TOXECON Cost Estimates for Coal

- Fired Boilers 

### EPA Contract No. 68

- W

- 03

- 028
Subcontract Number: 23BL00114 Work Assignment No. 3

- 4



# TOXECON Cost Estimates for Coal

- Fired
Boilers

December 2006



### Prepared for

U.S. Environmental Protection Agency
Clean Air Markets Division 1310 L Street, NW

Wash ington, DC 20005

By

Andover Technology Partners

112 Tucker Farm Road North Andover, MA 01845

Subcontractor to

ICF Consulting 9300 Lee Highway Fairfax, VA 22031

- 1207TOXECON Cost Estimates for Coal

- Fired Boilers i



## Contents

Sections Page

1. Background 1

2. Objectives 2

3

. Program Results 3TOXECON Cost Estimates for Coal

- Fired Boilers 1



## Background

ICF Consulting (ICF) supports the Environmental Protection Agency in analysis to support EPA’s policy development. Andover Technology Partners (ATP) provides ICF technical

services to support these activities.

Since mercury is known to have adverse health impact on humans, there is considerable concern over emissions of mercury into the atmosphere. Coal

- fired power plants are known to comprise the dominant anthropogenic source of merc ury emissions and recently EPA has taken regulatory

actions to control these emissions. Seve ral technologies/processes for controlling mercury

emissions from coal

- fired power plants are in various stages of development. ATP has supported

ICF and EPA in e valuation of mercury control technologies and this work assignment builds on

that effort

.TOXECON Cost Estimates for Coal

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## Objectives

The purpose of this report is to develop algorithms in estimation of TOXECON baghouse costs. Baghouses downstream of existing ESPs may be necessary for high levels of control of mercury emissions from some boilers. Therefore, the information developed from this report will be helpful in evaluating the cost of some mercury control policies.TOXECON Cost Estimates for Coal

- Fired Boilers 3



## Program Resul t s

The purpose of this report is to develop a lgorithms for estimation of capital and operating costs

for Pulse

- Jet Fabric Filter (PJFF) baghouse retrofits downstream of an existing ESP where mercury sorbent is injected upstream of the fabric filter

.

In order to develop these algorithms, ATP develo ped sizing and cost estimates of TOXECON baghouse application s on coal

- fired boilers, including the following:

1. S izing of TOXECON baghouse applications on 200, 500, and 900 MW boile rs firing sub

bituminous coals

.

2. Develop ing the baghouse design basis, w ith the assumption that activated carbon is being injected upstream of each baghouse and that a 98 percent efficient electrostatic precipitator is installed upstream of the baghouse.

3. Obtain ing budgetary quotes for the above baghouses, new induced draft booster fans, new ash handling systems, etc. to develop cost estimates for the complete TOXECON baghouse retrofits.

4. Including an impact of using different bag materials on the baghouse cost. Different bag

materials are required to suit the application environment, such as high

- moisture, acidic, high

- temperature, etc., especially when high

- sulfur bituminous coals are used.

5. Develop ing capital, fixed O&M, and variable O&M cost estimates (variable cost estimates to include costs of bag replacement, auxil iary power, solid waste disposal, etc.).

6. Develop ing cost algorithms to allow estimation of capital, fixed O&M, and variable O&M costs for varying boiler sizes (expressed in MW).TOXECON Cost Estimates for Coal

- Fired Boilers 4

1.0 Removal of Mercury Through Sorbent Injection

- Background

Mercur y removal by Sorbent Injection (SI) is a control technology that has been used in other industries for mercury control and has been tested at numerous coal

- fired units in the United

States. After co

- benefit from other controls, SI technology is the mercur y control technology that is most likely to be deployed at coal

- fired power plants.

SI technology is a well

- established method to control mercury from Municipal Waste Combustors (MWCs) in the United States and Europe. The most widely used sorbent for the se applications is powdered activated carbon ( PAC ). Whether on a MWC or on a coal

- fired power plant, the equipment for a sorbent injection system consists of a storage silo, metering valve, pneumatic conveying system and a series of pipes that direct the sorbent that is blown into the plant ductwork. The sorbent is always injected upstream of a particulate matter (PM) collection

device

– typically either an electrostatic precipitator or fabric filter as in Figure 1 . The dry particles are dispersed in the flue gas stream and are captured by the downstream PM collection

device. When an electrostatic precipitator ( ESP ) collects the sorbent, the mercury capture must occur as the sorbent and mercury interact “in

- flight”. For a fabric filter, there is “in

- fl ight” interaction, but additional interaction occurs between the sorbent and mercury as the gas passes through a layer of sorbent and fly ash collected on the surface of the filter bag. As a result, mercury capture by sorbent is more effective when a fabr ic filter is used

– resulting in greater mercury capture for a given amount of sorbent.

However, most coal

- fired boilers in the United States use ESPs. As a result, without addition of a fabric filter, these boilers are limited to the capabilities of “in flight” mercury capture.

For coal

- fired applications, where it may be desirable to keep the sorbent separate from the captured fly ash (such as when the fly ash is sold for use in concrete ), the sorbent may be injected in a way that segregates the captur ed sorbent from most of the fly ash. Toxic Emission Control (TOXECON) offers a way to do this, and t here are two types of TOXECON systems . One method is to inject the sorbent between fields of the ESP. This is called a TOXECON II arrangement. The bulk o f the fly ash is collected in the ESP upstream of the sorbent injection point and is separated from the sorbent and remaining fly ash that is collected in the ESP downstream of the injection point as shown in the TO XECON II arrangement of Figure 1

. TOXECO N II is a technology that has had limited testing. In other cases it may be preferable to install a new fabric filter downstream of the existing ESP. In this case the configuration is a TOXECON arrangement as shown in Figure 2 . This configuration has th e benefits of providing segregation of fly ash from sorbent and higher mercury removal efficiencies at lower sorbent injection rates. However, the disadvantage is that the equipment is more expensiv e than in the case of Figure 1

.TOXECON Cost Estimates for Coal

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Figure 1

. Arrangement f or a Typical Sorbent Injection System for Mercury Control , Normal

Arrangement in Solid and TOXECON II in Dashed

Figure 2

. Sorbent Injection in a TOXECON Arrangement for Mercury ControlTOXECON Cost Estimates for Coal

- Fired Boilers 6

The sorbent injection hardware does not take up much space and i s relatively easy to retrofit onto an existing plant. Figure 3 shows a photo of the equipment used at one coal

- fired power plant. The size of the storage silo is relatively small compared to existing APC equipment. Except in the case of TOXECON, it is n ot necessary to make any major alterations to ductwork or existing equipment when installing a sorbent injection system.

Figure 3 Sorbent Injection equipment compared to other air pol lution control equipment. 1

There have been a few full

- scale tests of TOXECON, or TOXECON

- like methods for controlling

mercury. The first major program was conducted at the existing Compact Hybrid Particle Collection (COHPAC) system at Southern Company’s Gaston unit #3 , a bituminous coal fired

unit . At this plant a long

- term test program was undertaken that established design conditions for a TOXECON system. 2 The next full

- scale test was at the Presque Isle Power Plant, a plant firing Powder River Basin (PRB) fuel. Unlike Gaston, which was originally designed an d built to capture the fly ash that escapes the upstream hot

- side ESP, the Presque Isle fabric filter was designed with the intention of being used to capture mercury sorbent in addition to a small amount of fly ash. A third test was at the existing COHPA C system at TXU’s Big Brown station, which has two 600 MW units that fire a 70%/30% lignite/PRB blend and have a COHPAC baghouse with a 12:1 air to cloth ratio. 3 Of these three programs

– Gaston, Presque Isle, and Big Brown,

- the most significant from t he perspective of cost estimating is Presque Isle since it was designed specifically as a TOXECON system for mercury from the start while the

other COHPAC fabric filter systems were initially designed solely to enhance PM control beyond what was possible w ith the existing ESP.

1.1 Presque Isle Power Plant (PIPP) TOXECON System

This was the first true TOXECON system (not a n existing COHPAC baghouse that was tested out of convenience as a TOXECON arrangement, such as at Gaston and Big Brown) and was partly funded by the Department of Energy. At the PIPP, units 7, 8, & 9 fire PRB coal and are equipped with hot

- side ESPs. The fabric filters were installed downstream of the air preheater. Based upon the testing experience at Gaston, an A/C ratio less than 6. 0 was determined to be the maximum A/C ratio to result in sufficiently low bag cleaning frequency for acceptable bag life. 2

Therefore, at PIPP an A/C ratio less than 6.0 was selected (5.5). At Presque Isle, a single fabric

filter was installed on three 90 MW boilers

– units 7, 8 & 9. It was not possible to locate the

fabric filter near the stack due to site constraints. Due to the location available for the fabricTOXECON Cost Estimates for Coal

- Fired Boilers 7

filter, a complex and lengthy ductwork arra ngement was necessary, as shown in Figure s 4 a an 4b

. As a result, although this fabric filter treats nominally up to 270 MW of flue gas, there were additional complexities associated with connecting three smaller units to a common baghouse.

This included four

- port diverter dampers for each unit so that any unit might be able to bypass the TOXECON system with the others in operation. The four

- port dampers were included because this was a test plant and it was desirable to be able to isolate one unit from the others. In a commercial application where the equipment had to be running at all times, the dampers might not have been installed. The four ports for each unit included:

**•** From the boiler

**•** To the stack

**•** To the baghouse

**•** From the baghouse

Another complexi ty was that the installation used three booster fans in order to better match the flowrate of the fans to the flowrate of the units, as shown in Figure 5. The costs associated with the Presque Isle TOX ECON system are shown in Table 1

. Included in the $3. 93 million of Engineering Costs of Table 1 are $1 million of development money for mercury CEMS and another $566,000 that are one

- time development costs that would not apply to future applications. Table 1 also includes $300,000 for the mercury CEMS hardw are. Excluding these costs from the total retrofit cost results in a total of $32.6 million, or about $121/KW. 4 The complexities associated with the Presque Isle installation contribute to the high co st of the project

– roughly $121 /KW, with the fabric f ilter itself comprising only $37/KW of the total. Therefore, on a new unit, you would expect significantly lower cost than what was experienced at Presque Isle. For other retrofit applications, the cost would be very dependent upon the site conditions

a nd might be similar to what was experienced at Presque Isle in some cases and might be lower

in others.

Figure 4 a . Configuration of the TOXECON system at the Presque Isle Plant in Marquette, MI 5TOXECON Cost Estimates for Coal

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Figure 4 b

. Site Plan of the TOXECON system at the Presq ue Isle Plant in Marquette, MI 6TOXECON Cost Estimates for Coal

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Figure 5. Basic Schematic of the Presque Isle TOXECON Process 6

Table 1

. Costs of Equipment for the Presque Isle TOXECON system. 6TOXECON Cost Estimates for Coal

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1.2 Other Studies

Reference 7 describes an engineering study by a fabric filter supplier that examined the impact of fabric filter size in terms of A/C ratio on mercury control economics. In general, they confirmed that A/C >6.0 was generally u nattractive. Moreover, they found that if A/C = 4.0 the ESP could be secured, saving some parasitic loads, and filter bag lifetime could be extended. In this case the economics of the larger fabric filter (A/C of 4.0 rather than 6.0) could be better than that of the smaller fabric filter despite the higher capital cost. The study also found that an important economic driver in the equation is whether or not the fly ash is sold for beneficial re

- use. In that case the economics might favor operation of t he ESP to segregate carbon from the fly ash and the smaller fabric filter (A/C = 6.0) might prevail over the larger fabric filter. Although many plants do not sell their fly ash, those that don’t would like to keep that option available. Moreover,

utilit ies are very comfortable with ESPs, which they have a great deal of experience with. Therefore, because the capital cost is lower and because it maintains the option of selling fly ash we expect that most facilities would opt for a smaller fabric filter w hile maintaining the ESP in operation rather than the larger fabric filter and securing the ESP. Therefore, a TOXECON arrangement is the subject of this study rather than conversion of ESP to fabric filter.

The capital cost reported in Reference 7 showed that for a fabric filter system where the A/C is roughly 6.0 the equipment cost (excluding fan) on an erected basis was about $25 million for a 350 MW unit and $28 million for a 550 MW unit. These equate to $71/KW and $51/KW, respectively, before additio n of any other costs

. A breakdown for these costs is given in Table 2.

An important similarity between the costs shown in Table 1 and those shown in Table 2 is the large contribution to cost made by the ductwork

. Ductwork is a major cost item for many r etrofit

situations. But

, it is a relatively minor cost for a new plant. Since the study did not evaluate the effects of different fan requirements, the cost of the fans are not included in Table 2 although fan

costs would be a necessary budget item in an actual installation.

Table 2. Breakdown of costs from Reference 7

– all costs on an erected basis 8

Cost Item 350 MW 550 MW Baghouse $12,674,000 $16,403,000 Ash Handling $1,660,000 $1,966,000

Foundations $584,000 $711,000

Electrical $1,497,000 $2,1 97,000

Ductwork ( not including booster fan) $8,649,000 $6,696,000

Total $25,064,000 $27,973,000TOXECON Cost Estimates for Coal

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2.0 Determination of Gas Conditions for the Basis of the Budgetary Estimates

In order to obtain equipment quotations that are on a comparable basis, it w as necessary to define conditions for the vendors to base their estimates upon. US EPA’s Coal Utility Environmental Cost (CUECost) program was used to estimate gas conditions for the basis conditions . Using a Powder River Basin (PRB) coal that is part of the program’s coal library and shown in Table 3

, the gas conditions of Table 4 were estimated for the cold

- side ESP inlet for the three cases of interest for nominal 200, 500 and 900 MW plants. A PRB coal was selected as being conservative from the persp ective of gas flow rate and the impact to fabric filter sizing and cost.

It is assumed that the minimum capture efficiency of the ESP is 98%, so that no more than 2% of the inlet particle matter escapes the ESP. The downstream PJFF would be expected to c apture the remaining particle matter plus any sorbent that is injected after the ESP.

Table 3 . Coal Used for Analysis from US EPA’s CUECost Program

FUEL ANALYSIS FOR SPECIFIED COALS

DOE PRB PROXIMATE ANALYSIS (wt. %)

Moisture wt% 30.4

Volatile Matter wt% 30.79

Fixed Carbon wt% 32.41

Ash wt% 6.4

TOTAL 100

COAL ULTIMATE ANALYSIS (wt. %)

Moisture wt% 30.4

Carbon wt% 47.85 Hydrogen wt% 3.4 Nitrogen wt% 0.62

Chlorine wt% 0.003

Sulfur wt% 0.48

Ash wt% 6.4 Oxygen wt% 10.82

TOTAL 100.0 Mercury Content mg/kg 0.07

HIGHER HEATING VALUE (HHV) Modified Mott Spooner

- calc Btu/lb 8304

COAL COST $/MMBtu 1.5 COAL ASH ANALYSIS ( ASTM, as rec'd)

SiO 2 wt% 31.6

Al 2 O 3 wt% 15.3

TiO 2 wt% 1.1

Fe 2 O 3 wt% 4.6

CaO wt% 22.8 MgO wt% 4.7

Na 2 O wt% 1.3

K 2 O wt% 0.4

P 2 O 5 wt% 0.8

SO 3 wt% 16.6

Other Unaccounted for wt% 0.8

TOTAL wt% 100TOXECON Cost Estimates for Coal

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A sorbent injection rate of 2 lb/MMacf was assumed. This is consistent with tests at Gaston where about 95% removal was achieved during simulated conditions with air

- to

- cloth ratio of 6.0

ft/min. 2 Also, at the Presque Isle Power Plant demonstration program, parametric testing showed that an injection rate of 2 lb/MMacf resulted in 90% mercury removal using untreated activated

carbon. 9 A halogenated carbon is expected to provide better remo val at the same treatment rate or, alternatively, the same re moval at a lower treatment rate. Also , at Big Brown about 90% removal was achieved despite the high A/C at 2 lb/MMacf using treated carbon while it was necessary to inject over 6 lb/MMacf with u ntreated carbon. That study concluded that treated

carbon was more economical than untreated carbon. 3 Moreover, at higher injection rates, pressure drop on the filter or cleaning frequency can be unacceptable

.

Table 4

. Gas Conditions At ESP Estimated by CUECost

Case1 Case 2 Case 3

Nominal MW 200 500 900 Flue Gas, Upstream of ESP Temperature °F 300 300 300

Pressure In. H2O

- 12

- 12

- 12

Flow Rate SCFM 511,799 1,279 ,499 2,303,098

Flow Rate ACFM 784,771 1,961,928 3,531,471

CO 2 lb/hr 441,168 1,102,919 1,985,255

N 2 lb/hr 1,597,006 3,992,516 7,186,529

SO 2 lb/hr 2,425 6,063 10,914

O 2 lb/hr 121,070 302,675 544,815

HCl lb/hr 8 20 35

Other Gases lb/hr 670 1,675 3,015

H2O lb/hr 180,757 451,892 813,406 Fly Ash lb/hr 13,432 33,580 60,444 Total (gas only) lb/hr 2,477,994 6,187,291 11,127,643

Wet Flue Gas PPMV & % Vol

% O 2 % Vol 4.7 4.7 4.7

% CO 2 % Vol 12.4 12.4 12.4

% N 2 % Vol 70.5 70.5 70.5

PPMV NOx ppmv 180.0 180.0 180.0

PPMV HCL ppmv 2.6 2.6 2.6

PPMV SO 2 ppmv 468.0 468.0 468.0

% H 2 O % Vol 12.4 12.4 12.4

TOTAL 100.0 100.0 100.0

Min ESP PM Collection Eff % 98.0% 98.0% 98.0%

Max PM out of ESP lb/hr 269 672 1,209

Sorbent Injection Rate lb/Mmacf 2 2 2 Sorbent Injection Rate lb/hr 94 235 424

Max Emission Rate after PJFF lb/MMBtu 0.150 0.150 0.150

Max Emission Rate after PJFF lb/hr 315 788 1,418TOXECON Cost Estimates for Coal

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2.1 Baghouse and Filter Media Design Criteria

The fabric filter downstream of an ESP in a COHPAC arrangement or in a TOXECON arrangement does not have to be as large as a fabric filter sized to capture all of the PM from a boiler. Since most of the PM is removed in the upstream ESP, the bags do not accumulate particulate build up as quickly. Air to cloth ratio (A/C) , measured in acfm of gas per square foot of capture area (ft/min) is a commonly used parame ter to gauge fabric filter size. Where a fabric filter for the full particulate loading of the boiler might be sized for an A/C = 4.0, testing of sorbent injection into a fabric filter at the Gaston Station under a Department of Energy sponsored program d etermined that for a TOXECON arrangement A/C should be no greater than

6.0.

The filter material is another factor in the design of a fabric filter. Suppliers try to balance the competing requirements of:

**•** Low cost

**•** Ease of cleaning

**•** Low pressure drop

**•** Durabi lity

**•** Chemical stability

**•** Thermal stability

Generally, denser fabrics are more durable and also tend to clean better, but at the cost of higher pressure drop. Some suppliers provide filter media that is coated with a thin, porous film on the dirty side to improve cleaning while maintaining low pressure drop, but this typically adds cost.

T he fabric will be chosen depending upon the gas conditions. For example, at the Presque Isle

Power Plant (PIPP) TOXECON system polyphenylene sulfide (PPS) filter media w as selected based upon the flue gas temperature. Other characteristics of this filter bag were: 6

**•** Felted, 2.7 denier PPS fabric

**•** Weight of nominally 18 ounces/yd 2

**•** Singed on both sides

**•** Scrim material made from 3 ounces/yd 2 of PPS

**•** Mullen burst minimum of 500 psi

**•** Maximum temperature for continuous use is 375 oF

**•** Permeability at 0.5 inches H 2 O of 25

– 40 cfm/ft 2

Other filter media is available. Gas conditions effect the selection of filter media as well as the

selection of material s. Filter media used in power plant applications fall into three broad types:

**•** PPS

– the most commonly used filter media for most power pl ant applications up to about

375 o F

**•** P84

– this filter media is used in higher temperature applications up to about 45 0 o F

**•** PTFE

- coated

– this filter media is used in temperature regimes that approach 500 o F.TOXECON Cost Estimates for Coal

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Woven fiberglass is another option that is resistant to acid attack. But, these bags may not be suitable for pulse jet applications due to their fragility. They ma y be better suited for reverse air baghouses.

Of the three, PPS is the least expensive media and is most widely used. However, in high

- acid environments it may not have good cleaning characteristics and may suffer from acid attack. Therefore, a coated b ag may be preferable if not necessary. PTFE coated bags will not develop an adherent dust cake as well as PPS bags, and may be less attractive from the perspective of mercury removal. Hence, mercury removal on the filter may be less likely in high acid

e nvironments. P84 bags are another alternative since they are capable of higher temperature operation where acid dew point may not be a problem.

Temperature is generally higher for applications with high acid dew points. High dew point is impacted by sul fur, moisture level in the gas, and the configuration of the unit (i.e., if there is an

SCR that raises SO 3 concentration). Acid will also affect the choice of filter bag cage materials. Instead of carbon steel cages, coated steel or even 316 stainless s teel may be selected

– but at a higher cost. For similar reasons, tube sheets might be coated or manufactured from stainless steel in a high acid environment, which will increase cost. Another option for high acid environments is injection of trona or so dium bisulfate to capture the SO 3 . Or, alternatively, use of a spray drier that would capture SO 2 . Any of these alternatives would enable temperatures to

be lower and permit use of standard materials.

Fortunately, high sulfur applications are most likel y going to be equipped with SO 2 scrubbers, which provide good mercury capture

. So, in these cases fabric filters are unlikely to be added for the purpose of mercury control. As a result, for most cases where fabric filters are added,

standard materials

– such as filter bags of PPS and baghouse construction from mild steel

- are acceptable. In the minority of cases where more costly materials will be needed, filter media and materials of construction will be somewhat more expensive.

The filter media can be cleaned “on

- line” or “off

- line”. On line cleaning entails pulsing air in the reverse direction for a short moment to clean the bags while the bag is still on line. Of f

- line cleaning involves isolating a compartment of the fabric filter system to rever se pulse the bags

. O n

- line cleaning is most often preferred because the pressure drop across the fabric filter system

remains more consistent since there is not a need to secure flow through any section of the system only to increase flow and pressure dro p elsewhere. On

- line cleaning also results in a somewhat smaller, and less expensive, fabric filter. Therefore, on

- line cleaning is usually preferred and for this study we have chosen on

- line cleaning.TOXECON Cost Estimates for Coal

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3.0 MAJOR EQUIPMENT ITEM S AND CAPITAL COST

In t his section the major equipment items in a fabric filter retrofit will be described along with

the costs that are associated with these items. To determine the costs, vendor budgetary quotes

were received

. As a basis of comparison, the vendor quotes were compared to reported c osts for actual projects or engineering studies of actual projects , such as those of Presque Isle and the

costs of Reference s 7 and 8

.

3.1 Costs for Each Major Piece of Eq uipment

The major pieces of equipment include:

**•** Baghouse

– this is the major control device being added. Included with the baghouse is the cleaning system that includes air compressors and also PLC controls.

**•** Ash Handling

– this is the material conveying system used to transport the ash from the baghouse hopper discharge to silos or other temporary storage prior to disposal or
transport.

**•** ID Booser Fans

– used to overcome the additional pressure drop of the baghouse and

associated ductwork

**•** Electrical

– this is additional switchgear cable routing and other electrical equipment

associated with the additional load of the fans, compressors, controls, and PAC system

**•** Ductwork

– used to route the gas from ESP or air preheater outlet to the new fabric filter

inlet a nd from the fabric filter outlet to the fan inlet

**•** Controls

– these include fan controls and DCS modifications

**•** PAC System

– this includes the storage silo, pneumatic conveying system, sorbent injection grid, controls and other equipment associated with the PAC injection system.

According to Tables 3.2

- 5 and 3.2

- 3 of Reference 10 , the cost of installation of flue gas cleanup equipment on a new plant is equal to nearly 60% of the cost of the e quipment, making the

installed cost close to 1.6 times the cost of t he equipment. For a retrofit , one would expect that this cost would be higher since the equipment must be installed with existing site conditions rather than conditions that can be designed for ease of installation as in a new plant. This may be

addresse d with a retrofit difficulty factor , which multiplies the estimated installed cost for new equipment by a factor to address the additional difficulty . Or, alternatively, a hi gher estimate of erection costs may be applied. In this report, we will use the latt er approach because this is also consistent with what some of the suppliers informed us to use as an estimating method

. Therefore, we will assume that the installed cost is 2 times the cost of equipment rather than 1.6 times the cost of the equipment as would be the case for a new facility.

3.1 .1 Baghouse Costs

Technology suppliers provided budgetary estimates for baghouses. The baghouse costs on an erected basis were plotted against ACFM. The baghouses in these cases include the entire fabric

fi lter system, including compressed air system for cleaning and also the controls. As shown inTOXECON Cost Estimates for Coal

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Figure 6 , there was close correspondence between all sources and also with t he PIPP fabric filter

cost and the costs reported for Reference 7

. PIPP fabric filter cost was plotted on this figure using the full gas flow into the fabric filter. Where the budgetary cost was not provided on an erected basis, it was assumed that the cost of erecting the fabric filter was equal to the mater ial

cost because this is consistent with what

. Where vendors did not include compressed air, for example, quotes for compressed air systems were sought and added to make all budgetary quotes on an equal basis.

Figure 6. Estimated baghouse costs on an e rected basis

Baghouse - Erected

y = 6.9007x + 5E+06

R

2 = 0.9794

$ 0 $ 5 ,0 0 0 ,0 0 0 $ 1 0 ,0 0 0 ,0 0 0 $ 1 5 ,0 0 0 ,0 0 0 $ 2 0 ,0 0 0 ,0 0 0 $ 2 5 ,0 0 0 ,0 0 0 $ 3 0 ,0 0 0 ,0 0 0 $ 3 5 ,0 0 0 ,0 0 0

0 500,000 1,000,000 1,500,000 2,000,000 2,500,000 3,000,000 3,500,000 4,000,000

ACFM Baghouse Vendors PIPP Refs 7 & 8 vendor trendline .

3. 1. 2 Ash Handling

Ash handling equipment budgetary quotes were provided by vendors for all

- new ash handling
systems , including conveying systems, storage, etc

. However, as shown in Figure 7, costs for fly

ash handling at the PIPP and t he cost estimates for additional fly ash handling equipment in

Reference 7 were significantly less than the vendor quotes for new systems. This is because the existing fly ash system at PIPP and in the case of Reference 5 cou ld be modified to address the

ash and sorbent collected from a retrofit TOXECON baghouse for less than the cost of an altogether new fly ash system

. In this case, the estimates determined from the PIPP and

Reference 5 data would be applicable for most pla nts and the estimate for the new fly ash handling system might be an upper limit for some cases. Regarding the data shown in Figure 7, where the cost was not provided on an erected basis, it was assumed that the cost of erecting the ash handling equipment was equal to the material cost.TOXECON Cost Estimates for Coal

- Fired Boilers 17

Figure 7. Costs for fly ash handling on an erected basis

Ash Handling- Erected

y = 1.4396x + 454291

R 2

= 0.9733

y = 0.5734x + 759141

R 2

= 0.907

$0 $1,000,000 $2,000,000 $3,000,000 $4,000,000 $5,000,000 $6,000,000

0 500,000 1,000,000 1,500,000 2,000,000 2,500,000 3,000,000 3,500,000 4,000,000

ACFM Vendor All New Fly Ash Conveying and Storage Refs 7 & 8 and PIPP fly ash upgrade

vendor trendline

Ref 5 and PIPP trendline

.

PIPP Refs 7 & 8

3. 1. 3 Booster Fans

Booster fan budgetary quotes were also provided. These provided relatively good correspondence with the PIPP cost. In the case of th e fans and the ductwork, the PIPP estimate

was treated as if it were a 90 MW unit and dividing total cost by 3. This is because although the baghouse was built to handle 270 MW worth of flue gas, the ductwork was for three 90 MW

boilers and there were thr ee 90 MW fans and associated ductwork

. Most of the installation cost

for the fan is included in the ductwork and electrical cost . So, Figure 8 can be used as an

estimate of fan cost

.TOXECON Cost Estimates for Coal

- Fired Boilers 18

Figure 8. Installed Cost for Booster Fans

Fans

y = 0.6922x + 51525

R 2

= 0.9999

$0 $500,000 $1,000,000 $1,500,000 $2,000,000 $2,500,000 $3,000,000

0 500,000 1,000,000 1,500,000 2,000,000 2,500,000 3,000,000 3,500,000 4,000,000

ACFM Fan Vendors

PIPP Fans

vendor trendline

.

3. 1. 4 Electrical

Elec trical hardware is associated with the switchgear and motor control centers (MCC’s) cabling, etc. for the booster fans and also the electrical for the PAC system and the baghouse system, including the compressors. However, it is probably reasonable to ass ume that most of this cost is

associated with the booster fans as they contribute to most of the additional electrical load

. For PIPP, the total electrical (material and installation) divided by three should be reasonable for a 90 MW plant because PIPP ha s three separate booster fans and associated electrical for each of the 90 MW boilers. We compare this to the electrical for References 7 and 8 , and this is shown in Figure 9.

Figure 9. Electrical Cost

– Material and Installation

Electrical- Material and Installation

y = 0.8897x + 276594

R 2 = 1

$0 $500,000 $1,000,000 $1,500,000 $2,000,000 $2,500,000

0 500,000 1,000,000 1,500,000 2,000,000 2,500,000

ACFM Electrical

Refs 7 & 8 and PIPP trendline . Refs 7 & 8

PIPPTOXECON Cost Estimates for Coal

- Fired Boilers 19

3. 1. 5 Ductwork

Some of the vendors quoted fifty feet of inlet and fifty feet of outlet ductwork , and Figure 10

shows estimated erected ductwork and a trendline

. Because a fabric filter has a top plenum that allows inlet and outlet ductwork to be on the same side, i f there i s sufficient open space in the vicinity of the chimney, 50 feet of inlet and outlet ductwork may be adequate. However, i n many retrofit situation s , more than fifty feet of ductwork is likely to be necessary. So , the actual

amount of ductwork will vary wi dely from one application to another. Figure 10 compares the

estimated ductwork cost (on an installed basis assuming that installation labor costs equal

material cost

– based upon vendor inputs for ductwork installation costs ) from different sources

. Two points are shown for PIPP. One is the estimated total cost of material based upon what is reported in Table 1 (times 2 to address installed cost and divided by 3 to adjust from 270 MW to 90 MW). As noted earlier, even though the baghouse is sized for 27 0 MW of flue gas, the ductwork is the equivalent of three 90 MW units that each requires a few hundred feet of

ductwork

– an installation that was rather complex

. The other PIPP data point on Figure 10 results from making an adjustment in an attempt to ma ke it equivalent to a 50 foot length of ductwork (50 feet of inlet and 50 feet of outlet). To make this adjustment for ductwork length, the PIPP ductwork length was estimated from figures in Reference 6 to be on average about 223

feet for each inlet and outlet per unit . With this adjustment for duct length, the ductwork cost at

PIPP is more consistent with what the vendors estimated. Therefore, these two sources, when adjusted, are relatively consistent. Also shown on Figur e 10 is estimated ductwork cost from the study performed in Reference s 7 & 8

. As shown on Figure 10, the cost fo r the 350 MW unit of

References 7 & 8 is actually higher than for the 550 MW unit, which confirms the perspective

that ductwork cost in a retro fit will be very site specific. A trendline is plotted for these points

and the estimate PIPP erected cost. But, it is important to keep in mind that the cost of ductwork may be the single biggest uncertainty in estimating the cost of a retrofit TOXECON system and that actual costs may vary significantly from this trendline. So, the 50 foot trendline would be the minimum ductwork cost and the PIPP costs might be toward the high end of what we’d
expect. Figure 10. Costs for ductwork on an erected basis

Ductwork- Erected

y = 0.4639x + 399273

R

2 = 0.7776 y = 2.7264x + 2E+06

R

2 = 0.5382

$0 $1,000,000 $2,000,000 $3,000,000 $4,000,000 $5,000,000 $6,000,000 $7,000,000 $8,000,000 $9,000,000 $10,000,000

0 500,000 1,000,000 1,500,000 2,000,000 2,500,000 3,000,000 3,500,000 4,000,000

ACFM Vendor Ductw ork (50 feet) PIPP PIPP adjusted for 50 foot ducts Ductw ork - Ref 7 & 8 and PIPP vendor 50 ft duct trendline PIPP and Refs 7 & 8 Ductw ork

. Refs 7&8

PIPPTOXECON Cost Estimates for Coal

- Fired Boilers 20

3. 1. 6 Controls

In thi s work the cost of controls was included in the baghouse cost since all of the baghouse vendors included controls in their quotation.

3. 1. 7 Activated Carbon Injection (ACI) System

Vendors also provided budgetary quotations for AC I systems. On an erected basis, the costs were as shown in Figure 11. Where information was provided on a material

- only basis, such as PIPP, it was assumed that the erected cost was (material and erection) was double the material

cost.

Figure 11. Estim ated Erected Costs of ACI

ACI -Erected

y = 0.3885x + 1E+06

R

2 = 0.6044

$0 $500,000 $1,000,000 $1,500,000 $2,000,000 $2,500,000 $3,000,000

0 500,000 1,000,000 1,500,000 2,000,000 2,500,000 3,000,000 3,500,000 4,000,000

ACFM ACI

PIPP

vendor trendline .TOXECON Cost Estimates for Coal

- Fired Boilers 21

3.1.8 Foundations

Foundation costs for PIPP and for References 7 & 8 are plotted on Figure 12. In this case, PIPP foundation cost is displayed apportioned for a 90 MW plant (essentially, 1/3 of the flowrate and

1/3 of the cost) because it is likely that the ductwork arrangement for three 90 MW units had a major impact on the cost of the foundations.

Figure 12 . Cost of Foundations

Foundations

y = 0.1063x + 465904

R

2 = 0.9397

$400,000 $450,000 $500,000 $550,000 $600,000 $650,000 $700,000 $750,000

0 500,000 1,000,000 1,500,000 2,000,000 2,500,000

ACFMCost Foundations

Foundations trendline

PIPP Refs 7 & 8

3.2 Estimating Total Process Capital

The installed cost of the hardware is the total pro cess capital. Based upon the trendlines in the previous section for major items, algorithms for total process capital can be derived. For each major piece of equipment, the installed cost can be estimated as with an equation in the form:

Cost = A * X + B Eq. 1

Where

**•** Cost is expressed in $

**•** X = gas flow in ACFM

**•** A and B are coefficients from the Table 5 :

Values for the coefficients are shown in Table s 5 a and 5b

.

As an alternative to ACFM, capacity in MW could be used. In that case, it would be necess ary to adjust the value for A from Table 5 by multiplying it by the number of ACFM per MW of capacity, which is typically in the range of about 3500 acfm/MW to about 4000 acfm/MW, depending upon the fuel, the heat rate of the unit and the temperature of th e gas at the fabric

filter.TOXECON Cost Estimates for Coal

- Fired Boilers 22

Table 5 a

. Coefficients for Equation 1 (longer duct runs) Equipment A B Baghouse 6.9007 5,000,000 Ash Handling 0.5734 759,141

Booster Fans 0.6922 51

, 525

Electrical 0.8897 276

, 594

Ductwork 2.7264 2

, 000

, 000 ACI System 0.3 885 1

, 000

, 000

Foundations 0.1063 465

, 904

Table 5 b . Coefficients for Equation 1 (shorter duct runs)

Equipment A B Baghouse 6.9007 5,000,000 Ash Handling 0.5734 759,141

Booster Fans 0.6922 51

, 525

Electrical 0.8897 276

, 594

Ductwork 0.4639 399

, 273 ACI System 0.3885 1

, 000

, 000

Foundations 0.1063 465

, 904

Using Equation 1 and the coefficients in Tables 5a and 5b, as well as information in Section 4.0 Operating Costs, Total Capital Requirement can be developed per the guidance in Section 5.0

Estimat ing Total Capital Requirement.TOXECON Cost Estimates for Coal

- Fired Boilers 23

4.0 OPERATING COSTS

4.1 Variable Operating Costs

Variable Operating Costs (VOC) include the following:

**•** Parasitic loads

**•** Bag replacement

**•** Sorbent

**•** Sorbent Disposal

4.1 .1 Parasitic loads for pressure loss.

This cost cate gory covers the parasitic load associated with fan power needed to overcome the pressure drop of the pulse

- jet fabric filters and associated ductwork

. It also includes the power for the air compressor used to provide cleaning air for the baghouse. An expr ession from Reference

11 for computing the fan electricity cost ( C
e ) is given here:

C e **= (**  0. 746 * Q * Δ P *s* θ * p e ) **/(** 6356* η) Eq. 2

where Ce = Cost of power in $/year Q = gas flow rate (actual ft 3 /min, acfm)

Δ P = pressure drop through system (inches of wa ter column )

s = specific gravity of gas relative to air (usually close to 1.0)
θ = operating factor (hr/yr)

η = combined fan and motor efficiency ( around 0.80 )

p e = electricity cost ($/kwhr)

Using 3900 acfm/MW, an efficiency of 8 0 %, capacity factor of 85 %, price of electricity of $0.025/KWhr ($25/MWhr)

, pressure drop of 11 IWC and 8760 hours per year, s ≈ 1.0.

C e = 937 * M W Eq. 3

4. 1. 2 Other Electric Loads

Other electric loads include the equipment for the sorbent injection system, controls, and fo r the compressed air. Figure 13 shows the estimated electric load for the sorben t injection system and controls as well as for the compressed air system. Summing both equations, the total KW load is equal to:

Load (in KW) = 1.4 E

- 4 * ACFM + 42.24 Eq. 4

So, the annual cost would beTOXECON Cost Estimates for Coal

- Fired Boilers 24

C load = (1.4 E

- 4 * ACFM + 42.24)*( PE /1000)*8760*CF Eq. 5

If it is assumed that there are 3900 ACFM per MW, price of electricity of $25/MWhr, and capacity factor of 85%, then the annual cost of this load can alternativel y be estimated by:

C load = 102 * MW+7818 Eq. 6

Where

C load = Cost of power in $/year

MW = MW rating of the boiler

Figure 1 3 . Estimated Electric Loads

Electric load - excluding booster fans

y = 4E-05x + 42.22

R

2 = 0.8888 y = 1E-04x + 0.0243

R

2 = 1

0 50 100 150 200 250 300 350 400

0 500,000 1,000,000 1,500,000 2,000,000 2,500,000 3,000,000 3,500,000 4,000,000

ACFMKW Electric Load compressed air load electric load trendline compressed air load trendline

.

4. 1. 3 Bag Replacement

The cost of replacing bags includes both material and labor. Th ese c osts are shown in Figure 14 for PPS bags. All of the vendors offered 2

- 3 year guarantees on bag life. However, their expected bag lifetime was typically in the range of 4

- 5 years. Therefore, this cost is expected to be realized every 4

- 5 years and it wo uld be reasonable to attribute roughly 20%

- 25% of the total cost to each year of operation.

Roughly 80% of the cost is in the materials. For a higher sulfur or higher temperature application filter bags made from more expensive fabrics would be necessary . One fabric filter supplier stated the material cost of the filter bags would increase by 50% in these cases. If labor costs to replace the bags stay the same, then the total replacement cost would be 140% of that of the less expensive PPS filter bags.TOXECON Cost Estimates for Coal

- Fired Boilers 25

Figure 1 4 . Bag Replacement

– material and labor for PPS fabric

Bag Replacement - material and labor

PPS filter media

y = 0.5853x + 26023

R

2 = 0.8786

$0 $500,000 $1,000,000 $1,500,000 $2,000,000 $2,500,000 $3,000,000

0 500,000 1,000,000 1,500,000 2,000,000 2,500,000 3,000,000 3,500,000 4,000,000

ACFM Filter Bag Replacement

trendline .

This cost will be realized every 4

- 5 years or may be apportioned 20%

- 25% per year. If it is assumed that there are 3900 ACFM per MW, then the annual cost of bag replacement for

standa rd PPS bags as shown in Figure 14 can be estimated by:

C bags = ( 2283 *MW + 26,023 )/4 = 57* MW + 6506 * Eq. 7

Where:

C bag = Cost annual cost apportionment of bag replacement in $ MW = MW rating of the boiler, and

4. 1. 4 Sorbent usage

Activated carbo n sorbent costs in the range of $0.50/lb for untreated activated carbon and in the range of $0.80/lb

- $0.90/lb for treated carbon. For a bituminous coal, untreated carbon would be used. For PRB or lignite coals treated carbons might be used, depending upo n how effective untreated carbon is at the particular site. From the carbon treatment rates on Table 4, it can be shown that the treatment rate is roughly 0.47 lb of sorbent per MW

- hr. Thus, the annual cost of

sorbent can be estimated as:

C sorbent = 0.4 7 * P sorbent *MW*8760*CF Eq. 8

Where:

C sorbent = Cost of sorbent in $/year MW = MW rating of the boiler, and

P sorbent = the price of sorbent in $/lb CF = Capacity Factor

* Assumes a life of 4 years. Substitute 5 if a five year life is expected.TOXECON Cost Estimates for Coal

- Fired Boilers 26

If sorbent costs $0.50/lb and capacity factor is 85%, then

C sorbent = 1750 *M W Eq. 9

4. 1. 5. Sorbent and fly ash disposal

The incremental cost of disposal will be propo rtional to the amount of captured sorbent and additional captured fly ash that is disposed of

.

According to EIA form 767 data for 2004, $178,498,000 was repo rted as expenses relating to fly ash disposal. A total of 12,940,000 tons of fly ash were reported as sent offsite. Assuming that all of the expenses reported for disposal were associated with off

- site disposal, this is roughly $9.27/ton for offsite disp osal

. However, in some locations , particularly near cities, offsite disposal may be much more expensive.

From Table 4, it is shown that there is up to 1.34 lb/MW

- hr of fly ash that escapes the ESP and is

collected in the PJFF and about 0.47 lb/MWhr of so rbent that is captured, for a total of no more

than 2.81 lb/MWhr

.

Hence, the cost of disposal of the additional fly ash captured and the sorbent is:

C disposal = 2.81 * P disposa l *MW*8760*CF/2000 Eq. 10

Where:

C disposal = Cost of disposal in $/year

M W = MW rating of the boiler, and

P disposal = the price of disposal in $/ton CF = Capacity Factor

Using the average prices stated above and a capacity factor of 85%, Equation 9 becomes:

C disposal = 2.81 * P disposa l *MW*8760*CF/2000 = 10.46 * MW Eq. 1 1

However, keep in mind that the amount of fly ash going into the PJFF is likely to be less than what this equation shows since this is based on a minimum ESP capture efficiency of 98%.

4.1.6 Total Annual Variable Operating Costs

Combining Equations 3, 6, 7, 9 and 11 to find the total variable operating costs,

C

voc = 937 * M W + 102 * MW+7818 + 57* MW + 6506 + 1750 *MW + 10.46 * MW

= 2856 * MW + 14,324 Eq. 12TOXECON Cost Estimates for Coal

- Fired Boilers 27

4.2 Fixed Operating Costs

Annual f ixed operating costs are associated with regular maint enance and can be estimated as a percentage of Total Process Capital (TPC, as will be described in Table 6 Section 5 Estimating Total Capital Requirement ).

Fixed O&M Cost, $/Yr = 0.03 * TPC Eq. 11TOXECON Cost Estimates for Coal

- Fired Boilers 28



### 5.0 ESTIMATING TOTAL CAP ITAL REQUIREMENT (TC R )

The T otal Capital Requirement (TCR) is the total cost that a power plant incurs when installing a piece of hardware. TCR includes all project costs including equipment and all other costs associated with installing it, managing the project, financing it, and c ommissioning it . For example, equipment will often be quoted flange

- to

- flange on an erected basis, excluding foundations and structural steel, ductwork, fans, etc. Other parts of the plant may be affected and require modification. And, the owner incurs financial costs as well. As a result, there are other costs that must be rolled up to get from the equipment supplier costs to the total project costs

- TCR.

A commonly used approach for determining the TCR starts with an estimated cost of the erected

ha rdware. The cost of the equipment as installed on a new unit is multiplied by a retrofit factor, typically greater than 1.0 and the magnitude increases with the difficulty of the retrofit. Retrofit difficulty factor addresses the additional costs associa ted with retrofitting an existing plant that was not originally designed to accommodate the control equipment versus the costs of installing the equipment on a new plant. This results i n Total Process Capital (TPC). As described in Section 3.1, the retro fit difficulty factor in this case is intrinsic to the installation cost estimate we will be using

. We could have alternatively used an installation cost estimate similar to that of a new unit (which would have been about 40% lower ) and multiplied by a re trofit difficulty factor. Either approach would be reasonable and result in similar results.

Onto TPC are added General Facilities (GF, roads, buildings, etc. that may be needed), Engineering and Construction Management (ECM), and Project Contingency (PC ). Typically, GF, and ECM are estimated as a percentage of TPC, but these percentages may vary slightly from case to case. PC is equal to a percentage of TPC+GF+ECM. Total Plant Cost (TPLC) is equal to TPC+GF+ECM+PC. Prime Contractor Markup (PCM) is equa l to a percentage of TPLC and is added to TPLC. Allowance for Funds Used During Construction (AFUDC) accounts for the borrowing costs for the construction loans. AFUDC is partly offset by the Total Cash Expended (TCE) factor, which is a factor less than o ne that accounts for cost escalation during the project making early expenses less costly on a cash basis than later ones. The sum of TPLC, PCM and AFUDC is multiplied times the TCE factor resulting in Total Plant Investment (TPI). TPI plus Inventory Cap ital (spares, etc., plus initial chemicals and reagents), Preproduction Cost (costs associated with commissioning of the equipment), and royalties equals Total Capital Requirement (TCR). For the technologies of interest in this report, royalties are assum ed to be equal to zero or included in other costs.

**•** GF=5% of TPC

**•** ECM=10% of TPC

**•** PC=15% of (TPC+GF+ECM)

**•** PCM = 3% of (TPC+GF+ECM+PC)

**•** AFUDC and TCE factors are calculated based upon project duration, interests rates, inflation, etc. In the case of IPM and th e default in CUECost, the assumed project

duration is rela ted to the MW size of the plant

– larger plants being longer in duration and therefore having a higher AFUDC effect

**•** Total Plant Cost = TPLC = TPC + GF + ECM + PCTOXECON Cost Estimates for Coal

- Fired Boilers 29

**•** Total Plant Cost including Prime Con tractor’s Markup = TPLC + PCM

**•** Total Plant Investment = TPI = ( ( TPLC + PCM )*(1+AFUDC) ) * TCE

**•** Preproduction Costs (PPC) = 2% of TPI to address spare parts, etc., plus one month of

fixed and variable O&M

**•** Inventory Capital (IC) = initial reagent based upon nu mber of days of storage (in this case, 30 days).

**•** Total Capital Requirement ( TCR ) = TPI + PPC + IC

PPC and IC can be estimated based upon operating costs described in the next section.

Table s 6 a and 6b and Figure 15 show the Total Capital Requirement esti mate for the three cases and for an estimate for a long duct run and an estimate for short duct run for each case

. Figure 15 also shows the average trendline for the long duct run and short duct run cases.

These results also incorporate a 15% Project Co ntingency, which might be high in light of the fact that this estimate is fairly comprehensive in including the various equipment and items such as foundations and electrical. Thus, it might be reasonable to reduce the estimate somewhat. A

reduction in P roject Contingency factor should be considered.

Table 6 a

. Total Capital Requirement for Long Duct Arrangement

Case 1 Case 2 Case 3

MW 200 500 900

ACFM 784,771 1,961,298 3,531,471 Baghouse $10,415,469 $18,534,329 $29,369,622 Ash Handling $1,209,129 $1,883,749 $2,784,086

Booster Fans $594,743 $1,409,135 $2,496,009

Electrical $974,805 $2,021,561 $3,418,544

Ductwork $4,139,600 $7,347,283 $11,628,203 ACI System $1,304,884 $1,761,964 $2,371,976

Foundations $549,325 $674,390 $841,299

Total Process C apital (TPC) $19,187,955 $33,632,412 $52,909,740
General Facilities (GF) $959,398 $1,681,621 $2,645,487 Engineering Construction Mgt (ECM) $1,918,795 $3,363,241 $5,290,974 Project Contingency (PC) $3,309,922 $5,801,591 $9,126,930

Prime Contractor’s Mar kup (PCM) $761,282 $1,334,366 $2,099,194
Total Plant Cost Estimate (TPLC) $26,137,352 $45,813,231 $72,072,325
$/KW $131 $92 $80

AFUDC Factor 5.3% 10.7% 16.4%

TCE Factor 98.72% 97.46% 96.22%

TPI $27,160,402 $49,433,332 $80,701,281

Pre Production Costs $96,764 $204,275 $347,668 Inventory Capital $412,926 $745,565 $1,189,445 Total Capital Requirement $27,670,092 $50,383,172 $82,238,393
$/KW $138 $101 $91TOXECON Cost Estimates for Coal

- Fired Boilers 30

Table 6 b

. Total Capital Requirement for Short Duct Arrangement

Case 1 Case 2 Case 3

MW 200 500 900

ACFM 784,771 1,961,298 3,531,471 Baghouse $10,415,469 $18,534,329 $29,369,622 Ash Handling $1,209,129 $1,883,749 $2,784,086

Booster Fans $594,743 $1,409,135 $2,496,009

Electrical $974,805 $2,021,561 $3,418,544

Ductwork $763,328 $1,309,119 $ 2,037,522 ACI System $1,304,884 $1,761,964 $2,371,976

Foundations $549,325 $674,390 $841,299 Total Process Capital (TPC) $15,811,683 $27,594,248 $43,319,060
General Facilities (GF) $790,584 $1,379,712 $2,165,953 Engineering Construction Mgt (ECM) $1,5 81,168 $2,759,425 $4,331,906 Project Contingency (PC) $2,727,515 $4,760,008 $7,472,538 Prime Contractor’s Markup (PCM) $627,329 $1,094,802 $1,718,684
Total Plant Cost Estimate (TPLC) $21,538,279 $37,588,195 $59,008,140
$/KW $108 $75 $66

AFUDC Factor 5 .3% 10.7% 16.4%

TCE Factor 98.72% 97.46% 96.22%

TPI $22,381,316 $40,558,365 $66,072,969

Pre Production Costs $88,323 $189,179 $323,691 Inventory Capital $345,400 $624,802 $997,631 Total Capital Requirement $22,815,039 $41,372,346 $67,394,291
$/KW $11 4 $83 $75

Figure 1 5 . Total Capital Requirement in $/KW plotted versus MW

y = 606.06x -0.2819

R

2 = 0.9712

y = 510.67x -0.286

R

2 = 0.9716 y = 558.32x -0.2838

R 2 = 0.9714

$70 $80 $90 $100 $110 $120 $130 $140 $150

0 200 400 600 800 1,000 MW$/KW long duct short duct

average long duct trendline

short duct trendline averageTOXECON Cost Estimates for Coal

- Fired Boilers 31

REFERENCES

1 Durham, “Advances in Mercury Control Technology”, Pennsylvania Mercury Rule Workgroup Meeting , November 18, 2005

2 Berry, M., Irvin, N., Monroe, L., Bustard, J., Lindsey, C., Brignac, P., Taylor, T., Schlager, R.

, Sjostrom, S., Starns, T., Chang, R., O’Palko, A., “Field Test Program for Long

- Term Operation of a COHPAC® System for Removing Mercury from Coal

- Fired Flue Gas”, Presented at the Joint EPRI DOE EPA Combined Utility Air Pollution Control Symposium, The Me ga Symposium, August 31

- September 2, 2004, Washington, D.C.

3 Pavlish, J., Thompson, J., Martin, J., Weimuth, B., Pletcher, S., “Field Testing of Activated Carbon Injection Options for Mercury Control at TXU’s Big Brown Station” , Presented

at the Joint EPR I DOE EPA Combined Utility Air Pollution Control Symposium, The Mega Symposium, August 28

- 31, 2006, Baltimore, MD

4 personal communication by e

- mail with Steve Derenne, WE Energies, 10/16/06

5 Johnson, D., Cummings, J. , “TOXECONTM Retrofitfor Mercury and Multi

- Pollutant Control”, presentation on Clean Coal Power Initiative, downloaded from www.netl.doe.gov

6 Wisconsin Electric Power Company, “TO XECONTM Retrofit for Mercury and Multi

- Pollutant

Control on Three 90

- MW Coal

- Fired Boilers

- Preliminary Public Design Report”, DOE Cooperative Agreement No.: DE

- FC26

- 04NT41766, May 15, 2006

7 Snyder, R., Novogoratz, D., “Fabric Filter Size Impacts on Mercu ry Control Using Activated Carbon Injection”, Presented at the Joint EPRI DOE EPA Combined Utility Air Pollution Control Symposium, The Mega Symposium, August 28

- 31, 2006, Baltimore, MD

8 personal phone conversation with D. Novogoratz, 10/17/06

9 Derenne, S., Sartorelli, P., Bustard, J., Stewart, R., Schlager, R., Sjostrom, S., Chang, R., Utter, R., Cummings, J., McMahon, T., and Sudhoff, F., “ TOXECON Clean Coal Demonstration for Mercury and Multi

- Pollutant Control at We Energies Presque Isle Power Plant”, Presented at the Joint EPRI DOE EPA Combined Utility Air Pollution Control Symposium, The Mega Symposium, August 28

- 31, 2006, Baltimore, MD

10 US Department of Energy, “MARKET

- BASED ADVANCED COAL POWER SYSTEMS FINAL REPORT”, DOE/FE

- 0400, MAY 1999

11 EPA AIR POLLUTION CONTROL COST MANUAL, Sixth Edition

, EPA/452/B

- 02

- 001

, January 2002