N/A N/A N/A 60 14.7 N/A

12/22/2009 WIL1 N/A N/A N/A N/A N/A 0.000000281 N/A N/A N/A 640.4 13.7 N/A 6.2 13.6 125 N/A 60 14.7 N/A

 

41 Provide emission test data for all tests conducted since January 1, 2005. Please include 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.

42 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 (°F), Flue gas pressure at sampling point (atm), Standard temperature (°F), Standard pressure (atm).

43 If emission testing recorded the emission 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.

44 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium; indicate emission level for all metal HAP for which an emission test has been conducted.

45 Please provide separate results for total Hg, elemental Hg, oxidized Hg, and particulate Hg, as available. If the emission s testing recorded the amount of unburned carbn in fly ash (as reflected by the “Loss on Ignition” *L.O.I.+) at the time of any Hg testing, please 

include these data.