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 

Appendix N - 1
FOUR FACTOR ANALYSIS 

DAK AMERICAS COOPER RIVER, SC 

FOUR FACTOR ANALYSIS 

OF CANDIDATE SO2 CONTROL MEASURES 

FOR REASONABLE PROGRESS 

UNDER THE REGIONAL HAZE RULE 

November 2007 

Prepared by: 

TRINITY CONSULTANTS 

2327 Englert Drive 

Suite 201 

Raleigh, NC 277 13 

(919) 544-781 1 

Project 073401.0051.02.01 

Appendix N - 2
3 . SO2 CONTROL 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 . REMAINING USEFUL LIFE OF EXISTING SOURCES IN BOILER NO . 2 ..................... 21 

DAK Americas. LLC I Trinity Consultants 

Four-Factor Analysis 

Appendix N - 3
TABLES 

Table 2-1. Past Actual SO2 Emissions 

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 

Table 4-4. 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 

Appendix N - 4
The purpose of this 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. 0420-0089 issued 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 of the 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 were prepared by the Visibility 

Improvement State and Tribal Association of the 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 of the Clean Air Act sets the following goal for visibility in Class I areas. 

Congress hereby declares as a national goal the prevention of any future, and the remedying 

of any existing, impairment of visibility in rnandatoiy class I Federal areas which impairment 

resultsfi-om manmade air pollution. 

Congress directed each State implementation plan (SIP) to contain emission limits, compliance 

schedules and other measures as may be necessary to make "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 to the visibility-protection requirements of the Act, the U.S. Environmental Protection 

Agency (EPA) promulgated regulations in 1999 to guide States' development of plans to reduce 

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 guidelines for best available retrofit technology (BART) determinations, but made 

no substantive changes with respect to other reasonable progress requirements. 70 Fed. Reg. 391 04 (July 6, 2005). 

DAK Americas, LLC 1 Trinity Consultants 

Four-Factor Analysis 

Appendix N - 5
included an analytical methodology for how States were to establish reasonable progress goals for 

each Class I area.3 Because that methodology has been based on application of the specific statutory 

factors identified above, that approach to determining reasonable progress has become known as the 

"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 factors to candidate emission control measure^.^ 

The Regional Haze Rule specifies a planning period of 2004-20 18 for States' initial regional haze 

SIPs. Those SIPs must be submitted to EPA by December 17,2007. The State of South Carolina is a 

member of the 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 of regional haze, visibility and 

other air quality issues in the Southeastern United States. After extensive analysis, VISTAS has 

concluded that sulfate is the primary cause of visibility impairment in Class I areas throughout the 

Southeast. 

VISTAS has further demonstrated that the principal cause of that atmospheric sulfate is the emission 

of sulfur dioxide (SOz) from utility and industrial boilers. In particular, VISTAS' analysis found that 

SOz emissions from DAK's Cooper River facility contributed greater than 1% of the total visibility 

impairment in the Cape Romain Wilderness Area (Cape Romain), a Class I area located near the 

DAK Americas Cooper River Facility. Accordingly, DAK has performed this Four-Factor Analysis 

of candidate SO2 control measures to assist SC DHEC's evaluation of the issue. 

It is important to note that the contribution analysis included several simplifying assumptions that 

reduce the accuracy in assigning contribution to any individual source. The VISTAS analysis 

considered total visibility impairment, frequency of air masses from source areas entering the Class I 

area of interest, and SOz mass emissions. No attempt was made to consider the specific atmospheric 

dispersion parameters of individual sources or the differences in atmospheric chemistry that can occur 

during differing lengths of transport. Thus, while the VISTAS analysis assigned a greater than 1% 

contribution to DAK Cooper River that value cannot be directly correlated to greater than 1% of the 

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-Factor Analysis. 

- Id. 

U.S. EPA, Guidancefor Setting Reasonable Progress Goals Under the Regional Haze Program (June 1,2007). 

DAK Americas, LLC 2 Trinity Consultants 

Four-Factor Analysis 

Appendix N - 6
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). SC DHEC has requested that the four-factor analysis 

address SO2 emissions 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 is the 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 of the 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 (Boiler No. 1) that is not evaluated in this four-factor analysis. In July 2007, per 

instructions from DHEC upon submittal of the 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 320 MMBtuJhr, but not exceeding 360 MMBtuhr. 

The baseline SO2 emission rate was calculated for the purposes of the four-factor analysis to be 

approximately 415 tons per any consecutive 365-day period. The calculation is an average of the 

actual SO2 emissions from Boiler No. 2 for the three most recent full calendar years (2004,2005 and 

2006) for the purposes 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 of calculation are presented below. The 

emission factor used in the analysis was developed from Cooper River stack test data to reflect actual 

SO2 emissions. 

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 

Appendix N - 7
Em2 = 3.1 9 x 10' 

lb 

x 0.79 % Sx 32,911 tons coal 

ton - % sulfur 

Where: 3.19* 1 o3 is the SO2 emission 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 levels to 1 .OO percent, and compliance is demonstrated 

through calculations based on 12-month rolling averages values from supplier certification as stated 

in the Cooper River permit. As shown in Table 2-1, the actual coal sulfur content has averaged much 

less than 1% over the last three years. 

DAK Americas, LLC 

Four-Factor Analysis 

4 Trinity Consultants 

Appendix N - 8
According to the EPA data for coal-fired electric generating units2, about 97 percent of the I ,I 40 coalfired utility boilers operating in the U.S. in 1999 used one of the following SO2 control technologies: 

1. Low-sulfur coal - switching to a coal with a sulfur content lower than that of the 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 SO2 in the flue gas 

3. Spray dryer absorber (SDA) - injection of a liquid slurry of sorbent material into the flue gas 

downstream of the 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 of the 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 are commercially available. The following 

presents an assessment of the technical feasibility of applying each of these technologies to control 

SO2 emissions from Boiler No. 2. Note that even though the technologies below may be technically 

feasible, they may not be cost effective to implement. Section 4 (Cost/ Economic Impact) discusses 

cost effectiveness considerations related to the technologies discussed below. 

3.1 Low SULFUR COAL 

The emission of SO2 from 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 to under one percent by weight) 

depending on where the coal was mined. It is often possible, within certain limits, for a combustion 

source to control SO2 emissions from combustion of coal by sourcing the coal from a mine or mines 

having coal of the desired average sulfur content. Limiting factors for this practice include the 

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 of time over which SO2 reduction by this method may be 

feasible). 

Reducing SO2 emissions from Boiler No. 2 by switching to a lower-sulfur coal is deemed to be 

technically feasible but does not have reliable availability for low sulfur coals below 0.7 to 0.65 

DAK Americas, LLC 

Four-Factor Analysis 

5 Trinity Consultants 

Appendix N - 9
percent sulfur coals. Below 0.7 to 0.65 percent sulfur, coal is not considered consistei~tly able to 

procure without risk of increases in average sulfur content due to availability. 

Procurement personnel have researched the availability of coal that both meets the 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 of market reports, it is 

considered opinion that 0.7 to 0.65 percent is the minimum average sulfur level 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 order to 

be compatible with the design of the 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 are not 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 SO2 in water to 

remove SO2 from the flue gas. Since water ceases to effectively remove SO2 when 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 SO2 and form essentially 

non-volatile compounds. Some percentage of the scrubber liquor must be bled off and fresh water 

added during operation in order to limit the build up of both 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 are easier to separate from wastewater. 

Commercial wet FGD systems are available in many variations and proprietary desibms. For 

example, spray tower or packed tower absorbers can attain SO2 removal efficiencies in the range of 

approximately 90 percent in applications where the particulate matter concentration of the 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. This typically 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 SO2 removal efficiency of wet FGD systems is a function of the concentration. 

Higher removal efficiencies are possible when the inlet concentration of the species to be 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 Consultants 

Appendix N - 10
Wet 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 FGD technology has been determined to be technically feasible to use for control of emissions of 

SO2 from Boiler No. 2. Because wet scrubbers are less costly and more reliable if the majority of PM 

is removed from the flue gas upstream of the scrubber, it has been assumed that this option would 

involve the installation of a scrubber downstream of the existing baghouse and ID fan 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 SO2 is contacted with fine spray droplets of hydrated lime sluny in a spray 

dryer vessel. This vessel is located downstream of the air heater outlet where the gas temperatures 

are in the range of 120 to 180 OC (250 to 350 OF). The SO2 is 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. 

The water is evaporated by the hot flue gas and forms dry, solid particles containing the reacted 

sulfur. These particles are entrained in the flue gas, along with fly ash, and are collected in a PM 

collection device. Most of the SO2 removal occurs in the spray dryer vessel itself, although some 

additional SO2 capture 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 be technically feasible for the control of SO2 from 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 SO2 liberated from 

combustion of the 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 SO2 emissions 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 into the ductwork upstream of a PM control device. Some systems use spray 

humidification followed by dry injection. This dry process eliminates the sluny production and 

DAK Americas, LLC 

Four-Factor Analysis 

7 Trinity Consultants 

Appendix N - 11
handling equipment required for wet scrubbers and spray dryers, and produces dry reaction waste 

products for easier disposal. The SO2 is adsorbed and reacts with the powdered sorbent. The dry 

solids are entrained in the combustion gas stream, along with fly ash, and collected by the PM control 

device. The SO2 removal efficiencies of existing dry injection systems range from 40 to 60 percent. 

Dry sorbent injection has been determined to be technically feasible for use in controlling SO2 

emissions from Boiler No. 2. It has been assumed that the baghouses in the existing air pollution 

control train for Boiler No. 2 would be retained for use in collection of the spent reactant and flyash 

from the boilers. An average SO2 removal efficiency of 50 percent has been projected for this 

technology assuming that slaked lime is used 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 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 which deliver it to a local cement kiln for recycling into product. This is all a dry process. 

Changes in the ash make-up would cause an inability to use 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 Consultants 

Appendix N - 12
The 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 of total capital investment (TCI) and total annual cost (TAC) were made for each of the 

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. 

The TAC estimate includes recurring 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 of use of the option. These include administrative charges, taxes, insurance premiums, and the 

capital recovery cost. The capital recovery cost is a means of annualizing the 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 of calculating 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 sulfur content drops below 1 percent. 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 so than 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 Consultants 

Appendix N - 13
will be identical. Using these assumptions, the dccrease in SO2 emitted 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 ($ 1 ton) = $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 feasible to 

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 

after the baghouse and induced draft fan in the existing air pollution control trains in Boiler No. 2. 

Each scrubber as quoted has the capacity to accept the maximum flow rate capacity of the baghouse 

with which it would be associated. The manufacturer has guaranteed that each will achieve a 

minimum of 92 percent SO2 removal when Boiler No. 2 is fueled with coal containing up to 1.25 

percent by weight sulfur, with potentially lower control efficiency at reduced SO2 inlet 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 as the SO2 

reactant at a maximum rate of approximately 695 pounds per hour. Therefore, a silo for the hydrated 

lime was included in the equipment to be installed. 

It was assumed that the stacks for each air pollution control system train would be mounted directly 

on top of the scrubber, as recommended by the manufacturer. This would help reduce the extent of 

water droplet carryover in the flue gas exiting the stacks. 

The TCI 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 the period of 

2004,2005 and 2006. 

The estimated quantity of SO2 removed by the wet FGD option from the flue gas under the baseline 

operating conditions is 382 tons per year. The estimated quantity of SO2 emitted under this option 

DAK Americas, LLC 10 Trinity Consultants 

Four-Factor Analysis 

Appendix N - 14
was estimated to be 33 tons per year. The estimated cost effectiveness of the 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-site wastewater plant and discharge to the Cooper 

River, and solids (sludge) are sent to a local publicly-owned treatment works (POTW). It is unclear 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 2.5 percent by weight. 1f this 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 for removal of SOz. 

DAK Americas, LLC 

Four-Factor Analysis 

11 Trinity Consultants 

Appendix N - 15
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 

Sales tax 0.03 x A $30,600 

Freight 0.05 x A $5 1,000 

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 

Total Direct 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 $1 4,076 

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 of EPN452lB-02-00 I 

2. Vendor estimate includes one absorber for $620,000 and a second identical absorber for $608,000. Right now assumed me 

absorber 

3. Already have a waste water treahnent plant in place, but pH may be a concern. Cost of adding caustic feed. 

DAK Americas, LLC 

Four-Factor Analysis 

12 Trinity Consultants 

Appendix N - 16
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 $1 0,003 

Maintenance 

Labor $22.70/hr x 4 man-hrlday x 7 daylweek x 52 weekly $33,05 1 

Materials I00 percent of maintenance labor $33,051 

Wastewater treatment plant operation & maintenance2 5 165,000 

Reagent for SO2 Control 

200 Ibhr x $0.050/lb x 24 hrlday x 7 daylweek x 52 weekly $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 electricity rate 

= (49 kW + 41 kW) x $0.0500 kW-hr x 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 16 gpm 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 of operating, 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 of EP.4/151/B-02-00I and DAK 

2. DAK estimate. 

Fixed (wages. maintenance. senera1 0 8i M) = $337,000 year 

Variable (chemicals. sludge disposal) = $165~000 year (projected) 

DAK Americas, LLC 

Four-Factor Analysis 

13 Trinity Consultants 

Appendix N - 17
A 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 to be the reactant used in the SDA system. The efficiency of the system for 

removal of SO2 from the flue gas of Boiler 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 as pH, 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 or undesirable 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 to the current situation. 

The estimated cost of the SDA option for the Facility was based on general cost data for SDA 

systems provided in Table 1A of the Air Pollution Control Technology Fact 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 of the 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 1A indicate that each of the above costs associated with control of SO2 

using SDA increases substantially as the firing rate of the 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 of the upper 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 of Boiler No. 2, Trinity believes that the costs of 

the SDA alternative will be at least as high as the upper end of each of the 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 - 4,000 

Appendix N - 18
Based on the use of the upper end of the cost ranges presented in Table 1A of the 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 $4,000 per ton. 

Trinity prepared an analysis of the process and equipment requirements associated with the 

installation of a DSI system during consideration of potential control options for the National 

Emission Standards for Hazardous Air Pollutants (NESHAP) for Industrial Boilers (also known as the 

Boiler MACT). The system was assumed to consist of a separate lime injection system in the ducting 

upstream of the baghouses in the existing air pollution 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 the baghouse would need to be upgraded and, due to the substantial increase 

in the potential quantity of material to be removed from the baghouse, the existing flyash handling 

system may have to be upgraded. 

The DSI system was assumed to have an SO2 control efficiency of 50 percent using hydrated lime as 

the reactant. At the baseline SO2 emission rate, the required injection rate of hydrated lime was 

estimated to be 330 pounds per hour. 

The ash originating from the baghouses in the DSI option would be expected to have different 

materials properties such as pH, moisture content, and ash fusion temperature than the ash currently 

removed from the baghouses. It would be expected to contain substantially higher 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 of total capital cost and total annual cost for installation and operation of the 

DSI system. 

The TCI for the DSI 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 Boiler No. 2 

would be operated under the same average conditions as occurred during the period of 2004,2005 

and 2006. 

The estimated quantity of SO2 removed by the DSI option from the flue gas under the baseline 

operating conditions is 208 tons per year. The estimated quantity of SO2 emitted under this option 

was estimated to be 208 tons per year. 

DM Americas, LLC 

Four-Factor Analysis 

15 Trinity Consultants 

Appendix N - 19
The estimated cost effectiveness of the DST option when Boiler No. 2 is operated under the baseline 

conditions was estimated to be $7,328 per ton of SO2 removed. - 

DAK Americas, LLC 

Four-Factor Analysis 

Trinity Consultants 

Appendix N - 20
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 

lnstrumentation 0.10 xA $147,100 

Sales Tax 0.03 x A $44,130 

Freight 0.05 x A $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 $69,43 1 

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 x B $69,43 1 

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 0.01 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 

1. All capital cost data from VGA EST - REV 3-4-1 8-06. 

DAK Americas, LLC 

Four-Factor Analysis 

17 Trinity Consultants 

Appendix N - 21
Cost 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 = 0.1 5 x $66,685 $10.003 

Consu~nrnables 

Li~ne 330 lbhr x 1 ton/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 I00 percent of maintenance labor $33,051 

Replacement parts 

Bags (Inaterials and labor) CRF for bags x bag replacement cost: 0.388 x $1 56,800 $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-hr x 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% 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% of Total Capital Investment = 0.01 x $4,700,000 $47,000 

Capital recovery CJU x 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 

Appendix N - 22
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 

The major activities anticipated to be necessary for implementation of the low sulfur coal option 

include the following: 

Time to Implement 

1 year 

+ Obtain quotations from vendors 

+ Negotiate a procurement contract 

+ Complete the existing coal contract and depletion of the existing coal stock 

+ Receive sufficient quantities of the lower sulfur coal 

The major 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 

Appendix N - 23
6. ENERGY AND NON-AIR QUALITY ENVIRONMENTAL IMPACTS 

The anticipated energy and non-air quality environmental impacts of the SO2 reduction 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 electricity usage 

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 he1 usage to transport lime 

to Facility, increased electricity usage 

for lime injector and due to increased 

pressure drop in 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 solids requiring 

disposal at the POTW. 

Use of substantial quantities 

of fresh water. Potential for 

degradation in quality of 

water discharged from ash 

pond outfall due to lime and 

dissolved salts. Potentially 

substantial increase in solid 

waste generation and disposal 

if flyash cannot be recycled. 

Substantial increase in solid 

waste generation and disposal 

associated with flyash and 

spent reactant. 

DAK Americas, LLC 

Four-Factor Analysis 

20 Trinity Consultants 

Appendix N - 24
7. REMAINING USEFUL LIFE OF EXISTING SOURCES IN BOILER NO. 2 

DAK estimates that the useful lifetime of Boiler No. 2 is up to and exceeding 50 years. This would 

leave the remaining useful life of this unit to be around 31 years. 

It is difficult to specify a remaining useful life of the boilers, as the remaining useful life is directly 

related to the degree of routine maintenance completed on the units and the utilization factors of the 

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 of the 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 1900 and was still operating reliably as late as 

1988. It is DAK's opinion that if things are well maintained coal fired boiler systems can last for well 

over 50 years. 

For the purposes of this analysis, DAK believes that 3 1 years is a reasonable estimate of the 

remaining useful life of the unit, though the value could range could fluctuate depending on 

equipment repair, maintenance, and other factors. 

DAK Americas, LLC 

Four-Factor Analysis 

Trinity Consultants 

Appendix N - 25
All options were deemed not cost effective according to the $2,00O/ton guidance provided by SC 

DHEC. 

The energy and non-air quality impacts of the options have been qualitatively ranked according to the 

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 of the 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 landfilling that 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 

(tonly r) 

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 

for 

Compliance 

(Years) 

1 

3 

3 

3 

Appendix N - 26
Sizing Calculations 

Vendor Supplied Data 

Four-Factor Analysis A-1 Trinity Consultants 

Appendix N - 27
Air Pollution Control Technology 

Fact Sheet 

Name of Technology: Flue Gas Desulfurization (FGD) -Wet, Spray Dry, and Dry Scrubbers 

Type of Technology: 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 in the 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 Industrial Applications: Stationary coal- and oil-fired combustion units such as utility and 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 in the 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 MMBtuIhr to 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 

temperatures for SO, removal for dry sorbent injection systems range from 150°C to 180°C (300°F 

to 350°F). Optimal temperatures for SO, removal when applying dry sorbent injection systems 

vary between 150°C to 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 in salt deposition on the 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 Desulfuriiration 

Appendix N - 28
Many wet 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 

costs for SO, scrubbers applied to electric utilities are reported to be approximately $100/kW (Smith, 2001). 

Retrofit of scrubbers on existing 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&M costs increase with increasing sulfur content since more reagent is required to 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 available for 10 to 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 

evaporation of water and the energy required to drive the reaction. New scrubber designs result in an 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 1 b: 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 Desulfurization 

Appendix N - 29
Theory of Operation: 

The FDG or 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 be chosen if space or disposal options are limited and markets for 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 be further categorized as wet, dry, or semi-dry. 

Each of these processes is described in the 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 between the waste gas and sorbent, the nozzles and 

injection locations are designed to optimize the size and density of slurry droplets formed by the 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 bottom of the absorber where it is collected. Treated flue gas passes 

through a mist eliminator before exiting the absorber which removes any entrained slurry droplets. The 

absorber effluent is sent to a reaction tank where the SO,-alkali reaction is completed forming a neutral 

salt. In a regenerable system, the spent slurry is recycled back 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. Limestone is very inexpensive but control efficiencies for 

limestone systems are limited to approximately 9O0/0. Lime is easier to manage on-site and has control 

efficiencies up to 95% but is significantly more costly (Cooper 2002). Proprietary sorbents with reactivityenhancing additives provide control efficiencies greater 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 available for reaction with SO,. Higher UG ratios result in higher 

control efficiencies. Higher L/G also increases oxidation of the SO,, which results in a decrease of the 

formation of scale in the absorber. O&M costs are a direct function of reagent usage, so increasing the 

UG increases annual costs. UG ratios are approximately 1:l for wet scrubbers and are expressed as 

gallons of slurry per 1000 ft3 of flue gas (liters of slurry11000Nm3 of flue gas). 

Oxidation of the slurry sorbent causes gypsum (calcium sulfate) scale to form in the absorber. 

Limestone forced oxidation (LSFO) is a 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 reaction tank prior to the slurry being recycled to the absorber. The recycle 

slurry has a lower concentration of gypsum and scale formation in the absorber is significantly reduced. 

Gypsum can be commercially sold, eliminating the need for landfilling of the waste product (Srivastava, 

2001). In addition to scale control, the larger size gypsum crystals formed in LSFO settle and dewater 

EPA-CICA Fact Sheet 3 Flue Gas Desulfurization 

Appendix N - 30
more 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 is the 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 is collected with a standard particulate matter (PM) 

collection device such as a baghouse or ESP. The waste product can be disposed, sold as a 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 limestone and 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°F to 50°F) below saturation temperature (Srivastava, 2000). 

Lower UG ratios, approximately 1:3, must be utilized do to the limitation on flue gas moisture (Schnelle, 

2002). Flue gas with high SO, concentrations or temperatures reduce the performance of the scrubber 

(Schnelle, 2002). 

SO, control efficiencies for spray dry scrubbers are slightly lower than wet 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 

multiple absorber systems. The capital and operating cost for spray dry scrubbers are lower than for wet 

scrubbing because equipment for handling wet waste products is not required. In addition, carbon steel 

can be used to manufacture the absorber since the flue gas is less 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 such as a baghouse or electrostatic precipitator (ESP). The flue gas is generally cooled prior 

to the entering the PM control device. Water can be injected upstream of 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) in order 

to decompose the sorbent into porous solids with high surface area (Srivastava 2001). 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 a fine sorbent spray into the flue gas downstream of the air preheater. 

The injection must occur at flue gas temperatures between 150°C to 180°C (300°F to 350°F) (Joseph, 

1998). 

EPA-CICA Fact Sheet 4 Flue Gas Desulfurization 

Appendix N - 31
Dry sorbent systems typically use calcium and sodium based alkaline reagents. A number of 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 increases SO, 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 less water and waste disposal is less complex. Dry injection systems install easily and 

use less space, therefore, they are good candidates retrofit applications. SO, removal efficiencies are 

significantly lower than wet systems, between 50% and 60% for calcium based sorbents. Sodium based 

dry sorbent injection into the duct can achieve up to 80% control efficiencies (Srivastava 2001). Dry 

sorbent injection is viewed as an emerging SO, control technology for 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 in a 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 FGD Manual, Volume I: FGD Process Design. Department of 

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 Review APT1 Course". 

Developed by North Carolina State University under EPA Cooperative Assistance Agreement. Raleigh, 

N.C 1998. 

EPA-CICA Fact Sheet 5 Flue Gas Desulfurization 

Appendix N - 32
Schenelle, 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 Management Assoc., 51:1676-1688,2001. 

EIA, 2002. EIA-767 Database; Annual Steam-Electric Plant Operation and Design Data, 2001. Energy 

Information Administration, Department of Energy. November 26, 2002. 

http://www.eia.doe.aov/cneaf/electricitv/pae/eia767. html 

EPA-CICA Fact Sheet 6 Flue Gas Desulfurization 

Appendix N - 33
Paqe 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 lower than 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 be for 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 2004 

Appendix N - 34
Appendix N - 35
turboson~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, Suite A-14 

Waterloo, Ontario, N2L 5V4 

Phone: (51 9) 885-551 3 

Fax: (51 9) 885-6992 

This proposal is and remains the property of TurboSonic. It contains proprietary 

and confidential information and is issued for the purpose of bid evaluation and 

purchase only. 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 returned or destroyed. 

Appendix N - 36
Turbosonic Page 2 of 10 

TRINITY CONSULTANTS 25 September, 2007 

Wet Scrubber for Coal Fired Boiler Proposal Q08-1269 

GENERAL DESCRIP-TION 

The purpose of the proposed Equipment is to remove SO2 and HCI in the exhaust 

gases from three coal .fired Boilers in southern Tennessee. 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 surface for 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 contact with the liquid. 

After passing through the Spray Zones the gas enters two Mist Eliminators of 

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 DCS and is intermittent and 

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 SO2 hydrated lime Ca(OH)2 is 

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 maintained at 10% by a bleed (blow 

down) connected to the discharge side of the 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 conditions would so require. 

Evaporation takes 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. 

Appendix N - 37
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 condensation will 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 the Absorber. 

Appendix N - 38
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 

SO2 Loading 

HCI Loading 

Gas Volume (saturated) 

Gas Temperature 

Dry Gas Volume 

(saturated) 

Moisture Content 

Gas Pressure at Outlet 

SO2 Loading 

HCI Loading 

ACFM 

Appendix N - 39
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 in Absorber inch WG 

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 Eliminator Wash Fresh Water 

Flow Rate GPM (Intermittent) 62 

Per each of (3) levels 5 minutes per (3) zones eve 

Appendix N - 40
Turbosonic 

TRINITY CONSULTANTS 

Wet Scrubber for Coal Fired Boiler 

Page 6 of 10 

25 September, 2007 

Proposal Q08-1269 

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) 31 6 Stainless Steel 

Spray Nozzles 316 Stainless Steel 

Mist Eliminators (2) 316 Stainless Steel 

Wash Headers (3) 31 6 Stainless Steel 

Wash Nozzles 31 6 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-type for Venturi 

(1) pH Sensor & Transmitter 

(1) Density Sensor & Transmitter of El. Conductivity type 

(8) Liquid Pressure Gauges 

(4) Liquid Pressure Switches with alarm 

Appendix N - 41
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 

Appendix N - 42
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: 

SO2 Emission shall not exceed 

HCI Emission shall not exceed 

26 lbslhr 

For SOz lnlet 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,fic items listed above and does not extend to other items listed 

under 'Operating Data. 

Appendix N - 43
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 IN THlS 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 

THE PRICE LISTED ABOVE 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 RESERVE THE 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 

Appendix N - 44
Turbosonic Page 10 of 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 Manager 

Appendix N - 45
turbosontc Page 1 of 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: No order 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 adjusted to 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 be subject 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, in tort, 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. 

* GST not applicable to projects F. 0. B. outside Canada. 

Revised: May 2004 

Appendix N - 46
turboson~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 negligence of 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 in the Company's scope of work. 

unless such back charges have been authorized by the Company in writing 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 be first 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 

arising from the improper use of 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 and from 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 

Appendix N - 47
Four-Factor Analysis B-1 Trinity Consultants 

Appendix N - 48
DAK Americas, LLC 

Four-Factor Analysis 

BASELINE EMISSIONS 

Based off AP-42 EF 

l~ear lCoal IAvg. Sulfur ]SO, ~rnittedl 

(tons) 

505.14 

478.08 

Average: 32,911.33 

Based off 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 

Btu 

Appendix N - 49
DAK 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 CC mn. 5ZU1 C>.llL,, 

Appendix N - 50
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 of bag replacement $156,800 

Residue generation rate 2,480 lblhr 

Residue disposal cost3 $4 5 /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. Estimate 

Appendix N - 51
DAK 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 Emissions from 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,, x S,,, 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 Removed from 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%) 

Estimated Total Make-Up Water Usage at Baseline Operating Conditions 

Rwbase = Rmax x (CevglCm) y. (SaqlSma) 

= 78 gallmin x (32.912 tonlyr 1 90.228 tonlyr) x (0.79% 11.00%) 

Estimated Total Blow Down Flow at 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 

32,912 tonlyr 

0.79% 

74,000 acfm 

4.0 inch wg 

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 

382 tonlyr 

200 lblhr 

22 gallmin 

16 gallmin 

Appendix N - 52
DAK Americas, LLC 

Four-Factor Analysis 

Estimated Total Electrical Power Required for Recirculation Pumps at Maximum Design Conditions 

From Sect~on 5 of the EPA OAQPS Control Cost Manual (EPN4521B-02-001) 

~~hcrc En-.a -. (ui h11w.vnmj ~cfe~s to the elm= -. ~leeckd totno1 e a ET. PII I olunietnc flow rate ofau 

[ncfi~l) G i5ttkz \va\r< pi flowrate mte~ulgtliz absorb- Pli thc toralpzssuuzrtopthough the 

slstmi (uici1~s oofH;O) and is the coniI~u1~d fal-n~orrnrfficte~lc: Vdws for hpcCallyr~~~ frmn 

0.4 ro O 7 Ltksxx-isz. thc electricin reqr~iredb?- a rcqcle p~mlpc~mk calculated ns~ng Equation 

149 

10.7J5, (-'.:2 ;< ifi ' t ;?vc~;:i2e; 

E~:er~~~,~~ = (1.49) F 

v. here 0 745 1s hc factor~iscl to cmli at I~rn~~r-ir toktV pre\sme 15 eqx.sseduifertofv ater 

N.I~ 1s tllcro~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 1 0.70 

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): 

The elecn icil-\' coui ~<<ocl;rtcr-l I\-~rh ollt.1 anng a ps ;~bsrn.l.e~ tlenve fa~l~eqli~r~uiait< 

lo ovelcolnrthcpresslu~ (11 op UI cht ct~~crwnik. and otl~ei IIIUI~VCI~I~C~~~UI sys~elii. a11(l 

1'tulip ~-eqtlumlelas to ~wua~late Ili solvent Thv ellel?:, ~eq~iuedfn~ tlirfui c~ibecnlcula~alusui~ 

Equat'io~ll .AS 

~\hr~e Ellcrp? (inlulow;rt~a) rehs lothe elwrsylieedcd tollio\.e ;igi\*e~:\.olumetnc tlow~are uf;111 

(acfiii) G. 1s tliex~nste gasflowraleeiltauigll~e ab~011wi. Pi5 111e totalpressuredop tlu-oi~,dirl~e 

s>rrm( u~clizs oi1I.O) ,and is the cmnbuled fall-~nntol ct-ficiency \.slues for &~>icallyirni~r fro111 

O 4 ro O T Lkzlr 1s;. lhe elec~~ic~ty~ec~r~~~ell hyilrec! clr p~ui~pc;~~i be calculated uhinp E~lrlntiorl 

1.17x10-~x %,, Pd-IE 

Where E is the combined fanlmotor efficiency 

= 0.0001 17 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 1 382 ton 

Estimated Cost of Recirculation Pumps (for TCI estimate) 

From the OAQPS Control Cost Manual: 

The a\ elage p ice for a FRP pll~np of this size is 51 6,'gpm at a pressure of 60 ft u ates. based 

oil the r~ndor iulvey [I 31 Therefore. tllr cost of therecyclepuu~~p is esrililatrd as: 

Cost = R, x $16lgpm 

=3,300 gallmin x $16lgpm 

Estimated Average Heat Input for Boiler No. 2 Operating at Baseline Consitions 

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,, 1 2,000 + Ed, x EU,,, 1 8,760 x (1 36.142 - 74.093) 1 64.054 

= 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 

Appendix N - 53
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 

Sales tax 0.03 x A $30,600 

Freight 0.05 x A $5 1,000 

Total Parrchused Equipmen1 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 $1 40,760 

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 

I. Estimation methodology is from section 5 of EPAl452lB-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 may be a concern. Cost of adding caustic feed. 

Appendix N - 54
DAK Americas, LLC 

Four-Factor Analysis 

TABLE 4-2 Wet FGD TAC 

Cost Item Calculation cost' 

Direct Annual Costs (DC) 

Operating labor 

Operator S22.90hr x 8 man-hrlday x 7 daylweek x 52 weeWyr $66.685 

Supervisor 15% of operator labor = 0. I5 x $66,685 $10,003 

Maintenance 

Labor $22.70hr x 4 man-hrlday x 7 daylweek x 52 weeWyr $33,051 

Materials 100 percent of maintenance labor $33,051 

Wastewater treatment plant operation & maintenance2 $1 65,000 

Reagent for SOz Control 

200 Ibhr x $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 52 weeklyr x W5.001ton $164,101 

Utilities 

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

= (49 kW + 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 60 min/hr x 24 hrlday x 7 daylweek x 52 week/yr $8,836 

Wastewater $0.0020lgal x 16 gpm x 60 minhr x 24.0 hrlday x 7.0 daylweek x 52 week/yr $15,905 

Total DC $623,630 

Indirect Annual Costs (1C) 

Overhead 34% of sum of operating, supv., maint. labor & materials $48,549 

= 0.34 x ($66,685 + $10,003 + $33,051 + $33.051) 

Administrative charges 2% of Total Capital Investment = 0.02 x $4;1 15,736 $82,3 15 

Property taxes 1 % of Total Capital Investment = 0.01 x $4,1 15,736 $41,157 

Insurance 1% of Total Capital lnvestment = 0.01 x $4,1 15,736 $41,157 

Capital recovery CRF x 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 of EPN452B-02-001 and DAK. 

2. DAK estimate. 

Fixed (wages, maintenance, general 0 & M) = 5337,000 year 

Variable (chemicals, sludge disposal) = $165,000 year (projected) 

Appendix N - 55
DAK Americas, LLC 

Four-Factor Analysis 

DSI CALCULATIONS 

Variable 

Cavg 

HVcoa~ 

EFso2 

Savg 

Rgrnax 

Pdrnax 

Ectl 

N SR 

Rllyash 

pr 

Do, 

Average coal consumed in 2004,2005,2006 

Average coal heating value 

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 

Flyash generation rate for Boiler No. 2 

Scrubber liquor recirculation pressure 

Assumed operating duty cycle of Boiler No. 2 per 365 day period 

Baseline Uncontrolled SO2 Emissions from Boiler No. 2 

Cav, x SaV, x EFso, 12,000 lblton 

= 32,911 tonlyr x25.22 12,000 lblton 

Baseline Controlled SO2 Emissions from Boiler No. 2 

EUbase (I - CE) 

= 415 tonlyr x (1 - 0.50) 

SO2 Removed from Boiler No. 2 Under Baseline Operating Conditions 

EUbase - ECbase 

= 415 tonlyr - 208 tonlyr 

Estimated Total Ca(OH), Usage at Baseline Operating Conditions 

NSR x EUbaS, x 2,000 1 Do, 

= 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 inch wg 

50% 

3.48 

0.00366 tonlMMBtu 

20 psig 

8,760 hr 

41 5 tonlyr 

208 tonlyr 

208 tonlyr 

330 lblhr 

Estimated Average Heat Input for 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 BtulMMBtu x 8,760 

hrlyr) 98 MMBtulhr 

Estimated Total 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) 1 64.054 

= 98 MMBtuIhr x 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 

Appendix N - 56
DAK Americas, LLC 

Four-Factor Analysis 

Estimated Total Additional Electrical Power Required for I.D. Fan 

at Maximum Design Conditions 

From Section 5 of the EPA OAQPS Control Cost Manual (EPAl4521B-02-001): 

Tlie e~echicit?~costs associated\~~itlloperati~le a gas absorlxr deliye fi.0111 fali~.erpilc.lllellts 

to o\-ercolllr the pressure ckop ui the cohulul. d~~ct\roxk. nlid orherl~alts of tlie colitl-ol iyitenl. and 

puii1,1.qli~e11lel1tso mcu-c~~late tlie~olvalt. llie aler~y reqnireci for the f:al~callbecnlcnlated usll~e 

Equation 1.48- 

n l~ele Elielg! (111 L~Iouatt~) 1efei'~ to the ellerg neetied to rllove a glvell x ohuiieh lc fkw. late of nu 

(acfiil) G 15 tlle\~,aste @as floi+-irate crlrelllig the abborbel PIS tlle total p essme d~optluollgll the 

sysrenl (ulcll& ofH.0) alld is tIie colllbmed L?li-nlotol efliclr~lcy \-a11ies fc,~ ~~ylcall! range floll~ 

0 4 to 0 7 Lbe\vlse the elech~crh ~equuedby a lecycle ymil11yc:illbe cal~tio~~ 

- EP!dfanmax - 1.17~10~~ xPdma, 1 E 

Where E is the combined fanlmotor efficiency 

= 0.0001 17 x 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 1208 ton 

Appendix N - 57
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 eqzripment cost (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 $69,43 1 

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 $69,43 1 

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 3-4-1 8-06 

Appendix N - 58
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 = 0.1 5 x $66,685 $10,003 

Consummablcs 

Lime 330 Ib/h x I ton12.000 Ib x $1 OOlton 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 100 percent of maintenance labor $33,051 

Replacement parts 

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

Residue Disposal 

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

Utilities 

Electricity $0.0500 kW-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% of Total Capital Investment = 0.01 x $4,700,000 $47,000 

insurance 1% of Total 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 

Appendix N - 59
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 SO2 Decrease Effectiveness 

(tonly r) ($/ton) ($1~ r) (lblton) (lb/y r) (tonl~r) ($1~ r)(tonlyr) ($/ton) 

32,9 1 1 0.79% $6 1 .OO $2,007,591 25.22 830,024 415 BASELINE 

32,9 10 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 20.75 682,93 1 34 1 $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% Sulhr is "unavailable" in large enough quantities 

I Using data from Massey Coal Supplier for DAK America's Cooper River 

Currently $6 1 dollarslton 

Appendix N - 60
GIANT CEMENT COMPANY 

Post Office Box 2 18 

Harleyville, South Carolina 29448 

OVERNIGHT DELIVERY 

November 2,2007 

Ms. Renee G. Shealy 

Assistant Bureau Chief, Bureau of Air Quality 

South Carolina Department of Health 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 Factor Analysis 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) 85 1-5669. 

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 

Appendix N - 61
FOUR FACTOR ANALYSIS 

for 

GIANT CEMENT COMPANY 

HARLEYVILLE, SOUTH CAROLINA 

November 2,2007 

Appendix N - 62
TABLE OF CONTENTS Page 

1.0 INTRODUCTION 1 

1.1 Overview of Cement Kiln System 1 

1.2 Request from the South Carolina Department of Health and Environmental 

Control 1 

2.0 THE "TOP-DOFW"APPR0ACHAND FOUR FACTOR ANALYSIS 3 

2.1 Background 3 

2.2 Approach Utilized by Giant 4 

3.0 ANALYSIS OF FUEL SWITCHING 5 

3.1 New Cement Kiln System 

3.2 Baseline SO2 Emissions 

3.3 Ana4vsis 

3.4 Fuel Oil 

4.0 CONCLUSIONS 8 

TABLES 

TABLE 1 -Emissions Data 

TABLE 2 - Sulfur Input Data 

TABLE 3 - Btu Contribution by Fuel Type 

TABLE 4 - Comparison of Actual Coal Used and Low Sulfur Coal 

TABLE 5 - Sulfur Input Data with Low Sulfur Coal 

TABLE 6 - Coal Cost Comparison 

APPENDICES 

APPENDIXA - October 4,2007 Letter from DHEC 

APPENDIX B - Quotation Summary Table Used to Develop Costs 

Page i Revision 0 

November 2007 

Appendix N - 63
INTRODUCTION 

1.1 Overview of Cement Kiln 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 manufacturing process involves many steps. Large quantities of raw 

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 of the raw meal elevates. At the base of the preheater 

tower is the rotary portion of the 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 Request from 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 in the letter. 

1. Determined Pollutants of Concern. The regional planning organization for 

the Southeastern United States, Visibility Improvement - State and Tribal 

Association of the 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 determined that the focus should be on electric generating 

units (EGUs) and non-EGU point sources. 

Page 1 Rev~sion 0 

November 2007 

Appendix N - 64
3. Determined if the 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 on Input. 

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 A01 and calculated by DHEC as contributing one percent or more 

of the 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 

SO2 controls for Giant, and identified fuel switching "as a potentially realistic 

option of controlling SO2 emissions," with a potential control cost below 

$2,000 per ton. 

DHEC performed a limited analysis of potential SO2 control alternatives and determined 

that fuel switching was a potentially realistic option for the Giant facility because DHEC 

calculated the potential control cost utilizing fuel switching to be below the established 

threshold of $2,000 per ton of SO2 removed. 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 

Appendix N - 65
2.0 THE "TOP-DO FW" APPROACH AND FOUR FACTOR ANALYSIS 

2.1 Background 

DHEC's letter to Giant requests that the analysis follow a "top-down" approach 

containing the following elements: 

1. Identification of Possible Control Alternatives. The first step in the topdown approach is to develop a comprehensive list of potential control 

technologies and improvements to existing control equipment that could 

potentially reduce SO2 emissions. The developed list of SO2 control options 

can be based on a wide variety of technologies including those listed in 

Section IV(D) of Appendix Y to 40 CFR Part 5 1. 

2. Identification and Ranking of Feasible Control Alternatives. The second 

step of the 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 if they have 

been installed and operated successfully on a particular type of emission unit 

(in this 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 on physical, 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 of the emission unit; location of the emission unit; site constraints for 

deploying the control technology; reliability; or adverse impacts on the 

emission unit operations, such as the generation of a waste product which is 

expensive to dispose. 

3. Assessment of Cost, Energy, and Other Non-Air Quality Environmental 

Impacts of Compliance for Technically Feasible Alternatives. The third 

portion of the assessment incorporates the four factor analysis which consists 

of the 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 OAQPS Air Pollution Control 

Cost Manual. 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 

Appendix N - 66
. . 

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 if the "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 of the Control Alternative, ifAny Technically Feasible 

Alternatives are Found to be Reasonable. 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 SO2 control options and determined that fuel 

switching was a potential control option with a cost of compliance of less than $2,000 per 

ton of SO2 removed. 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 $9,900 per ton of sulfur dioxide removed. While there may 

be alternative coiltrol optioils that are technically feasible to control SO2 emissions, Giant 

concurs with DHEC that fuel switching is the only potential SO2 control option to 

consider. DHEC calculated that fuel switching has a potential cost of compliance that 

approaches $2,000 per ton of SO2 removed. Additionally, DHEC requested that the four 

factor analysis be completed and the results submitted by November 2, 2007. A 

significantly longer period of time 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 

Appendix N - 67
ANALYSIS OF FUEL SWITCHING 

3.1 New Cement Kiln 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-intensive process. Air temperatures in the rotary kiln 

portion of the 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 to the 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 SO2 Emissions 

Following receipt of the letter requesting the four factor analysis, Giant obtained 

information from DHEC that identified Giant's 2002 base year SO2 emissions as 2,825 

tons. Giant generally agrees that this value is accurate for the wet-process facility; 

however, SOz emissions have decreased as a result of the modernization of the 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 PSD permit 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 

Appendix N - 68
this was a transition year for the facility that included the perinanent removal froin service 

of the four wet-process kilns as well as the startup operations of the 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 of the 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 3.5 1 % for 

calendar years 2006 and 2007, respectively. In other words, the sulfur in the coal 

accounts for 4.32% and 3.51% of the total sulfur introduced to the kiln system. 

Attributing SOz emissions 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 

quotations requested by Giant require that the minimum heating value for coal exceed 

1 2,500 Btullb. This minimum value is utilized in the analysis. Additionally, the facility 

continuously samples and analyzes coal that is fired in the kiln2 and has averaged the 

individual samples to 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 of the increased heating value of 

the low sulfur coal in this particular instance (12,500 Btulpound vs. 11,635 Btulpound 

(2006) and 11,576 Btulpound (2007)), Giant predicts it would have combusted 

approximately 3,000 tons less coal in each of the 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 same heating 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 SO2 emissions from the low sulfur coal of 33 tons 

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

coal generally contains 1 percent 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 

Appendix N - 69
(2006) and 3 1 tons (2007). This is a reduction in SO2 emissions 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 of the 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 SO2 removed 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 

Appendix N - 70
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 SO2 emissions 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 69 tons of SO2 emitted per 

year. Switching to a low sulfur coal reduces emissions between 24 and 36 tons of SO2 

per year but at a cost ranging from $7,801 to $1 1,152 per ton of SO2 reduced. 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 SO2 emissions much 

lower than if the facility operated using 100% coal, and that switching to low sulfur coal 

for the portion of the coal combusted at the facility is cost prohibitive. 

Page 8 Rev~sio~i 0 

November 2007 

Appendix N - 71
TABLES 

Appendix N - 72
Four Factor Analysis 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 - Sulfur Input Data 

Notes: 

SO, Emission Rate 

(Ibs SOzlton clinker) 

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 ;60 1 

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 

0.1 1598 

0.1 I598 

0.10850 

0.10850 

0.10850 

0.10850 

Appendix N - 73
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 

S WDF 

Kiln Feed 

I 

> 

2006 

2006 

2006 

2006 

Total 

Coal 

LWDF 

SWDF 

Kiln Feed 

Table 4 - Comparison of Actual Coal Used and Low Sulfur Coal 

\, 

41,195 

60,014 

17,417 

1,422,2 14 

I I I I I 

2,603,792 

Notes: 

[I] The data developed for calendar year 2007 is a prqjected annual total based on nine months of data. 

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 of data. 

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 

1 1,400 

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) 

Appendix N - 74
Four Factor Analysis Calculation Tables 

Giant Cement Company 

Harleyville, South Carolina 

Table 5 - Sulfur Input 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 

Coal 2,995:590 

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 

0.8 1 

0.50 

96.67 

100.00 

Total $/ton 

7 1.99 

84.64 

Sulfur Contribution 

(%) 

2.13 

0.86 

0.35 

96.66 

100.00 

7 1.99 

84.64 

0.1085043 11 

0.108504311 

0.10850431 1 

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 

0.1 15984555 

0.1 15984555 

0.1 15984555 

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 

Appendix N - 75
APPENDICES 

Appendix N - 76
APPENDIX A 

October 4,2007 Letter from DHEC 

Appendix N - 77
BOARD: 

Paul C. Aughrry, 111 IIenlY C Scott 

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?notmg nndp~.otcctmng the healtl~ ofthept/blic rind the 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 1977 Amendments 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 OF HEALTH -- A N D E N V I R O N M E N T A L CONTROL 

2600 Bullstreet Columbia, SC 29201 Phone: (803) 898-3432 www.scdhec.gov 

Appendix N - 78
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 as the basis for much of the Regional Haze SIP. 

SC DHEC has just 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 of the Southem Appalachian 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 SOz emissions from coal combustion. 

Step 2: Determine which source sectors should be cvaluated for 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 201 8). 

Step 4: 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 A01 is based on a back trajectory analysis performed by VIS'T'AS 

Appendix N - 79
Mr. Roberts 

October 4, 2007 

Pagc 3 

that identified the sources of SO2 emissions 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 is reasonable 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 SO2 A01 for 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 dollars per ton of SO2 removed. 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 

on the same terms as the AirControlNet cost estimates, so they are directly comparable to 

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<ing for CAIR of what constitutes cost-effective einission reduction controls for 

SO2 and 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 SO2 and NOx colltrols for non-EGUs. 

During the current reasonable progress assessment, one or more of the units at Giant 

Cement Company was identified as having a potential control cost below the established 

Appendix N - 80
Mr. Ro belts 

October 4, 2007 

Page 4 

threshold of $2,000.00 pcr ton. Specifically, the cost to switch to a lower sulfur fuel was 

identified as a potentially realistic option of controlling SOz en~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 of possible 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 you have 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 of Air Quality 

South Carolina Department of Health and Environmental Control 

cc: Robert J. Brown, Jr., Director, Division of Air 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 N - 81
APPENDIX B 

Quotation Summary Table Used to Develop Costs 

Appendix N - 82
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 

Price Ton $46.00 

Specifications 

Btu / Pound 

I~oisture 1 9%max. 1 8% max. 

Company B 

511 712007 

$44.90 

IVOIS. 36 min. 

12,500 guar. 

Giant Cement Company 

Harleyville, South Carolina 

12,700 min 

Company C 

511 512007 

30+ 36 min. I I 

12,800 

1.5% max. 

Notes: 

[l] The names of the 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 of the quotations provided. The averages are the costs used in the analysis. 

12,500-1 2,600 

1.3-1.5% 

Quotation for Low Sulfur Coal for Potential Use at Giant 

Company E 

9/7/2007 

Supplier Company D 

IDate I 11/1/2007 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 

911 012007 

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% 

Appendix N - 83
Holcim (US) Inc. Phone803496 5027 H o 1 c i rn 200 safety street I Hwy 453 F,X 803 496 2733 

P.O. Box 698 www.holcim.com1us 

Holly Hill, SC 29059 

November 2,2007 

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 Response to DHEC Request for Development of a State 

lmplementation Plan for Regional Haze Concerns 

Dear Ms. Shealy: 

In response to your October 4, 2007 letter requesting Holcim to 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 SO2 emissions 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 in four basic categories: 

P Lime (calcareous) 

P Silica (siliceous) 

P Alumina (argillaceous) 

BUREAU OF AIR QUALIN 

Appendix N - 84
> Iron (ferriferous) 

The limestone, or any other form of calcium carbonate, such as marl used at the 

Holly Hill Plant, makes up over 80 percent of the combination of raw materials 

used to prodl~ce the "kiln feed." Since the cement kiln system utilizes a highly 

alkaline kiln feed material, up to 95 ~c3rcent of the SO2 emissions can be 

absorbed in the process Exceptions to this are cement kiln systems which 

utilize raw materials that contain significant amounts of sulfide sulfur (pyrites). In 

addition, the majority of the SO2 introduced into the kiln from the fuels are 

incorporated into the product (clinker) produced by the kiln system. 

COST EFFECTIVENESS REVIEW 

Holcim has prepared a SOs cost effectiveness analysis to assess the potential 

switch ,from 3 percent sulfur coal, the level .the current permit is based upon, to 

lower sulfur fuel oil, as requested. The results of this analysis are provided in 

Table 1. The switch to 0.9 percent sulfur fuel oil would result in an additional 

cost to Holcim of $41,039.00 per ton of SO2 removed. 

CONCLUSION 

From ,the October 4, 2007 correspondence, it was suggested that a threshold of 

$2,000.00 per ton would be used when considering additional SO2 controls. 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 analysis was 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 Ferguson 

Appendix N - 85
Stale 

SC 

SC 

SC 

SC 

SC 

SC 

G A 

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 JEFFERSON SMURFIT 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 11 98 004 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 11 98 005 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 11 98 005 12 57 

FbracsC10UM003STOblEaM##W~~ RJIkls . -. S Wdll Mat5 SlJ19 138.80 524 0.04 20.83 

Rlchmond 24500006 INTERNATIONAL PAPER - AU( PBZA Pulp Mills B~tum~no~ FGD1,574 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 

Putnam Cc 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 (0 996 3.703 4,329 0 1.342 31 $2.435.476 $1.815 $1,815 41092 1053 003 7 12 

N- Hano, 17129001 1 SOLJTHERN STATES CHEMICdG-21 lnduslnal lnomanlc Suhnc A Increase % Conversl 931 1.112 0 $46 85 9427.461 $452 $452 21664 5 13 002 12 57 

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

01d >=I, .TUX >= I, Cat r= Il0,OOO 

Appendix N - 86
Table 1 

% 3 Sulfur Coal 

#2 Fuel Oil 

Potential clinker production 

Heat consumption 

Heat used to get clinker 

Calorific Value of coal 

Coal use per year 

Price of Coal 

Total cost of coal 

SO2 Cost 

Potential clinker production 

Heat consumption 

Heat used to get clinker 

Calorific Value of oil 

Oil use per year 

Price of Oil 

Total cost of oil 

Permitted Maximum Clinker Production 

(Assume 3700 kJlkg heat consumption, value from 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 

metric tonslyear 

kJlkg clinker 

GJIyear 

GJlmton 

mtlyear 

short tonlyear 

USDlshort ton 

USDlyear 

2,462,318 

2,233,815 

3,700 

8,265,115 

42.3 

195,393 

21 5,380 

858.8 

184,968,397 

The price difference 

Max. SO2 reduction 

Cost per ton SO2 reduction 

short tonslyear 

metric tonslyear 

kJ/kg clinker 

GJIyear 

GJImton 

mtlyear 

short tonlyear 

USDlshort ton 

USDlyear 

164,609,251 

401 1 

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. 

Appendix N - 87
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 response to your email of November 6, 2007, Holcim (US) Inc. (Holcim) is 

providing to you at your request the analysis results for the other three factors 

which our November 2, 2007 letter to 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 Holcim to switch from the use of coal (3% maximum ) as the primary fuel for 

the kiln to use of 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 permits would 

need to be amended (i.e., SPCC Plan). This process would be expected to take 

a minimum period of 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 

associated with a switch from use of 3 percent sulfur coal as the primary fuel for 

the kiln to use of a 0.9 percent sulfur fuel oil. For this potential switch of fuels, 

Appendix N - 88
there is an increased risk of oil spillage and the potential for contamination of 

soils from the delivery, storage, and handling of the fuel oil. 

The potential fuel switch will also not be expected to produce any anticipated 

irreversible or irretrievable commitment of natural resources, such as water, and 

is not expected to result in changes in mbient noise, radiant heat, or dissipated 

static electricity. 

FACTOR 3: REMAINING USEFUL LIFE 

Since the new kiln began operation in October 2003, the life of the new kiln 

systerrl is expected to be rrrinimally 40 years before major system components 

would need to be replaced. Due to 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 SO2 cost effectiveness analysis to assess the 

potential switch from 3 percent sulfur coal, the current level that 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 letter to 

you to result in an additional cost to Holcim of $41,039.00 per ton of SO2 

removed. 

CONCLUSIONS 

From the October 4,2007 SC DHEC correspondence, it was suggested that a 

threshold of $2,000.00 per ton would be used when considering the cost 

effectiveness of additional SO2 controls. Based upon the results of the four point 

analysis it is concluded by Holcim ,that a potential switch 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 

Appendix N - 89
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 of Air Quality 

2600 Bull Street 

Columbia, SC 29201 

Subject: Request for Additional Information for Use in the 

South Carolina Regional Haze State Implementation Plan 

Dear Renee: 

International Paper (IP) - Georgetown Mill is providing the additional information you requested 

during our telephone conversation on October 2,2007. We understand SC DHEC is required to 

prepare and submit a Regional Haze State Implementation Plan in December, 2007 and federal 

regulations (Reasonable Further Progress) require that cost information on control technologies 

be included, even though emissions reductions between now and 201 8 are predicted to meet the 

impl ::.?ent goals for 201 8 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 confirm many of the 

assumptions used in that study, the cost-effectiveness results were similar to 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 switchng and you indicated their costs were less than the $2,000 per ton cost 

effectiveness threshold that DHEC has adopted. Since fuel switching appeared to be cost 

effective based on the 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 of interest for this exercise are No. 1 Power Boiler, No. 2 Power Boiler, No. 1 

Recovery Boiler and No. 2 Recovery Boiler. The Power Boilers currently burn a diverse fuel mix 

consisting of wood, coal, tire-derived fuel, fuel oil, natural gas, propane, and are permitted 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. The Recovery 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 

Appendix N - 90
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-derived fuel and No. 6 fuel oil) with natural gas, low-sulfur fuel oil and distillate oils. 

Four Factor Analvsis 

International Paper considered four factors when evaluating the feasibility of burning alternate 

low-sulfur fuels. These four statutory factors are: cost of compliance, time necessary for 

compliance, energy and non-air quality environmental impacts of compliance and remaining 

useful life of the source. 

Cost of Compliance 

The Mill evaluated the cost of replacing 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 practices in 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, since the power boilers obtain a 

significant portion of their heat from wood, the resulting alkaline wood 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 

modifications to fuel tanks, piping systems, delivery systems, and burners or combustion controls 

would be required to implement these options. The costs included herein are just the cost of 

fuel; not included is funding required to implement these options. The modifications listed 

would be significant; however, it was not possible to perform the necessary engineering estimates 

in th :he available. 

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 for the Georgetown Mill. 

The detailed calculations for both fuel costs and reduced SO2 emissions can 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 sulfur fuel oil. It should be noted that the Mill's 

Title V Permit limits No. 6 fuel oil consumption in the power boilers. Therefore, the Mill 

calculated thls alternative two 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 

sulfur fuel oil, calculating a complete fuel switch to 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 

estimates for fuel switching range from $6,417/ton SO2 to $10,012/ton SO2. 

Time Necessarv for Compliance 

The changes required to modify the fuel tanks, piping systems, delivery systems, and burners or 

combustion would require capital funding and would take considerable time to implement. 

Enerm and Non-Air Ouality Environmental Impacts of Compliance 

In addition to the capital and operating costs, conversion to low sulfur fuels would have other 

impacts on the International Paper mill operations. These additional impacts include: 

The Georgetown Mill currently bums tire-derived fuel which is a environmentally 

beneficial use of this material. 

Appendix N - 91
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, the tank(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 Useful Life of the Source 

Due to the fact that this option is cost prohibited, the life of the boilers does not factor into the 

feasibility of implementation. 

Comments 

We wish to point out that these alternatives appear to be 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 for residential 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 to reduce use of imported oil and domestic 

natural gas in favor of more 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 Gnergy priorities. 

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 switch to 

natural gas would not only have the impact of making domestic natural gas supplies even more 

scarce and expensive, it would make the U.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 are not cost 

effective and it was not necessary to repeat 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 Gas Prices Around the World, Industrial Energy Consumers of America, August 2007 

Appendix N - 92
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 the basis 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 

Gary N. Weinreich, P.E. 

Environmental Manager 

Attachments: 

Figure 1 : 

Table 1 : 

Table 2: 

'i..cl~ 3: 

Tahle 4: 

Table 5: 

Table 6: 

Table 7: 

Table 8: 

Table 9: 

Table 10: 

Natural Gas Prices Around the World 

Summary of Economic Impact for Fuel Switching Alternatives 

Fuel Reference Data 

Fuel Switching Cost Estimate: Natural Gas Alternative 

Fuel Switchng SO2 Emission Offset: Natural Gas Alternative 

Fuel Switching Cost Estimate: Low Sulfur No. 6 Fuel Oil & Natural Gas 

Alternative 

Fuel Switching SO2 Emission Offset: Low Sulfur No. 6 Fuel Oil & Natural Gas 

Alternative 

Fuel Switching Cost Estimate: Low Sulfur No. 6 Fuel Oil 

Fuel Switching SO2 Emission Offset: Low Sulfur No. 6 Fuel Oil 

Fuel Switching Cost Estimate: Distillate Oil Alternative 

Fuel Switching SO2 Emission Offset: Distillate Oil Alternative 

cc: Deborah Feck - IP 

Kirk Carlson - IP 

Jim Witkowski - IP 

Appendix N - 93
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Appendix N - 96
Table 3 

Fuel Switching Cost Estimate: Natural Gas Alternative 

International Paper - Georgetown Mill 

URS Project No. 31825960 

I 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 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-mo rolling sum); If 15OMBtuIgal max of 780,000 MMBtuIyr 2 Used Oil shall not exceed 876,000 gallonslyear (per recovery boiler, 12-mo rolling sum) 

3 Assume heat value of coal is 12,700 Btullb 

Appendix N - 97
Table 4 

Fuel Switching SO2 Emission Offset: Natural Gas Alternative 

International Paper - Georgetown Mill 

URS Project No. 31825960 

1 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 he1 burned 

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 10 tph (total for boilers) 

Used Oil shall not exceed 5.2 MMgalIyear (per boiler, 12-mo rolling sum); If 15OMBtu/gal max of 780,000 MMBtuJyr 

2~sed Oil shall not exceed 876,000 gallonstyear (per recovery boiler, 12-mo rolling sum) 3 Assume 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 

-- 

-- 

-- 

-- 

Switch to 

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 

2006 Fuel 

Usage 

Unit ID 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 

0 

Appendix N - 98
Table 5 

Fuel Switching Cost Estimate: Low Sulfur No. 6 Fuel Oil & Natural Gas Alternative 

International Paper - Georgetown Mill 

URS Project No. 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 (1 2-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/gal max of 780,000 MMBtuJyr 2 Used Oil shall not exceed 876,000 gallonslyear (per recovery boiler, 12-mo rolling sum) 

3 Assume heat value of coal is 12,700 BtuJlb 

Switch to Low S 

No. 6 Oil with 

Balance Natural 

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 ID 01''~ 

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 

Appendix N - 99