# Appendix N Four Factor Analyses

## Four Factor Analyses by Source DAK Americas.....................................................................................................................2 Giant Cement .....................................................................................................................61 Holcim – Holly Hill ...........................................................................................................84 International Paper – Georgetown, SC ..............................................................................88 International Paper – Savannah, GA................................................................................103 MeadWestvaco.................................................................................................................147

# FOUR FACTOR ANALYSIS DAK AMERICAS 

## COOPER RIVER,

## SC

FOUR FACTOR ANALYSIS OF 

### CANDIDATE SO2CONTROL MEASURES FOR 

### REASONABLE PROGRESS UNDER THE REGIONAL 

### HAZE RULE



## November

## 2007

Prepared by: 

### TRINITY CONSULTANTS 

### 2327 Englert Drive Suite201 Raleigh, NC 277 13 (919) 

### 544-7811


### Project 073401.0051.02.01

# ..................................... 3


## . SO2CONTROL 

### TECHNOLOGY FEASIBILITY

### ASSESSMENT 5



### .................................................................................................. 3.1 Low SULFUR COAL 

### 5 3.2 WET FGD SYSTEMS


### .................................................................................................. 6 3.3 SPRAY DRYER ABSORBER



### ......................................................................................... 7 3.4 FLUIDIZED BED COMBUST~ON WITH 

### LIMESTONE



### ...................................................... 7 

### 3.5 DRY SORBENT INJECTION



### ......................................................................................... 7 4

# . COST/ECONOMIC 

### IMPACT


# ....................................................................................... 9 4.1 Low SULFUR COAL



### .................................................................................................. 9 4.2 WET FGD SYSTEM



### ................................................................................................. 10 4.3 SPRAY DRYER ABSORBER SYSTEM



### .........................................................................14 4.4 DRY SORBENT INJECTION SYSTEM



### .......................................................................... 15 5

# . TIME NECESSARY FOR 

### COMPLIANCE 

# ...................................................................19 6

# . ENERGY AND NON-AIR QUALITY ENVIRONMENTAL IMPACTS 

# ..............................20 7

# . REMAININGUSEFUL LIFE OF EXISTING SOURCES IN 

### BOILER NO

# . 2 

# ..................... 21

DAK Americas. LLC I Trinity Consultants Four-Factor Analysis

### TABLES Table 2-1. Past Actual SO2Emissions Table 4-1. Total Capital Investment Estimate -Wet 

### FGD Option Table 4-2. Total Annual Cost Estimate -Wet FGD Option Table 4-3. Extract from EPA Table 1A Table4-4. TotaI Capital Investment Estimate -Dry Sorbent Injection Option Table 4-5. Total Annual Cost Estimate -Dry Sorbent Injection Option Table 5-1. Time Necessary for Compliance Table 6-1. Energy and Non-Air Quality Environmental Impacts Table 

### 8-1. Analysis Summary

DAK Americas, LLC Four-Factor Analysis .. 11 Trinity Consultants

### Thepurpose ofthis document is to present the four-factor analysis for DAK Americas, LLC (DAK). DAK operates a facility (known as the Cooper River Facility) in Moncks Comer, South Carolina,just north of Charleston. The Cooper River Facility, formerly operated by DuPont, has three main process areas: (1) a continuous polymerization (CP) area for polyethylene terephthalate (PET)production; (2) a PET finishing area to produce fiber products; and (3) 

### a PET finishing area to produce bottle resin products. Support operations at the facility include an ethylene glycol refining area, combustion sources for steam and process heat, raw material and product storage vessels, and a wastewater treatment plant. The Cooper River Facility is a major source of air emissions and operates under a Part 70 (Title V) major source permit No. 0420-0089issued by the South Carolina Department of Health and Environmental Control (DHEC). The facility is considered eligible to be regulated under the Best Available Retrofit Technology (BART)provisions ofthe Regional Haze Rule.

This four-factor analysis has been requested by the South Carolina Department of Health and Environmental Control (SC DHEC) based on screening analyses that wereprepared by the Visibility Improvement State and Tribal Association ofthe Southeast (VISTAS) for the Cape Romain Wilderness Area (Cape Romain). SC DHEC requested the analysis to determine whether to require any additional sulfur dioxide (SO2)emissions control for the coal boiler at the Cooper River facility as SC DHEC develops its Regional Haze State Implementation Plan (SIP), due in December 2007.

Section 169A ofthe Clean Air Act setsthe following goal for visibility in Class I areas. Congress hereby declares as a national goal the prevention ofany future, and the remedying of any existing, impairment ofvisibility in rnandatoiy class 

### I Federal areas which impairment resultsfi-om manmade airpollution. 

### Congress directed each State implementation plan (SIP) to contain emission limits, compliance schedules and other measures as may be necessary tomake "reasonable progress" toward meeting that national goal. 

### In determining reasonable progress, the Act requires the following factors to be taken into consideration: (1) the costs of compliance, (2) the time necessary for compliance, 

### (3)the energy and nonair quality environmental impacts of compliance and (4) the remaining useful life of any existing source subject to such requirements.'


### In response tothe visibility-protection requirements of the Act, the U.S. Environmental Protection Agency (EPA)promulgated regulations in 1999to guide States' development ofplans toreduce visibility impairment in Class I areas attributable to regional haze.2 That Regional Haze Rule 

### (RHR) 

# ' 42 U.S.C.

### 9 7491(g)(l).

64 Fed. Reg. 35714 (July I, 1989) (codified within 40 C.F.R.Part 51, Subpart P). Revisions to the Regional Haze Rule in 2005 primarily addressed guidelinesfor best available retrofit technology (BART) determinations,but made no substantive changes with respect to other reasonable progress requirements. 70 Fed. Reg. 39104 (July 6,2005). 

### DAK Americas, LLC 1 

### Trinity Consultants Four-Factor Analysis

### included an analytical methodology forhow States were to establish reasonable progress goals for each Class I area.3 Because that methodology has been based on application ofthe specific statutory factors identified above, that approach to determining reasonable progress hasbecome known asthe "Four-Factor Analysis." More recently, EPA has issued a guidance document that provides the Agency's current thinking on how to establish reasonable progress goals by applying the four statutory factorsto candidate emission control 

### measure^.^
TheRegional Haze Rule specifies a planning period of2004-20 

### 18 for States' initial regional haze SIPs. Those SIPsmust be submitted toEPA byDecember 17,2007. The State of South Carolina is a member ofthe Visibility Improvement State and Tribal Association of the Southeast (VISTAS) -- 

### a collaborative effort of state governments, tribal governments, and various federal agencies established to initiate and coordinate activities associated with the management ofregional haze, visibility and otherair quality issues in the Southeastern United States. After extensive analysis, VISTAShas concluded that sulfate isthe primary cause ofvisibility impairment in Class

### I areas throughout the Southeast.
VISTAS has further demonstrated that the principal causeofthat atmospheric sulfateis the emission of sulfur dioxide (SOz)from utility and industrial boilers. In particular, VISTAS' analysis found that SOzemissions from DAK's Cooper River facility contributed greater than 1% ofthe total visibility impairment in the Cape Romain Wilderness Area (CapeRomain), a Class

### I area located near the DAK Americas Cooper River Facility. Accordingly, DAK hasperformed thisFour-Factor Analysis ofcandidate SO2control measures to assist SCDHEC's evaluation ofthe issue.
It is important tonote that the contribution analysisincluded several simplifying assumptionsthat reduce the accuracy in assigning contribution to any individual source. TheVISTAS analysis considered total visibility impairment, frequency ofair masses from source areas entering the Class 

### I area ofinterest, and SOzmass emissions. No attempt was made to consider the specific atmospheric dispersion parameters of individual sources orthe differences in atmospheric chemistrythat can occur during differing lengths of transport. Thus, while the VISTAS analysis assigned a greater than 1% contribution toDAK Cooper River that value cannotbe directly correlated to greater than 1% ofthe visibility impact on Cape Romain.

Visibility improvement achieved by BART is a specific component of reasonable progress which is separately determined by a methodology similar to the Four-FactorAnalysis. Id. - U.S.EPA, Guidancefor Setting Reasonable Progress Goals Underthe RegionalHaze Program (June 1,2007). 

### DAK Americas, LLC 2 Trinity Consultants Four-Factor Analysis

## 2.1 

## EMISSION UNIT(S) SUBJECT TO THE

## FOUR-FACTOR ANALYSIS Visibility impairment in the Southeast is dominated by sulfate (SO4),which is largely formed via atmospheric oxidation of sulfur dioxide (SO2). SCDHEC has requested that the four-factor analysis address SO2emissions from the coal-fired boiler, Boiler No. 2. Boiler No. 2 is a 206 MMBtuIhr bituminous coal-fired boiler. Currently the existing air pollution control device is a baghouse to control particulate matter (PM) and a 1% sulfur limit on the coal sulfur content to control sulfur emissions.
Boiler No. 2 isthe only coal-fired boiler at the Cooper River site. In order to have a reliable source of steam (e.g. in the event of the failure ofthe primary boiler), and to provide sufficient steam when steam demand exceeds the capacity of any one boiler, 

### DAK normally maintains a second No. 21 No.6 fuel oil-fired boiler (BoilerNo. 1) that is not evaluated in this four-factor analysis. 

### In July 2007, per instructions from DHEC upon submittal ofthe BART Applicability Analysis, DAK submitted a Title V modification request to incorporate operational restrictions that yield visibility impacts at BART exemption levels. DAK requested that the current Title V permit be modified to allow the use of No. 6 fuel oil up to 320 MMBtuIhr total heat input (for both boilers) and No. 2 fuel oil for any operations above 320MMBtuJhr,but not exceeding 360MMBtuhr.

Thebaseline SO2emission rate was calculated for the purposes ofthe four-factor analysis to be approximately 415 tons per any consecutive 365-day period. The calculation is an average of the actual SO2emissions from Boiler No. 2 forthe three most recent full calendar years (2004,2005 and 2006) for thepurposes of calculating emissions fees. Based on current knowledge of future operations at the plant, the coal consumption rates for 2004-2006 are consistent with future average coal consumption projections. The data used and methods ofcalculation arepresented below. The emission factor used in the analysis was developed from Cooper River stack test data toreflect actual SO2emissions.

DAK Americas, LLC Four-Factor Analysis Year
2004 2005 2006 Average:

3 Trinity Consultants Coal Combusted (tons) 32,578.00 34,305.00 31,851.OO 32,911.33 Avg. Content 

### (Yo) 0.80 0.78 0.79 0.79% 

### so2 Emitted (tons) 410.81 432.59 401.64 41 5.01

### Em2 = 

### 3.1

### 9x 

### 10' 

### lb x

### 0.79

### % Sx

### 32,911

### tons coal ton

## - %

### sulfur
Where: 3.19*1 

## o3is the SO2emission factor for Bituminous Coal [Stack test data (from June 7,2005) and average sulfur content] 0.79 % 

### is the 2004-2006 average sulfur content 32,911 tons is the average total coal combusted in 2004-2006 2,000 lblton is a unit conversion factor
Note that the current permit limits fuel sulfur levelsto 1 .OO 

### percent, and compliance is demonstrated through calculationsbased on 12-monthrolling averages values from supplier certification as stated in the CooperRiver permit. As shown in Table 2-1, the actual coal sulfur content has averaged much lessthan 1%over the last three years.

DAK 

### Americas, LLC Four-Factor Analysis 4 Trinity ConsultantsAccording tothe EPA data for coal-fired electric generatingunits2, about 97 percent of the 

### I ,I40 coalfired utility boilers operating in the U.S. in 1999used one ofthe following SO2 control technologies:


### 1. Low-sulfur coal - switchingto a coal with a sulfur content lower than that ofthe coal being combusted 

### 2. Wet flue gas desulfurization (FGD) -passage of flue gas through a contactor where it comes into intimate contact with a scrubbing solution that reacts with SO2in the flue gas 

### 3. Spray dryer absorber (SDA) -injection of a liquid slurry of sorbent material into the flue gas downstream ofthe boiler and upstream of a contact chamber and the fabric filter 4. Fluidized-bed combustion (FBC) with limestone -coal is combusted in a fluidized bed with limestone added to react with the SO2 formed 5. Dry sorbent injection (DSI) -injection of finely divided dry sorbent material into the flue gas immediately upstream ofthe fabric filter

These technologies were chosen for inclusion in this four-factor analysis because they have been demonstrated (at least for coal-fired utility boilers) and arecommercially available. The following presents an assessment of the technical feasibility of applying each of these technologies to control SO2emissions from BoilerNo. 

### 2. Note that even though the technologies below may be technically feasible, they may not be cost effectiveto implement. Section 4 (Cost/ Economic Impact) discusses cost effectiveness considerationsrelated to the technologies discussed below. 

## 3.1 

## Low SULFUR 

## COAL The emission of SO2from conlbustion of coal occurs due to the oxidation of a significant fraction of the naturally occurring sulfur contained in the coal. As with the other characteristics of coal, the sulfur content of coal can vary appreciably (e.g., from several percent tounder one percent by weight) depending on where the coal was mined. It is often possible, within certain limits, for a combustion source to control SO2emissions from combustion of coal by sourcing the coal from a mine ormines having coal of the desired average sulfur content. Limiting factors for this practice includethe compatibility of numerous other coal characteristics (e.g., heating value, ash fusion temperature, capability to be stoked) with the specific design parameters of the combustion source and associated coal and ash handling equipment. Other limiting factors include the distance over which the coal must be transported (which impacts its cost), and extent of coal reserves having the desired characteristics (which can impact the length oftime over which SO2reduction by this method may be feasible). Reducing SO2emissions from BoilerNo. 

### 2 by switching to a lower-sulfur coal is deemed to be technically feasiblebut does not have reliable availability for low sulfur coals below 0.7 to 0.65

DAK Americas, LLC Four-Factor Analysis 5 Trinity Consultantspercent sulfur coals. Below 0.7to 0.65 percent sulfur, coal is not considered consistei~tly able to procure without risk of increases in average sulfur content dueto availability. Procurement personnel have researched the availability of coal that both meetsthe specifications for combustion in the coal boiler and has varying levels of average sulfur content. Based on these studies, lengthy history in procuring coal for various mines, and regular review ofmarket reports, it is considered opinion that 0.7 to 0.65percent is the minimum average sulfurlevel in bituminous coal that it could consistently procure without risk of increases in average sulfur content due to availability.
Alternative coal must meet certain minimum specifications (e.g., ash fusion temperature) in orderto be compatible with the design ofthe boilers and material handling systems of Boiler No. 

### 2. Although sub-bituminous coals from particular regions in the western United States, such as the Powder River Basin, have low-sulfur concentrations, those coals have other properties that are not compatible with the design of the boilers and material handling systems in Boiler No. 2. Consequently, low-sulfur sub-bituminous coals arenot considered to be technically feasible for combustion at the Facility.



## 3.2 WET 

## FGD SYSTEMS Wet FGD technology exposes the flue gas to a significant surface area of water (in the form of droplets or films on solid surfaces) and relies upon the relatively high solubility of SO2in waterto remove SO2from the flue gas. Since water ceases to effectively remove SO2when it reaches an equilibrium concentration with SO2 in the gas phase, calcium-, sodium- or ammonium-based chemicals are injected into the scrubber liquor to react with the dissolved SO2and form essentially non-volatile compounds. Somepercentage of the scrubber liquor must be bled off and fresh water added during operation in order to limit the build up ofboth suspended and dissolved solids. Sodiumbased reactants (e.g., sodium hydroxide) form water-soluble sulfate salts, minimizing the generation of solids that require disposal. However, it may be difficult to treat the salt-bearing wastewater to achieve low dissolved solid discharge limits. Calcium based reactants typically form insoluble reaction products that must be landfilled, but areeasierto separate from wastewater. Commercial wet FGD systems are available in many variations and proprietary desibms. For example, spray tower orpacked tower absorbers can attain SO2removal efficiencies in therange of approximately 90 percent in applicationswhere the particulate matter concentration ofthe flue gas to be treated has already been significantly reduced. However, packed tower absorbers and other designs containing any significant amount of internal structure are susceptible to plugging and fouling if there is any appreciable quantity of PM in the flue gas. 

### In such applications, these types of scrubbers must follow a separate PM control device. Thistypically represents a considerable additional expense unless FGD is being retrofitted on an existing source that already has a PM control device.
The acid gas and SO2removal efficiency of wet FGD systems is a function ofthe concentration. Higher removal efficiencies arepossible when the inlet concentration of the speciestobe removed is high. Removal efficiency decreases as concentration decreases, leading many vendors to guarantee a minimum outlet pollutant concentration. DAK Americas, 

### LLC Four-Factor Analysis 

### 6 Trinity ConsultantsWet scrubbers require energy (to overcome the pressure drop and circulate the scrubbing fluid) and clean water, and generate wastewater andlor sludge that must be treated or disposed of. Due to the likelihood that water will condense from the flue gas in components downstream of a wet scrubber, additional expense for corrosion resistant materials is required. Furthermore, wet scrubbers also create saturated plumes that will be quite visible under most weather conditions.
Wet FGDtechnology has been determined to be technically feasibleto use for control of emissions of 

### SO2from Boiler No. 2. Because wet scrubbers are less costly and more reliable ifthe majority of PM isremoved from the flue gas upstream ofthe scrubber, it has been assumed that this option would involve the installation of a scrubber downstream ofthe existingbaghouse and 

### IDfan train in the Facility.

A spray dryer absorber (SDA, sometimes referred to as a wet-dry or semi-dry scrubber) operates by the same principle as wet lime scrubbing, except that the flue gas is contacted with a fine mist of lime sluny instead of a bulk liquid (as in wet scrubbing). For the spray dryer absorber process, the combustion gas containing 

### SO2is contacted with fine spray droplets of hydrated lime sluny in a spray dryer vessel. This vessel is located downstream ofthe air heater outlet where the gas temperatures are in the range of 120to 180 OC (250 to 350 OF). The 

### SO2is absorbed in the sluny and reacts with the hydrated lime reagent to form solid calcium sulfite and calcium sulfate as in a wet lime scrubber. Thewater is evaporated by thehot flue gas and forms dry, solid particles containing the reacted sulfur. Theseparticles areentrained in the flue gas, alongwith fly ash, and are collected in a PM collection device. Most ofthe 

### SO2 removal occurs in the spray dryer vessel itself, although some additional 

### SO2capture has also been observed in downstream particulate collection devices, especially fabric filters. This process produces 

### dry reaction waste products for easy disposal.
An SDA system was determined to betechnically feasible for the control of 

### SO2from Boiler No. 2 at the Facility. 

## 3.4 

## FLUIDIZED BED 

## COMBUSTION WITH 

## LIMESTONE Fluidized-bed combustion involves the combustion of coal particles suspended by a stream of combustion air and flue gas. Limestone may be added to the bed to react with the 

### SO2liberated from combustion ofthe coal. Spent reactant and ash are continuously removed from the bed and the flue gas stream exiting the boiler.
FBC with limestone is not technically feasible for control of 

### SO2emissions from Boiler No. 2 because it requires an entirely different type of combustor design than that of Boiler No. 2.

For the dry sorbent injection process, dry powdered hydrated lime (or another suitable reactant) is directly injected intothe ductwork upstream of a 

### PM control device. Some systems use spray humidification followed by dry injection. This dry process eliminates the slunyproduction and DAK Americas, LLC Four-Factor Analysis 

### 7 Trinity Consultantshandling equipment required for wet scrubbers and spray dryers, and produces dry reaction waste products for easier disposal. The 

### SO2is adsorbed and reacts with thepowdered sorbent. The dry solids are entrained in the combustion gas stream, along with fly ash, and collected by the

### PM control device. The 

### SO2removal efficiencies ofexisting dry injection systems range from 

### 40 to 

### 60 percent. 

### Dry sorbent injection has been determined to be technically feasible foruse in controlling 

### SO2 emissions from Boiler No. 

### 2. It has been assumed that thebaghouses in the existing air pollution control train for Boiler No. 

### 2 would be retained foruse in collection of the spent reactant and flyash from the boilers. An average 

### SO2removal efficiency of 

### 50percent hasbeen projected for this technology assumingthat slaked lime isused as the reactant.
The installation of a 

### DSI system may cause significant changes in the manner in which fly ash must be disposed. Currently, dry fly ash from thebaghouse is conveyed via vacuum blower to a large ash silo where it is combined with bottom ash from Boiler No. 

### 2 and stored. The ash is drop fed into trucks which deliver it to a local cement kiln forrecycling intoproduct. This is all a dry process. Changes in the ash make-up would cause an inabilitytouse it in the cement plant and it most likely would have to be disposed of at a landfill at a significant additional cost.

DAK Americas, LLC Four-Factor Analysis 

### 8 Trinity ConsultantsThe cost/economic impacts analyses provided in this four factor assessment have been generally prepared in accordance with protocols provided in the EPA Office of Air Quality Planning and Standards (OAQPS) Air Pollution Control Cost Manual, Sixth Edition (EPA 452/B-02-001) (the "Manual").
Estimates oftotal capital investment (TCI) and total annual cost (TAC) were made for each ofthe above options using the techniques described in the Manual, quotes obtained directly from equipment vendors and service contractors, and data developed by 

### DAK and Trinity procurement and engineering personnel. Because they are not based on firm equipment and construction quotes, and were prepared prior to engineering, the accuracy of these estimates is generally accepted to be approximately *30 percent. Copies of the budgetary quotes received from equipment vendors are attached in Appendix A.
The TCI estimate includes one-time costs associated with each option, including purchase of capital equipment, electrical, mechanical and structural construction costs, engineering, permitting, and testing fees, etc.
TheTAC estimate includesrecurring direct and indirect costs one would anticipate to be incurred during each year of operation. Direct costs (also known as variable costs), are those directly related to the extent or duration of operation of the option. These include costs of operator labor,utilities, replacement parts, etc. Indirect costs are those costs that are fixed, and do not generally vary with the extent ofuse ofthe option. These include administrative charges, taxes, insurancepremiums, and the capital recovery cost. The capital recovery cost is a means of annualizingthe TCI over a certain period of time. In the case of this study,the equipment lifetime was assumed to be 10 years for the purposes ofcalculating the capital recovery costs. 

## 4.1 Low

## SL.TLFLTR COAL DAK has obtained coal cost data for various sulfur contents from their current coal supplier. It is apparent that the cost of coal increases very rapidly as the sulfurcontent dropsbelow 1percent. The following costs were approximated for different low sulfur coals:
0.8 - 0.9 % (Current range) = $6]/ton 0.7 - 0.8 % = $65-$70/ton 0.6 - 0.7% = $75-$80 /ton
To calculate a cost effectiveness, the change in emissions must be determined. For 2004-2006, while the coal sulfur level was specified at 1 %, the as-received coal average value was 0.79%, and this value is used to calculate the actual emissions. For coal-specified at 0.70%, it is likely that the asreceived value would also be slightly lower, though likely much less sothan for 1% specification coal. 

### In the absence of as-received data to verify a realistic as-received value for coal specified at 0.70%, the potential future emissions were calculated assuming the as-received and specified value
DAK Americas, LLC Four-Factor Analysis 9 Trinity Consultantswill be identical. Using these assumptions, the dccrease in 

### SO2emitted over baseline was calculated to be approximately 47 tons per year using the following equation:



### Decrease -

### SO2 

### (ton /

### yr) =

### 4 1

### 5 ton/

### yr x 

### 1 

### - - 

# ( 

# :;I

The cost effectiveness (cost per ton of 

### SO,

- emission reduction) was calculated to be approximately $6,265 per ton using the following equation:



### Cost($ 

### 1ton)= 

### $296,202 47 to?? Although there is no capital cost associated with the low sulfur coal option, low sulfur coal is increasing in demand and decreasing in reliable availability at low sulfur ranges below 0.7 to 0.65 percent. This increase in demand not only decreases reliable availability, (making it not feasibleto use low sulfur coal) but it also change in the set price range. Therefore, there is no way to accurately estimate how the cost effectiveness of the low sulfur coal option will increase in the coming years. 

## 4.2 WET 

## FGD SYSTEM A budgetary quotation was obtained for a wet FGD system from Turbosonic Technologies, a manufacturer of emission control equipment. The quoted FGD system consists of two cyclonic scrubbers,but was scaled down to one for DAK's purposes. Each FGD system would be installed afterthebaghouse and induced draft fan in the existing airpollution control trains in Boiler No. 2.
Each scrubber as quoted has the capacityto accept the maximum flow rate capacity of thebaghouse with which it would be associated. The manufacturer has guaranteed that each will achieve a minimum of 92 percent 

### SO2removal when Boiler No. 2 is fueled with coal containing up to 1.25 percent by weight sulfur, with potentially lower control efficiency at reduced 

### SO2inlet loading to the scrubber. (For conservatism the 92 percent was used in the calculations even though Boiler No. 2 is permitted for up to 

### 1 percent sulfur coal.) The scrubber is designed to use hydrated lime asthe 

### SO2 reactant at a maximum rate of approximately 695pounds per hour. Therefore, a silo forthe hydrated lime was included in the equipment tobe installed.
It was assumed that the stacks for each air pollution control system train would be mounted directly on top ofthe scrubber, asrecommended by the manufacturer. This would help reduce the extent of water droplet carryover in the flue gas exiting the stacks.
TheTCI for the wet FGD system, presented in Table 5-1, is $4,115,736. The estimated TAC for the wet FGD system, presented in Table 5-2, is $ $1,450,174. This cost was estimated assuming that Boiler No. 2 would be operated under the same average conditions as occurred during theperiod of 2004,2005 and 2006.
The estimated quantity of 

### SO2removed by the wet FGD option from the flue gas under the baseline operating conditions is 382tonsper year. The estimated quantity of 

### SO2emitted under this option 

### DAK Americas, LLC 10 Trinity Consultants Four-Factor Analysis

### was estimated to be 33 

### tons per year. The estimated cost effectiveness ofthe wet 

### FGD system when Boiler No. 2 

### is operated under the baseline conditions was estimated to be 

### $3,798 per ton of SO2 - 

### removed. Currently the Cooper River Facility has the on-sitewastewater plant and dischargeto the Cooper River, and solids (sludge) are sent to a local publicly-owned treatment works (POTW). It isunclear at this time if there would be a problem with the disposal of blowdown from the scrubbers containing dissolved salts at a concentration on the order of 2.5percent by weight. 1fthis proves to be a problem, an additional wastewater pretreatment system could be needed to process the scrubber blowdown prior to its disposal. The addition of a wastewater pretreatment system would have the effect of increasing the capital and operating cost of the technology, which would proportionately raise the effectiveness, figure forremoval of SOz.



### DAK Americas, LLC Four-Factor Analysis 

### 11 Trinity Consultants

### TABLE 4-1. 

### TOTAL CAPITAL INVESTMENT ESTIMATE -WET

### FGD OPTION

Cost Item Factor ~stimate' Direct Costs Purchased equipment costs Wet scrubbers (including standard options) Vendor quote' $620.000 Pumps Estimate $100,000 Stacks Estimate $50,000 Lime silo Estimate $200,000 Other equipment Estimate $50,000 A= $1,020,000 Contengencies 0.2 x A $204,000 Instrumentation 0.10 x A $102,000 Salestax 0.03 x A $30,600 Freight 0.05 x A $51,000 Total Purchased Equiynierrt Costs B= $1,407,600 Direct installation costs Labor 0.49 x B $689,724 Field material 0.25 x B $35 1,900 Foundations and supports 0.12 x B $168,912 Handling and erection 0.40 x B $563,040 Electrical 0.01 x B $14,076 Piping 0.03 x B $42,228 Insulation for ductwork 0.01 x B $14,076 Contingencies 0.20 x B $28 1,520 TotalDirect installation costs $2,125,476
Waste water treatment plant ~stimate~ $70,000 Total Direct Costs (DC) $3,603,076 Indirect Costs (installation) Engineering 0.10 x B $140,760 Construction and field expenses 0.10 x B $140,760 Contractor fees 0.10 x B $140,760 Start-up 0.01 x B $14,076 Permits, licenses, fees Estimate $20,000 Performance test 0.01 x B $14,076 Contingencies 0.03 x B $42,228 Total Indirect Cost (IC) $512,660 Total Capital Investment (TCI) =DC

### +IC $4,115,736

1. Estimation methodology is from section 5 ofEPN452lB-02-00I 2. Vendor estimate includes one absorberfor $620,000and a second identicalabsorberfor $608,000. Right now assumed me absorber 3. Alreadyhave a waste water treahnent plant in place, but pH may be a concern. Cost ofadding caustic feed.



### DAK 

### Americas, LLC Four-FactorAnalysis 12 

### Trinity Consultants

### TABLE 

### 4-2. TOTAL ANNUAL COST ESTIMATE -

### WET 

### FGD OPTION

Cost Item Calculation cost' Direct Annual Costs (DC) Operating labor

Operator $22.90/hr x 8 man-hrlday x 7 daylweek x 52 weekly $66,685 Supervisor 15% of operator labor = 0.15 x $66.685 $10,003 Maintenance

Labor $22.70/hr x 4 man-hrlday x 7 daylweek x 52weekly $33,05 1 Materials I00percent ofmaintenance labor $33,051

Wastewater treatment plant operation & maintenance2 5 165,000 Reagent for SO2Control 200 Ibhr x $0.050/lb x 24 hrlday x 7 daylweek x 52weekly $87.527 Residue Disposal

Flyash 0.42 tonihr x 24 hrlday x 7 daylweek x 52 weeWy x M5.001ton 5164,101 Utilities

Electricity = (Added fan kW + pump kW) x annual operating haul-s x electricityrate

= (49kW + 41 kW) x $0.0500 kW-hrx 24 hrlday x 7 daylweek x 52 weeWyr $39,472 Water $0.00075/gal x 22 gallmin x 60 minihr x 24 hrlday x 7 daylweek x 52 weeWyr $8,836 Wastewater $0.0020/gal x 16gpm x 60 minhr x 24.0 hrlday x 7.0 day!week x 52 weeWyr $15,905 Total DC $623,630 Indirect Annual Costs (IC) Overhead 34% of sum ofoperating, supv., maint. labor & materials 548,549

= 0.34 x ($66,685 + $10,003 + $33.051 + 533;05l) Administrative charges 2%of Total Capital lnvestlnent = 0.02 x $4,1 15.736 $82,315 Property taxes 1% ofTotal Capital Investment =0.01 x 54,115,736 $41,157 Insurance I% of Total Capital Investment = 0.01 x $4,115,736 $41,157 Capital recovery CRF x TCI =0.1490 x 54;115,736 $613,366
Total lC $826,544 Total Annual Cost (rounded) $1,450,174

1. Estimation methodology is from seclion 5 ofEP.4/151/B-02-00I and DAK 2. DAK estimate. Fixed (wages. maintenance. senera1 08i M) = $337,000 year Variable (chemicals. sludge disposal) = $165~000 year (projected)



### DAK Americas, LLC Four-FactorAnalysis 13 

### Trinity ConsultantsA SDA system for the Facility is expected to consist of a separate reactant atomization and injection systems and adsorption vessel located upstream of the PM control device. It is anticipated that the existing baghouse would be retained for use for collection of flyash and spent reactant. Hydrated lime is anticipated tobe the reactant used in the SDA system. The efficiency ofthe system for removal of SO2from the flue gas ofBoiler No. 2 was assumed to be 85 percent.
The installation of an SDA system may cause significant changes in the manner in which the spent sorbentlfly ash mixture must be disposed. Currently, dry fly ash from the baghouse is conveyed via vacuum blower to a large ash silo where it is combined with bottom ash from Boiler No. 2 and stored. The ash is drop fed into trucks that deliver it to a local cement kiln for recycling into product. This is all a dry process. The ash originating from the baghouses in the SDA option would be expected to have different materials properties such aspH, moisture content, and ash fusion temperature. It would be expected to contain substantially higher concentrations of calcium, sulfur and chlorine than currently. These changes may make the mixture from the baghouses unacceptable orundesirable for use in the cement kiln. If so, the mixture would have to be trucked offsite for disposal in a landfill at a substantial increase in cost relative tothe current situation.
The estimated cost ofthe SDA option for the Facility was based on general cost data for SDA systems provided in Table 1A oftheAir Pollution Control TechnologyFact Sheet -Flue Gas Desuljiurization (EPA-Fl452-03-34). This source was used because there is no Chapter in the EPA OAQPS Control Cost Handbook pertaining to the estimation of costs for SDA systems. According to Table 1A ofthe EPA control technology fact sheet, the range of costs for an SDA system for boilers having firing rates of less than 2,000 MMBtu per hour are as listed in Table 5-3. 

### TABLE 4-3. EXTRACT FROM 

### EPA TABLE 1A (EPA-F/452-03-34)

The SDA cost data from Table 1Aindicate that each ofthe above costs associated with control of SO2 using SDA increases substantially as the firing rate ofthe associated boiler decreases. The maximum design firing rate for which each SDA system in the Facility would be designed to accommodate is approximately eight percent oftheupper end of the lowest firing rate range (2,000 MMBtuIhr) for which Table 1A contains cost data (as shown in Table 5-1). Given the inverse relationship in boiler size and control equipment cost, and the small size ofBoilerNo. 2, Trinity believes that the costs of the SDA alternative will be at least ashigh astheupper end of each ofthe ranges provided. 

### Capital Cost ($/MMBtu/hr) 30,000 - 150,000

DAIS Americas, LLC Four-Factor Analysis 14 Trinity Consultants 

### 0 & 

### M Cost ($/MMBtu/hr) 1,000 - 30,000 

### Annual Cost ($MMBtu/hr) 10,000 -50,000 

### Cost of 

### SO2 Removed

($/ton) 500 -4,000Based on the use ofthe upper end ofthe cost ranges presented in Table 1A ofthe EPA CICA Fact Sheet for flue gas desulfurization, the cost effectiveness of SDA for control of= from Boiler No. 2 has been estimated to be at least $4,000per ton.

Trinity prepared an analysis ofthe process and equipment requirements associated with the installation of a DSI system during consideration ofpotential control options for the National Emission Standards for Hazardous Air Pollutants (NESHAP) for Industrial Boilers (also known asthe Boiler MACT). The system was assumed to consist of a separate lime injection system in the ducting upstream of the baghouses in the existing airpollution control train, which the analysis assumed were retained for use for collection of flyash and spent reactant. A new lime storage silo and handling system was also assumed to be necessary. The installation of a DSI system is expected to cause significant changes in the manner in which fly ash must be collected from the baghouse, handled and disposed. DM engineering has determined that the type of bags in thebaghouse would need to be upgraded and, due to the substantial increase in the potential quantity ofmaterial to be removed from the baghouse, the existing flyash handling system may have to be upgraded.
TheDSI system was assumed to have an SO2control efficiency of 50percent using hydrated lime as the reactant. At the baseline SO2emission rate, the required injection rate of hydrated lime was estimated tobe 330 pounds per hour.
The ash originating from the baghouses in the DSI option would be expected to have different materials properties such aspH, moisture content, and ash fusion temperature than the ash currently removed from the baghouses. It would be expected to contain substantiallyhigher concentrations of calcium, sulfur and chlorine than it currently does. These changes have been assumed to make the mixture from the baghouses unacceptable or undesirable for use in the cement kiln. Therefore, it has been assumed that the mixture would have to be trucked offsite for disposal in a landfill at a substantial increase in cost relative to the current situation. A budgetary quotation was obtained by Trinity from Bundy Environmental Technology for the injection components of a DSI system. The quotation was used along with other equipment cost data in a factored estimate oftotal capital cost andtotal annual cost for installation and operation of the DSI system.
TheTCI for theDSI system, presented in Table 5-4, is $4,700,000. The estimated TAC for the DSI system, presented in Table 5-5, is $1,520,640. This cost was estimated assuming that BoilerNo. 2 would be operated under the same average conditions as occurred during the period of 2004,2005 and 2006.
The estimated quantity of SO2removed by theDSI option from the flue gas under the baseline operating conditions is 208tonsper year. Theestimated quantity of SO2emitted under this option was estimated to be 208 tons per year.

DM Americas, LLC Four-Factor Analysis 15 Trinity Consultants

### The estimated cost effectiveness ofthe 

### DST option when Boiler No. 

### 2 is operated under thebaseline conditions was estimated to be $7,328 

### per ton of 

### SO2removed.

-



### DAK 

### Americas, LLC 

### Four-Factor Analysis Trinity ConsultantsCost Item Factor ~stimate'
Direct Costs Purchased equipment costs Lime injection equipment Quotation $475,000 Dry fly ash system Quotation $830,000 New filter bags Quotation $1 16,000 Lime storage silo Estimate $8,000 Other equipment Estimate $42,000 A= $1,471,000 lnstrumentation 0.10 xA $147,100 Sales Tax 0.03 xA $44,130 Freight 0.05 xA $73,550 Total Pirrchased equipment cost (PEC) B= $1,735,780 Direct installation costs Labor Estimate $328,786 Field materials Estimate $142,700 Dismantlement & removal Estimate $80,000 Foundations & supports 0.04 x B $69,431 Handling & erection 0.50 x B $867,890 Electrical 0.08 x B $138,862 Piping 0.01 x B $17.358 lnsulation for duct work 0.07 x B $121,505 Painting 0.04 xB $69,431 Contengencies 0.20 xB $347,156 Total Direct installation cost $2,183,119 Total Direct Cost (DC) $3,918,899 Indirect Costs (installation) Engineering 0.10 xB $173,578 Construction and field expenses 0.20 xB $347,156 Contractor fees 0.10 xB $173,578 Start-up 0.01 xB $17,358 Performance test 0.01 xB $17,358 Contingencies 0.03 xB $52,073 Total Indirect Cost (IC) $781,101
Total Capital Investment (TCI) =DC +IC $4,700,000

1. All capital cost data from VGA EST - REV 3-4-18-06.



### DAK 

### Americas, 

### LLC Four-Factor Analysis 

### 17 Trinity ConsultantsCost Item Calculation Cost Direct Annual Costs (DC) Operating labor

Operator S22.90hr x 8 man-hrlday x 7.0 dayiweek x 52 weeWyr $66,685 Supervisor 15%of operator labor = 0.15 x $66,685 $10.003 Consu~nrnables

Li~ne 330 lbhrx 1ton/2,000 Ib x $100iton x 24 hriday x 7 dayiweek x 52 weeWyr $144,028 Maintenance

Labor S22.70hr x 4.0 hriday x 7.0 dayiweek x 52 weeWyr $33,051 Material I00percent ofmaintenance labor $33,051 Replacement parts

Bags (Inaterials and labor) CRF for bags x bag replacement cost: 0.388 x $156,800 $60,844 Residue Disposal

Flyash 0.55 todhr x 24 hriday x 7 dayiweek x 52 weeWyr x $45.001ton $214,380 Utilities

Electricity $0.0500 kW-hrx 49 kW x 24 hriday x 7 dayiweek x 52 weeWyr $21,610

Total DC $583,653 Indirect Annual Costs (IC) Overhead 34% of sum of operating, supv., maint. labor & materials

= 0.34 x ($66,685

### + $10,003 + $33,051 + $33,051) $48,549 Ad~ninistrative charges 2% ofTotal Capital Investment = 0.02 x $4,700,000 $94,000 Property taxes 1% ofTotal Capital Investment = 0.01 x $4,700,000 $47,000 Insurance 1% ofTotal Capital Investment = 0.01 x $4,700,000 $47,000 Capital recovery CJUx TCI = 0.1490 x $4,700.000 $700,439 Total IC $936,987 Total Annual Cost (TAC) $1,520,640



### DAK Americas, LLC Four-Factor Analysis 18 Trinity Consultants

## 5. TIME NECESSARY FOR

## COMPLIANCE

The estimated minimum time in calendar years necessary for DAK to implement each of the four SO2 control options that were determined in Section 4 to be technically feasible is listed in the table below.

TABLE 

### 5-1. TIME NECESSARY FOR COMPLIANCE



## I 2 

## I Wet FGD svstem 

## I 3 vears 

## 1

Option No. 1


### 3 

# I Spray dryer absorber system 

# I 3 years 

## I 4 

## I Drv sorbent iniection svstem 

## I 3 vears 

## 1 Description Low sulfur coal

Themajor activities anticipated to be necessary for implementation of the low sulfurcoal option include the following: TimetoImplement 1year



## + Obtain quotations from vendors 

# + Negotiate a procurement contract 

## + Complete the existing coal contract and depletion ofthe existing coal stock 

# + Receive sufficient quantities ofthe lower sulfur coal
Themajor activities anticipated to be necessary for implementation of any of the post-combustion SO2 emission control systems are anticipated to include the following: Complete a full engineering estimate of capital and O&M costs Obtain approval for the project and allocate funds Initiate detailed design project Order long-lead items Obtain necessary permits Solicit bids and award construction project Construct the system Start up system and debug Commence normal operations.



### DAK Americas, LLC Four-Factor Analysis 19 Trinity Consultants

## 6. ENERGY AND NON-AIR QUALITY ENVIRONMENTAL IMPACTS

The anticipated energy and non-air quality environmental impacts ofthe SO2reduction options that were determined to be technically feasible are listed below.



### TABLE 6-1. ENERGY AND

### NON-AIR QUALITY ENVIRONMENTAL IMPACTS

usage. 

### Option

No.



### 1

Additional fuel usage to transport lime to Facility, increased electricity usage for lime handling, recirculation pumps, and to overcome increased pressure drop across scrubbers. 

### Description Low sulfur coal 

### Energy Impacts May have to be shipped from greater distances, resulting in additional fuel


### 2

3

4 Additional fuel usage to transport lime to Facility, increased electricityusage for lime injector and due to increased pressure drop in absorption chamber and baghouse. Potentially increased fuel and electricity usage if flyash must be disposed of at the landfill. 

### NOD-Air Quality Environmental Impacts None identified

Wet FGD system

Spray dryer absorber

Dry Sorbent Injection System Additional he1usage to transport lime to Facility, increased electricityusage for lime injector and due to increased pressure dropin baghouse. Increased fuel and electricity usage due to disposal of flyash at the landfill Use of substantial quantities of fresh water. Generation of substantial quantities of industrial wastewater containing suspended and dissolved solidsrequiring disposal at the POTW. Use of substantial quantities of fresh water. Potential for degradation in quality of water discharged from ash pond outfall dueto lime and dissolved salts. Potentially substantial increase in solid waste generation and disposal if flyash cannot berecycled. Substantial increase in solid waste generation and disposal associated with flyash and spent reactant.

DAK Americas, LLC Four-Factor Analysis 

### 20 Trinity Consultants

## 7. 

## REMAINING USEFUL LIFE OF EXISTING SOURCESIN

## BOILER NO.

## 2

DAK estimates that theuseful lifetime of Boiler No. 2 is up to and exceeding 50years. This would leave the remaining useful life ofthis unit to be around 31 years.
It is difficult to specify a remaining useful life oftheboilers, asthe remaining useful life is directly related tothe degreeofroutine maintenance completed on the units and the utilization factors ofthe units. Also, the coal-fired boiler is really a system rather than just one identifiable piece of equipment although the boiler proper is certainly a large and important part ofthe system. Unlike oil fired packaged boilers, field erected coal fired boilers can last for a very long time. There was a coal-fired boiler in a carpet mill in Georgia that was installed in 1900and was still operating reliably as late as 1988. It isDAK's opinion that if things are well maintained coal fired boiler systems can last for well over 50years. For the purposes ofthis analysis, DAK believes that 31years is a reasonable estimate ofthe remaining useful life oftheunit, though the value could range could fluctuate depending on equipment repair, maintenance, and other factors.

DAK Americas, LLC Four-Factor Analysis Trinity ConsultantsAll options were deemed not cost effective according to the $2,00O/ton guidance provided by SC DHEC.
The energy and non-air quality impacts ofthe options have been qualitatively ranked according tothe degree of energy usage and waste generation generally associated with the option.
The spray dryer absorber option is the first in the list based on cost effectiveness number, which it is anticipated would have been found to be over $4,000 per ton had a manufacturer's quotation been available.
The cost effectiveness ofthe wet FGD option was the next in lowest cost effectiveness.
The dry sorbent injection system option has the highest non-air quality environmental impact due to the substantial quantities of wastes requiring landfillingthat it generates.

DAK Americas, LLC Four-Factor Analysis Control Option

Baseline

Low sulfur coal Wet FGD Spray dryer absorber Dry sorbent injection

Trinity Consultants Projected 

## soz Reduction (%)

11%

92%

65%

50% Controlled Emissions

(tonlyr)

4 15
2 1

3 3

48

208 Cost Effectiveness ($/ton)

$6,262
$3,798
>$4,000

$7,328 Energy Impact Ranking (l=least) 1
2

5

4

3 Non-Air Quality Environment Impact Ranking (l=least) 1
2

4

3

5 Time forCompliance (Years)

1

3

3

3

### Sizing Calculations Vendor Supplied Data

Four-Factor Analysis 

### A-1 Trinity Consultants

## Air Pollution Control Technology Fact Sheet

Name of Technology: Flue Gas Desulfurization (FGD) -Wet, Spray Dry, and Dry Scrubbers Type ofTechnology: Control Device -absorption and reaction using an alkaline reagent to produce a solid compound. Applicable Pollutants: Sulfur dioxide (SO,) Achievable Emission LimitslReductions: Scrubbers are capable of reduction efficiencies inthe range of 50% to 98%. The highest removal efficiencies are achieved by wet scrubbers, greater than 90% and the lowest by dry scrubbers, typically less than 80%. Newer dry scrubber designs are capable of higher control efficiencies, on the order of 90%. Applicable Source Type: Point Typical IndustrialApplications: Stationary coal- and oil-fired combustion units such as utilityand industrial boilers, as well as other industrial combustion units such as municipal and medical waste incinerators, cement and lime kilns, metal smelters, petroleum refineries, glass furnaces, and H,SO, manufacturing facilities. Approximately 85% of the FGD systems installed inthe US are wet systems, 12% are spray dry and 3% are dry systems. Emission Stream Characteristics:

a. Combustion Unit Size: SO, scrubbers have been applied combustion units firing coal and oil ranging in size from 5 MW to over 1,500 MW (50 MMBtuIhrto 15,000 MMBuffhr). Dry and spray scrubbers are generally applied to units less than 3,000 MMBtuIhr (300 MW) (EPA, 2000). b. Temperature: For wet scrubbers, typical inlet gas temperatures are 150°C to 370°C (300°F to 700°F) (FETC, 1996). For spray dry systems, the temperature of the flue gas exiting the absorber must be 10°C to 15°C (20°F to 30°F) above the adiabatic saturation temperature. Optimal temperaturesfor SO, removalfor dry sorbent injection systems range from 150°Cto 180°C(300°F to 350°F). Optimal temperatures for SO, removal when applying dry sorbent injection systems vary between 150°Cto 1000°C (300°F to 1830°F) depending on the sorbent properties (Joseph, 1998)

c. Pollutant Loading: SO, scrubbers are limited to dilute SO, waste gas streams of approximately 2000 ppm.(Cooper, 2002). d. Other Considerations: The amount of chlorine in the flue gas affects the amount of water evaporated by the system due to the formation of salts. Chlorine content improves the SO, removal but also results insalt deposition onthe absorber and downstream equipment (Schnelle, 2002). An additional or upgraded induced draft (ID) fan may be required to compensate for flue gas pressure drop across the absorber.

EPA-CICA Fact Sheet 1 Flue Gas DesulfuriirationManywet systems reheat the flue gas downstream of the absorber to prevent corrosion caused by condensation inside the ducts and stack and reduce plume visibility. Emission Stream Pretreatment Requirements: In spray dry and dry injection systems, the flue gas must be cooled to a temperature range of 10°C to 15°C (20°F to 30°F) above adiabatic saturation. This temperature range avoids wet solids deposition on downstream equipment and plugging of the baghouse. A heat recovery boiler, an evaporative cooler or a heat exchanger is typically used to cool the gas. Cost Information: Capital costs for SO, scrubbers have decreased by over 30% since the beginning of the 1990's. Current costsfor SO, scrubbers applied to electric utilities are reportedto be approximately$100/kW (Smith, 2001). Retrofitof scrubbersonexisting units can increase the capital cost up to 30%. Retrofit costs vary significantly between sites and depend on space limitations, major modifications to existing equipment (e.g., ductwork and stack) and the operating condition of the units (e.g., temperature, flowrate). O&Mcosts increase with increasingsulfur content since more reagent is requiredto treat the same volume of gas. Typical reagents such as lime and limestone are inexpensive; however, the use of proprietary reagents or reagent enhancers or additives that can significantly increase the O&M cost. Limestone is generally availablefor 10to 20 $/ton and lime is available for 60 to 80 $/ton (Smith, 2001). Waste product disposal costs vary from $lO/ton to $30/ton and byproduct saleable prices vary from 0 to 15 $/ton (Smith, 2001). The addition of a scrubbers causes a loss of energy available for generating steam due to evaporationofwater and the energy requiredto drive the reaction. New scrubber designs result inan energy penalty of less than 1% of the total plant energy (Srivastava, 2001).

Table la: Summary of Cost lnformation in $/MMBtu/hr (2001 Dollars) 

### " Unit Size Capital Cost O&M Cost Annual Cost Cost per Ton of Scrubber Type Pollutant Removed (MMBtuIhr) ($/MMBtu) ($/MMBtu) ($/MMBtu) ($/ton) Wet > 4,000 10,000 -25,000 200 

### - 800 25 

### - 40 200 

### - 500
Spray Dry > 2,000 4,000 

### - 15,000 600 

### - 1,000 150

### - 300

Table 1b: Summary of Cost lnformation in $/MW (2001 Dollars) 

### " Cost per Ton of Scrubber Unit Size Capital Cost O&M Cost Annual Cost Pollutant Removed Type (MW) ($/kW) ($/kW) ($/kW) ($/ton) Wet > 400 100

### - 250 2-8 20 - 50 200 

### - 500 < 400 250 

### - 1,500 8 

### - 20 50 

### - 200 500 

### - 5,000 Spray Dry > 200 40 - 150 4-10 20 -50 150 - 300 < 200 150

### - 1,500 10

### - 300 50 

### - 500 500 

### - 4,000 

### " ( EIA, 2002; EPA, 2000; Srivastava, 2001)

Assumes capacity factor > 80%

€PA-CICA Fact Sheet Flue Gas DesulfurizationTheory of Operation: The FDGor SO, scrubbing process typically uses a calcium or sodium based alkaline reagent. The reagent is injected in the flue gas in a spray tower or directly into the duct. The SO, is absorbed, neutralized and/or oxidized by the alkaline reagent into a solid compound, either calcium or sodium sulfate. The solid is removed from the waste gas stream using downstream equipment. Scrubbers are classified as "once-through" or "regenerable", based on how the solids generated by the process are handled Once-through systems either dispose of the spent sorbent as a waste or utilize it as a byproduct. Regenerable systems recycle the sorbent back into the system. At the present time, regenerable processes have higher costs than once-through processes; however, regenerable processes might bechosen if space or disposal options are limited and marketsfor byproducts (gypsum) are available (Cooper, 2002). In 1998, approximately 3% of FDG systems installed in the US were regenerable. Both types of systems, once-through and regenerable, can befurther categorized as wet, dry, or semi-dry. Each of these processes is described inthe following sections. Wet Systems In a wet scrubber system, flue gas is ducted to a spray tower where an aqueous slurry of sorbent is injected into the flue gas. To provide good contact betweenthewaste gas and sorbent,the nozzles and injection locations are designed to optimize the sizeand density of slurry droplets formed bythe system. A portion of the water in the slurry is evaporated and the waste gas stream becomes saturated with water vapor. Sulfur dioxide dissolves into the slurry droplets where it reacts with the alkaline particulates. The slurry falls to the bottomof the absorber where it iscollected. Treated flue gas passes through a mist eliminator before exitingthe absorberwhich removes any entrained slurry droplets. The absorber effluent issent to a reactiontank where the SO,-alkali reaction is completed forming a neutral salt. Ina regenerable system, the spent slurry is recycledback to the absorber. Once through systems dewater the spent slurry for disposal or use as a by-product. Typical sorbent material is limestone,or lime. Limestoneisvery inexpensive but control efficienciesfor limestone systems are limited to approximately9O0/0. Lime iseasierto manage on-site and has control efficiencies upto 95% but issignificantly more costly (Cooper 2002). Proprietary sorbents with reactivityenhancing additives provide control efficienciesgreater than 95% but are very costly. Electrical utilities store large volumes of limestone or lime on site and prepare the sorbent for injection, but this is generally not cost effective for smaller industrial applications. The volume ratio of reagent slurry to waste gas is referred to as the liquid to gas ratio (UG). The UG ratio determines the amount of reagent availablefor reaction with SO,. Higher UGratios result in higher control efficiencies. Higher L/G also increases oxidation of the SO,, which results in a decrease of the formation of scale inthe absorber. O&Mcosts are a direct function of reagent usage, so increasing the UGincreases annual costs. UGratios are approximately 1:lfor wet scrubbers and are expressed as gallons of slurry per 1000 ft3 of flue gas (liters of slurry11000Nm3of flue gas).
Oxidation of the slurry sorbent causes gypsum (calcium sulfate) scale to form in the absorber. Limestone forced oxidation (LSFO) isa newer process based on wet limestone scrubbing which reduces scale. In LSFO, air is added to the reaction tank which oxidizes the spent slurry to gypsum. The gypsum is removed from the reactiontank priorto the slurry being recycled to the absorber. The recycle slurry has a lower concentration of gypsum and scale formation inthe absorber is significantly reduced. Gypsum can be commercially sold, eliminating the need for landfillingof the waste product (Srivastava, 2001). Inaddition to scale control, the larger size gypsum crystals formed in LSFO settle and dewater EPA-CICA Fact Sheet 3 Flue Gas Desulfurizationmore efficiently, reducing the size of the byproduct handling equipment (EPA, 2002). However, LSFO requires additional blowers which increase the capital and annual costs of the system. Wet limestone scrubbing has high capital and operating cost due to the handling of liquid reagent and waste. Nonetheless, it isthe preferred process for coal-fired electric utility power plants burning coal due to the low cost of limestone and SO, control efficiencies from 90% up to 98% (Schnelle, 2002). Semi-Dry Systems Semi-dry systems, or spray dryers, inject an aqueous sorbent slurry similar to a wet system, however, the slurry has a higher sorbent concentration. As the hot flue gas mixes with the slurry solution, water from the slurry is evaporated. The water that remains on the solid sorbent enhances the reaction with SO,. The process forms a dry waste product which iscollected with a standard particulate matter (PM) collection device suchasa baghouseor ESP. The waste product can be disposed, sold asa byproduct or recycled to the slurry. Various calcium and sodium based reagents can be utilized as sorbent. Spray dry scrubbers typically inject lime since it is more reactive than limestoneand less expensive than sodium based reagents. The reagent slurry is injected through rotary atomizers or dual-fluid nozzles to create a finer droplet spray than wet scrubber systems (Srivastava, 2000). The performance of a lime spray dry scrubber is more sensitive to operating conditions. A "close approach" to adiabatic saturation temperature is required to maximize the removal of SO,. However, excess moisture causes the wet solids to deposit on the absorber and downstream equipment. The optimum temperature is 10°C to 15°C (20°Fto 50°F) below saturation temperature (Srivastava, 2000). Lower UGratios, approximately 1:3, must be utilized doto the limitationonflue gas moisture (Schnelle, 2002). Fluegaswith high SO, concentrationsor temperatures reduce the performance of the scrubber (Schnelle, 2002). SO, control efficienciesfor spray dry scrubbers are slightly lower thanwet systems, between 80% and 90% due to its lower reactivity and L/G ratios. Application of a single spray dry absorber is limited to combustion units less than 200 MW (2,000 MMBtuIhr) (IEA, 2001). Larger combustion units require multipleabsorber systems. The capital and operatingcost for spraydry scrubbers are lower thanfor wet scrubbing because equipmentfor handlingwet waste products is not required. Inaddition, carbon steel can be used to manufacture the absorber since the flue gas isless humid. Typically applications include electric utility units burning low- to medium- sulfur coal, industrial boilers, and municipal waste incinerators that require 80% SO, control efficiency (Schnelle, 2002). Dry systems Dry sorbent injection systems, pneumatically inject powdered sorbent directly into the furnace, the economizer, or downstream ductwork. The dry waste product is removed using particulate control equipment suchasa baghouse or electrostatic precipitator(ESP). The flue gas isgenerally cooled prior to the entering the PMcontrol device. Water can be injected upstreamof the absorber to enhance SO, removal (Srivastava, 2001). Furnace injection requires flue gas temperatures between 950°C to 1000°C (1740°F to 1830°F)inorder to decompose the sorbent into porous solids with high surfacearea (Srivastava2001). Injection into the economizer requires temperatures of 500°C to 570°C (930°F to 1060°F) (Srivastava 2001). Duct injection requires the dispersion of afinesorbent sprayintotheflue gas downstream of the air preheater. The injection must occur at flue gas temperatures between 150°Cto 180°C (300°F to 350°F) (Joseph, 1998). EPA-CICA Fact Sheet 4 Flue Gas DesulfurizationDry sorbent systems typically use calcium and sodium based alkaline reagents.A numberof proprietary reagents are also available. A typical injection system uses several injection lances protruding from the furnace or duct walls. lnjection of water downstream of the sorbent injection increasesSO, removal by the sorbent. An even distribution of sorbent across the reactor and adequate residence time at the proper temperature are critical for high SO, removal rates (Srivastava 2001). Flue gas must be kept 10°C to 15°C (20°F to 50°F) below saturation temperature to minimize deposits on the absorber and downstream equipment. Dry scrubbers have significantly lower capital and annual costs than wet systems because they are simpler, demand lesswater andwaste disposal isless complex. Dry injection systems install easily and use less space, therefore,they are good candidates retrofit applications. SO, removal efficiencies are significantly lower thanwet systems, between50%and60% for calcium based sorbents. Sodium based dry sorbent injection into the duct can achieve up to 80% control efficiencies (Srivastava 2001). Dry sorbent injection isviewed as an emerging SO, control technologyfor medium to small industrial boiler applications. Newer applications of dry sorbent injection on small coal-fired industrial boilers have achieved greater than 90% SO, control efficiencies. Advantages: High SO, removal efficiencies, from 50% up to 98%. Products of reaction may be reusable Difficulty of retrofit is moderate to low Inexpensive and readily available reagents Disadvantages: High capital and O&M costs Scaling and deposit of wet solids on absorber and downstream equipment Wet systems generate a wet waste product and may result ina visible plume Cannot be used for waste gas SO, concentrations greater than 2,000 ppm Disposal of waste products significantly increases O&M costs References: Cooper, 2002. Cooper, C.D. and Alley, F.C. Air Pollution Control :A Design Approach. Waveland Press, Inc. Prospect Heights, IL, 2002. EPA, 2000. Srivastava Ravi K. Controlling SO, Emissions: A Review of Technologies. US Environmental Protection Agency, Office of Research and Development. EPAl600lR-00/093. Washington, D.C. 2002. htt~://www.epa.~ovlordntrntlORDNVebPubslso2lindex.html FETC, 1996. Electric Utility Engineer's FGDManual, Volume I: FGDProcess Design. Departmentof Energy, Federal Energy Technology Center. Morgantown,WV, 1996. IEA, 2001. " Coal Research, Sorbent Injection Systems for SO, Control", Clean Coal Technologies Database. http://ww.iea-coal.or~.uklCCTdatabase/sorbinq.htm. Joseph, 1998. Joseph, G. T. and Beachler, D.S. "Scrubber Systems Operation ReviewAPT1 Course". Developed by North Carolina State University under EPA Cooperative Assistance Agreement. Raleigh, N.C 1998.

EPA-CICA Fact Sheet 5 Flue Gas DesulfurizationSchenelle, 2002. Schenelle, K.B. Jr and Brown, C.A. Air Pollution Control Technology Handbook. CRC Press LLC. Boca Raton, FL. 2002. Smith 2001. Smith, Douglas. "SO, Controls: Cost of Scrubbers down to $lOO/kWn. Power Engineering, September, 2001. Srivastava, 2001. Srivastava R. K., and W. Josewicz.. "Flue Gas Desulfurization:The State of the Art" Air and Waste ManagementAssoc., 51:1676-1688,2001. EIA, 2002. EIA-767 Database; Annual Steam-Electric Plant Operation and Design Data, 2001. Energy Information Administration, Department of Energy. November26, 2002. http://www.eia.doe.aov/cneaf/electricitv/pae/eia767. html

EPA-CICA Fact Sheet 6 Flue Gas DesulfurizationPaqe 1 of 1



### CONDITIONS FOR 

### PERFORMANCE GUARANTEE The process guarantee is subject to the following conditions: 1) Operation: The equipment must be installed, adjusted and operated according to instructions provided by the Company or its authorized representative and shall be operated within its rated capacity and within its design range and operating conditions set forth in Design Conditions and Operating Data section of proposal. 2) Testing: Performance testing shall be determined by a method mutually agreeable to both the Purchaser and the Company and conducted as soon as practicable after completion of the installation. The parties will use their best efforts to conduct the tests within sixty (60) days of successful start-up. The testing shall be performed by an independent test firm, which meets the approval of both the Purchaser and the Company. The Company requires reasonable prior notice of performance testing to facilitate inspection of equipment before tests commence. 3) Averaging: At least three Performance tests shall be conducted for the equipment in accordance with the applicable Testing Procedures set forth above and the equipment shall be deemed to have met the Guaranteed Performance Specification if the average of these three performance tests show compliance with each of the Guaranteed Performance Specifications. 4) Reliable Test Data: All test data obtained for the compliance testing of the systems must by reliable and repeatable for the levels of the compounds to be tested as they appear in the system discharge stacks. Emissions levels lowerthan this reliable and repeatable range shall be considered as satisfying the performance guarantee. 5) Equipment Condition: If, through no fault of the Company, the equipment has been abused, altered or otherwise impaired, the Purchaser shall be required to recondition the equipment to the original condition and any replacement of parts, materials and labour shall befor the Purchaser's account. 6) Remedy: In the event that the proposed equipment does not meet the performance guarantee, the Company has the right, at its own expense on a straight time basis, to make such adjustments, changes and additions to the equipment, as it may deem necessary to meet the performance guarantee. 7) Delays: In the event performance testing is delayed through no fault of the Company beyond twelve (12) months from start-up or eighteen (18) months from shipment (whichever occurs first) the Company shall be relieved from all obligations to the Purchaser. 8) Test Results: The Purchaser agrees to provide the Company, upon the Company's request, the results of any performance tests or emission data whether performed by the Purchaser or the Company or any third party acting for either Purchaser or Company.

Revised: March 2004turboson~c 

### Proposal to 

# TRINITY CONSULTANTS Atlanta, Georgia

Wet Scrubber for Coal Fired Boiler
Proposal No: Q08-1269 September 25,2007

Prepared 

### by 

### TurboSonic Technologies, lnc. 239 New Road Building "Bn, Suite 205 Parsippany, 

### NJ, 07054 Phone: (973) 244-9544 Fax: (973) 244-9545 Contact: Jorgen 

### G. Hedenhag



### TurboSonic Inc. 550 Parkside Drive, SuiteA-14 Waterloo, Ontario, N2L 5V4 Phone: (51 9) 885-551 3 Fax: (51 9) 885-6992
This proposal is and remainsthe property of TurboSonic. It contains proprietary and confidential information and is issuedfor the purpose of bid evaluation and purchaseonly. It is intended for the Addressee only and must not be copied or distributed without prior written consent of TurboSonic. Upon completion of evaluation this material shall be returnedor destroyed.

### Turbosonic Page 2 of 10 TRINITY CONSULTANTS 25 September, 2007 Wet Scrubber for Coal Fired Boiler Proposal Q08-1269


## GENERAL DESCRIP-TION
The purposeof the proposed Equipment is to remove SO2and HCI inthe exhaust gases from three coal .fired Boilers in southernTennessee. This proposal is based on information from Trinity Consultants received via e-mail, September 19, 2007. GENERAL The ID Fan will draw the gases from the two existing baghouses blow them into two Scrubbers, one for each baghouse. The Scrubbers consist of Spray Tower Absorbers for acid gas absorption.

SPRAY TOWER ABSORBER Each Spray Tower is a vertical vessel with radial inlet, where the gas continues vertically upwards through a number of spray zones, which provide the necessary contact surfacefor absorption of the acid gases. The Spray Headers are provided with large orifice spray nozzles, which are located so that the Absorber cross sectional area is completely covered and that no gas can escape without coming in intimate contactwith the liquid. After passing through the Spray Zones the gas enters two Mist Eliminatorsof chevron type, which will eliminate droplet carry-over to the Tower outlet. In order to remove possible build up of reaction salts, the bottom Mist Eliminator is provided with wash sprays, one above and one below the unit. The upper Mist Eliminator has a wash spray from below. 'The wash will expose the units to a powerful spray of clean water. The wash is triggered by the plant DCSand is intermittentand covers only part of the Mist Eliminator at the same time. A few minutes per day are sufficient to maintain the Mist Eliminators clean. In order to attain required absorption of HCI and SO2hydrated lime Ca(OH)2is added to the top Spray Header,so that the gas leaving the Scrubber sees the highest pH. LIQUID LOOP The salt concentration in the recycle loop is maintainedat 10% by a bleed (blow down) connected to the discharge side ofthe recycle pump(s). We propose one Pump for each Spray Zone, which yields a flexible Scrubber and makes it possible to shut down any Zone, if the acid gas conditionswould so require. Evaporationtakes place in the Scrubber and in order to compensate for the liquid removed from the Scrubber in the bleed and by evaporation, a liquid level controller in the bottom of the Absorber adds water via a control valve to maintain the pre-determined level.

### T~~rboSonic Page 3 of 10 TRINITY CONSULTANTS 25 September,2007 Wet Scrubber for Coal Fired Boiler Proposal 008-7269


## GENERAL DESCRIPTION (Cont'd)
STACK 

### The Exhaust Stack (supplied by Others) can be located on top 

### of the Absorber. That yields a compact assembly with small footprint. We recommend that the gas velocity in the Stack shall not exceed 33 FPS. The gas entering the Stack is 

### 100% saturated and condensationwill take place on the inside stack walls. At higher gas velocities than 33 FPS the condensate will be thrown out of the Stack and cause "raining" around the stack area. At lower velocities the condensate drains back into theAbsorber.

### Turbosonic TRINITY CONSULTANTS Wet Scrubber for Coal Fired Boiler



### PLANT DATA: Plant Elevation Design Wind Load. Seismic Zone: Fuel Boiler Rating (2 Boilers) Boiler Rating (1 Boiler) Page 4 of 10 25 September, 2007

Proposal Q08-1269

feet ASL MPH UBC



### INLET CONDITIONS: (PER

### ABSORBER) Gas Flow ACFM Normal Gas Flow Gas Temperature Gas Composition (assumed)
02 % by volume Co2 % by volume H20 % by volume N2 % by volume Dry Gas Volume SCFMD Gas Pressure at Absorber Inlet Gas Density SO2Loading
HCI Loading

Gas Volume (saturated) Gas Temperature Dry Gas Volume (saturated)
Moisture Content Gas Pressure at Outlet SO2Loading
HCI Loading ACFM

### TurboSor~ic Page 5 of 10 TRINITY CONSULTANTS 25 September, 2007 Wet Scrubber for Coal Fired Boiler Proposal Q08-1269



## OPERATING DATA: (PER 

### ABSORBER) Pressure Drop Pressure at Absorber Inlet inch WG Pressure Drop inAbsorber inchWG Pressure at Absorber Outl. inch WG Liquid Rates Scrubbing Liquid Recycled Water Absorber Recycle Flow GPM 3,300 Flow per Spray Zone GPM 825 Liquid Pressure PSIG 20 Ca (OH), Consumption 100% Ibslhr 423 20% slurry GPM System Bleed Absorber Bleed Flow Salt Concentration % by weight CaCI2 % by weight Evaporative Loss GPM 24 Water Make-up Rate GPM 78 Mist EliminatorWash Fresh Water Flow Rate GPM (Intermittent) 62 Per each of (3) levels 5 minutes per (3) zones eve

### Turbosonic TRINITY CONSULTANTS Wet Scrubber for Coal Fired Boiler Page 6 of 10 25 September, 2007

ProposalQ08-1269



### One (1) SPRAY TOWER ABSORBER The Spray Tower is a cylindrical vessel with vertical gas upflow. It is provided with four (4) spray zones. Each spray zone consists of a main header with branch pipes equipped with large orifice pigtail nozzles. Above the upper spray zone are two (2) Mist Eliminators of chevron type. Each Mist Eliminator has a wash spray to remove possible reaction salt build-up. The wash is intermittent with frequency and duration controlled by the plant DCS. Material of Construction: Entire Absorber 316 L Stainless Steel Plate Thickness 114 inch Spray Headers 

### (4) 316 Stainless Steel Spray Nozzles 316 Stainless Steel Mist Eliminators (2) 316 Stainless Steel Wash Headers (3) 316 Stainless Steel Wash Nozzles 316 Stainless Steel



### One (1) SET of 

### FIELD INSTRUMENTATION (type 

### Honeywell), consisting of (1) Differential Gas Pressure Sensor & Transmitter (1 

### ) Liquid Level Sensor & Transmitter for Venturi (4) Liquid Flow Meter of Mag-typefor Venturi (1) pH Sensor & Transmitter (1) Density Sensor & Transmitter of El. Conductivity type 

### (8) Liquid Pressure Gauges (4) Liquid Pressure Switches with alarm

### TurboSonic TRINITY CONSULTANTS Wet Scrubber for Coal Fired Boiler Page7of 10 25 September, 2007

Proposal Q08-1269



## SERVICES Technical Services TurboSonic will provide the following services with drawings and flow sheets in 'Solid Works' format: 

### 1. Design and Engineering of the Equipment specified under 'Equipment Supply' 

### 2. General Arrangement Drawing of 'Equipment Supply' 

### 3. Four 

### (4) Operating and Maintenance Manuals



### Services Provided by 

### Others The following services are not included as part of TurboSonic services unless otherwise specified:

1. Foundations, Anchor Bolts and Grouting 

### 2. Ductwork and Stack 

### 3. Fan & Motor 

### 4. Pumps, Piping and Valves 

### 5. Design of Pipe Hangers and Supports 

### 6. Motor Starters & MCC 

### 7. Electric Wiring and Conduits 8. 

### Structural Support Steel and Access Platforms 

### 9. Field Installation and Erection Materials 

### 10. Performance Guarantee Testing 

### 11. All Permits

### TurboSonic TRINITY CONSULTANTS Wet Scrubber for Coal Fired Boiler Page 8 of 10 25 September, 2007

Proposal Q08-1269



### TurboSonic guarantees that the equipment supplied, when operated in accordance with the Design Data and Operating Data specified in this document, and TurboSonic Operating and Maintenance Manual, will meet the following performance:

SO2Emission shall not exceed

HCI Emission shall not exceed 26 lbslhr For 

### SOzlnlet loadings above the values specified in Design Data, the Removal Efficiency shall not be less than 92% 2.4 lbslhr For 

### HCI lnlet loadings above the values specified in Design Data, the Removal Efficiency shall not be less than 82%



### The above performance is subject to the TurboSonic 'Conditions of Performance Guarantee' attached to this proposal. The guarantee is valid for the speci,ficitems listed above and does not extend to other items listed under 'Operating Data.

### Turbosonic Page 9 of 10 TRINITY CONSULTANTS 25 September, 2007 Wet Scrubber for Coal Fired Boiler Proposal (208-1269

PRICE FOR THE DESIGN, ENGINEERING AND SUPPLY OF EQUIPMENT, DRAWINGS AND FLOW SHEETS AS SPECIFIED INTHlS PROPOSAL:

Currency U.S. Dollars FOB Point Point of Manufacture Freight Not Included,will be billed separately at cost Proposal Validity November 25,2007 nditions of Sale'

diem at $850 /calendar day plus travel expenses Startup Service: Per diem at $850 /calendar day plus travel expenses
THEPRICE LISTEDABOVE IS BASED ON THE COST OF THE RAW MATERIAL AT THE DATE OF THlS PROPOSAL. IN VIEW OF THE PRESENT SHORTAGE OF STAINLESS STEEL WE RESERVETHE RIGHT TO REVIEW AND ADJUST THE PRICE IN ACCORDANCE WITH THE RAW MATERIAL COST AT THE TIME OF THE ORDER.

4 weeks Supply of iqu\pment after App 12 - 14 weeks 4 weeks

20% on submittal of Approval Drawings
- --. . 70% upon delivery of the Equipment

### Turbosonic Page 10of 10 TRINITY CONSULTANTS 25 September, 2007 Wet Scrubber for Coal Fired Boiler

-- Proposal Q08-1269

All 

### equipment will be manufactured to TurboSonic standard specifications unless otherwise noted.



### TERMS AND 

### CONDITIONS This Proposal is subject to TurboSonic 'Terms and Conditions of Sale' attached to this proposal.

TurboSonic Technologies Inc. Jorgen 

### G. Hedenhag Sales Managerturbosontc Page 1of 2


### TERMS AND 

### CONDITIONS OF 

### SALE
1) Definitions: Seller means Turbosonic Inc., also referred to as the Company. Buyer means the organization issuing the purchase order, also referred to as the Purchaser. 2) Acceptance: Noorder or contract shall be binding upon Seller until accepted and acknowledged by the Company. Sales representatives are not authorized to bind the Company. Typographical errors are not binding. The Purchaser agrees to accept the equipment and thereby release the Company from all obligations to the Purchaser upon completion of the contract scope proposed herein except those provided under "Material and Workmanship" and "Performance Guarantee", if applicable. 3) Force Majeure: The Company shall not be held responsible for any loss, delay, damage or failure to perform caused by the Purchaser, the Company's inability to secure material, labor or material shortages, fires, acts of God, strikes, lockouts, accidents, Government acts or requirements, embargoes, insurrections or riot, or any other cause beyond the reasonable control of the Company or the Company's vendors, fabricators, or equipment suppliers. 4) Cancellation: The Company reserves the right to full compensation for all costs incurred and a reasonable allowance for profit and overhead if this contract is cancelled. 5) Terms of Payment: Net 30 days from date of invoice with a 2% late payment penalty per month. The Company shall have the option of invoicing for partial shipments delayed by the Purchaser, on a pro-rata basis. Quotations subject to acceptance within 30 days from date thereof. 6) Prices: Prices quoted are F.O.B. Waterloo, transportation charges extra, unless otherwise stated. In cases where freight is allowed and so stated, it is prepaid only to the railway siding or truck terminal nearest to the destination. On freightallowed shipments, the Company reserves the right to select the carrier and routing. Prices on equipment of our manufacturer are firm for shipments to be made within 4 months from date of quotation. For shipments to be made between 4 and 8 months from date of quotation, prices are subject to adjustment to the Company's prices at time of shipment, with adjustment limited to 15% of the quoted price. For shipments to be made after 8 months from date of quotation, prices are to be adjustedto the Company's prices at time of shipment. Prices on equipment not of the Company's manufacture are subject to adjustment by the same percentage of price change as may be made effective by the Company's supplier(s) prior to date of its shipment. 7) Taxes: All present and future Federal and Provincial sales taxes, including the Canadian Federal Goods and Services Tax (GST) shall be extra* to the price quoted, if applicable, unless specifically stated. If taxes are to be included in the Company's scope of work, they are calculated at present rates, and any increase in taxes will be chargeable if they become applicable to any portion of this contract scope during the life of the contract. The contract price shall be adjusted to reflect any changes in tax rates from those in effect at the date of this proposal to those in effect during contract execution. 8) Patents: The Company warrants that the goods shall be free of the rightful claim of any third person by way of any Canadian or U.S. patent infringement and Seller will hold Purchaser harmless against such claim, but if Purchaser furnishes the specifications, then Purchaser shall hold Seller harmless against any such claim which arises out of compliance with the specifications. 9) Credit: Shipments and deliveries shall at all times besubject to the approval of Seller's credit department. 10) Limit of Liability: Notwithstanding any other provision of this proposal, the Seller shall not be liable for any special, indirect, incidental, or consequential damages. The remedies of Purchaser set forth herein are exclusive, and the liability of Seller with respect to any contract, or anything done in connection therewith such as the performance or breach thereof. or from the manufacture, sale, delivery, resale, installation, or technical direction of installation repair or use of any equipment covered by or furnished under this contract whether in contract, intort, or otherwise, shall not exceed 50% of the contract material price of the equipment or part of which such liability is based. In no event shall the Company incur liability for: compliance with any air pollution regulation, laws, statutes and ordinances; defects in equipment purchased caused by corrosion, erosion or abrasion; loss or harm caused by negligence of the Purchaser; loss or damage of equipment furnished by the Company after transfer of case, custody or control of same from the Company.

* GSTnot applicable toprojects F.0. B. outside Canada.
Revised: May 2004turboson~c

-- Page 2 of 2 11) Drawings: Unless otherwise stated in this quotation, prices include one set of contract drawings specified by the Purchaser in his request for quotation. If additional drawings are needed or customer initiated changes are required, they will be provided only upon receipt of a written order authorizing additional charges for such additional drawings. 12) Title and Risk: Title to equipment supplied remains with the Seller until payment in full is received. All goods shall be at the sole risk of the Purchaser from and afler the time the goods are consigned to a carrier by Seller. The Purchaser thereafter shall assume full responsibility for any loss or damage to such material or equipment except for damage resulting from negligenceof the Company. 13) Proprietary Information: The specifications, drawings, designs, manufacturing data and other related information are the property of the Company and are disclosed in confidence upon the condition that they are not, at any time, to be reproduced or copied or used for furnishing information or equipment to others, or for any other purpose in a manner that may be injurious to the Company. The Company's technology is protected under U.S. Patent Nos.: #4.067,703; #4,865,817; #4,893,752; #4,963,329 and related patents in other countries. 14) Back Charges: The Company will not be liable for back charges for labour, materials or other costs incurred by Purchaser or others in modification, adjustment, service or repair of materials furnished inthe Company's scope of work. unless such back charges have been authorized by the Company inwriting by purchase order or work requisition. 15) Material 8 Workrnanship Warranty: The Company warrants for a period not in excess of 18 months from date of shipment or 12 months from date of installation, whichever is earlier, the design, construction and materials of our products to befirst class, and free from defects in materials and workmanship. The Company's sole obligation under this Warranty is limited to repairing or furnishing, without charge, F.O.B. the Company's Factory, any parts found to be defective under normal and proper use. The Purchaser shall give the Company prompt written notice (within 5 working days) of such defects and reimburse the Company at direct cost for any premium time which may be required by the Company to accommodate the Purchaser's schedule. The Company will not be responsible for damages of any nature, resulting from the above-stated Warranty or from any defect in our products, either in materials, design or construction arisingfrom the improper useof such products. Careful consideration is given to selection of materials of construction. Materials are recommended only and it is the Buyer's responsibility to approve this selection. The Company will not be liable for improper selection of materials nor will the Company be liable for any consequential damages resulting from this selection. The Company does not guarantee against abrasion, corrosion or erosion. The above-stated warranty, which is given expressly in lieu of all other warranties expressed or implied, including warranties of merchantability and fitness for particular purpose, constitutes the only warranty made by the Seller. Warranties on equipment not of the Company's manufacture are limited to Terms of Warranty furnished by our suppliers. 16) Delivery: The Company will make every effort to ship the equipment in accordance with the delivery schedule noted in this proposal and availability of materials. The Purchaser, if unable to receive the material, shall promptly advise the Company to what point delivery may be made, and shall assume the risk of all loss or damage while the material is in storage and/or in transit to andfrom storage. 17) Execution: This Proposal shall become a contract between the parties hereto and their successors and assigns when accepted by the Purchaser and executed by an officer of the Company at its home office, Waterloo, Ontario (it being agreed that such contract shall be subject to the laws of the Province of Ontario). 18) Escalation: The Company pricing is based on material prices in effect at time of tender, inclusive of surcharges to proposal validity date. Cost increases of surcharges in effect at the time of material deliveries to the manufacturer's facility will be additional.

Revised: May 2004

### Four-FactorAnalysis 

### B-1 Trinity ConsultantsDAK Americas, LLC Four-Factor Analysis

BASELINE EMISSIONS

Basedoff AP-42 EF l~ear lCoal IAvg. Sulfur ]SO, ~rnittedl (tons)
505.14 478.08 Average: 32,911.33

Basedoff Stack Test EF )year lCoal IAvg. Sulfur 

### ISO, ~rnittedl

Stack Test Emission Factor = SO2 (IbIMMBtu)' Heat ~nput of Coal (~tullb)'10~~'20001bslton

Stack Test Emission Factor =

Slack Test Emission Factor = 25.22 Ib SO2 ton coal cornbusled Stack Test Emission Factor = 3.19E+03 IbS02 ton coal- % SO2 0.97 2,000.00 Ibs
ton Ib SO2 MMBlu 13.000.00 Blu Ib coal cornbusted 1.00 1.000.000.00 MMBtu BtuDAK Americas, LLC Four-Factor Analysis STACK TEST SUMMARY
Run MMBtulhr FPM (Iblhr) FPM (IblMMBtu) NOX (Iblhr) NOX (IblMMBtu) SO2 (Iblhr) SO2 (IblMMBtu)

1 190.00 8.74 0.046 90.73 0.48 187.30 0.99 2 180.00 7.88 0.044 89.78 0.50 174.28 0.97 3 186.00 7.22 0.039 88.10 0.47 179.45 0.96 Average 185.33 7.95 0.043 89.54 0.48 180.34 0.97

"a. &3.,C">S, : 3 ::. .,.'*

P.ilr 4 1r.r*I .l,,:LIv CCmn. 5ZU1 C>.llL,,

## DAK Americas, 

## LLC Four-Factor Analysis COMMON PARAMETERS

Parameter Assumed Value Operating schedule 24 hrtday Operating schedule 7 daylweek Operating schedule 52 weeWyr Operating schedule 8,736 hrlyr Operator wage $22.90 /hr Supervisory costs 15% of operating labor Reagent usage rate' 0.348 tonlhr Reagent cost2 $100 /ton Lime usage rate (max) 695 lbhr Lime cost $0.050 /lb Maintenance requirement 4 hrlday Maintenance labor rate $22.70 /hr Maint. material cost 1.5% ofTCl Bag lifetime 3 Yr Cost ofbag replacement $156,800 Residue generation rate 2,480 lblhr Residue disposal cost3 $45 /ton Distance to landfill 0 mi Waste hauling cost $0 /ton-mi Electical load kW Electrical requirements 0 kW-hrtyr Electrical costs, $/kwh' $0.050 /kW-hr Water usage rate gallhr Water cost1 $0.00075 /gal Wastewater generation rate gaVmin Wastewater treatment cost $0.0020 /gal Overhead 34% of labor and materials Administrative charges 2% of TCl Property tax 1% of TCl Insurance 1% of TCI Economic lifetime 10 yr Interest rate 8.0% Cost adjustment ratio 200511987 1.469 Capital recovery factor (system) 0.1490 Capital recovery factor (replacement parts) 0.3880

1. From "Cooper River SO2.xls". 2. Vendor supplied information to other similar operation 3. EstimateDAK Americas, LLC Four-Factor Analysis
WET FGD CALCULATIONS Variable Maximum permitted coal consumption

%ax Maximum permitted coal sulfur content SO, emission factor Average coal consumed in 2004, 2005, 2006 Average sulfur content of coal consumed in 2004, 2005, 2006 Gas flow rate per scrubber at maximum design conditions Pressure drop per scrubber at maximum design conditions SO, removal efficiency of scrubbers at maximum design conditions Ca(OH), usage per scrubber at maximum perm~tted coal sulfur and consumption Fresh water makeup rate per scrubber at maximum design conditions Blowdown rate per scrubber at maximum design conditions Liquor recirculation rate per scrubber at maximum design conditions Scrubber liquor recirculation pressure Design inlet SO, mass flow rate per scrubber at maximum design conditions Assumed operating duty cycle of Boiler No. 2 per 365 day period Average coal heating value Flyash generation rate for Boiler No. 2 Maximum Potential Uncontrolled SO2 Emissionsfrom Boiler No. 2
EUmax = C, x S,,, x EFso, 12,000 lblton

= 90,228 tonlyr x 1.00% x 25.22 1 2,000 lblton Baseline Uncontrolled SO2 Emissions from Boiler No. 2 C,, xS,,, x EF,,, 1 2,000 lblton

= 32,912 tonlyr x 25.22 12,000 lblton Baseline Controlled SO2 Emissions from Boiler No. 2 EUba,, x (1- CE)
= 415 tonlyr x (1- 0.92) SO2 Removedfrom Boiler No. 2 Under Baseline Operating Conditions

ER~~~tsese = EUbase 

### - ECbase
= 415 tonlyr - 33 tonly~ Estimated Total Ca(OH), Usage at Baseline Operating Conditions

Lbase = Lmm x (caqIcmm),x(savgIs-x) =695 lblhr x (32,912 tonlyr 190,228 tonlyr) x (0.79% 11.00%) EstimatedTotal Make-Up Water Usage at Baseline Operating Conditions

Rwbase = Rmaxx (CevglCm) y. (SaqlSma)

= 78 gallmin x (32.912 tonlyr 1 90.228 tonlyr) x (0.79% 11.00%) Estimated Total Blow Down Flowat Baseline Operating Conditions

Rbbae = %,a x (cevgIcm) x (sevIs-x)
= 54 gallmin x (32,912 tonlyr 190.228 tonlyr) x (0.79% 11.00%) Value 90,228 tonlyr 1 00% 25 22 32,912tonlyr 0.79% 74,000 acfm 4.0 inchwg 92% 695 lblhr 78 gallmin 54 gallmin 3,300 gallmin 20 psig 327 lblhr 8,760 hr 10,000 Btullb 0.00366 tonlMMBtu

1,138 tonlyr

415 tonlyr

33 tonlyr

382tonlyr

200 lblhr

22 gallmin

16gallminDAK Americas, LLC Four-FactorAnalysis

Estimated Total Electrical Power Requiredfor Recirculation Pumps at Maximum Design Conditions From Sect~on 5 of the EPA OAQPS Control Cost Manual (EPN4521B-02-001)
~~hcrc En-.a (uih11w.vnmj~cfe~s totheelm= ~leeckd totno1e a ET.PII I olunietncflowrateofau -. -. [ncfi~l) G i5ttkz\va\r< piflowratemte~ulgtliz absorb- Pli thctoralpzssuuzrtopthoughthe slstmi(uici1~s oofH;O) and istheconiI~u1~d fal-n~orrnrfficte~lc: Vdwsfor hpcCallyr~~~ frmn 0.4ro O 7 Ltksxx-isz.thc electricin reqr~iredb?- arcqclep~mlpc~mk calculated ns~ng Equation 149 10.7J5, (-'.:2 ;< ifi ' t ;?vc~;:i2e; E~:er~~~,~~ = (1.49) F

v.here0 745 1s hc factor~iscl tocmli atI~rn~~r-ir toktV pre\sme 15eqx.sseduifertofv ater N.I~ 1stllcro~l~h~~~rcl yrmigumtorefficirnc~ EPr,,rcm,a = 0.746 x 2.52~10.~ x R, x P, I E Where E is the combined pumplmotor efficiency =0.746 x 0.000252 x 3,300 gallmin x 20 psig x 2 307 ft waterlpsig 10.70 Estimated Total Additional Electrical Power Required for I.D. Fan at Maximum Design Conditions From Section 5 of the EPA OAQPS Control Cost Manual (EPN452lB-02-001): Theelecnicil-\'coui~<<ocl;rtcr-l I\-~rh ollt.1anngaps ;~bsrn.l.e~ tlenve fa~l~eqli~r~uiait< loovelcolnrthcpresslu~ (11opUIchtct~~crwnik. andotl~ei IIIUI~VCI~I~C~~~UI sys~elii. a11(l 1'tulip ~-eqtlumlelas to ~wua~late Ilisolvent Thvellel?:, ~eq~iuedfn~ tlirfuic~ibecnlcula~alusui~ Equat'io~ll .AS

~\hr~e Ellcrp? (inlulow;rt~a) rehslotheelwrsylieedcd tollio\.e ;igi\*e~:\.olumetnctlow~are uf;111 (acfiii) G.1stliex~nste gasflowraleeiltauigll~e ab~011wi. Pi5111e totalpressuredop tlu-oi~,dirl~e s>rrm( u~clizs oi1I.O) ,and isthecmnbuled fall-~nntol ct-ficiency \.sluesfor &~>icallyirni~r fro111 O 4 ro O T Lkzlr 1s;. lheelec~~ic~ty~ec~r~~~ell hyilrec! clrp~ui~pc;~~i becalculateduhinpE~lrlntiorl

1.17x10-~x %,, Pd-IE Where E isthe combined fanlmotor efficiency
= 0.000117 x 74,000 acfm x 4 inches wg 10.70 Estimated Cost Effectiveness of FGD Option at Baseline Conditions

cetl = TACFGD I ERFGD~~~~

= $1,450,174 1382 ton Estimated Cost of Recirculation Pumps (for TCI estimate) From the OAQPS Control Cost Manual:
The a\ elagepiceforaFRPpll~np ofthis sizeis516,'gpm atapressureof60ftuates. based oilther~ndor iulvey [I31 Therefore.tllrcostoftherecyclepuu~~p isesrililatrdas:

Cost = R, x $16lgpm =3,300 gallmin x $16lgpm Estimated Average Heat Inputfor Boiler No. 2 Operating at BaselineConsitions

HJb~e = C,, x 2,000 x HV, 1(1,000,000 x 8,760)

= 32,912 tonlyr x 2,000 lblton x 10,000 Btullb 1(1,000,000 BtulMMBtu x 8,760 hrlyr) Estimated Total FlyashlSpent Reactant Generation at Baseline Operating Conditions

R,,, = Hlb,, x + L,, 12,000 + Ed, xEU,,, 18,760 x (1 36.142 

### - 74.093) 164.054

= 75 MMBtulhr x 0.00366 tonlMMBtu + 200 lblhr 12,000 lblton + 0.92 x 415 tonlyr I 8.760 hrlyr x (136.142 - 74.093) 164.054

### DAK Americas, 

## LLC Four-Factor Analysis
TABLE 4-1 Wet FGD TCI

Cost Item Factor ~stimate' Direct Costs Purchased equipment costs Wet scrubbers (including standard options) Vendor quote' $620,000 Pumps Estimate $100,000 Stacks Estimate $50,000 Lime silo Estimate $200,000 Other equipment Estimate $50,000
A= $1.020,000 Contengencies 0.2 x A $204,000 Instrumentation 0.10 x A $102,000 Salestax 0.03 x A $30,600 Freight 0.05 x A $5 1,000 Total ParrchusedEquipmen1 Costs B= $1,407,600 Direct installation costs Labor x B $689,724 Field material x B $35 1,900 Foundations and supports x B $168,912 Handling and erection x B $563,040 Electrical x B $14,076 Piping x B $42,228 Insulation for ductwork x B $14,076 Contingencies x B $281,520 Total Dii-ect installalion costs $2,125,476 Waste water treatment plant ~stimate~ $70,000 Total Direct Costs (DC) $3,603,076 Indirect Costs (installation) Engineering 0.10 x B $140,760 Construction and field expenses 0.10 x B $140,760 Contractor fees 0.10 x B $140,760 Start-up 0.01 x B $14,076 Permits, licenses, fees Estimate $20,000 Performancetest 0.01 x B $14,076 Contingencies 0.03 x B $42,228 Total Indirect Cost (IC) $512,660 Total Capital Investment (TCI) =DC 

### +IC $4,115,736

I. Estimation methodology is from section 5 ofEPAl452lB-02-001 2. Vendor estimate includes one absorber for $620,000 and a second identical absorber for $608,000. Right now assumed one absorber 3. Already have a waste water treatment plant in place, but pH maybe a concern. Cost ofadding caustic feed.

### DAK Americas, 

### LLC Four-Factor Analysis TABLE 4-2 Wet FGD TAC

Cost Item Calculation cost' Direct Annual Costs (DC) Operating labor

Operator S22.90hrx 8 man-hrlday x 7 daylweek x 52 weeWyr $66.685 Supervisor 15%ofoperator labor =0.I5x $66,685 $10,003 Maintenance

Labor $22.70hr x 4 man-hrlday x 7 daylweek x 52 weeWyr $33,051 Materials 100percent ofmaintenance labor $33,051

Wastewater treatment plant operation & maintenance2 $1 65,000 Reagent for SOzControl 200 Ibhrx $0.05011b x 24 hrlday x 7 daylweek x 52 weeWyr $87,527 Residue Disposal

Flyash 0.42 ton/hr x 24 hrlday x 7 daylweek x 52weeklyr x W5.001ton $164,101 Utilities

Electricity = (Added fan kW +pumpkW) x annual operating hours x electricity rate

= (49kW 

### +41 kW) x $0.0500 /kW-hr x 24 hrlday x 7 daylweek x 52 weeWyr $39,472 Water $0.00075lgal x 22 gallmin x 60min/hr x 24 hrlday x 7 daylweek x 52 week/yr $8,836 Wastewater $0.0020lgal x 16gpm x 60minhrx 24.0 hrlday x 7.0daylweek x 52 week/yr $15,905 Total DC $623,630 Indirect Annual Costs (1C)

Overhead 34% ofsum ofoperating, supv., maint. labor & materials $48,549

= 0.34 x ($66,685 + $10,003 

### + $33,051 + $33.051) Administrative charges 2% ofTotal Capital Investment = 0.02 x $4;1 15,736 $82,3 15 Property taxes 1% ofTotal Capital Investment =0.01 x $4,1 15,736 $41,157 Insurance 1% ofTotal Capital lnvestment = 0.01 x $4,1 15,736 $41,157 Capital recovery CRFx TCI =0.1490 x $4,115,736 $613,366
Total IC $826,544 Total Annual Cost (rounded) $1,450,174
I. Estimation methodology is from section 5 ofEPN452B-02-001 and DAK. 2. DAK estimate. Fixed (wages, maintenance, general 0& M) = 5337,000 year Variable (chemicals, sludge disposal) = $165,000 year (projected)

### DAK Americas, LLC Four-Factor Analysis
DSI CALCULATIONS Variable Cavg HVcoa~ EFso2 Savg Rgrnax Pdrnax Ectl NSR Rllyash pr Do, Average coal consumed in 2004,2005,2006 Average coal heatingvalue SO, emission factor Average sulfur content of coal consumed in 2004,2005, 2006 Gas flow rate per scrubber at maximum design conditions Additional pressure drop per baghouse at maximum design conditions SO, removal efficiency of DSI system at maximum design conditions Normalized stoichiometric ratio Flyashgeneration rate for Boiler No. 2 Scrubber liquor recirculation pressure Assumed operating duty cycle of Boiler No. 2 per 365 day period
Baseline UncontrolledSO2 Emissions from Boiler No. 2 Cav,x SaV,x EFso, 12,000 lblton

= 32,911 tonlyr x25.22 12,000 lblton Baseline Controlled SO2 Emissionsfrom Boiler No. 2

EUbase (I- CE)
= 415 tonlyr x (1

### - 0.50) SO2 Removedfrom Boiler No. 2 Under Baseline Operating Conditions
EUbase - ECbase
= 415 tonlyr - 208 tonlyr EstimatedTotal Ca(OH), Usage at Baseline Operating Conditions
NSR x EUbaS, x 2,000 1Do,

= 3.48 x 415 tonlyr x 2,000 lblton 18,760 hrlyr Value 32,911 tonlyr 13,000 Btullb 25.22 0.79% 74,000 acfm 4.0 inchwg 50% 3.48 0.00366 tonlMMBtu 20 psig 8,760 hr

415 tonlyr

208 tonlyr

208 tonlyr

330 lblhr Estimated Average Heat Inputfor Boiler No. 2 Operating at Baseline Consitions

Hlbase = C,, x 2,000 x HVcoal / (1,000,000 x 8,760)

= 32,911 tonlyr x 2,000 lblton x 13,000 Btullb l(1 ,000,000 BtulMMBtux 8,760 hrlyr) 98 MMBtulhr EstimatedTotal FlyashISpent Reactant Generation at Baseline Operating Conditions

Rwbase = HIbase x 

### by,,, + Lbase 12,000 + El x EU,,,, I 8,760 x (136.142 - 74.093) 164.054

= 98 MMBtuIhrx 0.00366 tonlMMBtu + 330 lblhr 12,000 lblton + 0.50 x 415 tonlyr I 8,760 hrlyr x (136.142

### - 74.093) I 64.054 0.55 tonlhr

### DAK Americas, 

### LLC Four-Factor Analysis

Estimated Total Additional Electrical Power Requiredfor I.D. Fan at Maximum Design Conditions From Section 5 of the EPA OAQPS Control Cost Manual (EPAl4521B-02-001):
Tliee~echicit?~costs associated\~~itlloperati~le agas absorlxrdeliyefi.0111fali~.erpilc.lllellts too\-ercolllr thepressureckopui thecohulul.d~~ct\roxk. nlidorherl~alts oftliecolitl-oliyitenl.and puii1,1.qli~e11lel1ts o mcu-c~~late tlie~olvalt. lliealer~y reqnireci forthef:al~callbecnlcnlated usll~e Equation 1.48-

nl~ele Elielg! (111 L~Iouatt~) 1efei'~ tothe ellerg neetiedtorlloveaglvellx ohuiieh lcfkw. lateofnu (acfiil) G 15tlle\~,aste @as floi+-irate crlrellligthe abborbel PIS tlle totalp essmed~optluollgll the sysrenl(ulcll&ofH.0) alld istIiecolllbmedL?li-nlotolefliclr~lcy \-a11ies fc,~ ~~ylcall! rangefloll~ 0 4to 0 7 Lbe\vlse theelech~crh ~equuedby alecycleymil11yc:illbe cal~tio~~

- EP!dfanmax - 1.17~10~~ x Pdma,1E Where E is the combined fanlmotor efficiency
= 0.000117x 74,000 acfm x 4 inches wg 10.70 Estimated Cost Effectiveness of FGD Option at Baseline Conditions

TAC~~l ER~~lbase
= $1,520,640 1208ton

## DAK Americas, LLC 

## Four-Factor Analysis 

# 0 TABLE 4-4 DSI TCI

Cost Item Factor ~stimate' Direct Costs Purchased equipment costs Lime injection equipment Quotation $475,000 Dry fly ash system Quotation $830,000 New filter bags Quotation $1 16,000 Lime storage silo Estimate $8,000 Other equipment Estimate $42,000 A= $1,47 1,000 Instrulnentation 0.10 x A $147,100 Sales Tax 0.03 x A $44,130 Freight 0.05 x A $73,550 Total Purchased eqzripmentcost (PEC) B= $1,735,780 Direct installation costs Labor Estimate $328,786 Field materials Estimate $142,700 Dismantlement R: removal Estimate $80,000 Foundations & supports 0.04 x B $69,431 Handling & erec~ion 0.50 x B $867,890 Electrical 0.08 x B $138,862 Piping 0.01 x B $17,358 Insulation for duct work 0.07 x B $121,505 Painting 0.04 x B $69,431 Contengencies 0.20 x B $347,156 Total Direct installation cost $2,183,119 Total Direct Cost (DC) $3,918,899 Indirect Costs (installation) Engineering 0.10 x B $173,578 Construction and field expenses 0.20 x B $347,156 Contractor fees 0.10 x B $173,578 Start-up 0.01 x B $17,358 Performance test 0.0 1 x B $17,358 Contingencies 0.03 x B $52,073 Total Indirect Cost (IC) $781,101 Total Capital Investment (TCI) =DC 

### +IC $4,700,000

I. All capital cost data from VGA EST - REV 3-4-18-06

### DAK Americas, 

### LLC Four-Factor Analysis 

# a TABLE 4-5 DSI TAC

Cost Item Calculation Cost Direct Annual Costs (DC) Operating labor

Operator $22.90ihr x 8 man-hrlday x 7.0 daylweek x 52 weeWyr $66,685 Supervisor 15%of operator labor = 0.15 x $66,685 $10,003 Consummablcs

Lime 330 Ib/hx I ton12.000 Ib x $1OOlton x 24 hrlday x 7 daylweek x 52 week/yr $144,028 Maintenance

Labor $22.70/hr x 4.0 hrlday x 7.0 daylweek x 52 week/yr $33,051 Material 100percent of maintenance labor $33,051 Replacement parts

Bags (materials and labor) CRFforbags x bag replacement cost: 0.388 x $156,800 $60,844 Residue Disposal

Flyash 0 55tonlhr x 24 hrlday x 7 daylweek x 52 week!yr x $45.00/ton $214,380 Utilities

Electricity $0.0500kW-hr x 49 kW x 24 hrlday x 7 daylweek x 52 weeWyr $21,610

Total DC $583,653 Indirect Annual Costs (1C)

Overhead 34% of sum of operatins, supv., maint. labor & materials

= 0.34 x ($66,685

### + $10,003+ $33,051 

### +$33,051) $48,549 ad mini strati^.^ charses 2% of Total Capital Investment = 0.02 x $4,700,000 $94,000 Property taxes 1%ofTotal Capital Investment = 0.01 x $4,700,000 $47,000 insurance 1%ofTotal Capital lnvestment =0.01 x $4,700,000 $47,000 Capital recovery CRF x TCl = 0.1490 x $4,700,000 $700,439 Total IC $936,987
Total Annual Cost (TAC) $1,520,640

## DAK Americas, 

## LLC Four-Factor Analysis LOW SULFUR COAL EVALUATION
Table below uses Stack Test derived factor Average Coal Coal Cost Cost Consumption S Content Coal Cost1 Coal Cost 

## so2 so2 

## so2 Differential SO2Decrease Effectiveness (tonlyr) ($/ton) ($1~ r) (lblton) (lb/yr) (tonl~r) ($1~ r) (tonlyr) ($/ton) 32,9 1 1 0.79% $61.OO $2,007,591 25.22 830,024 415 BASELINE 32,910 0.75% $65.00 $2,139,172 23.94 787,973 3 94 $131,580 2 1 $6,262 32,911 0.70% $70.00 $2,303,793 22.35 735,464 368 $296,202 4 7 $6,265 32,911 0.65% $75.00 $2,468,350 20.75 682,931 341 $460,759 74 $6,265 32,911 0.60% $80.00 $2,632,907 19.15 630,398 315 $625,315 100 $6,265 BELOW 0.6% Sulhris "unavailable" in large enough quantities

IUsing data from Massey Coal Supplier for DAK America's Cooper River Currently $61 dollarslton

# GIANT CEMENTCOMPANY Post Office Box 2 18 Harleyville, SouthCarolina 29448



### OVERNIGHT DELIVERY 

### November 2,2007
Ms. Renee G. Shealy Assistant Bureau Chief, Bureau of Air Quality South Carolina Department ofHealth and Environmental Control 2600 Bull Street Columbia, South Carolina 29201 Re: Giant Cement Company Four Factor Analysis Plant: (803) 496-5033 Fax: (803) 496-2 195



### Dear Ms. Shealy: Giant Cement Company (Giant) received a letter from the South Carolina Department of Health and Environmental Control (DHEC) dated October 4, 2007 (Shealy, DHEC to Roberts, Giant), requesting that Giant prepare and submit a four factor analysis by November 2, 2007. As requested, please find attached the Four FactorAnalysis for the Giant facility located in Harleyville. South Carolina. If you have any questions or require additional information, please contact Clinton E. Roberts at (803) 496-285 1 or me at (843) 851-5669. Sincerely,

Lane 

### H. Smith,P.E. Manager, Eilvironmental Projects Attachment: Four Factor Analysis for Giant Cement Coinpany

cc (w1Attachment): Clinton 

### E. Roberts John Von Tress

## FOUR FACTOR ANALYSIS for GIANT CEMENT COMPANY HARLEYVILLE, SOUTH CAROLINA



## November 2,2007

## TABLE OF CONTENTS Page

1.0 

### INTRODUCTION 1 1.1 

### Overview of Cement Kiln System 1 1.2 

### Request from the South Carolina Department ofHealth and Environmental Control 1 2.0 

### THE "TOP-DOFW"APPR0ACHAND FOUR FACTORANALYSIS 3 2.1 

### Background 3 2.2 

### Approach Utilizedby Giant 4 3.0 

### ANALYSIS OFFUEL SWITCHING 

### 5 3.1 

### New CementKiln System 3.2 

### Baseline SO2Emissions 3.3 

### Ana4vsis 3.4 

### Fuel Oil 4.0 

### CONCLUSIONS 8



### TABLES TABLE1 

### -Emissions Data TABLE2 -

### Sulfur Input Data TABLE3 -

### Btu Contribution by Fuel Type TABLE4 - 

### Comparisonof Actual Coal UsedandLow Sulfur Coal TABLE

### 5 -

### SulfurInput Data with Low Sulfur Coal TABLE 6 - 

### Coal Cost Comparison

APPENDICES APPENDIXA - 

### October4,2007

### Letter from DHEC APPENDIX B - 

### QuotationSummary Table UsedtoDevelop Costs



### Page i Revision 0 November 2007

### INTRODUCTION 

### 1.1 Overview of CementKiln System Giant Cement Company (Giant) owns and operates a Portland cement manufacturing facility located in Harleyville, Dorchester County, South Carolina. Giant's operations at this site include limestone (marl) quarrying, stone crushing, cement manufacturing, packaging, and shipping. The facility operates one dry process cement kiln system to produce cement clinker. An air permit to construct and operate the kiln system was issued in 2003, and the first clinker was produced in March 2005. The cement manufacturingprocess involves many steps. Large quantities ofraw materials (e.g., limestone, sand, slag, and flyash) are appropriately proportioned and introduced to the raw mill, where size reduction and inaterial drying occurs. The mixed raw materials (raw meal) are introduced to the preheater tower, in which additional drying takes place and the temperature ofthe raw meal elevates. At the base ofthe preheater tower is the rotary portion ofthe cement kiln, where air temperatures in the burning zone can reach 3,500°F. At this temperature the raw meal is heated to its fusion point (approximately 2,700°F) and clinker is formed. Upon exiting the kiln system, the clinker is cooled and either conveyed to bulk storage or to the finish mill. Gypsum and other admixtures are combined with the cement in the finish mill and finely ground to make finished Portland cement. The finished cement is transported in bulk (i.e., truck and railcar) or packaged and sold in individual bags. 

### 1.2 Requestfrom the South Carolina Department of Health and Environmental Control Giant received a letter from the South Carolina Department of Health and Environmental Control (Shealy, DHEC to Roberts, Giant), dated October 4,2007,requesting a four factor analysis to identify potential controls for sulfur dioxide (SO2)emitted from the kiln system (Appendix A). The request was made in response to the reasonable progress assessment performed for the first Regional Haze State Implementation Plan (SIP). DHEC outlined the reasonable progress assessment process inthe letter. 1. 

### Determined Pollutants ofConcern.The regional planning organization for the Southeastern United States,Visibility Improvement - 

### State and Tribal Association ofthe Southeast (VISTAS), concluded that the controlling SO2 emissions was the appropriate step in addressing the reasonable progress assessment for 201

### 8. 2. 

### Determined Which Source Sector Should be Evaluated for Reasonable Progress. VISTAS determinedthat the focus should be on electric generating units (EGUs) and non-EGU point sources. Page 1 Rev~sion 0 November 2007

### 3. 

### Determined ifthe Clean Air Interstate Rule (CAIR) is Sufficient for Reasonable Progress for Subject EGUs. DHEC determined that existing regulatory programs (i.e., CAIR) are sufficient for the EGUs within South Carolina.
4. 

### Determined Which Emissions Units would be Evaluated Based onInput. DHEC identified the specific area of influence (AOI)that most likely influences the Class I Federal area within South Carolina (Cape Romain) based on a back trajectory analysis performed by VISTAS. Sources identified within the A01and calculated by DHEC as contributing one percent or more ofthe visibility extinction on the 20% worst visibility days for Cape Romain were retained for further evaluation. 

### 5. Evaluate the Four Factors. DHEC performed a preliminary evaluation of SO2controls for Giant, and identified fuel switching "as a potentially realistic option of controlling SO2emissions," with a potential control cost below $2,000 per ton. DHEC performed a limited analysis of potential SO2control alternatives and determined that fuel switching was a potentially realistic option for the Giant facility because DHEC calculated the potential control cost utilizing fuel switchingto be below the established threshold of $2,000 per ton of SO2removed. Subsequently, DHEC requested Giant perform a four factor analysis following a "top-down" approach. A brief summary of the "top-down" approach utilizing the four factor analysis is provided in Section 2.0.

Page 2 Rev~s~on 0 November 2007

### 2.0 

### THE "TOP-DO

## FW" APPROACHAND FOUR FACTORANALYSIS 2.1 

### Background DHEC's letter to Giant requests that the analysis follow a "top-down" approach containing the following elements: 

### 1. 

### Identification ofPossible Control Alternatives. The first step in the topdown approach is to develop a comprehensive list ofpotential control technologies and improvements to existing control equipment that could potentially reduce SO2emissions. The developed list of SO2control options can be based on a wide variety oftechnologies including those listed in Section IV(D) 

### of Appendix 

### Y to 40 CFR Part 

### 51. 2. 

### Identification andRanking ofFeasible ControlAlternatives. The second step ofthe top-down approach evaluates the available control technology's capabilities and eliminates the control alternatives that are not technically feasible. Control technologies are considered technically feasible ifthey have been installed and operated successfully on a particular type of emission unit (inthis case, a cement kiln system), or the control technology could be reasonably adapted or applied to that type of emission unit. Technical infeasibility of specific control alternatives can be based onphysical, chemical or engineering principles. There may also be technical problems that cannot be resolved with the implementation of a particular control technology such as size ofthe emission unit; location ofthe emission unit; site constraints for deploying the control technology; reliability; or adverse impacts onthe emission unit operations, such as the generation of a waste product which is expensive to dispose.
3. 

### Assessment ofCost,Energy, and Other Non-Air Quality Environmental Impacts of Compliance for Technically FeasibleAlternatives. The third portion ofthe assessment incorporates the four factor analysis which consists ofthe following four statutory and regulatory factors: i. 

### Cost of Compliance. The cost of compliance represents the estimates of capital and operating costs based upon a combination of sources including, but not limited to, control equipment vendor quotes, EPA control technology guideline (CTG) documents, BART specific technology guidance documents, and the OAQPSAir Pollution Control CostManual. When it is possible, site-specific design and/or other conditions that affect the site-specific costs of a control technology can be estimated (i.e., available space for add on controls; ducting requirements; chemical, labor, energy, and waste disposal costs; etc.). Page 3 fievision 0 Novcmber 2007

### . . 11. 

### Time Necessary for Compliance. This portion of the four-factor analysis estimates the time the may be required for the facility to incorporate all aspects of each control option (e.g., permitting, design, and construction)before the facility is able to operate utilizing the evaluated compliance option.



### . . . 111. 

### Energy and Non-Air Quality Environmental Impacts of Compliance. Energy impacts that result in additional cost are included as a part of the cost analysis. The energy impact analysis may also consider whether there are relative differences between control options that would impact the use of locally or regionally available fuels or raw inaterials and if that impact will cause a significant economic disruption or unemployment. iv. 

### Remaining useful life of the emission unit. An emission unit's "remaining useful life" may be considered a part of the overall cost analysis ifthe "remaining useful life" is less than the time period used for amortizing costs. In such a case, the shorter time period should be used in the cost calculations. 4. 

### Selection ofthe Control Alternative, ifAny Technically Feasible Alternatives are Found to beReasonable. Once all of the evaluation steps are completed, a determination is made that either: one or more control alternatives meet the selected criteria; or that no evaluated alternatives meet the selected criteria. 

### 2.2 APPROACHUTILIZEDBYGIANT As noted above, Giant received a letter from DHEC dated October 4, 2007. DHEC performed a limited evaluation of potential SO2control options and determined that fuel switching was a potential control option with a cost of compliance of less than $2,000 per ton of SO2removed. It is Giant's understanding that the other option evaluated in DHEC's limited analysis was fluidized gas desulfurization (FGD), which resulted in a cost of compliance exceeding $9,900per ton of sulfur dioxide removed. While there may be alternative coiltrol optioils that are technically feasible to control SO2emissions, Giant concurs with DHEC that fuel switching is the only potential SO2control option to consider. DHEC calculated that fuel switchinghas a potential cost of compliance that approaches $2,000 per ton of SO2removed. Additionally, DHEC requested that the four factor analysis be completed and the results submitted by November 2, 2007. A significantly longer period oftime would be required to perform a comprehensive topdown evaluation of all potential control options. Therefore, Giant submits this four factor analysis for fuel switching only.

Page 4

### ANALYSIS OFFUEL SWITCHING 3.1 New CementKiln System
In 2005, Giant completed the modernization of its cement manufacturing facility in Harleyville, Dorchester County, South Carolina. The modernized ceinent facility consists of one dry-process cement kiln system that replaced four wet-process ceinent kilns. Although the facility decreased the number of kilns from four to one, actual clinker production has increased nearly 30%. In addition, the modernized ceinent kiln system is a state-of-the-art manufacturing facility that is significantly more energy efficient that the previous wet-process cement kilns. Cement manufacturing is an energy-intensiveprocess. Air temperatures in the rotary kiln portion ofthe kiln system can reach 3,50C1°F in order to heat the raw materials to the point of fusion (approximately 2,700°F) to form clinker. In order to generate the heat necessary to produce clinker, the facility is permitted to combust a multitude of fuels, both conventional fuels (e.g., oil, coal, natural gas) and waste derived fuels (both liquid and solid hazardous and non-hazardous waste-derived fuels). The facility typically utilizes natural gas to begin preheating the kiln system. Once the temperature reaches a pre-determined set point, the facility switches to coal and heats the kiln until the raw meal is introduced to the kiln system. Once the raw meal has been introduced tothe kiln system and other operating parameters have been met, the facility utilizes liquid hazardous waste-derived fuels (LWDF), solid hazardous waste-derived fuels (SWDF), and non-hazardous waste derived fuels as a substitute for conventional fuels. Giant can operate the kiln system with up to 100% substitution rates of conventional fuels. It is the goal of the facility to safely maximize the use of waste-derived fuels for energy recovery during the cement manufacturing process. 

### 3.2 Baseline SO2Emissions Following receipt of the letter requesting the four factor analysis, Giant obtained information from DHEC that identified Giant's 2002 base year SO2emissions as 2,825 tons. Giant generally agrees that this value is accurate for the wet-process facility; however, SOzemissions have decreased as a result of the modernization ofthe facility. As noted above, the number of cement kilns decreased from four to one, and the energy efficiency of the new facility significantly increased. The baseline emissions from calendar year 2002 are not applicable to the facility as it is currently constructed and operated. Giant's PSDpermit application utilizes an emission factor of 3.5 lbs S021ton clinker produced. Therefore, reported emissions from the new kiln system are substantially lower than the einissions reported from the out of service wet-process kilns (see Table 1). The time periods for which this analysis has been performed are calendar year 2006 and tlie first nine months of calendar year 2007. Calendar year 2005 was excluded because Page 5 Revls~on 0 November 2007

### this was a transition year for the facility that included the perinanent removal froin service ofthe four wet-process kilns as well asthe startup operations ofthe modernized kiln system. During the shakedown period of the new kiln, the facility did not utilize wastederived fuels. Giant has a vested interest in utilizing waste-derived fuels to the greatest extent practicable, and therefore, the shakedown period ofthe new kiln system is not considered representative of normal facility operations. Since the facility has data for only nine months of calendar year 2007, Giant developed a monthly average (i.e., dividing the summed data by nine months) and then multiplied 

### the monthly average by 12 months in the year to generate projected annual totals. 

### 3.3 Analysis Giant reviewed all of the feedstreams to the cement kiln for sulfur content and calculated the percent sulfur contribution of each (see Table 2). This table shows that the sulfur contribution to the cement kiln system by coal is approximately 4.32% and 3.51 % 

### for calendar years 2006 and 2007, respectively. In other words, the sulfur in the coal accounts for 4.32% and 3.51% ofthe total sulfur introduced to the kiln system. Attributing SOzemissions to each feedstream based on the percent of sulfur input, the einissions attributable to coal are 69 (2006) and 55 (2007) tons per year. For this analysis, Giant has defined low sulfur coal as coal containing less than 0.6 pounds of sulfur per million ~tu.' At 12,500 Btulpound, this equates to approximately 0.75% sulfur by weight. The higher heating value of coal (i.e., Btulpound) call fluctuate greatly depending on many factors (e.g.,geological source, inherent variability). The quotationsrequested by Giant require that the minimum heating value for coal exceed 

### 12,500 Btullb. This minimum value is utilized in the analysis. Additionally, the facility continuously samples and analyzes coal that is fired in the kiln2and has averaged the individual samplesto produce an actual heating value for coal for calendar years 2006 and 2007. Table 4 provides a comparison of the actual coal used versus information provided in a low sulfur coal cost quotation. Because ofthe increased heating value of the low sulfur coal in this particular instance (12,500 Btulpound vs. 11,635Btulpound (2006) and 11,576 Btulpound (2007)), Giant predicts it would have combusted approximately 3,000 tons less coal in each ofthe past two years to provide the equivalent amount of heat. With the reduction in sulfur content of the coal comes a reduction in the total sulfur input to the cement kiln system. Assuming the sameheating value requirements for 2006 

### and 2007, the sulfur contributions attributable to low sulfur coal are 2.13% and 2.02%, respectively, which results in estimated SO2emissions from the low sulfur coal of 33tons

I This definition of low sulfur coal was obtained from the Energy Information Administration. It states, "Low sulfur

coal generally contains 1percent or less sulfur by weight. For air quality standards, "low sulfur coal" contains 0.6 pounds or less sulfur per million Btu, which is equivalent to 1.2 pounds of sulfur dioxide per million Btu." See http://www.eia.doe.gov/glossary/glossary~c.htm. 2 Coal analysis is performed on a weekly basis. 

### Page 6 Revision 

### o November 2007

### (2006) and 3 1 tons (2007). This is a reduction in SO2emissions of 36 tons for 2006 and 24 tons for 2007. Table 5 summarizes this data.
In order to evaluate the costs of switching to low sulfur coal from the coal currently utilized by the facility, Giant reviewed several vendor quotes for coal containing up to 1.5% sulfur. The average coal and delivery cost per ton from all ofthe vendors was used ill tlie analysis. The cost comparison is provided in Table 6. Based on the information contained herein, the cost per ton of SO2removed as a result of switching to low sulfur coal ranges from $7,801 to $1 1,152 for calendar years 2006 and 2007, respectively.
3.4 

### Fuel Oil Tlie use of lower sulfur virgin liquid fuel oil, such as No. 2 fuel oil, would require the construction of infrastructure (i.e., tanks, unloading, and pumping facilities) at the Giant facility and has been qualitatively determined not to be cost effective. Therefore, this fuel switching analysis focuses solely on Giant's use of lower sulfur coal.

Page 7 Rev~s~on 0 November 2007

### 4. 

### CONCLUSIONS As previously indicated, Giant maximizes the use of alternative fuels as a substitute for virgin fuels in its operations. Giant considers its current use of waste-derived fuels that have sulfur concentrations well below that of coal as a form of fuel switching. As noted in Table 2, the average sulfur concentrations for liquid waste-derived fuels were 0.194% and 0.179%, and average sulfur concentrations for solid waste derived fuels were 0.271% and 0.34%, well below the low sulfur coal concentration of 0.75%. Based on the information provided, switching to low sulfur coal is not a cost effective solution to address SO2emissions at the Giant facility in Harleyville, South Carolina. Sulfur input to the cement kiln system as a result of coal usage is less than five percent of the total sulfur input, which corresponds to between 55 and 69tons of SO2emitted per year. Switching to a low sulfur coal reduces emissions between 24 and 36tons of SO2 per year but at a cost ranging from $7,801 to $11,152per ton of SO2reduced. This is well above DHEC's established cost-effective control threshold of $2,000 per ton SOz removed. Accordingly, Giant believes that its continued usage of waste-derived fuels for energy recovery is effectively "fuel switching" that keeps Giant's SO2emissions much lower than ifthe facility operated using 100% coal, and that switching to low sulfur coal for the portion ofthe coal combusted at the facility is cost prohibitive.

Page 8 Rev~sio~i 0 November 2007

## TABLES

### Four FactorAnalysis Calculation Tables Giant Cement Company Harleyville, South Carolina



### Table 

### 1 

### - Emissions Data

Notes: 2006 2007 rll [I]The data developed for calendar year 2007 is a prqjected annual total based on nine months of data. Clinker Produced (tons) 914:933 898.997



### Table 

### 2 

## - SulfurInput Data

Notes: SO, Emission Rate (Ibs SOzltonclinker) 3.5 3.5

[I]The data developed for calendar year 2007 is a projected annual total based on nine months of data. SO, En~issions (tons) 1;601 1.573

Coal LWDF SWDF Kiln Feed

Coal LWDF SWDF Kiln Feed Quantity Used (tons) 41,195 60,014 17:4 17 1;422,214 Year [I]

2006 2006 2006 2006

41,611 64:379 21;177 1;393,445 2007 2007 2007 2007 Average Sulfur (PP~) 14,489 1;935 2,708 9,172 Total 12,229 1,788 3,397 9,906 Total Total Sulfur lnput (tons) 597 116 47 13,045 13.805

509 115 72 13,803 14.499 Sulfur Contribution 

### (%I 4.32 0.84 0.34 94.49 100.00
3.51 0.79 0.50 95.20 100.00 SO, Emissions by Input (tons) 69 13 5 1,513 1.601

5 5 12 8 1,498 1.573 Tons SO, Emissions1 Ton Sulfur Input 0.11598 0.11598 0.11598 0.1I598

0.10850 0.10850 0.10850 0.10850

### Four Factor Analysis Calculation Tables Giant Cement Company Harleyville, South Carolina



### Table 3 

## - Btu Contribution by Fuel Type 

# I Quantity Used 

# I Year (tons) 

# I Btullb 

# I Total MMBtu 

# I %of Total 

# I
Coal LWDF SWDF Kiln Feed 

# I > 2006 2006 2006 2006 Total
Coal LWDF SWDF Kiln Feed



### Table 

### 4 

## - Comparison ofActual Coal Used and Low Sulfur Coal \, 41,195 60,014 17,417 1,422,214 I I 

### I I I 2,603,792

Notes: [I]The data developed for calendar year 2007 is aprqjected annual total based on nine months ofdata. 2007 2007 2007 2007

Year Ill Coal

Notes: [I]The data developed for calendar year 2007 is a projected annual total based on nine ~nonths ofdata. 100.00

Coal 11,635 11,758 6,7 15

41,611 64,379 21,177 1,393,445

Btullb 2006 Low S Coal 

## I 2006
2007 958,596 1,411,280 233,916

11,576 11,400 6,432
Total

Total MMBtu 11,635 

## 1 958,596 

## 1 41.195 36.82 54.20 8.98

12,500 

## 1 958,596 

## 1 38,344 11,576 

## 1 963;383 

## 1 41.611 Low S Coal 

### I 2007 963,383 1,467,834 272,424 2;703,640

Quantity Used (tons) 14,489

12.500 

### 1 963.383 

### 1 38.535 7.500 35.63 54.29 10.08
100.00

597 7,500 12,229 289 Average Sulfur (vv~)
288
509 Total Sulfur Input (tons)

### Four Factor Analysis Calculation Tables Giant Cement Company Harleyville, South Carolina



### Table 5 

### - SulfurInput Data with Low Sulfur Coal

Low S Coal LWDF S

WDF Kiln Feed Year 2006 2006 2006 2006

Low S Coal LWDF SWDF Kiln Feed



### Table 6 

## - Coal Cost Comparison

- Notes: [I]The data developed for calendar year 2007 is a projected annual total based on nine months of data. Notes: [I]The data deleloped for calendar year 2007 is a projcctcd annual total based on nine months of data. 38,535 64,379 21.177 1.393,445 2007 2007 2007 2007

Coal Low S Coal Quantity Used (tons) 38.344 60.0 14 17.417 1.422.2 14

2,995:590 Coal 7:500 1;788 3,397 9,906 Total

$/ton coal

45.10 57.75 Average SulT~lr (PP~) 7,500 1,935 2,708 9,172 Total

45.10 LOW 

### s coal 

### I 57.75 289 115 72 13,803 14,280

$/ton trans

26.89 26.89 Total SulTur Input (tons) 288 116 47 13,045 13,495

26.89 26.89 2.02 0.81 0.50 96.67 100.00

Total $/ton

71.99 84.64 Sulfur Contribution (%) 2.13 0.86 0.35 96.66 100.00

71.99 84.64 0.108504311 0.108504311 0.108504311 0.10850431 1

Quantity Used (tons) 41,195 38,344 41,611 38,535 SO, Emissions Reduction (tons) 3 6 0 0 0 3 6 Tons SO, Emissions/

Ton Sulfur Input

0.1 15984555 0.115984555 0.115984555 0.115984555

3 1 12 8 1,498 l;549 SO, Emissions by Input (tons) 3 3 13 5 1,513 1,565
24 0 0 0 24

Total Annual $ for Coal 2.965.592 3.245.423

3,261,628 SO, Emissions Reduction (tons)
3 6 Additional $ for Low Sulfur Coal
279.83 1 $/Ton SO, Reduced
7.801

266.038 24 11.152

## APPENDICES

## APPENDIX A
October 4,2007Letter from 

### DHECBOARD: IIenlYC Scott Paul C. Aughrry, 111 Chairman Edwin H. Cooper, I11 Vice Chairman Steven C,. Kisner Secrerary C.Earl Hunter, Commissioner 

### 4u M. David Mitchell, MD Glenn A. McCall


### october 4: 2007 l'ro?notmgnndp~.otcctmng the healtl~ ofthept/blicrindthe cnuiroizmeizt


### Mr. Clinton Roberts Giant Cement Company P.O.Box 218 Harleyville, SC 29448 

### Re: South Carolina's Regional Haze State Implementation Plan Dear Mr. Roberts: The South Carolina Department of Health and Environmcntal Control (SC DHEC) respectfully requests Giant Cement Company's assistance in our development 

### 01 

### a State Implementation Plan (SIP) for addressing regional haze concerns in Class 

### I areas. Section 169A of the 1977Amendments to the Clean Air Act (CAA) sets forth a program for protccting visibility in Federal Class 

### I areas that calls for the "prevention of any future, 

### and the remedying of any existing, impairment of visibility in mandatory Class 

### I Federal areas at which impairment results Gcom manmade air pollution." In the 1990 Amendments to the CAA, Congress added section 169B and called on the U.S. Environmental Protection Agency (EPA)to issue regional haze rules. In 1999, the U.S. 

### Environmental Protection Agency finalized the Regional Haze Rule (RHR, 

### 64 

### FK 35713). 'I'he rule calls for state, tribal, and federal agencies to work together to improve visibility in 156 national parks and wilderness areas, including the 2

### 1 Class 

### I Wilderness areas. As part of the rule, States need to develop and implement air quality protection plans (SIPS) to reduce the pollution that causes visibility impairment. Under the Regional Haze Rule, states are required to develop SIPS to reduce visibility impairment with the express intent that, by 2064, the visibility in the Class 

### I areas will be returned to natural conditions. Provisions of the RHR require statcs to establish reasonable progress goals (WGs), expressed in deciviews, for visibility improvement at each affected Class I Federal 

### area. The first set of reasonable progress goals must be met through measures contained in the state's long-term strategy covering the period from the present until 2018. States are required to evaluate progress toward reasonable progress goals every five (5)years to assure that installed emission controls are on track with emission reduction forecasts in each SIP. The first interim rcview will be due to EPA in December 2012. If emissions controls are not on track to meet SIP forecasts, then states will need to take action to assure emission controls by 2018 will be consistent with the SIP. South Carolina is in the process of preparing a SIP to address visibility and regional haze issues for our own Class I Federal area, the Cape Romain Wilderness area (Cape Romain). This 

### SIP establishes reasonable progress goals for visibility in~provenleilt at Cape Romain, as well as a long-term strategy that will achieve these goals within the first

SOU'L'lI CAROLINA DEPARTMENT OFHEALTH -- A N D E N V I R O N M E N T A L CONTROL 2600Bullstreet Columbia,SC29201 Phone:(803) 898-3432 www.scdhec.gov

### Mr. Roberts October 4,2007 Page 2 planning period. As you may know, SC DHEC has been active in the Visibility Improven~ent - 

### State and Tribal Association of the Southeast (VISTAS), the regional planning organization for the Southeastern U.S. The various technical products developed by VISTAS serve asthe basis formuch ofthe Regional Haze SIP. SC DHEC hasjust completed the Reasonable Progress Assessment for the first Regional Haze SIP. The followiilg is the process that the SC DHEC followed: Step 1:

### Determine pollutants of concern. VISTAS evaluated the species contribution of the 20 percent worst visibility days and coi~cluded that sulfate accounted for greater than 70 percent of the visibility iinpairing pollution. The VISTAS states therefore concluded that controlling SO2 emissions was the appropriate step in addressing the reasonable progress assessment for 2018. The VISTAS findings were consistent with the finding ofthe SouthemAppalachian Mountain Initiative (SAMI). SAMI confirmed that sulfate particles account for the greatest portion of haze affecting Class I Federal areas and that these sulfates were produced in large 

### part from SOzemissions from coal combustion. Step 2:Determine which source sectors should be cvaluatedfor reasonable propress. Since SO2 point source emission in 2018 are projected to rcpresent greater than 

### 95 percent of total SO2 emission inventory, the VISTAS states concluded that the focus should bc on electric generating units (EGUs) and non-EGU point sources of SO2 emissions. Step 

### 3: Detemline if the Clean Air Interstate Rule (CAIR) is sufficient for reasonable pIpgress for subiect EGU's. SC DHEC evaluated the amount of SO2 reductions from the EGU sector resulting from CAIR. The EGIJs in South Carolina are expected to reduce their SOz emissions by greater than 80 percent between 2002 and 2018. Much 

### of that reduction is the result of CAIR. Based on the controls predicted by IPM under CAIR, SC DHEC has concluded that existing regulatory programs constitute reasonable progress measures for South Carolina EGlJs during this first assessment period (between baseline and 2018). Step4: Determinc which emission units would be evaluated based on impact. With SO2 emissions from EGU and non-EGU point sources having already been established as the greatest contributors to visibility impairment, SC DHEC then identified the specific geographic area (Area of InfluenceIAOI)that most likely intluences visibility at Cape Romain. This A01is based on a back trajectory analysis performed by VIS'T'AS

### Mr. Roberts October 4, 2007 Pagc 3 that identified the sources of SO2emissions for the 20 percent worst visibility days. SC DHEC identified the major SO2 point sources located within Cape Romain's A01 Lhat would likely have the greatest impact on visibility. Finally, SC DHEC calculated the fractioilal coiltribution, based on visibility extinction on the 20 percent worst days, for all emission units within the SO2 A01 for Cape Romain and identified those emission units with a relative contribution of one percent or more. Collectivcly the VISTAS states have agreed that a one percent threshold isreasonable and is consistent with significant impact levels set for other federal thresholds including Prevention of Significant DeterioratiodNew Source Review. Step 5: Evaluate the Four Factors. The list of facilities within the SO2A01for Cape Romain and identified by SC DHEC as having emission units with a relative contribution of one percent or more are being asked to evaluate possible SO2 controls on these units.. This evaluation, aimed at reducing these units' coiltribution to visibility impairment, will require each facility to use a four factor analysis to include the following statutory and regulatory factors: (1) cost of compliance, (2) time necessary for compliance, (3) thc energy and non-air quality environmental impacts of compliance, and (4) the remaining useful life of the emission unit. For the limited purpose of evaluating the cost for the reasonablc progress assessment in this first Regional Haze SIP; SC DHEC believes it is not equitable to require non-EGUs to bear a greater economic burden than the EGUs for a given control strategy. A cost of $2,000.00 per ton was chosen as the threshold to represent the typical cost of compliance. This cost is based in pat on the facility-by-facility and system-wide costs for implcmenting North Carolina's Clean Smoke Stacks Act (CSA). Such costs ranged from $912.00 to $1,922.00 dollars per ton of SO2 removed, and the average cost per system ranged from $1,23 1 

### .OO to $1,375.00 dollarsper ton of SO2removed. These costs were estimated using the capital costs from CSA 2006 compliance plans and projected operating costs provided by Duke Energy and Progress Encrgy. The costs were evaluated onthe same terms as the AirControlNet cost estimates, so they are directly comparableto the cost estimates for the non-EGU units in South Carolina. In addition, thc cost of $2,000.00 per ton is within the range cited by U.S. EPA in the notice of proposed rulemal<ingfor CAIR of what constitutes cost-effective einission reduction controls for SO2and NOx emissions for EGUs (70 FR 25204 

### - 25207). Other CAIR-affected states (e.g., Connecticut) are using this EGU cost range to establish a range constitutiilg costeffective SO2and NOx colltrols for non-EGUs. During the current reasonable progress assessment, one or more of the units at Giant Cement Company was identified ashaving a potential control cost below the established

### Mr. Robelts October 4, 2007 Page 4 threshold of $2,000.00pcr ton. Specifically, the cost to switch to a lower sulfur fuel was identified as a potentially realistic option ofcontrolling SOzen~issions. As such, the Department requests that Giant Cement Company conduct a four factor analysis (using the aforementioned statutory and regulatory factors) to determine the feasibility of switching to a lower sulfur fuel, andlor identifying othcr potential controls that might benefit the air quality of South Carolina's only Class I area, Cape Komain. The Department requests that this analysis follow a "top-down" approach conlaining the followiilg elements: Identification ofpossible control alternatives Identification and ranking of feasible control alternatives Assessment of cost, energy, and other non-air quality environmental impacts of compliance for technically feasible alternatives Selection of the control alternative, if any technically feasible alternatives are found to be reasonable In ordcr to facilitate this process and to continue our colleclive efforts to develop a complete SIP package for submittal in December of this year, the Department has established a tiineline for conducting a Public Hearing and subsequent submittal of [he appropriate Notices to the South Carolina 

### State Register. As such, the Department requests that this four factor analysis be cornplcted and the results be submitted to us by 

### November 2,2007. The Department remains committed to improving air quality and appreciates this opportunity for consultation with you. Should youhave any further questions concerning South Carolina's regional haze SIP development, please contact Maeve S.R. Mason of my staff at (803) 898-2230 or masonmr@dhcc.sc.pov. Sincerely, 

# G-Q% by/px Renee Shealy, Assist. t ureau Chief Bureau ofAir Quality South Carolina Department of Health and Environmental Control cc: Robert J. Brown, Jr., Director, Division ofAir Planning, Development and Outreach, SCDHEC Stacey Gardner, Manager, Regulation Development Section, SCDHEC Tim Allen, U.S. FWS Air Quality Branch Nacosta Ward, U.S. EPA Region 4

## APPENDIX 

## B Quotation Summary Table Used to Develop Costs

### Four Factor Analysis Quotation Summary Table

Quotations for Coal Currently Used at Giant

l~ail Cost 

## 1 $26.82 

## 1 $26.88 Supplier [I] Date I I

l~ulfur 

## 1 1.5% max. 

## 1 1.5% max. Company A 513 112007 $46.00 Price Ton

Specifications Btu / Pound
I~oisture 

## 1 9%max. 

## 1 8% max. Company B 511712007 $44.90

IVOIS. 36 min. 12,500 guar. 

### Giant Cement Company Harleyville, South Carolina

12,700 min Company C 511512007

30+ 36 min. 

# I 

# I 12,800 1.5% max.

Notes: [l]The names ofthe suppliers have been withheld from the analysis. Companies A and B provided separate quotes for different time frames. Company D

9/7/2007

[2] The average costs are the averages for all seven ofthe quotations provided. The averages are the costs used in the analysis. 12,500-12,600 1.3-1.5%

Quotation for Low Sulfur Coal for Potential Use at Giant Company E 9/7/2007

Supplier Company D 11/1/2007 IDate 

# I I

Price Ton $57.75 12,700 1.50%

Rail Cost $26.89 [I] Landed Cost $84.64 Company B 9/7/2007

0.75% max. 12,700 1.50% Company A 911012007

12,500 1.50%

Notes: [I]A rail cost was not provided with this quotation. Therefore, the average rail cost from all quotations received by Giant is used here. Average r21

Ash Vols. 12%Holcim (US) Inc. Phone803496 5027 

# Ho

# 1c

# irn 200 safety street I Hwy 453 F,X 803 496 2733 P.O. Box 698 www.holcim.com1us Holly Hill, SC 29059



### November2,2007 Ms. Renee Shealy Assistant Bureau Chief Bureau of Air Quality South Carolina Department of Health and Environmental Control 2600 Bull Street Columbia, SC 29201 Subject: Holcim Responseto DHEC Requestfor Development of a State lmplementation Planfor Regional Haze Concerns 

### Dear Ms. Shealy: In response to your October 

### 4, 2007 letter requesting Holcimto assess the feasibility of switching to a lower sulfur ,fuel in support of South Carolina's Regional Haze State lmplementation Plan, Holcim (US) Inc. Holly Hill Plant has evaluated costs associated with a switch to use a low sulfur fuel oil. 

### A low sulfur oil cost analysis was then performed as suggested from your preliminary analysis information (Figure 1). 

### It should be noted that the analysis sheet provided by SC DHEC indicated a baseline year of 2002. At the Holly Hill facility, the wet process cement kilns were shutdown in 2003 and eventually demolished. They were replaced with a single more efficient preheaterlprecalciner kiln system which began operation in 2003. The cost analysis is based on the potential emissions from the new kiln as represented in Table 1. However, SC DHEC should consider the reduced potential SO2emissions of 160 tons per year from the new system. BACKGROUND 

### The cement making process is unique in many aspects with regard to sulfur dioxide (SO2)emissions in comparison to systems such as boilers and incinerators. The cement kiln categorized as an industrial furnace system can use over 30 raw materials which can be divided infour basic categories: 

### P Lime (calcareous) 

### P Silica (siliceous) 

### P Alumina (argillaceous)

BUREAU 

### OF AIR QUALIN

# > Iron (ferriferous) The limestone, or any other form of calcium carbonate, such as marl used at the Holly Hill Plant, makes up over 80 percentof the combination of raw materials used to prodl~ce the "kiln feed." Sincethe cement kiln system utilizes a highly alkaline kiln feed material, upto 95 ~c3rcent of the SO2emissions can be absorbed in the process Exceptionsto this are cement kiln systems which utilize raw materials that contain significant amounts of sulfide sulfur (pyrites). In addition,the majorityof the SO2introduced into the kilnfrom the fuels are incorporated into the product (clinker) produced by the kiln system. 

### COST EFFECTIVENESS REVIEW Holcim has prepared a SOscost effectiveness analysisto assess the potential switch ,from3 percent sulfur coal, the level .thecurrent permit is based upon, to lower sulfur fuel oil, as requested. The results of this analysis are provided in Table 1. The switchto 0.9 percent sulfurfuel oil would result in an additional cost to Holcimof $41,039.00 per ton of SO2removed. 

### CONCLUSION From ,the October4, 2007 correspondence, it was suggested that a threshold of $2,000.00 per ton would be used when considering additional SO2controls. From the results of the cost analysis (Table I),it is concluded by Holcim that a lower sulfur fuel switch would significantly exceed the established $ 

### 2,000.00 per ton threshold. Due to these results, a four factor analysiswas not performed. Should you have any questions, please feel free to contact me at (803) 496- 2756. Sincerely,



## 0 Glenn Raynor Enviror~mental Manager
c: Chester Goodson Michelle FergusonStale SC SC SC SC SC SC GA SC SC 

# ---- SC SC SC SC SC SC FL NC NC SC G A SC FL FL NC " A FbnmsCl~~CONTCL*(eR~NlbfP Nassau Cc 0890003 JEFFERSONSMURFIT CORPC 15 Paperboard Mills B~turn~no~ FGD 3.242 3.639 4 3.260 90 525,163,913 $7.720 $7.720 303 79 1198 004 15 18 New Hano, 37129000E INVISTA S A R L G-247 lnduslnal Organic C Resldual Low Sulfur 011 (0 9% 3.249 2,611 0 810 31 $1,469.295 $1.815 $1.815 21801 1198 005 1257 New Hano? 37129000E INVISTA. S A R L G-247 lnduslnal Organlc C Resldual FGD 3.249 2,611 0 2,350 90 $3,754.002 $1.597 $1 597 21801 1198 005 12 57 FbracsC10UM003STOblEaM##W~~ RJIkls

. -. S Wdll Mat5 SlJ19 138.80 524 0.04 20.83 Rlchmond 24500006 INTERNATIONALPAPER - AU( PBZA Pulp Mills B~tum~no~ FGD 1,574 1.767 4 1 583 90 $15.181 164 $9,593 $9593 21831 809 004 1233 cwtwan o~2oane-mw~rn 

# - FW~W-~~OQ #-

# - =wtrktrt:> -w* s: 

### tm i ,st 96. 

### wmm sr.m imra sw 0.04 13.94 PutnamCc 1070005 GEORGIA-PACIFIC CORP P 15 Paper Mills Resldual FGD 3,703 4.329 0 3.896 90 $17.425.139 94,473 $5.869 410 92 10 53 003 7 12 Putnam Cc 1070005 GEORGIA-PACIFIC CORP P 15 Paper Mills Res~dual Low Sulfur 011 (0996 3.703 4,329 0 1.342 31 $2.435.476 $1.815 $1,815 41092 1053 003 7 12 N- Hano,17129001 1SOLJTHERNSTATES CHEMICdG-21 lnduslnal lnomanlc SuhncA Increase% Conversl 931 1.112 0 $46 85 9427.461 $452 $452 21664 5 13 002 12 57

--- *.

. ., ~ - ,. -- .. . -...- .---. ",- 

### --

~ *-. -. .*- .. - -- 01d >=I, .TUX >= I, Catr= Il0,OOOTable 1 % 3 Sulfur Coal

#2 Fuel Oil Potential clinker production Heat consumption Heat usedto get clinker CalorificValue of coal Coal use peryear Priceof Coal Total cost of coal

SO2 Cost Potential clinker production Heat consumption Heat usedto get clinker CalorificValue of oil Oil use peryear Price of Oil Total cost of oil Permitted Maximum Clinker Production (Assume 3700 kJlkg heat consumption, valuefrom ATR 2006) (Assume 27.4 GJlmton of coal, value from NAPO) 2,462,318 2,233,815 3,700 8,265,115 27.4 301,647 332,503 61,23 20,359,146 short tonslyear metrictonslyear kJlkg clinker GJIyear GJlmton mtlyear short tonlyear USDlshortton USDlyear

2,462,318 2,233,815 3,700 8,265,115 42.3 195,393 215,380 858.8 184,968,397

The price difference Max. SO2 reduction Cost perton SO2 reduction short tonslyear metric tonslyear kJ/kg clinker GJIyear GJImton mtlyear short tonlyear USDlshortton USDlyear
164,609,251 4011 41,039 Permitted Maximum Clinker Production (Assume 3700 kJ/kg heat consumption, value from ATR 2006) (Assume 129,000 BTUIgal, value from NAPO) ($3.04/gal * 1 ga117.08 lbs * 2000 Ibslton) = $858.8/short ton, NAP0

USDIyear short tonslyear USDIyear Current PTE SO2 Emissions using 3 % Coal Threshold is $2,000.Holcirn (US) Inc. Phone8034965027 200 Safety Street I Hwy 453 Fax 803 496 2733 PO. Box 698 www.holcim.corn/us Holly Hill, SC 29059



### November 19,2007

Ms. Renee Shealy Assistant Bureau Chief Bureau of Air Quality South Carolina Department of Health and Environmental Control 2600 Bull Street Columbia, SC 29201 

# BUREAU 

# OF AIR 

# QUALITY Subject: Four Factor Analysis to Support DHEC Request for Development of a State Implementation Plan for Regional Haze Concerns Dear Ms. Shealy: In responseto your email of November6, 2007, Holcim (US) Inc. (Holcim) is providingto you at your requestthe analysis results for the other three factors which our November2, 2007 letterto you did not address. To perform the analysis of the other three factors, Holcim has utilized the "Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) Determinations; Final Rule, July 6, 

### 2005"as guidance. Provided below are the results of this analysis. FACTOR I:TIME NECESSARY FOR COMPLIANCE For Holcimto switch from the use of coal (3% 

### maximum ) as the primary fuel for the kilnto useof a 0.9 percent sulfur fuel oil, new above ground oil storage, handling, and delivery systems would need to be designed, permitted, and constructed. Additionally other Holcim Holly Hill environmental permitswould need to be amended (i.e., SPCC Plan). This process would be expectedto take a minimum periodof three years to complete. FACTOR 2: 

### ENERGY AND NON-AIR QUALITY ENVIRONMENTAL IMPACTS OF COMPLIANCE This section addresses any potential non-air quality environmental impacts associatedwith a switch from use of 

### 3 percent sulfur coal as the primary fuel for the kilnto use of a 0.9 percent sulfur fuel oil. For this potential switch of fuels,

### there is an increased risk of oil spillage and the potential for contaminationof soils from the delivery, storage, and handling of the fuel oil. The potential fuel switch will also not be expected to produce any anticipated irreversibleor irretrievable commitment of natural resources, such as water, and is not expectedto result in changes in mbient noise, radiant heat, or dissipated static electricity. FACTOR 

### 3: REMAINING USEFUL LIFE Since the new kiln began operation in October2003, the life of the new kiln systerrl is expected to be rrrinimally40 years before major system components would need to be replaced. Dueto the length of the time period, the remaining useful life is assessed to have essentially no effect on the cost controls and the BART determination process. FACTOR 4: COST EFFECTIVENESS ANALYSIS Holcim has previously prepared a SO2cost effectiveness analysisto assess the potential switch from 3 percent sulfur coal, the current levelthat our Title 

### V Operating Permit is based upon, to 0.9 percent sulfur fuel oil, as requested. The switch to 0.9 percent sulfur fuel oil was shown in our November 2, 2007 letterto you to result in an additional cost to Holcim of $41,039.00 per ton of SO2 removed. CONCLUSIONS From the October4,2007 SC DHEC correspondence, it was suggested that a threshold of $2,000.00 per ton would be used when considering the cost effectivenessof additional SO2controls. Based uponthe results of the four point analysis it is concluded by Holcim ,thata potentialswitch to a 0.9 percent sulfur fuel oil would significarltly exceed the established $ 2,000.00 per ton threshold. Should you have any questions, please feel free to contact me at (803)496- 2756.

Glenn Raynor Environmental Manager c: Chester Goodson Michelle Ferguson

## IN-I

## EKNATIONAL~ PAPER George~own Mill 700 South Kaminslu Street Georgetown, SC 29440 October 30,2007

\

# k\'& Ms. Renee G. Shealy Assistant Bureau Chief SC DHEC Bureau ofAir Quality 2600 Bull Street Columbia, SC 29201 Subject: Request for Additional Information for Use in the South Carolina Regional Haze StateImplementation Plan


### Dear Renee: International Paper (IP) -

### Georgetown Mill is providing the additional information you requested during our telephone conversation on October 2,2007. Weunderstand SC DHEC is required to prepare and submit a Regional Haze State Implementation Plan inDecember, 2007 and federal regulations (Reasonable Further Progress) require that cost information on control technologies be included, even though emissions reductions between now and 2018 

### arepredicted to meet the impl ::.?ent goals for 2018 

### and possibly beyond. Earlier !his year, you requested that we review the results of a four-factor analysis conducted for VISTAS by Alpine Geophysics of Asheville, NC. Alpine Geophysics used the EPA-approved model AirControlNET to perform this analysis. While we were unable to confirmmany ofthe assumptions used in 

### that study, the cost-effectiveness results were similarto those we have seen at other paper mills and we responded to that effect. We understood during our October 2nd telephone conversation that the original Alpine Geophysics' work product was determined to be deficient by EPA and the FLM because it did not evaluate the cost effectiveness of fuel switching alternatives. Alpine Geophysics subsequently evaluated fuel switchngand you indicated their costs were less thanthe $2,000 per ton cost effectiveness threshold that DHEC has adopted. Sincefuel switching appeared to be cost effective based onthe results compiled by Alpine Geophysics, you requested that International Paper -

### Georgetown Mill complete and submit a facility-specific assessment of fuel switching alternatives for Unit 

### ID 01. Power and Recoverv Operations 

### Unit 

### ID 01 at the Georgetown Mill includes equipment that supports the Power and Recovery Operations. Units ofinterest forthis exercise are No. 1

### Power Boiler, No. 2 

### Power Boiler,No. 1 

### Recovery Boiler and No. 2 Recovery Boiler. ThePower Boilers currently burn a diverse fuel mix consisting of wood, coal, tire-derived fuel, fuel oil, natural gas, propane, and arepermitted for several additional fuels that we are currently not utilizing. The fuels that contribute to sulfur emissions are coal, tire-derived fuel and No. 6 fuel oil. TheRecovery Boilers primarily bum black liquor solids but also burn limited amounts of No. 6 

### fuel oil,primarily during start-up (e.g.,


### National Environmental PerformanceTrack U 5 Env ro-merta Prltect~on Agency

### Ms. Renee G. Shealy October 30, 2007 Page 2

less than 2% of fuel input annually). The Mill evaluated switching sulfur-contributing fuels (coal, tire-derivedfuel andNo. 6 fuel oil) with natural gas, low-sulfurfuel oil and distillate oils. 

### Four Factor Analvsis International Paper consideredfour factorswhen evaluating the feasibility ofburning alternate low-sulfur fuels. These four statutory factors are: cost of compliance, time necessary for compliance,energy and non-air quality environmentalimpacts of compliance and remaining useful life ofthe source. Cost ofCompliance 

### The Mill evaluated the cost ofreplacing sulfur-containing fuels with alternate low-sulfur fuel options. Table 1 summarizes the results of the fuel switching analysis. It should be noted that the Mill has practicesin place that help minimize sulfur emissions. Although not required to do so by regulation,the Georgetown Mill historically has chosen to burn low-sulfur fuel oil, consisting of 0.7% sulfur on average in the power boilers. In addition, sincethe power boilers obtain a significant portion of theirheat from wood, the resulting alkalinewood ash serves as an effective scrubbing medium for the resulting stack gas. The Power Boilers are equipped to bum natural gas and fuel oil. However, significant modificationsto fuel tanks, piping systems, delivery systems, andburners or combustion controls would be required to implement these options. 

### The costs included herein arejust the cost of fuel; not includedis funding requiredto implement these options. The modificationslisted would be significant;however, it was not possibleto perform the necessary engineering estimates in th :heavailable. It should be noted that all options, with only the fuel cost, are well above the threshold limit of $2000/ton SO2. Therefore,fuel switching is not a viable option forthe Georgetown Mill. The detailed calculationsfor both fuel costs andreduced SO2emissionscan be found in Tables 

### 3- 10. The first option was to replace all coal,No. 6 fuel oil and tire-derived fuel with natural gas. The next option replaces all sulfur fuels with low sulfurfuel oil. It shouldbe noted that the Mill's Title

### V Permit limitsNo. 6 

### fuel oil consumption in the power boilers. Therefore, the Mill calculatedthls alternativetwo ways: (A) replacing as much fuel oil as possible with low sulfur fuel oil and the balance natural gas, and 

### (B) assuming the mill would not be limited on firing low sulfurfueloil, calculating a complete fuel switchto low sulfur fuel oil. The third option was to replace all coal,No. 6 fuel oil and tire-derived fuel with low sulfur distillate oils. The cost estimatesfor fuel switchingrange from $6,417/ton SO2 to $10,012/ton SO2. TimeNecessarvfor Compliance 

### The changes requiredto modify the fuel tanks,piping systems, delivery systems, and burners or combustion would require capital funding and wouldtake considerabletime to implement. Enermand Non-Air Ouality Environmental Impacts ofCompliance 

### In addition to the capital and operating costs, conversion to low sulfur fuels wouldhave other impacts on the International Paper mill operations. These additional impacts include: The Georgetown Mill currently bums tire-derived fuel which is a environmentally beneficialuse ofthis material.

### Ms. Renee G. Shealy October 30,2007 Page 3

Conversion to additional fuel oil andlor distillate oil would require the installation of additional tank storage. Additional tank(s) would require secondary containment along with other environmental and safety monitoring systems. 

### In addition, thetank(s) would require incorporation into the mill's Spill Prevention, Control and Countermeasures (SPCC) Plan. Receiving additional fuel oil and distillate oil via trucks would impose additional environmental and safety requirements at the mill and create traffic, personnel and material flow problems. Remaining UsefulLife ofthe Source 

### Due to the fact that this option is cost prohibited, the life oftheboilers does not factor into the feasibility of implementation. Comments Wewish to point out that these alternatives appear tobe contrary to the national energy policy which we understand promotes reduced dependence on 1)foreign energy (in the case of oil) and 2) finite supplies of domestic fuels better used forresidential heating (in the case of natural gas). The energy-use strategy in American industry over recent years (especially since the significant price increase following Hurricane Katrina) has been toreduce use of imported oil and domestic natural gas in favor ofmore plentiful domestic energy sources, sources of renewable energy, and other alternate fuels (e.g., tire-derived fuel, railroad-derived fuels, and various other cleanburning waste materials). We trust that any evaluation of fuel switching by state or federal environmental agencies will balance environmental improvement objectives with costs and natio..d Gnergypriorities. We have also found that paper mills around the world compete based on cost of fiber, cost of labor, and cost of energy. Energy costs in the United States, especially for natural gas, are among the highest in the world (Figure 

### I).' Any effort to drive large industrial users to fuel switchto natural gas would not only have the impact of making domestic natural gas supplies even more scarce and expensive, it would make theU.S. paper industry less competitive in the global marketplace. Other Alternatives The cost effectiveness of other control technologies has been well documented in the VISTAS/ Alpine Geophysics report and other individual four-factor analyses performed by paper companies including IP. These results universally show that additional controls arenot cost effective and it was not necessary torepeat these conclusions in this analysis given the short time available prior to your deadline for submitting the SIP. Path Forward We strongly suggest that DHEC hold another informational meeting on the processes and expectations associated with this next phase of Regional Haze Rule implementation (e.g., Reasonable Further Progress). The last informational meeting, held on June 21,2006 was very helpful in understanding DHEC's expectations on BART. 

### We realize DHEC is under obligation 

# 'Natural GasPrices Around the World, IndustrialEnergy Consumers ofAmerica, August 2007

### Ms. Renee G. Shealy October 30,2007 Page 4

to meet a December deadline for a Regional Haze SIP but we are not aware of the processes being used or thebasis for the assumptions and findings. We would appreciate the opportunity to learn more about this process and how we can participate.
Should you have any questions, please call me at (843) 545-2291.
Sincerely, INTERNATIONAL PAPER GEORGETOWN MILL

GaryN. Weinreich, P.E. Environmental Manager Attachments: Figure 1: 

### Table 1: 

### Table 2: 'i..cl~ 3: Tahle4: Table 5: Table 6: Table 7: Table 8: Table 9: Table 10: Natural Gas Prices Around the World Summary ofEconomic Impact for Fuel Switching Alternatives Fuel Reference Data Fuel Switching Cost Estimate: Natural Gas Alternative Fuel Switchng SO2Emission Offset: Natural Gas Alternative Fuel Switching Cost Estimate: Low Sulfur No. 6 Fuel Oil & 

### Natural Gas Alternative Fuel Switching SO2Emission Offset: Low Sulfur No. 6 Fuel Oil & 

### Natural Gas Alternative Fuel Switching Cost Estimate: Low Sulfur No. 6 Fuel Oil Fuel Switching SO2Emission Offset: Low Sulfur No. 

### 6 Fuel Oil Fuel Switching Cost Estimate: Distillate Oil Alternative Fuel Switching SO2Emission Offset: Distillate Oil Alternative cc: Deborah Feck -

### IP Kirk Carlson -

### IP Jim Witkowski -

### IP

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## 5 oYO1Table3 Fuel Switching Cost Estimate: Natural GasAlternative International Paper

# - GeorgetownMill URS ProjectNo. 31825960

IPower Boiler Permit Requirements Cannot bum more than 50%Fossil Fuel to avoid NO, Budget Trading Program (total for both boilers) Sludge shall not exceed 10% of total fuel burned Containerboard ClippingsB'ellets shall not exceed 40 tonslday (12-mo rolling avg) TDF shall not exceed 87,600 tpy (total for boilers, 12-mo rolling sum) TDF shall not exceed 10 tph (total for boilers) Used Oil shall not exceed 5.2 MMgalIyear (per boiler, 12-morolling sum); If 15OMBtuIgalmax of780,000 MMBtuIyr 2Used Oil shall not exceed 876,000 gallonslyear (per recovery boiler, 12-mo rolling sum) 3Assume heat value of coal is 12,700BtullbTable4 Fuel SwitchingSO2Emission Offset: Natural GasAlternative InternationalPaper

## - GeorgetownMill URS Project No. 31825960

1Power Boiler Permit Requirements Cannot bum more than 50%Fossil Fuel to avoid NO, Budget Trading Program (total for both boilers) Sludge shall not exceed 10% of total he1burned Containerboard ClippingsPellets shall not exceed 40 tonstday (12-mo rolling avg) TDF shall not exceed 87,600 tpy (total for boilers, 12-mo rolling sum) TDF shall not exceed 10tph (total for boilers) Used Oil shall not exceed 5.2 MMgalIyear (per boiler, 12-mo rolling sum); If 15OMBtu/galmax of780,000 MMBtuJyr 2~sed Oil shall not exceed 876,000 gallonstyear (per recovery boiler, 12-mo rolling sum) 3Assume heat value of coal is 12.700 Btutlb Fuel Switch MMBtuJyr

I 

## -- 0 0 0 3,844,485 

### -- 

### -- -- -- EF (lb SO,/MMBtu) 

# ------

-- 1.89 1.55 2.14 0.0006 

### -- 

### -- -- -- Switchto Natural Gas (tons S02/yr)
0 (1.517) ( 1421)

(287) 1 0 0 0 0 (3224) 2006 MMB~II/~~'

4,613,171 1,605,128 1,836,130

268,280 134,948 1 0 96,406 0 Units

tons tons MMBtu MMBtu MMSCF MGAL MMBtu MMBtu MMBtu 2006Fuel

Usage UnitID 03"' Wood Coal Tire-Derived Fuel No. 6 Fuel Oil Natural Gas Propane Used Oil Wastewater Sludge Containerboard ClippingsPellets TOTAL 518,101 63,194 1,836,130

268,280 131 2,468 0 96,406 0Table 5 Fuel Switching Cost Estimate: Low SulfurNo. 6 Fuel Oil &Natural Gas Alternative International Paper

# - GeorgetownMill URSProjectNo. 31825960

'power Boiler Permit Requirements Cannot bum more than 50% Fossil Fuel to avoid NO, Budget Trading Program (total for both boilers) Sludge shall not exceed 10% of total fuel bumed Containerboard ClippingsPellets shall not exceed 40 tonslday (12-mo rolling avg) TDF shall not exceed 87,600 tpy (total for boilers, 12-mo rolling sum) TDF shall not exceed 10 tph (total for boilers) Used Oil shall not exceed 5.2 MMgalIyear (per boiler, 12-mo rolling sum); If 15OMBtu/galmax of 780,000 MMBtuJyr 2Used Oil shall not exceed 876,000 gallonslyear (per recovery boiler, 12-mo rolling sum) 3Assume heat value of coal is 12,700BtuJlb Switch to Low S No. 6 Oil with BalanceNatural Gas ($1~) $0 ($4,927,742) ($3.121.421) ($2052,342) $14,664,115 $16,107,358 $0 $0 $0 $0 $20,669,968 2006 Cost ($/MMBtu)



### --

$3.07 $1.70 $7.65 $8.29 $8.30


### -- -- -- -- 2006 MMB~III~~~

4,613,171 1,605,128 1,836,130

268,280 0 134,948 1 0 96,406 0 Unit

### ID01''~ Wood Coal Tire-Derived Fuel No. 6 Fuel Oil Low Sulfur Fuel Oil Natural Gas Propane Used Oil Wastewater Sludge Containerboard ClippingsPellets TOTAL Fuel Switch MMBtuIyr



### -- 0 0 0 1,768,892 2,075,593
-- 

### -- -- -- 2006 Fuel

Usage 518,101

63,194 1,836,130

268,280 0 131 2,468 0 96,406 0 Units

tons tons MMBtu MMBtu MMBtu MMSCF MGAL MMBtu MMBtu MMBtu