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, pa ge 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 stree t address of facility (physical location):

13139 Augusta Highway

Canadys, SC 294 88

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 know2

10. Which of the following fossil fuels or other material(s) ar e 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 permitted 1 to be fired in any st eam

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 combuste d (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 o r 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 permitted 5 to 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 class ified 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 q uantities 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 combu sted for special

testing and research purposes”).4

15. Identification (or de signation) of all coal

- and oil

- fired steam generating units (boilers)(as

defined by Clean Air Act section 112(a)(8)) located at this facility.

Boiler ID 6 CAN1 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) 7 1161 * 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

Fuel 11 100% 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 operated 12 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 retirement 13 CBI 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 s chedule 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 high er 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 ID 14 Type 15 NO

x control 16 Date SO 2 control 17 PM control 18 Date Other control 19

CAN1 Tang. Fired

Wet B ottom 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 Gener ator 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

- NO

x 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, o ther). Also, please note if the

catalyst is specifically designed to reduce SO 3 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: fabri c 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, SO

3 , etc.). Examples: activated carbon injection (ACI); Powerspan ECO;

dry sorbent injection or wet ESP for SO

3 control; flue gas conditioning to control opacity (e.g. SO

3 injection, ammonia, other); additive use f or mercury control

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

controlled by this other technology (e.g. control technology [pollutant con trolled]).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 i nstalled for the

purpo se of participating in a control technology demonstration project 20 (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 ID 21 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) sponsore d (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 b ut 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 emi ssion

reduction or rate (if any), and the coal rank(s) in use or fuel type upon which the demonstration was conducted. Please spec ify 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 em ission rate),

and (2) the basis for calculating the percent reduction (i.e. where the “inlet” an d “outlet” are).

Boiler ID 22 Demonstration

activity actual

start

- up date Demonstrat i on

activity projected

start

- up date Demonstration

activity end

- date

or projected end

date Type of control

(e.g., sorbent and

type; chemical

additive 23 ) D esired 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 Gener ator 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 point8

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

(e.g., mercury, hydrogen chloride, etc.) control technology th at you have either contracted f o r , are installing, or have installed for the

purpose of providing a non

- demonstration, full

- scale operating system.

Boiler ID 24 Company (Vendor) name Company (vendor) contact information

Name Tel ephone 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 Genera tor 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 Gener ator 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 gu arantee (e.g.,

lb/MWh, lb/TBtu, percent reduction, etc.). If the format of the guarantee is perce nt 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 ID 25 Actual start

- up

date Expected or

projected start

up date Type of control

(e.g., sorbent and

type; chemical

additive 26 ) Guaranteed HAP

emission

reduction (%) or

emission rate Sorbent or

additive feed rate

on which

guarantee is

based Coal rank(s) upon

which g uarantee

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 injectio n point10

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

Boiler ID 27 CAN1

,

CAN2,

CAN3 Permitted Emission Limit Averaging

Period Compliance Method

( PM only ) Permit Type

PM 28 0.6 lb/MMBtu

0.47 lbMMBtu (CAN3) 3 hr A nnual Method 5 Title V

PM 10 29

PM 2.5 30

SO 2 3.5 lb/MMBtu 24 hr Title V

HCl and/or HF

HCN

Metal HAP 31

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 pl ants 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, respectivel y, 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, chro mium, 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 ID 32 CAN1

,

CAN2,

CAN3 Most recent guaranteed emission rate for each pollutant for which there is a permitted emission limit

PM 33 0.6 lb/MMBtu

0.47 lbMMBtu (CAN3)

PM 10

PM 2.5

SO 2 3.5 lb/MMBtu

HCl and/or HF

HCN

Metal HAP 34

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, p age 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 Gener ator 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 se parate emission rates.

34 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cob alt, 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 ID 35 CAN1 , CAN2,

CAN3 Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a

permitted emission limit

PM 36 

### 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

ave raging 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 an d 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 particul ate 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 cont rol 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 excursion s 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 grea ter 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 ID 35 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.

PM 10 NA

PM 2.5 NA

SO 2 

### 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 ra tes 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 analyze d 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 HAP 37 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 lev el 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 Analysis 39

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 thei r 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):



### CBI17

5.& 6. Analyses provided in Par t 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

av ailable 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 cond ucted.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 prog rams, 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, f uel, 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 report s 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

SO 2 emission contr ol 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 unscrubbe d 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 reports20

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 yes 40 , please

note for which pollutants CEMS data are available and the period of time (both total period and calendar period) for which da ta 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 d 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/m 3 Hours 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 SO 2 HCL/HF Metal

HAP Hg CO Unit Flue Gas

Filt Cond Total Elemental Oxidized Load Moist Flow O 2 CO 2 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 d uring run (MWh net), Flue gas moisture content (%), Flue gas flow rate(dscfm or Nm 3 /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), Stan dard temperature (°F), Standard pressure (atm).

43 If emi ssion testing recorded the emission of filterable and condensable PM, separately, please include those separate emission resu lts. Also, please include separate emission results for total PM, PM

10 , and PM 2.5

.

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

45 Please provide separate results for total Hg, elemental Hg, oxidized Hg, and particu late Hg, as available. If the emission s testing recorded the amount of unburned carbon in fly ash (as reflected by the “Los s 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, pa ge 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 know2

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 permitted 1 to be fired in any steam

generat ing 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 combuste d (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 o r 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 permitted 5 to 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 t o 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 an d 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 combu sted 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 ID 6 COP 1

Original Design fuel (i.e. coal rank

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

Design heat input, (MMBtu/hr) 7 4000 *

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

Fuel 11 99.93% Bit. Coal

0.07% #2 Oil

0% NG

Hours/year operated 12 7546.36

Average annual capacity factor

for the past 3 years 76.77 %

Applicable NSPS 40 CFR 60, Subpart Da

Estimated year of retirement 13 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 s chedule 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 high er 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 inst alled 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

ID 14 Type 15 NO

x control 16 Date SO 2 control 17 Date PM control 18 Date Other control 19

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 Gener ator 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

- NO

x 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

th e catalyst is manufactured and the type of reductant used in with the SCR (e.g. anhydrous ammonia, aqueous ammonia, urea, oth er). Also, please note if the

catalyst is specifically designed to reduce SO

3 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, SO

3 , etc.). Exa mples: activated carbon injection (ACI); Powerspan ECO;

dry sorbent injection or wet ESP for SO

3 control; flue gas conditioning to control opacity (e.g. SO

3 injection, ammonia, other); additive use for mercury control

(e.g. bromine, scrubber additives). In clude 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 eac h HAP

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

purpose of participating in a control technology demonstration project 20 (e.g., U.S. Department of Energy program, consent decree, etc.).

Boiler ID 21 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 i s 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 demonst rate 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 pag e 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 typ e 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 wa s 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 ID 22 Demonstration

activity actual

start

- up date Demonstrat i on

activity projected

s tart

- up date Demonstration

activity end

- date

or projected end

date Type of control

(e.g., sorbent and

type; chemical

additive 23 ) D esired 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 Gener ator ID (as reported on U.S.

DOE/EIA Form EIA

- 923 (2008), “Po wer Plant Operations Report,” schedule 5, part A, page 8).

23 If additive is used, please indicate injection point8

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 th at you have either contracted f o r , are installing, or have installed for the

pu rpose of providing a non

- demonstration, full

- scale operating system.

Boiler ID 24 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 pla nts 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 Gener ator 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 w hat an

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

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

Boiler ID 25 Actual start

- up

date Expected or

projected start

up date Type of control

(e.g., sorbent and

type; chemical

additive 26 ) Guaranteed HAP

emission

reduction (%) or

emission rate Sorbent or

additive feed rate

on which

guarantee is

based Coal rank(s) upon

which guarantee

is based

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 plant s 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 point10

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

Boiler ID 27 COP 1 Permitted Emission Limit Averaging

Period Compliance Method

( PM only ) Permit Type

PM 28 0.02 lb/MMBtu 3 hr A nnual Method 5 Title V

PM 10 29

PM 2.5 30

SO 2 0.25 lb/MMBtu 24 hr Title V

HCl and/or HF

HCN

Metal HAP 31

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 Gener ator ID (as reported o n 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 se parate limits. Also include th e

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; indic ate 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 ID 32 COP1 Most recent guaranteed emission rate for each pollutant for which there is a permitted emission limit

PM 33 0.02 lb/MMBtu

PM 10

PM 2.5

SO 2 0.25 lb/MMBtu

HCl and/or HF

HCN

Metal HAP 34

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 le ss 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 guarant eed 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 permi t 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 ID 35 COP 1 Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a

permitted emission limit

PM 36 

### 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 subj ect 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

- b lowing. 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

u nit 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 consecu tive 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 1 00 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 repo rt filterable and condensable

PM separately, please describe the separate actions required.13

Boiler ID 35 COP 1 Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a

permitted emission limit



### visual emission obs e rvations 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 produc tion, 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 Quali ty 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.

PM 10 NA

PM 2.5 NA

SO 2 

### 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 NA14

Boiler ID 35 COP 1 Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a

permitted emission limit

Metal HAP 37

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 boile r 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 antim ony, 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 de sired.15 PART II: FUEL ANALYSIS AND EMISSION DATA

Fuel Analysis 39

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):

CBI17

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, questio n 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 dat a 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 report s 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

SO 2 emission contr ol 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 unscrubbe d flue gas was19

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,

SO 2 and NO

x 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 SO

2 and NO

x reports20

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 yes 40 , please

note for which pollutants CEMS data are available and the period of time (both total period and calendar period) for which da ta 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/m 3 Hours 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 reque sts that these CEMS

data be submitted by the respondent. The respondent should also mark the periods of star up, shut down and malfunction event s (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 SO 2 HCL/HF Metal

HAP Hg CO Unit Flue Gas

Filt Cond Total Elemental Oxidized Load Moist Flow O 2 CO 2 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 da t a 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 fu ture 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 av eraging times and measurement units for all pollutants.

42 For each emissions test run the respondent should provide the fol lowing process information: Unit Load (MW), Net generation during run (MWh net), Flue gas moisture content (%), Flue gas flow rate(dscfm or Nm 3 /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 emissio n results. Also, pleas e in clude separate emission results for total PM, PM

10 , and PM 2.5

.

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 t est 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, pa ge 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 add ress 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) ar e 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 permitted 1 to be fired in any ste am

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 combuste d (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 o r 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 permitted 5 to 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 utilizi ng 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 combu sted 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 Ac t section 112(a)(8)) located at this facility.

Boiler ID 6 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) 7 1134 * 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

Fuel 11 99.83% Bit. Coal

0.17% Dist. Oil

0% NG 99.88% Bit. Coal

0.12% Dist. Oil

0% NG

Hours/year operated 12 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 retirement 13 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 s chedule 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 high er 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 follow ing the boiler, 2 for second control following the boiler,

etc.):

Boiler

ID 14 Type 15 NO

x control 16 Date SO 2 control 17 PM control 18 Date Other

control 19

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

- NO

x 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 th e 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 SO

3 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, SO

3 , etc.). Examples:

activated carbon injection (ACI); Powerspan ECO; dry sorbent injection or wet ESP for SO

3 control; flue gas

conditioning to control opacity (e.g. SO

3 injection, ammonia, other); additive use for mercury control (e.g. bromine,

scrubber ad ditives). 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 project 20 (e.g., U.S. Department of Energy

program, consent decree, etc.).

Boiler

ID 21 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 start

up, the date the demonstration was completed, the typ e 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 wa s 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

ID 22 Demonstration

activity actual

start

- up date Demonstrat i on

activity

projected s tart

up date Demonstration

activity end

date or

projected end

date Type of

control

(e.g.,

sorbent

and type;

chemical

additive 23 ) D esired

HAP

emission

reduction

(% ) or

emission

rate Coal

rank(s)

in use

20 A control technology demonstrati on 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 techn ology’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 Electr ic 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 point7

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 th at you have either contracted f o r , are installing, or have installed for the purpose of

providing a non

- d emonstration, full

- scale operating system.

Boiler

ID 24 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 che mical 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 f ormat 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), an d (2) the basis

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

Boiler

ID 25 Actual

start

- up

date Expected or

projected

start

- up

date Type of

control (e.g.,

sorbent and

type;

chemical

additive 26 ) Guaranteed

HAP emission

reduction (%)

or emission

rate Sorbent or

additive

feed rate on

which

guarantee is

based Coal rank(s)

upon which

guarantee is

based

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 point8

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

Boiler ID 27 MCM 1

,

MCM2 Permitted Emission Limit Averaging

Period Compliance Method

( PM only ) Permit Type

PM 28 0.03 lb/MMBtu 3 hr A nnual Method 5 Title V

PM 10 29

PM 2.5 30

SO 2 3.5 lb/MMBtu 24 hr Title V

HCl and/or HF

HCN

Metal HAP 31

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 Gener ator ID (a s 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 se parate limits. Als o 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 sel enium; 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 ID 32 MCM 1

,

MCM2 Most recent guaranteed emission rate for each pollutant for which there is a permitted emission limit

PM 33 0.03 lb/MMBtu

PM 10

PM 2.5

SO 2 3.5 lb/MMBtu

HCl and/or HF

HCN

Metal HAP 34

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 r eported on U.S.

DOE/EIA Form EIA

- 923 (2008), “Power Plant Operations Report,” schedule 5, part A, page 8).

33 If the boiler has sepa rate 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; in dicate permit level for

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

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

Boiler ID 35 MCM 1

,

MCM2 Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a

permitted emission limit

PM 36 

### 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 moni toring 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 completio n 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 opaci ty 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 a veraged 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 grea ter 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 ID 35 MCM 1

,

MCM2 Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a

permitted emission limit



### The permi ttee 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.

PM 10 NA

PM 2.5 NA

SO 2 

### 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/10 6 

### 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 b e calculated as follows:

l b

1 0 6 

### = 1

. 9 ( s u l f u r w e i g h t f r a c t i o n )

1 0 6 

### B t u l b c o a l

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 HAP 37

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

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

Boiler ID 35 MCM 1

,

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 sp ecify.

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 Analysis 39

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 thei r 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):

CBI15

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 anal yses, (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 samplin g 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, que stion 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, fu lfillment 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 Paramete r

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. Di d 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, ques tion 16.17

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

SO 2 emission control device (e.g., FGD, SDA, Dry Scrubber)? Yes___ No__ X __ If yes, please note

which reports and, in addition to the detailed descriptio n 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 sampli ng 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 reports18

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 yes 40 , 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/m 3 Hours 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 SO 2 HCL/HF Metal

HAP Hg CO Unit Flue Gas

Filt Cond Total Elemental Oxidized Load Moist Flow O 2 CO 2 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

1/17/2006 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 da t a 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 fol lowing process information: Unit Load (MW), Net generation during run (MWh net), Flue gas moisture content (%), Flue gas flow rate(dscfm or Nm 3 /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), Stan dard temperature (°F), Standard pressure (atm).

43 If emi ssion testing recorded the emission of filterable and condensable PM, separately, please include those separate emission resu lts. Also, pleas e include separate emission results for total PM, PM

10 , and PM 2.5

.

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 to tal Hg, elemental Hg, oxidized Hg, and particulate Hg, as available. If the emission s testing recorded the amount of unburn ed 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, pa ge 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 add ress 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 know2

10. Which of the following fossil fuels or other material(s) a re 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 permitted 1 to be fired in any steam

generating unit at this facility?

__ X __coal

__ X __oil (including pet coke)

__ X __ natural gas

__ X

__ Other (specify in question 14 below)

12. If coal or solid fuel, as described below, derived from a fossil source is fired, indica te 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 combuste d (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 o r 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 permitted 5 to 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 p ermitted 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 Co mbustion 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 combu sted 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 ID 6 URQ3

Original Design fuel (i.e. coal rank or

type of oil) Bit. Coal

Design heat input, (MMBtu/hr) 7 1100 *

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

Fuel 11 99.88% Bit. Coal

0.09% Spec. Oil

0.03% Dist. Oil

0% NG

Hours/year operated 12 7222.76

Average annual capacity factor for

the past 3 years 70.48%

Applicable NSPS Not Covered Under

NSPS

Estimated year of retirement 13 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 s chedule 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 high er 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 inst alled 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 ID 14 Type 15 NO

x control 16 Date SO 2 control 17 PM control 18 Date Other control 19

URQ3 Tang. Fired

W et 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 grea ter 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

- NO

x 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, o ther). Also, please note if the

catalyst is specifically designed to reduce SO

3 form ation.

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 contr ol any other pollutants (e.g. Hg, SO

3 , etc.). Examples: activated carbon injection (ACI); Powerspan ECO;

dry sorbent injection or wet ESP for SO

3 control; flue gas conditioning to control opacity (e.g. SO

3 injection, ammonia, other); additive use for mercu ry control

(e.g. bromine, scrubber additives). Include specific date that control went online or planned operational date for new instal lation. 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 eac h 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 project 20 (e.g., U.S. Department of Energy program, consent decree, etc.).

Boiler ID 21 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) sponsore d (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 fac ility’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 typ e 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 wa s 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 ID 22 Demonstration

activity actual

start

- up date Demonstrat i on

activity projected

s tart

- up date Demonstration

activity end

- date

or projected end

date Type of control

(e.g., sorbent and

type; chemical

additive 23 ) D esired HAP

emission

reduction (% ) or

emission rate Coal rank(s) in

use

22 Boiler ID (as reported on U.S. DOE/EI A 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 Gener ator 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 point8

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 th at you have either contracted f o r , are installing, or have installed for the

pu rpose of providing a non

- demonstration, full

- scale operating system.

Boiler ID 24 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 Repo rt,” 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 Gener ator ID (as reported on U.S.

DOE/EIA Form EIA

- 923 (2008), “Power P lant 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 w hat an

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

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

Boiler ID 25 Actual start

- up

date Expected or

projected start

up date Type of control

(e.g., sorbent and

type; chemical

additive 26 ) Guaranteed HAP

emission

reduction (%) or

emission rate Sorbent or

additive feed rate

on which

guarantee is

based Coal rank(s) upon

which guarantee

is based

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 point10

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

Boiler ID 27 URQ3 Permitted Emission Limit Averaging

Period Compliance Method

( PM only ) Permit Type

PM 28 0.6 lb/MMBtu 3 hr A nnual Method 5 Title V

PM 10 29

PM 2.5 30

SO 2 3.0 lb/MMBtu 24 hr Title V

HCl and/or HF

HCN

Metal HAP 31

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 gre ater 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, pleas e 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, co balt, 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 ID 32 URQ3 Most recent guaranteed emission rate for each pollutant for which there is a permitted emission limit

PM 33 0.6 lb/MMBtu

PM 10

PM 2.5

SO 2 3.0 lb/MMBtu

HCl and/or HF

HCN

Metal HAP 34

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 Gener ator 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 se parate emission rates.

34 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lea d, 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 ID 35 URQ3 Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a

permitted emission limit

PM 36 

### 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 equipme nt 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 plan ts 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 Gener ator 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 repo rt filterable and condensable

PM separately, please describe the separate actions required.13

Boiler ID 35 URQ3 Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a

permitted emission limit



### quarter show excursions above th e 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 th e period in question as required by SC Regulation 61

- 62.1, Section IV

– “Source Tests” before conducting the test.

PM 10 NA

PM 2.5 NA

SO 2 

### 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/10 6 

### 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:

l b

1 0 6 

### = 1

. 9 ( s u l f u r w e i g h t f r a c t i o n )

1 0 6 

### B t u l b c o a l

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 NA14

Boiler ID 35 URQ3 Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a

permitted emission limit

Metal HAP 37

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 t hrough the proper CBI procedure if desired.15 PART II: FUEL ANALYSIS AND EMISSION DATA

Fuel Analysis 39

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):

CBI17

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 calen dar 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 prog rams, 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, parametri c, 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 whi ch 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 for mat to Part I, question 16.

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

SO 2 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 was19

utilized at the time of testing (including percentage of total scrubber exhaust gas flow). Note by

d iagram 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 reports20

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 yes 40 , please

note for which pollutants CEMS data are available and the pe riod 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 Mont hly

Heat Input Emission Factor CEMS Total Monthly Total Monthly Average

from CEMS from CEMS Operating Hg Hg Monthly Hg

Urquhart 3 mmBTU uG/m 3 Hours 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), an d 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 event s (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 SO 2 HCL/HF Metal

HAP Hg CO Unit Flue Gas

Filt Cond Total Elemental Oxidized Load Moist Flow O 2 CO 2 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

2/3/2005 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 da t a 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 an d 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 fol lowing process information: Unit Load (MW), Net generation during run (MWh net), Flue gas moisture content (%), Flue gas flow rate(dscfm or Nm 3 /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), Standar d pressure (atm).

43 If emission testing recorded the emission of filterable and condensable PM, separately, please include those se parate emission results. Also, pleas e include separate emission results for total PM, PM

10 , and PM 2.5

.

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 re flected 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, pa ge 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 addr ess 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 know2

10. Which of the following fossil fuels or other material(s) ar e 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 permitted 1 to be fired in any ste am

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 o r 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 permitted 5 to 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 waste s, 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 requiremen ts 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 per mit 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 ID 6 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) 7 3577.5 * 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

Fuel 11 99.47% Bit. Coal

0.53% Dist. Oil 99.65% Bit. Coal

0.35% Dist. Oil

Hours/year operated 12 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 retirement 13 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 percent ages, 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 C BI procedure if desired.5

16. For each boiler noted in Part I, question 15, provide the following information for each current emission control device inst alled 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 ID 14 Type 15 NO

x control 16 Date SO 2 control 17 Date PM control 18 Date Other control 19

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 grea ter 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

- NO

x 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, o ther). Also, please note if the

catalyst is specifically designed to reduce SO

3 form ation.

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 contr ol any other pollutants (e.g. Hg, SO

3 , etc.). Examples: activated carbon injection (ACI); Powerspan ECO;

dry sorbent injection or wet ESP for SO

3 control; flue gas conditioning to control opacity (e.g. SO

3 injection, ammonia, other); additive use for mercu ry control

(e.g. bromine, scrubber additives). Include specific date that control went online or planned operational date for new instal lation. 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 i nstalled for the

purpose of participating in a control technology demonstration project 20 ( e.g., U.S. Department of Energy program, consent decree, etc.).

Boiler ID 21 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) sponsore d (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 fac ility’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 ID 22 Demonstration

activity actual

start

- up date Demonstrat i on

activity projected

start

- up date Demonstration

activity end

- date

or projected end

date Type of control

(e.g., sorbent and

type; chemical

additive 23 ) D esired HAP

emission

reduction (% ) or

emission rate Coal rank(s) in

use

22 Boiler ID (as reported on U.S. DOE/EI A 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 Gener ator 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 point8

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

(e.g., mercury, hydrogen chloride, etc.) control technology th at you have either contracted f o r , are installing, or have installed for the

purpose of providing a non

- demonstration, full

- scale operating system.

Boiler ID 24 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 Repo rt,” 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 Gener ator ID (as reported on U.S.

DOE/EIA Form EIA

- 923 (2008), “Power P lant 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

gua rantee is based, and the coal rank(s) or fuel type upon which the guarantee is based. Please specify the format of the guara ntee (e.g.,

lb/MWh, lb/TBtu, percent reduction, etc.). If the format of the guarantee is percent reduction, provide (1) an estimat e 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 ID 25 Actual start

- up

date Expected or

projecte d start

up date Type of control

(e.g., sorbent and

type; chemical

additive 26 ) Guaranteed HAP

emission

reduction (%) or

emission rate Sorbent or

additive feed rate

on which

guarantee is

based Coal rank(s) upon

which guarantee

is based

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 point10

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

Boiler ID 27 WAT 1

,

WAT 2, Permitted Emission Limit Averaging

Period Compliance Method

( PM only ) Permit Type

PM 28 0.34 lb/MMBtu 3 hr A nnual Method 5 Title V

PM 10 29

PM 2.5 30

SO 2 3.5 lb/MMBtu 24 hr Title V

HCl and/or HF

HCN

Metal HAP 31

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 gre ater 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, pleas e 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, co balt, 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 ID 32 WAT1, WAT2 Most recent guaranteed emission rate for each pollutant for which there is a permitted emission limit

PM 33 0.34 lb/MMBtu

PM 10

PM 2.5

SO 2 3.5 lb/MMBtu

HCl and/or HF

HCN

Metal HAP 34

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 Gener ator 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 se parate 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 ID 35 WAT 1

, WAT 2 Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a

permitted emission limit

PM 36 

### 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 pr otoco1. 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 p articulate

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 v alue 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

- 8 60 (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 Gener ator 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 repo rt filterable and condensable

PM separately, please describe the separate actions required.13

Boiler ID 35 WAT 1

, WAT 2 Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a

permitted emission limit



### shutdown, and malfu nction 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

particula te 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.

PM 10 NA

PM 2.5 NA

SO 2 

### 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 co mposited 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 HAP 37 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 i n place.14

Boiler ID 35 WAT 1

, WAT 2 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 s pecify.

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 Analysis 39

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):

CBI17

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 prog rams, 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, parametri c, 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 no te 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

SO 2 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 l ocation 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 w ere 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 al ready being provided to the U.S. EPA or

permit authority, even if from short

- term testing? Yes ____ No__ X __ If yes 40 , please note for

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

period) for which data ar e 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 SO 2 HCL/HF Metal

HAP Hg CO Unit Flue Gas

Filt Cond Total Elemental Oxidized Load Moist Flow O 2 CO 2 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 da t a 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 unit s for all pollutants.

42 For each emissions test run the respondent should provide the fol lowing process information: Unit Load (MW), Net generation during run (MWh net), Flue gas moisture content (%), Flue gas flow rate(dscfm or Nm 3 /hr), Flue gas oxygen co ntent (%, dry), Flue gas

carbon dioxide content (%, dry), flue gas temperature at sampling point (°F), Flue gas pressure at sampling point (atm), Stan dard 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, pleas e include separate emission results for total PM, PM

10 , and PM 2.5

.

44 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, m anganese, 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 test ing, 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 Operat ions 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 know2

10. Which of the following fos sil 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 permitted 1 to be fired in any steam

generating unit at this facility?

__ X __coal

__ X __oil (including pet coke) ____ natural gas

__ X

__ Other (specify in question 14 below)

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

of coal or solid fuel was utilized during the previous 12 months prior to the receipt of this ICR: 2

, 3

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 o r 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 permitted 5 to 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 Cons ervation 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 wort h 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 gene rating units (boilers)(as

defined by Clean Air Act section 112(a)(8)) located at this facility.

Boiler ID 6 WIL1

Original Design fuel (i.e. coal rank or

type of oil) Bunker C

Converted to Bit. C oal , Oil & Gas in 1984

Design heat input, (MMBtu/hr) 7 5500 *

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

Fuel 11 99.7 % Bit. Coal

0.03% Dist. Oil

0% NG

Hours/year operated 12 7216.56

Average annual capacity factor for

the past 3 years 73.24%

Applicable NSPS Not covered under NSPS

Estimated year of retirement 13 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 schedu le 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 provi de 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 “hour s/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 inst alled and

operating and/or planned (please designate the order of the emission controls

- 1 for first c ontrol following the boiler, 2 for second control

following the boiler, etc.):

Boiler

ID 14 Type 15 NO

x control 16 Date SO 2 control 17 Date PM control 18 Date Other control 19

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 Gen erator 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

- NO

x burners; selective catalytic re duction (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, o ther). Also, please note if the

catalyst is specifically designed to reduce SO

3 formation.

17 Examples: wet f lue 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 electrostati c 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, SO

3 , etc.). Examples: activated carbon injection (ACI); Powerspan ECO;

dry sorbent injection or wet ESP for SO

3 control; flue gas conditioning to control opacity (e.g. SO

3 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 instal lation. Also include any pollutants

controlled by this other technol ogy (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 i nstalled for the

purpose of participating in a control technology demonstration project 20 (e.g., U.S. Department of Energy program, consent decree, etc.).

Boiler ID 21 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) sponsore d (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 Gener ator 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 expecte d 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 perce nt

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

and (2) the basis for calculating the percent reduction (i.e. where the “inlet” and “outlet” are).

Boiler ID 22 Demonstration

activity actual

start

- up date Demonstrat i on

activity projected

start

- up date Demonstration

activity end

- date

or projected end

date Type of control

(e.g., sorbent and

type; chemical

additive 23 ) D esired 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, (fo r 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 point8

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

(e.g., mercury, hydrogen chloride, etc.) control technology th at you have either contracted f o r , are installing, or have installed for the

purpose of providing a non

- demonstration, full

- scale operating system.

Boiler ID 24 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 F orm 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 Gener ator ID (as rep orted 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 gu arantee (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 ID 25 Actual start

- up

date Expected or

projected start

up date Type of control

(e.g., sorbent and

type; chemical

additive 26 ) Guaranteed HAP

emission

reduction (%) or

emission rate Sorbent or

additive feed rate

on which

guarantee is

based Coal rank(s) upon

which guarantee

is based

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 Gener ator 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 point10

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

Boiler ID 27 WIL 1 Permitted Emission Limit Averaging

Period Compliance Method ( PM

only ) Permit Type

PM 28 0.239 lb/MMBtu 3 hr A nnual Method 5 Title V

PM 10 29

PM 2.5 30

SO 2 2.3 lb/MMBtu 24 hr Title V

HCl and/or HF

HCN

Metal HAP 31

Note: only applies if burning

waste other than virgin fuel Nickel 6.0 x10 - 3 lb/MMBtu Not

Specified Chemical analysis Title V

Cadmium 1.0x10 - 4 lb/MMBtu

Chromium 7.4x10 - 4 lb/MMBtu

Arsenic 1.7x10 - 3 lb/MMBtu

Lead 5.0x10 - 3 lb/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 ID 32 WIL1 Most recent guaranteed emission rate for each pollutant for which there is a permitted emission limit

PM 33 0.239 lb/MMBtu

PM 10

PM 2.5

SO 2 2.3 lb/MMBtu

HCl and/or HF

HCN

Metal HAP 34 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 Gene rator 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 Gener ator 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 se parate 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 ID 35 WIL 1 Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a

permitted emission limit

PM 36 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 approv ed 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 applic able 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 t o, 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

- ann ual 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 prev ious

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 accorda nce 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 grea ter 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 ID 35 WIL 1 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 a t 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 un it’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: A ll 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).

PM 10 NA

PM 2.5 NA

SO 2 Monitoring/Record Keeping/Reporting/Other: The owner/operator shall continue to

operate CEMS for monitoring and reporting emissions of SO 2 . In determining Emission Rates

for SO 2 , 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 pe riod. 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 hourl y 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 determin ed on a dry basis, and

5) The sulfur dioxide emission rate shall be calculated as follows:14

Boiler ID 35 WIL 1 Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a

permitted emission limit

SO 2 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 des cribed 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 allo wable 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 SO 2 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 f uel to be combusted during the entire 24

- hour period.

HCl and/or HF NA

HCN NA

Metal HAP 37 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 limit s 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

(1x10 6 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 lev el for

all metal HAP for which a permit limit is in place.15

Boiler ID 35 WIL 1 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. Rec ords 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 Capi tal 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 Analysis 39

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 thei r 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):

CBI18

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 abo ve. 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 prog rams, 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, parametri c, 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 id entify

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

SO 2 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 th e U.S. EPA or

permit authority, even if from short

- term testing? Yes ____ No__ X __ If yes 40 , 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 SO 2 HCL/HF Metal

HAP Hg CO Unit Flue Gas

Filt Cond Total Elemental Oxidized Load Moist Flow O 2 CO 2 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 da t a 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 fol lowing process information: Unit Load (MW), Net generation during run (MWh net), Flue gas moisture content (%), Flue gas flow rate(dscfm or Nm 3 /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), Stan dard temperature (°F), Standard pressure (atm).

43 If emi ssion testing recorded the emission of filterable and condensable PM, separately, please include those separate emission resu lts. Also, pleas e include separate emission results for total PM, PM

10 , and PM 2.5

.

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

45 Please provide separate results for total Hg, elemental Hg, oxidized Hg, and particu late 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.