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ES-1 

EXECUTIVE SUMMARY 

As part of the Best Available Retrofit Technology (BART) assessment for the J.E. Corette 

(Corette) coal-fired steam electric plant, an economic cost effectiveness analysis was performed in an 

initial report dated August 2007. Upon review and comment by the U.S. Environmental Protection 

Agency Region 8, the initial analysis was updated in an addendum report dated June 2008. On May 18, 

2011, EPA requested a further update on costs of SO2 controls for Corette. This Addendum to the initial 

reports provides an updated assessment to address SO2 control costs. 

The Corette power plant, located in Billings, Montana, is owned and operated by PPL Montana, 

LLC. The coal-fired boiler at the plant was determined to be BART-eligible under the Federal Regional 

Haze Rule by the U.S. Environmental Protection Agency Region 8. It is a 162 MW electrical generation 

unit that burns low sulfur sub-bituminous coal. 

Since these reports were prepared, new cost analysis techniques have been developed as part of 

the Integrated Planning Model (the IPM) under a grant from the U.S. EPA, “Documentation for EPA 

Base Case v.4.10 Using the Integrated Planning Model”. See the following link for more details: 

http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html#documentation) 

ICF International (ICF) developed the IPM to assess the combined effect that air rules have on the 

utility industry as a whole. This platform has also been used by EPA’s Clean Air Markets Division for 

analyzing recent air policy decisions. Based upon currently available information, the control technology 

cost estimation techniques developed for the IPM appear to be more robust than those used in the 

previous BART reports prepared by PPL Montana. TRC has used these IPM analytical techniques for 

updating the 2007 and 2008 cost effectiveness analyses for dry injection, spray dryer absorption, and wet 

flue gas desulfurization control technologies. These costs reflect our best high level estimate based on the 

data currently available. They include cost updating to reflect significant increases in material and labor 

costs. 

Consistent with the June 2008 Addendum, TRC estimated costs for the control technologies 

evaluated based on typical emission rates representative of a 30-day average and the maximum 24-

hour emission rates based on data during the modeling years (2001, 2002 & 2003) as requested by 

EPA. Even though PPL Montana believes that the actual cost effectiveness should be based on a 

longer time basis utilizing typical emission rates (30-day average at a minimum) and that a shorter 

time basis and maximum emission rates are not representative of site-specific cost effectiveness, we 
ES-2 

are providing the 24-hour cost calculation as requested. The 30-day running average SO2 emission 

rate is 0.46 lbs SO2/MMBtu and the 24-hour emission rate is 0.60 lbs SO2/MMBtu. 

For this updated assessment, we have evaluated three technologies for cost effectiveness in 

reducing sulfur dioxide (SO2) emissions. The results are discussed below. The details of the cost 

effectiveness calculations for each control technology are provided in Section 4 and the associated tables. 

Regarding the wet Flue Gas Desulfurization (FGD) option, the Corette air permit requires that 

plume buoyancy be maintained and a wet scrubber would decrease plume buoyancy significantly. 

Consequently, a significant amount of reheat would need to be applied in order to meet stipulated SO2 and 

plume buoyancy requirements. In addition to the high cost for FGD, there are significant site constraints 

that effectively eliminate this technology from any further evaluation. For completeness, control costs for 

this option are presented in Section 4 of this report. 

The two reagent injection technologies, “Dry Sorbent Injection” (DSI), and “Spray Dryer 

Absorption” (SDA) involve the injection of quantities of dry chemicals into the exhaust for the absorption 

of SO2. These injected reagents, plus the sulfates formed from the SO2 absorption, will result in increased 

particulate loading to and emissions from the control device which is currently an electrostatic 

precipitator. Controlling the additional particulate will likely require particulate control equipment 

upgrades. SDA will also likely require plume reheat, which has been included. This is because in a SDA 

system, a water slurry containing lime is sprayed into the gas stream that will reduce plume temperature 

and plume reheat will be required to maintain plume buoyancy. The cost of all these upgrades is included 

in the cost effectiveness calculations significantly increasing the cost to apply these technologies at 

Corette. 

The dry sorbent injection - DSI system is estimated to reduce SO2 emissions to about 0.26 lbs 

SO2/MMBtu with a cost effectiveness of approximately $10,920 per ton of SO2 removed on an annualized 

basis. The spray dryer absorption - SDA system is estimated to reduce emissions to about 0.13 lbs 

SO2/MMBtu with a cost effectiveness of approximately $18,839 per ton of SO2 removed on an annualized 

basis. For this report, PPL Montana determined that it is was not necessary to update any of the June 

2008 visibility assessments as the range of SO2 emission reductions achieved by the evaluated control 

technologies in this addendum is within the range of SO2 reductions previously evaluated. The additional 

analyses provided by this addendum do not change the conclusion that PPL Montana reached for the 

Corette boiler in its August 2007 BART Assessment or the June 2008 Addendum that implementation of 

further SO2 controls is not warranted. 
ii 

 TABLE OF CONTENTS 

SECTION PAGE

EXECUTIVE SUMMARY .................................................................................................................... ES-1 

1.0 BACKGROUND .......................................................................................................................... 1 

2.0 RECENT DEVELOPMENTS ...................................................................................................... 2 

2.1 The IPM Approach to the Costing of Air Pollution Controls ....................................................... 2 

2.2 Spray Dryer Absorbers and Wet Flue Gas Desulfurization .......................................................... 5 

3.0 APPENDICES TO THE IPM COST APPROACH ..................................................................... 6 

3.1 The Effect of Coal Sulfur Content ................................................................................................ 7 

3.2 Dry Sorbent Injection .................................................................................................................... 7 

3.3 Spray Dryer Absorption ................................................................................................................ 8 

3.4 Wet Flue Gas Desulfurization ....................................................................................................... 8 

4.0 COSTING ANALYSIS TABLES ................................................................................................ 9 

5.0 REFERENCES ........................................................................................................................... 26 
iii 

TABLE OF CONTENTS

(Continued) 

FIGURES

2.0-1 Illustrative Dry Scrubber Capital Costs ........................................................................................ 3 

2.0-2 Illustrative Dry Scrubber O&M Costs .......................................................................................... 4 

TABLES

4-1 S&L Empirical Equations for Cost Estimations ......................................................................... 10 

4-2a Dry Injection SO2 Control – Design Case for Capital Cost ........................................................ 11 

4-2b Dry Injection SO2 Control – 30-day Average SO2 Operational Parameters ............................... 12 

4-2c Dry Injection SO2 Control – Max 24-hr Average SO2 Operational Parameters ......................... 13 

4-2d Dry Injection SO2 Control – 30-day Rolling Average SO2 – Cost Effectiveness Calculations .. 14 

4-2e Dry Injection SO2 Control – Max 24-hr Average SO2 - Cost Effectiveness Calculations ......... 15 

4-3a SDA SO2 Control – Design Case for Capital Cost ..................................................................... 16 

4-3b SDA SO2 Control – 30-day Average SO2 Operational Parameters ............................................ 17 

4-3c SDA SO2 Control – Max 24-hr Average SO2 Operational Parameters ...................................... 18 

4-3d SDA SO2 Control – 30-day Rolling Average SO2 – Cost Effectiveness Calculations ............... 19 

4-3e SDA SO2 Control – Max 24-hr Average SO2 - Cost Effectiveness Calculations ....................... 20 

4-4a Wet FGD SO2 Control – Design Case for Capital Cost.............................................................. 21 

4-4b Wet FGD SO2 Control – 30-day Average SO2 Operational Parameters ..................................... 22 

4-4c Wet FGD SO2 Control – Max 24-hr Average SO2 Operational Parameters ............................... 23 

4-4d Wet FGD SO2 Control – 30-day Rolling Average SO2 – Cost Effectiveness Calculations ........ 24 

4-4e Wet FGD SO2 Control – Max 24-hr Average SO2 - Cost Effectiveness Calculations ............... 25 

ATTACHMENTS

A-1 Dry Sorbent Injection Cost Methodology Development – Sargent & Lundy, LLC, August 2010 

A-2 SDA FDG Cost Development Methodology – Sargent & Lundy, LLC, August 2010 

A-3 Wet FGD Cost Development Methodology – Sargent & Lundy, LLC, August 2010 
1 

1.0 BACKGROUND

In August 2007, TRC prepared a BART analysis for PPL Montana, LLC that contained cost 

analyses for potential control of SO2 emissions at Corette. Dry reagent injection (dry injection), dry gas 

scrubbing (spray dryer absorption), and wet scrubbing (wet FDG) were included in the August 2007 

assessment report as available and applicable control technologies. Cost information available at that 

time was limited to data developed by Srivastava in 2001 for wet and spray dryer control techniques, 

however, the data were only available in terms of broad ranges of capital equipment and annual operating 

and maintenance costs. TRC used this source of information in determining the cost effectiveness as 

contained in the US EPA Air Pollution Control Technology Fact Sheet, EPA-452/F-03-034. 

On February 4, 2008, EPA commented on the August 2007 submittal for Corette. Although TRC 

based the economic analysis on EPA data for SO2 control, EPA requested revisions to the capital cost 

amortization from 11 to 15 years, and analysis of higher SO2 control efficiencies. No additional 

references for developing the cost of SO2 control equipment were identified in the EPA letter or in the 

TRC response to the EPA request. EPA suggested that the 2002 Air Pollution Control Cost Manual (the 

CCM) be used to revise the cost estimations, however, TRC pointed out in the June 2008 addendum to 

the August 2007 BART assessment submittal, that the CCM provides cost estimation techniques for small 

industrial sized scrubbers with maximum exhaust gas flows up to about 200,000 actual cubic feet per 

minute (acfm) and therefore, no better data for cost estimation existed at that time. 

On May 18, 2011, EPA requested a further update on costs of SO2 controls for Corette. The 

results of the cost development for the IPM study shows that costs have increased for the installation of 

retrofit control equipment and the more robust analytical techniques for dry injection, spray dryer 

absorption and wet flue gas desulfurization have herein been applied to update the 2007 and 2008 cost 

estimations. 
2 

2.0 RECENT DEVELOPMENTS 

When the final rule was promulgated in 2005 (see FR Vol. 70, No. 128, July 6, 2005), much of 

the then available Air Pollution Control Equipment (APCE) cost data were contained in the CCM 

published in January 2002. For SO2, the gas absorber costing techniques were limited to industrial 

applications with up to approximately 200,000 acfm of exhaust flow. Utility applications of flue gas 

desulfurization (FGD) using wet scrubbing were installed and operating on utility boilers in the USA, 

however, no compilation of the cost of such utility sized systems was available. 

Using costing tools available at that time, analyses of BART were submitted to regional offices of 

EPA as required and reviews of the reports, such as those submitted by PPL Montana, were performed. 

Simultaneously, however, EPA was utilizing available planning tools to study the universe of 

environmental effects that rules such as the Clean Air Interstate Rule (CAIR), Best Available Retrofit 

Technology (BART), and other local rules would have on the utility industry in the USA. One such tool 

used by EPA is the Integrated Planning Model or the IPM. 

In the description of the development of the IPM, examples of the costing approach are included 

for model utility boiler plants. As shown in the illustrative example, costs for spray dryer absorbers, both 

capital and operating and maintenance costs, are a strong function of unit capacity. Figures 2.0-1 and 

2.0-2 show a general trend line for the application of the cost analysis techniques to coal-fired plants of 5 

values of gross power output from 100 to 1,000 megawatts (MW). Figure 2.0-1 is the total capital cost 

for equipment and installation and Figure 2.0-2 shows the operation and maintenance costs in $/KW. 

These figures are presented to illustrate the general tendency of the cost analysis to return higher 

capital and operation and maintenance costs for small capacity plants. Appendices to the EPA summary 

document contain the detailed equations used in the cost analysis developed to support the IPM. Copies 

of these reports are included in Attachment A. 

2.1 The IPM Approach to the Costing of Air Pollution Controls

ICF International (ICF) developed a proprietary tool known as the IPM to assess the combined 

effect that air rules have on the utility industry as a whole. This platform has also been used by EPA’s 

Clean Air Markets Division for analyzing air policy decisions. One aspect of the IPM is the capital, 

operating, and maintenance cost of air pollution control equipment. These costing analytical techniques 

were summarized in reference 1, available from the US EPA Clean Air Markets Division or through the 

link provided in the executive summary of this report. For SO2, APCE cost analyses for two control 

technologies are presented; lime spray dryer absorption (SDA), and wet flue gas desulfurization (wet 

FGD). 
3 

Figure 2.0-1 Illustrative Dry Scrubber Capital Costs 
4 

Figure 2.0-2 Illustrative Dry Scrubber O&M Costs 
5 

Greater detail regarding the IPM is included in three appendices to this document. Each appendix 

includes the analytical equations used by the engineering firm Sargent & Lundy (S&L) in their 

background studies upon which EPA based their control cost analyses. These appendices allow users to 

calculate cost estimations for plant specific data. Therefore, using the S&L equations, cost estimations 

were compiled for the Corette boiler. 

2.2 Dry Sorbent Injection, Spray Dryer Absorbers, and Wet Flue Gas Desulfurization

In dry sorbent injection, dry chemical sorbent is injected into the flue gas downstream of the 

boiler and prior to the particulate control device. The chemical reagent reacts with SO2 and forms sulfates 

which are partially removed in the particulate controls. The technique increases loading to the particulate 

control equipment and creates additional ash. 

In a spray dryer absorber (SDA), a slurry of slaked lime is sprayed into the gas stream where the 

lime reacts with SO2 to form solid sulfates. Unreacted lime and sulfate solids together with coal fly ash 

are then collected in the particulate APCD. System performance is limited by the capacity and type of 

particulate control equipment which is either an electrostatic precipitator or a fabric filter baghouse. In 

the SDA technique, adequate water is added to the lime to allow it to be sprayed into the hot exhaust, but 

the amount of water is limited to that which will totally evaporate into the gas stream. In a wet FGD 

system, a solution of limestone in water is intimately placed in contact with the SO2 laden exhaust and 

reactions occur in the liquid phase as opposed to the gas. Wet FGD systems are typically located after the 

particulate APCE. 

Corette at 162 MW in gross power output is in the range of the applicability of the calculation 

techniques which apply to utility boilers greater than 25 MW in gross power output. The three S&L 

appendices are included as Attachment A to this report in which the capital cost model breaks the costing 

analysis into several parts that sum to provide the total capital and engineering cost of an installation. 

These include the absorber island, the reagent preparation equipment, waste handling equipment, and the 

balance of the plant that includes ducting, fans, instrumentation, etc. 

2.3 Other Technologies

PPL Montana investigated the NeuStream-S wet scrubber that the Colorado Martin Drake 

#7 plant that is planning to implement for SO2 control in 2012. This technology is not 

commercially available at this time and any performance/costs estimates that are published are 

specifically related to a pilot study conducted at Martin Drake #7. Full scale, commercial 

numbers on performance and cost will not be available until after 2012. 
6 

3.0 APPENDICES TO THE IPM COST APPROACH 

The IPM costing approach to SO2 control includes more detailed analytical tools for cost 

determinations than is provided in the summary document. The three appendices provided as 

Attachments B to this revised costing study apply to 1) Dry Sorbent Injection, 2) Spray Dryer FGD 

control, and 3) Wet FGD control. These background studies were used by the EPA Clean Air Market 

Division for analysis of policy scenarios. Each of these three control technology descriptions will be 

discussed briefly and the methodology applied to the 162 MW Corette Powder River Basin (PRB) coalfired steam generating unit. 

Each document provides a concise summary of the approach to the cost development analysis, the 

empirical equations used in the approach, and an example of the application of the technique to a real 

case. All cost estimates are provided in 2009 dollars. To estimate the several engineering and 

construction contractor costs involved in the installation of retrofit controls, factors of the capital 

equipment cost are employed in such estimations just as EPA has historically done in the CCM. 

Each S&L report is based on an approach tailored to the particular system and knowledge of the 

cost of installations in the S&L proprietary data base. Each analysis included a “retrofit factor” which is 

assumed in each case to be 1.0 to indicate an “average” difficulty of retrofit. Estimation of this factor 

appears to be a matter of judgement and comments are provided that indicates that large increases in costs 

can occur with particularly difficult sites. Corette is a very congested site with very little physical space 

for the installation of controls. PPL Montana assumes that a retrofit factor of 2.0 may reflect the 

additional costs associated with controls installation at the very space limited Corette facility and site 

specific conditions justify setting this factor at 2.0 (or higher) to account for balance of plant effects of 

the application of these SO2 control technologies. Specifically, this site is constrained by a river to the 

east, a railroad to the west, and a small plant footprint. These factors complicate engineering, construction 

and tie-in of retrofit controls and significantly increase cost. 

An important fact in the application of either dry sorbent injection or spray dryer absorption at 

Corette is that particulate loading to the ESP and emissions from that control device will increase if either 

SO2 control option is installed. This will likely require an upgrade to the particulate control device to 

accompany one of those control options. In the January 2011 report “Potential Impacts of Environmental 

Regulation on the U.S. Generation Fleet” (Reference 4) the estimated retrofit cost for a pulse-jet fabric 

filter is estimated to be on the order of $379/kW in 2008 dollars. Such an upgrade to the particulate 

control equipment significantly increases the $/ton estimates of cost effectiveness for each of these 

possible SO2 control options. Although such unintended consequences of secondary pollutant generation 

and the necessity of particulate control equipment upgrades were not considered in application of the IPM 
7 

model cost analyses by Sargent & Lundy , LLC for these SO2 control options, they are incorporated into 

these cost estimates using the referenced cost data. 

3.1 The Effect of Coal Sulfur Content

In application of the costing techniques to the Corette PRB coal-fired boiler, it is important to 

note that PPL Montana already has lowered SO2 emissions due to the burning of 0.3 wt percent Powder 

River Basin (PRB) coal. The plant has a long term contract for the 0.3% S fuel, however, the allowable 

sulfur in the operating permit for Corette is 2 lbs/MMBtu SO2 (1% as S). Therefore, any SO2 controls 

would need to accommodate the allowable sulfur content in coal in the design of equipment. This has the 

effect of increasing the capital cost of the SO2 controls and making them less cost effective in actual 

operation. 

3.2 Dry Sorbent Injection

In the dry sorbent injection technique (Attachment A-1), a milled powdered dry sorbent is 

injected into the ducting downstream of the air preheater but prior to the particulate control device. Trona 

is the dry sorbent of choice and up to a 70% control efficiency for SO2 can be attained if a fabric filter is 

used for particulate control. However, at lower inlet SO2 loadings this efficiency is reduced and for 

purposes of this evaluation, we have estimated that an outlet emission rate of 0.26 lbs SO2/MMBtu can be 

achieved. This is consistent with recent emission rates that have been used in the industry. Baghouses 

have higher removal efficiencies due to the fact that a significant additional absorption in the fabric filter 

cake occurs. With electrostatic precipitators like Corette, the S&L model development document seems 

to indicate that a maximum of 40 to 50% SO2 removal can be realized without an increase in particulate 

emissions. However, for purposes of this evaluation, because controlling the additional particulate will 

likely require particulate control equipment upgrades, the cost of these upgrades is included in the cost 

effectiveness calculations, significantly increasing the cost to apply these technologies at Corette. 

The S&L dry sorbent injection cost evaluations used trona which is a mixture of sodium 

carbonate and sodium bicarbonate. This is the dry sorbent of choice where greater than 50% control of 

SO2 is necessary. Trona is the most economic sorbent for Corette to use in the dry injection technique 

due to its local availability. The IPM costing study did not include dry sorbent injection costing in the 

options for the EPA planning evaluations. Facilities that used some type of dry sorbent injection were 

treated as uncontrolled sources because dry sorbent injection was assumed to have a removal efficiency of 

less than fifty percent. Nevertheless, for purposes of this study, the cost of dry injection technology has 

been included. 

Dry sorbent injection technology costing is highly dependent on the inlet SO2 concentration. 

Therefore, the empirical equations from S&L show that the capital costs are directly related to the trona 
8 

injection rate. This technology option in particular must be oversized to accommodate potential inlet SO2

concentrations up to the allowable limit of 2 lbs/MMBtu applicable to the Corette boiler. 

3.3 Spray Dryer Absorption

The lime spray dryer absorber (SDA) technology option (Attachment A-2) is a semi-dry 

technology and the IPM costing techniques developed by S&L are based on numerous installed systems. 

The equipment needed to apply this control method includes a spray chamber, a lime/water mixing 

module, and waste handling equipment. While the costing analysis is based on 2 lbs/MMBtu SO2, as in 

the case of dry injection, the operation of a system sized for 2 lbs/MMBtu SO2 will be less cost effective 

when operated at the actual 30-day rolling average or even the maximum 24-hr SO2 emission rate. 

Numerous applications of SDA technology to PRB coal are in operation. It has shown the ability 

to reduce SO2 emissions to 0.13 lbs/MMBtu with PRB coal. S&L cautions that this control option is only 

effective up to a 3 lbs/MMBtu uncontrolled SO2 exhaust. As in the case of dry sorbent injection, 

particulate control using fabric filtration allows higher absorption of SO2 by the effect of the filter cake on 

the absorption. Application of this technology will affect the plume buoyancy and require additional 

costs for reheat (see the discussion in Section 3.4). This is because in a SDA, a water slurry containing 

lime is sprayed into the gas stream, reducing plume temperature. The water injected partially saturates the 

exhaust, but only to within 50 degrees of the saturation temperature. The cost for plume reheating has 

been added to the costing analysis. 

3.4 Wet Flue Gas Desulfurization (FGD)

The particular control technique included in the IPM study (Attachment A-3) is the limestone 

forced oxidation wet scrubbing (LSFO) technique. This technology was discussed by Srivastava 

(Reference 2) in his paper from 2001 that led to development of the cost estimation techniques in the EPA 

Fact Sheet used in the previous cost analyses by PPL. The cost analysis development for the IPM by 

S&L uses industry cost estimates not available until after the Srivastava studies that only produced the 

very broad ranges of costs. 

Local SO2 control requirements set plume buoyancy standards for the Corette Plant. Wet FGD 

will reduce plume buoyancy, necessitating a significant amount of reheat. In addition, there is very 

limited space at the facility to accommodate liquid impoundments and other related equipment for a wet 

FGD system including the installation of a new exhaust gas stack. Added retrofit costs to address plume 

buoyancy and the space required will significantly increase the cost of this technology making it 

infeasible for the Corette Plant. 

The cost assessment has been based on a LSFO outlet SO2 emission rate of 0.06 lbs/MMBtu. 
9 

4.0 COSTING ANALYSIS TABLES

Table 4-1 summarizes the equations used to calculate the control costs for each control technique 

as developed by S&L for the IPM. The cost development for each control technology is described by 5 

spreadsheets labeled “a” through “e”. The first three are the application of the S&L cost equations 

specific for each technology Each worksheet is designed to be representative of the sample calculation 

sheets in the S&L cost descriptions, also provided in Attachments A-1, A-2, and A-3. The important 

empirical equations developed to represent the several portions of control technology costs are listed on a 

separate page and the first three costing analysis sheets make reference to this description of the 

equations. 

The first sheet “a” is presented to develop the base equipment cost for each control option based 

on 2.0 lbs/MMBtu SO2. Although Corette uses 0.3% S PRB coal, the allowable sulfur content is 1% and 

therefore any SO2 controls must be applicable if the 0.3% S PRB coal supply were to be changed to a 

higher sulfur coal, still consistent with the allowable coal sulfur content. This spreadsheet was used to 

develop the capital cost estimate of the basic control technology. 

The actual operation of the controls with lower inlet SO2 concentrations, i.e., sheets “b” and “c” 

will consume lower quantities of reagent and therefore were prepared determine cost effectiveness based 

on the 30-day rolling average SO2 concentration and the maximum 24-hr average SO2 inlet values of 0.46 

and 0.60 lbs/MMBtu respectively. 

Likewise, spreadsheets “d” and “e” present the control costs in dollars per ton for 0.46 and 0.60 

lbs/MMBtu SO2 inlet concentrations respectively. 

 
TABLE 4-1 EMPIRICAL EQUATIONS USED IN THE IPM MODEL CONTROL COSTING ANALYSES

The written descriptions below are presented to represent the S&L empirical equations used in 

their cost analysis methodology. The note numbers are found on worksheets in this section. 

DRY SORBENT INJECTION 

(Notes)

1 NSR or "K" = 0.353 x EXP(0.028 x H) {assumes ESP control and milled trona}

2 Trona feed rate or "M"= 1.2011 x 10-6 x K x A x C x D, {units are in tons/hour}

3 Sorbent waste rate or "N" = (0.7035 - 0.00073696 x H / K) x M {units are in tons/hour}

4 Fly ash waste rate or "P" = (A x C) x 0.06 ash in PRB coal x (1 - 0.2) / (2 x 8,400 Btu/lb)

5 Basic module cost = $7,516000 x B x (M)0.284

6 Auxiliary power to run equipment = M x 20 / A {percent of gross plant power}

SPRAY DRYER ABSORBER

(Notes)

1 Lime rate = (0.6702 x (D)2 + 13.42 x D) x A x C /10,000 / 2000 {units are in tons per hour} 

2 Waste rate = (0.8016 x (D)2

 + 31.1917 x D) x A x C /10,000/2000 {units are in tons per hour}

3 Water rate = (0.04898 x (D) 2

 +0.5925 x D + 55.11) x A X 1.05 x C/10,000/1000 {units are in 103 gals/hr}

4 Basic spray dryer equipment = $566,000 x A0.716 x B x (1.18)0.6 x (D/4)0.01 

5 Reagent prep equip cost = $300,000 x A0.716 x B x (D x G)0.2

6 Balance of SDA equipment = $799,000 x A0.716 x B x (F x G)0.6

7 Aux power to run equipment = (0.000547 x D2

 + 0.00649 x D + 1.3) x 1.18

WET FLUE GAS DESULFURIZATION

(Notes)

1 Limestone rate or "K" = 17.52 x A x D x G /2000 {units are in tons per hour}

2 Waste rate = limestone rate x 1.811 {units are in tons per hour}

3 Water rate = (1.674 x D + 74.68) x A x F x G / 1000 {units are in 103

 gals/hr)

4 Basic absorber cost = $550,000 x A0.716 x B x (F X G)0.6 x (D/2)0.02 

5 Reagent prep equip cost = $190,000 x A0.716 x (D x G)0.3

6 Basic waste handling cost = $100,000 x A0.716 x B x (D x G)0.45

7 Balance of plant cost = $1,010,000 x B x A0.716 x (F X G)0.4

8 Aux power to run equipment = 1.05e^(0.155 x D) x F x G

Page 10
Table 4-2a

DRY SORBENT INJECTION COSTING DEVELOPMENT

DESIGN CASE FOR CAPITAL COST

Variable Designation Units Value Equation/Input(1)

DRY INJECTION CAPITAL COST DESIGN BASIS FOR 2 LBS/MMBTU SO2

Unit Capacity (Gross) A (MW) 162 Input

Retrofit Factor B 2 Difficulty of Retrofit

Gross heat rate C Btu/KW‐hr 11,982 Input

SO2 Emiss Rate D lbs/MMBtu 2 Uncontrolled

Type of Coal E Input

Particulate Control F ESP Input

Trona Milling G Yes Input

Removal Target H 70

Heat input J MM Btu/hr 1941.1 A X C x 1000

NSR K 2.51 See Note DSI Note 1

Trona Feed rate M (tons/hr) 11.69 See Note DSI Note 2

Sorbent Waste Rate N (tons/hr) 7.98 See Note DSI Note 3

Fly Ash Waste Rate P (tons/hr) 5.55 See Note DSI Note 4

Aux Power Q (%) 1.44 See Note DSI Note 6

Trona Cost R ($/ton) 150

Waste Disposal Cost S ($/ton) 50

Aux Power Cost T ($/kWhr) 0.06

Operating Labor Rate U ($/hr) 60

Capital Cost BM ($) $30,215,380 Base DSI Module See note 5

Engineering, Construction Mgmt 5% $1,510,769

Construction Labor 5% $1,510,769

Contractor Profit and Fees 5% $1,510,769

Owners Cost 5% $1,737,384

Total Project Cost $36,485,071

225 $/kW

Fixed Operator Cost $124,800 2,080 hrs‐ one operator

Maintenance Material $302,154 1% of BM Capital Cost

Admin Labor Cost $7,370

Trona Cost $1,752.82 Trona cost in $/hr

Waste Disposal Cost $676.31 Total Waste Cost in $/hr

Notes:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐Dry Sorbent Injection Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

PRB

CAPITAL EQUIPMENT COSTS

OPERATING AND MAINTENANCE COSTS

Page 11
Table 4-2b

DRY SORBENT INJECTION COSTING DEVELOPMENT

30-DAY ROLLING AVERAGE OPERATIONAL PARAMETERS

Variable Designation Units Value Equation/Input(1)

DRY INJECTION OPERATING VARIABLES ‐ ACTUAL OPERATION AT 0.46 LBS/MMBTU SO2

Unit Capacity (Gross) A (MW) 162 Input

Retrofit Factor B 2 Difficulty of Retrofit

Gross heat rate C Btu/KW‐hr 11,982 Input

SO2 Emiss Rate D lbs/MMBtu 0.46 Uncontrolled

Type of Coal E Input

Particulate Control F ESP Input

Trona Milling G Yes Input

Removal Target H 53

Heat input J MM Btu/hr 1941.1 A X C x 1000

NSR K 1.56 See Note DSI Note 1

Trona Feed rate M (tons/hr) 1.67 See Note DSI Note 2

Sorbent Waste Rate N (tons/hr) 1.13 See Note DSI Note 3

Fly Ash Waste Rate P (tons/hr) 5.55 See Note DSI Note 4

Aux Power Q (%) 0.21 See Note DSI Note 6

Trona Cost R ($/ton) 150 Corrected to 2011 $

Waste Disposal Cost S ($/ton) 50

Aux Power Cost T ($/kWhr) 0.06

Operating Labor Rate U ($/hr) 60

Capital Cost BM ($) $17,387,979 Base DSI Module

Engineering, Construction Mgmt 5% $869,399

Construction Labor 5% $869,399

Contractor Profit and Fees 5% $869,399

Owners Cost 5% $999,809

Total Project Cost $20,995,984

130 $/kW

Fixed Operator Cost $124,800 2,080 hrs‐ one operator

Maintenance Material $173,880 1% of BM Capital Cost

Admin Labor Cost $5,831

Trona Cost $250.46 Trona cost in $/hr

Waste Disposal Cost $333.94 Total Waste Cost in $/hr

Notes:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐Dry Sorbent Injection Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

PRB

CAPITAL EQUIPMENT COSTS

OPERATING AND MAINTENANCE COSTS

Page 12
Table 4-2c

DRY SORBENT INJECTION COSTING DEVELOPMENT

MAX 24-HR SO2 OPERATIONAL PARAMETERS

Variable Designation Units Value Equation/Input(1)

DRY INJECTION OPERATING VARIABLES ‐ ACTUAL OPERATION AT 0.60 LBS/MMBTU SO2

Unit Capacity (Gross) A (MW) 162 Input

Retrofit Factor B 2 Difficulty of Retrofit

Gross heat rate C Btu/KW‐hr 11,982 Input

SO2 Emiss Rate D lbs/MMBtu 0.6 Uncontrolled

Type of Coal E Input

Particulate Control F ESP Input

Trona Milling G Yes Input

Removal Target H 57

Heat input J MM Btu/hr 1941.1 A X C x 1000

NSR K 1.74 See Note DSI Note 1

Trona Feed rate M (tons/hr) 2.44 See Note DSI Note 2

Sorbent Waste Rate N (tons/hr) 1.65 See Note DSI Note 3

Fly Ash Waste Rate P (tons/hr) 5.55 See Note DSI Note 4

Aux Power Q (%) 0.30 See Note DSI Note 6

Trona Cost R ($/ton) 150 Corrected to 2011 $

Waste Disposal Cost S ($/ton) 50

Aux Power Cost T ($/kWhr) 0.06

Operating Labor Rate U ($/hr) 60

Capital Cost BM ($) $19,356,858 Base DSI Module

Engineering, Construction Mgmt 5% $967,843

Construction Labor 5% $967,843

Contractor Profit and Fees 5% $967,843

Owners Cost 5% $1,113,019

Total Project Cost 5% $23,373,406

144 $/kW

Fixed Operator Cost $124,800 2,080 hrs‐ one operator

Maintenance Material $193,569 1% of BM Capital Cost

Admin Labor Cost $6,067

Trona Cost $365.41 Trona cost in $/hr

Waste Disposal Cost $360.05 Waste Cost in $/hr

Notes:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐Dry Sorbent Injection Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

PRB

CAPITAL EQUIPMENT COSTS

OPERATING AND MAINTENANCE COSTS

Page 13
Table 4-2d

PPL BART Cost Effectiveness Analysis

Dry Injection (With Low Sulfur Coal) Sulfur Dioxide Control

162 Megawatt Coal Fired Steam Electric Plant

Trona Injection With Precipitator Replacement at J.E. Corette

SO2 =0.46 lbs/MMBtu

Stack Exhaust Volumetric Flowrate, (acfm) Q 726,262

Maximum Gross Heat Input MM Btu/hr 1,941

Design Percent Load % 89

Uncontrolled SO2 Emissions (with low S coal) lbs/MMBtu 0.460

ExhaustTemperature, (o

F) T 405

Steam Turbine Power Output (TMW) MW 162

Capacity Factor (89%) hrs 7,796

Controlled SO2 Emissions lbs/MMBtu 0.26

Overall SO2 Reduction Efficiency, (%) % 43.48

Uncontrolled SO2 Emissions, (lb/hr) 892.9

Uncontrolled SO2 Emissions, (tons/yr) 3480.7

Controlled SO2 Emissions, (ton/yr) 1967.4

Annual Interest Rate, (%) 7

Equipment Life, (yrs) yr 15

Capital Recovery Factor, CRF CRF 0.1098

Unit Item

Cost Item Suggested Factor Cost Cost

IPM Model, August 20, 2010(1) Capital Cost ($/KW)(2) 225 $36,485,071

Cost for Pulse-Jet Fabric Filter Capital Cost ($/KW)(3) 379 $61,398,000

Equipment Cost Total, (EC) EC (Adjusted by Cost Index Calcs) (2011 dollars)(4) $101,615,582

 Total Capital Costs, TCC --- $101,615,582

 Direct Annual Costs, DAC Trona Cost $1,952,695

Total waste disposal Cost $2,603,502

Parasitic power cost $156,216

Lost Ash Revenue $11.74/ton $352,200

Maintenance Labor $130,631

Maintenance Materials $173,880

 Total Direct Annual Costs, DAC $5,369,123

Indirect Annual Costs

 Capital Recovery CRF*TCC --- $11,156,845

 Total Indirect Annual Costs, IAC $11,156,845

 Total Annual Costs, TAC = DAC + IAC $16,525,967

Cost Effectiveness ($/ton pollutant Removed) $10,920

 Cost data references:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐Dry Sorbent Injection Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

2) $/kW in 2009 dollars

3) $/kW in 2008 dollars (See Edison Electric Institute reference on page 26)

4) Cost indices used to adjust 2008 and 2009 costs to 2011 costs (2008, 2009 CI= 108.302, 109.594 2011 CI= 113.065)

Page 14
Table 4-2e

PPL BART Cost Effectiveness Analysis

Dry Injection (With Low Sulfur Coal) Sulfur Dioxide Control

162 Megawatt Coal Fired Steam Electric Plant

Trona Injection With Precipitator Replacement at J.E. Corette

SO2 =0.60 lbs/MMBtu

Stack Exhaust Volumetric Flowrate, (acfm) Q 726,262

Maximum Gross Heat Input MM Btu/hr 1,941

Design Percent Load % 89

Uncontrolled SO2 Emissions (with low S coal) lbs/MMBtu 0.600

ExhaustTemperature, (o

F) T 405

Steam Turbine Power Output (TMW) MW 162

Capacity Factor (89%) hrs 7,796

Controlled SO2 Emissions lbs/MMBtu 0.26

Overall SO2 Reduction Efficiency, (%) % 56.67

Uncontrolled SO2 Emissions, (lb/hr) 1164.7

Uncontrolled SO2 Emissions, (tons/yr) 4540.1

Controlled SO2 Emissions, (ton/yr) 1967.4

Annual Interest Rate, (%) 7

Equipment Life, (yrs) yr 15

Capital Recovery Factor, CRF CRF 0.1098

Unit Item

Cost Item Suggested Factor Cost Cost

IPM Model, August 20, 2010(1) Capital Cost ($/KW)(2) 225 $36,485,071

Cost for Pulse-Jet Fabric Filter Capital Cost ($/KW)(3) 379 $61,398,000

Equipment Cost Total, (EC) EC (Adjusted by Cost Index Calcs) (2011 dollars)(4) $101,615,582

 Total Capital Costs, TCC --- $101,615,582

 Direct Annual Costs, DAC Trona Cost $2,848,845

Total waste disposal Cost $2,807,072

Parasitic power cost $227,908

Lost Ash Revenue $11.74/ton $352,200

Maintenance Labor $130,867

Maintenance Materials $193,569

 Total Direct Annual Costs, DAC $6,560,460

Indirect Annual Costs

 Capital Recovery CRF*TCC --- $11,156,845

 Total Indirect Annual Costs, IAC $11,156,845

 Total Annual Costs, TAC = DAC + IAC $17,717,304

Cost Effectiveness ($/ton pollutant Removed) $6,887

 Cost data references:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐Dry Sorbent Injection Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

2) $/kW in 2009 dollars

3) $/kW in 2008 dollars (See Edison Electric Institute reference on page 26)

4) Cost indices used to adjust 2008 and 2009 costs to 2011 costs (2008, 2009 CI= 108.302, 109.594 2011 CI= 113.065)

Page 15
Table 4-3a

SPRAY DRYER ABSORBER COSTING DEVELOPMENT

DESIGN CASE FOR CAPITAL COSTS 

Variable Designation Units Value Equation/Input(1)

LIME SPRAY DRYER CAPITAL COST DESIGN BASIS FOR 2 LBS/MMBTU SO2

Unit Capacity (Gross) A (MW) 162 Input

Retrofit Factor B 2 Difficulty of Retrofit

Gross heat rate C Btu/KW‐hr 11,982 Input

SO2 Emiss Rate D lbs/MMBtu 2 Uncontrolled

Type of Coal E Input

Coal Factor F PRB Coal 1.05 Input

Heat Rate Factor G 1.20 C / 10000

Heat input H MM Btu/hr 1941.1 A X C x 1000

Lime Rate K (tons/hr) 2.87 See SDA Note 1

Waste Rate L (tons/hr) 6.37 See SDA Note 2

Aux Power M (%) 1.65 See SDA Note 7

Make Up Water N 103 gph 11.51 See SDA Note 3

Lime Cost P ($/ton) 135.00 Input

Waste Disposal Cost S ($/ton) 50 Input

Aux Power Cost R ($/kWhr) 0.06 Input

Makeup Water Cost S $/103 gal 1 Input

Operating Labor Rate T ($/hr) 60 Input

Basic Absorber BMR ($) $49,281,061 See SDA Note 4

Reagent Preparation BMF ($) $27,294,545 See SDA Note 5

ID Fan, Other Costs BMB ($) $66,907,834 See SDA Note 6

Capital Cost BM Sum ($) $143,483,440 Base LSD Module

Engineering, Construction Mgmt 10% $14,348,344

Construction Labor 10% $14,348,344

Contractor Fees 10% $14,348,344

CECC $186,528,472 Capital, Eng, and Const

Owners Cost B1 5% $9,326,424 Various home office fees

AFUDC 10% of (CECC+B1) $19,585,490

Total Project Cost $215,440,385

1,330 $/kW

Fixed Operator Cost $998,400 2,080 hrs‐ 8 operators

Maintenance Material $4,304,503 1.5% of BM Capital Cost

Admin Labor Cost $81,606

Lime Cost $386.79 Lime cost in $/hr

Waste Disposal Cost $318.29 Waste Cost in $/hr

Notes:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐SDA FDG Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

PRB

CAPITAL EQUIPMENT COSTS

OPERATING AND MAINTENANCE COSTS

Page 16
Table 4-3b

SPRAY DRYER COSTING DEVELOPMENT

30-DAY ROLLING AVERAGE SO2 OPERATING PARAMETERS

Variable Designation Units Value Equation/Input(1)

LIME SPRAY DRYER OPERATING VARIABLES ‐ ACTUAL OPERATION AT 0.46 LBS/MMBTU SO2

Unit Capacity (Gross) A (MW) 162 Input

Retrofit Factor B 2 Difficulty of Retrofit

Gross heat rate C Btu/KW‐hr 11,982 Input

SO2 Emiss Rate D lbs/MMBtu 0.46 Uncontrolled

Type of Coal E Input

Coal Factor F PRB Coal 1.05 Input

Heat Rate Factor G 1.20 C / 10000

Heat input H MM Btu/hr 1941.1 A X C x 1000

Lime Rate K (tons/hr) 0.61 See SDA Note 1

Waste Rate L (tons/hr) 1.41 See SDA Note 2

Aux Power M (%) 1.64 See SDA Note 7

Make Up Water N 103 gph 11.29 See SDA Note 3

Lime Cost P ($/ton) 135.00 Input

Waste Disposal Cost S ($/ton) 50 Input

Aux Power Cost R ($/kWhr) 0.06 Input

Makeup Water Cost S $/103 gal 1 Input

Operating Labor Rate T ($/hr) 60 Input

Basic Absorber BMR ($) $48,562,085 See SDA Note 4

Reagent Preparation BMF ($) $20,343,301 See SDA Note 5

ID Fan, Other Costs BMB ($) $66,907,834 See SDA Note 6

Capital Cost BM Sum ($) $135,813,220 Base LSD Module

Engineering, Construction Mgmt 10% $13,581,322

Construction Labor 10% $13,581,322

Contractor Fees 10% $13,581,322

CECC $176,557,186 Capital, Eng, and Const

Owners Cost B1 5% $8,827,859 Various home office fees

AFUDC 10% of (CECC+B1) $18,538,505

Total Project Cost $203,923,550

1,259 $/kW

Fixed Operator Cost $998,400 2,080 hrs‐ 8 operators

Maintenance Material $4,074,397 1.5% of BM Capital Cost

Admin Labor Cost $78,845

Lime Cost $82.74 Lime cost in $/hr

Waste Disposal Cost $70.45 Waste Cost in $/hr

Notes:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐SDA FDG Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

PRB

CAPITAL EQUIPMENT COSTS

OPERATING AND MAINTENANCE COSTS

Page 17
Table 4-3c

SPRAY DRYER ABSORBER COSTING DEVELOPMENT

MAXIMUM 24-HR AVERAGE SO2 OPERATING PARAMETERS

Variable Designation Units Value Equation/Input(1)

LIME SPRAY DRYER OPERATING VARIABLES ‐ ACTUAL OPERATION AT 0.60 LBS/MMBTU SO2

Unit Capacity (Gross) A (MW) 162 Input

Retrofit Factor B 2 Difficulty of Retrofit

Gross heat rate C Btu/KW‐hr 11,982 Input

SO2 Emiss Rate D lbs/MMBtu 0.6 Uncontrolled

Type of Coal E Input

Coal Factor F PRB Coal 1.05 Input

Heat Rate Factor G 1.20 C / 10000

Heat input H MM Btu/hr 1941.1 A X C x 1000

Lime Rate K (tons/hr) 0.80 See SDA Note 1

Waste Rate L (tons/hr) 1.84 See SDA Note 2

Aux Power M (%) 1.64 See SDA Note 7

Make Up Water N 103 gph 11.31 See SDA Note 3

Lime Cost P ($/ton) 135.00 Input

Waste Disposal Cost S ($/ton) 50 Input

Aux Power Cost R ($/kWhr) 0.06 Input

Makeup Water Cost S $/103 gal 1 Input

Operating Labor Rate T ($/hr) 60 Input

Basic Absorber BMR ($) $48,691,288 See SDA Note 4

Reagent Preparation BMF ($) $21,453,597 See SDA Note 5

ID Fan, Other Costs BMB ($) $66,907,834 See SDA Note 6

Capital Cost BM Sum ($) $137,052,718 Base LSD Module

Engineering, Construction Mgmt 10% $13,705,272

Construction Labor 10% $13,705,272

Contractor Fees 10% $13,705,272

CECC $178,168,534 Capital, Eng, and Const

Owners Cost B1 5% $8,908,427 Various home office fees

AFUDC 10% of (CECC+B1) $18,707,696

Total Project Cost $205,784,657

1,270 $/kW

Fixed Operator Cost $998,400 2,080 hrs‐ 8 operators

Maintenance Material $4,111,582 1.5% of BM Capital Cost

Admin Labor Cost $79,291

Lime Cost $108.66 Lime cost in $/hr

Waste Disposal Cost $92.22 Waste Cost in $/hr

Notes:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐SDA FDG Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

PRB

CAPITAL EQUIPMENT COSTS

OPERATING AND MAINTENANCE COSTS

Page 18
Table 4-3d

PPL BART Cost Effectiveness Analysis

Lime Spray Drying (With Low Sulfur Coal) Sulfur Dioxide Control

162 Megawatt Coal Fired Steam Electric Plant

Lime Spray Drying With Precipitator Replacement at J.E. Corette

SO2 =0.46 lbs/MMBtu

Stack Exhaust Volumetric Flowrate, (acfm) Q 726,262

Maximum Gross Heat Input MM Btu/hr 1,941

Design Percent Load % 89

Uncontrolled SO2 Emissions (with low S coal) lbs/MMBtu 0.460

ExhaustTemperature, (o

F) T 405

Steam Turbine Power Output (TMW) MW 162

Capacity Factor (89%) hrs 7,796

Controlled SO2 Emissions lbs/MMBtu 0.13

Overall SO2 Reduction Efficiency, (%) % 71.74

Uncontrolled SO2 Emissions, (lb/hr) 892.9

Uncontrolled SO2 Emissions, (tons/yr) 3480.7

Controlled SO2 Emissions, (ton/yr) 983.7

Annual Interest Rate, (%) 7

Equipment Life, (yrs) yr 15

Capital Recovery Factor, CRF CRF 0.1098

Unit Item

Cost Item Suggested Factor Cost Cost

IPM Model, August 20, 2010(1) Capital Cost ($/KW)(2) 1,330 $215,440,385

Cost for Pulse-Jet Fabric Filter Capital Cost ($/KW)(3) 379 $61,398,000

Equipment Cost Total, (EC) EC (Adjusted by Cost Index Calcs) (2011 dollars)(4) $285,634,195

 Total Capital Costs, TCC --- $285,634,195

 Direct Annual Costs, DAC Lime $645,084

Total waste disposal Cost $549,262

Parasitic power cost $1,242,388

Lost Ash Revenue $11.74/ton $352,200

Stack Reheat Penalty reheat to 300o

F $7,740,315

Maintenance labor $1,077,245

Maintenance materials $4,074,397

 Total Direct Annual Costs, DAC $15,680,890

Indirect Annual Costs

 Capital Recovery CRF*TCC --- $31,361,099

 Total Indirect Annual Costs, IAC $31,361,099

 Total Annual Costs, TAC = DAC + IAC $47,041,990

Cost Effectiveness ($/ton pollutant Removed) $18,839

 Cost data references:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐Dry Sorbent Injection Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

2) $/kW in 2009 dollars

3) $/kW in 2008 dollars (See Edison Electric Institute reference on page 26)

4) Cost indices used to adjust 2008 and 2009 costs to 2011 costs (2008, 2009 CI= 108.302, 109.594 2011 CI= 113.065)

Page 19
Table 4-3e

PPL BART Cost Analysis

Lime Spray Drying (With Low Sulfur Coal) Sulfur Dioxide Control

162 Megawatt Coal Fired Steam Electric Plant

Lime Spray Drying With Precipitator Replacement at J.E. Corette

SO2 =0.60 lbs/MMBtu

Stack Exhaust Volumetric Flowrate, (acfm) Q 726,262

Maximum Gross Heat Input MM Btu/hr 1,941

Design Percent Load % 89

Uncontrolled SO2 Emissions (with low S coal) lbs/MMBtu 0.600

ExhaustTemperature, (o

F) T 405

Steam Turbine Power Output (TMW) MW 162

Capacity Factor (89%) hrs 7,796

Controlled SO2 Emissions lbs/MMBtu 0.13

Overall SO2 Reduction Efficiency, (%) % 78.33

Uncontrolled SO2 Emissions, (lb/hr) 1164.7

Uncontrolled SO2 Emissions, (tons/yr) 4540.1

Controlled SO2 Emissions, (ton/yr) 983.7

Annual Interest Rate, (%) 7

Equipment Life, (yrs) yr 15

Capital Recovery Factor, CRF CRF 0.1098

Unit Item

Cost Item Suggested Factor Cost Cost

IPM Model, August 20, 2010(1) Capital Cost ($/KW)(2) 1,330 $215,440,385

Cost for Pulse-Jet Fabric Filter Capital Cost ($/KW)(3) 379 $61,398,000

Equipment Cost Total, (EC) EC (Adjusted by Cost Index Calcs) (2011 dollars)(4) $285,634,195

 Total Capital Costs, TCC --- $285,634,195

 Direct Annual Costs, DAC Lime $847,165

Total waste disposal Cost $718,976

Parasitic power cost $1,243,331

Lost Ash Revenue $11.74/ton $352,200

Stack Reheat Penalty reheat to 300o

F $7,740,315

Maintenance labor $1,077,691

Maintenance materials $4,111,582

 Total Direct Annual Costs, DAC $16,091,260

Indirect Annual Costs

 Capital Recovery CRF*TCC --- $31,361,099

 Total Indirect Annual Costs, IAC $31,361,099

 Total Annual Costs, TAC = DAC + IAC $47,452,359

Cost Effectiveness ($/ton pollutant Removed) $13,343

 Cost data references:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐Dry Sorbent Injection Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

2) $/kW in 2009 dollars

3) $/kW in 2008 dollars (See Edison Electric Institute reference on page 26)

4) Cost indices used to adjust 2008 and 2009 costs to 2011 costs (2008, 2009 CI= 108.302, 109.594 2011 CI= 113.065)

Page 20
Table 4-4a

WET FGD COSTING DEVELOPMENT

DESIGN BASIS FOR CAPITAL COST

Variable Designation Units Value Equation/Input(1)

WET FGD CAPITAL COST DESIGN BASIS FOR 2 LBS/MMBTU SO2

Unit Capacity (Gross) A (MW) 162 Input

Retrofit Factor B 2 Difficulty of Retrofit

Gross heat rate C Btu/KW‐hr 11,982 Input

SO2 Emiss Rate D lbs/MMBtu 2 Uncontrolled

Type of Coal E Input

Coal Factor F PRB Coal 1.05 Input

Heat Rate Factor G 1.20 C / 10000

Heat input H MM Btu/hr 1941.1 A X C x 1000

Limestone Rate K (tons/hr) 3.40 See FGD Note 1

Waste Rate L (tons/hr) 6.16 See FGD Note 2

Aux Power M (%) 1.80 See FGD Note 8

Make Up Water N 103 gph 15.90 See FGD Note 3

Limestone Cost P ($/ton) 15.00

Waste Disposal Cost S ($/ton) 50

Aux Power Cost R ($/kWhr) 0.06

Makeup Water Cost S $/103 gal 1

Operating Labor Rate T ($/hr) 60

Basic Absorber BMR ($) $48,221,043 See FGD Note 4

Reagent Preparation BMF ($) $18,865,318 See FGD Note 5

Waste Handling Cost BMW ($) $11,319,948 See FGD Note 6

ID Fan, Other Costs BMB ($) $84,576,862 See FGD Note 7

Capital Cost BM Sum ($) $162,983,172 Base Wet FGD Module

Engineering, Construction Mgmt 10% $16,298,317

Construction Labor 10% $16,298,317

Contractor Fees 10% $16,298,317

CECC $211,878,123 Capital, Eng, and Const

Owners Cost B1 5% $10,593,906 Various home office fees

AFUDC 10% of (CECC+B1) $22,247,203

Total Project Cost $244,719,232

1,511 $/kW

Fixed Operator Cost FOMO $1,497,600 2,080 hrs‐ 12 operators

Maintenance Material $4,889,495 1.5% of BM Capital Cost

Admin Labor Cost $103,602

Auxiliary Power $175.07 $/hr

Water Cost $15.90 $/hr

Limestone Cost $323.07 Limestone cost in $/hr

Waste Disposal Cost $307.94 Waste Cost in $/hr

Notes:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐Wet FGD Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

PRB

CAPITAL EQUIPMENT COSTS

OPERATING AND MAINTENANCE COSTS

Page 21
Table 4-4b

WET FGD COSTING DEVELOPMENT

30-DAY ROLLING AVERAGE SO2 OPERATING PARAMETERS

Variable Designation Units Value Equation/Input(1)

WET FGD OPERATING VARIABLES ‐ ACTUAL OPERATION AT 0.46 LBS/MMBTU SO2

Unit Capacity (Gross) A (MW) 162 Input

Retrofit Factor B 2 Difficulty of Retrofit

Gross heat rate C Btu/KW‐hr 11,982 Input

SO2 Emiss Rate D lbs/MMBtu 0.46 Uncontrolled

Type of Coal E Input

Coal Factor F PRB Coal 1.05 Input

Heat Rate Factor G 1.20 C / 10000

Heat input H MM Btu/hr 1941.1 A X C x 1000

Limestone Rate K (tons/hr) 0.78 See FGD Note 1

Waste Rate L (tons/hr) 1.42 See FGD Note 2

Aux Power M (%) 1.42 See FGD Note 8

Make Up Water N 103 gph 15.38 See FGD Note 3

Limestone Cost P ($/ton) 15.00

Waste Disposal Cost S ($/ton) 50

Aux Power Cost R ($/kWhr) 0.06

Makeup Water Cost S $/103 gal 1

Operating Labor Rate T ($/hr) 60

Basic Absorber BMR ($) $46,824,286 See FGD Note 4

Reagent Preparation BMF ($) $12,138,988 See FGD Note 5

Waste Handling Cost BMW ($) $5,842,813 See FGD Note 6

ID Fan, Other Costs BMB ($) $84,576,862 See FGD Note 7

Capital Cost BM Sum ($) $149,382,948 Base Wet FGD Module

Engineering, Construction Mgmt 10% $14,938,295

Construction Labor 10% $14,938,295

Contractor Fees 10% $14,938,295

CECC $194,197,833 Capital, Eng, and Const

Owners Cost B1 5% $9,709,892 Various home office fees

AFUDC 10% of (CECC+B1) $20,390,772

Total Project Cost $224,298,497

1,385 $/kW

Fixed Operator Cost FOMO $1,497,600 2,080 hrs‐ 12 operators

Maintenance Material $4,481,488 1.5% of BM Capital Cost

Admin Labor Cost $98,706

Auxiliary Power $137.89 $/hr

Water Cost $15.38 $/hr

Limestone Cost $74.31 Limestone cost in $/hr

Waste Disposal Cost $70.83 Waste Cost in $/hr

Notes:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐Wet FGD Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

PRB

CAPITAL EQUIPMENT COSTS

OPERATING AND MAINTENANCE COSTS

Page 22
Table 4-4c

WET FGD COSTING DEVELOPMENT

MAXIMUM 24-HR AVERAGE SO2 OPERATING PARAMETERS

Variable Designation Units Value Equation/Input(1)

WET FGD OPERATING VARIABLES ‐ ACTUAL OPERATION AT 0.60 LBS/MMBTU SO2

Unit Capacity (Gross) A (MW) 162 Input

Retrofit Factor B 2 Difficulty of Retrofit

Gross heat rate C Btu/KW‐hr 11,982 Input

SO2 Emiss Rate D lbs/MMBtu 0.6 Uncontrolled

Type of Coal E Input

Coal Factor F PRB Coal 1.05 Input

Heat Rate Factor G 1.20 C / 10000

Heat input H MM Btu/hr 1941.1 A X C x 1000

Limestone Rate K (tons/hr) 1.02 See FGD Note 1

Waste Rate L (tons/hr) 1.85 See FGD Note 2

Aux Power M (%) 1.45 See FGD Note 8

Make Up Water N 103 gph 15.43 See FGD Note 3

Limestone Cost P ($/ton) 15.00

Waste Disposal Cost S ($/ton) 50

Aux Power Cost R ($/kWhr) 0.06

Makeup Water Cost S $/103 gal 1

Operating Labor Rate T ($/hr) 60

Basic Absorber BMR ($) $47,073,775 See FGD Note 4

Reagent Preparation BMF ($) $13,146,209 See FGD Note 5

Waste Handling Cost BMW ($) $6,584,897 See FGD Note 6

ID Fan, Other Costs BMB ($) $84,576,862 See FGD Note 7

Capital Cost BM Sum ($) $151,381,743 Base Wet FGD Module

Engineering, Construction Mgmt 10% $15,138,174

Construction Labor 10% $15,138,174

Contractor Fees 10% $15,138,174

CECC $196,796,265 Capital, Eng, and Const

Owners Cost B1 5% $9,839,813 Various home office fees

AFUDC 10% of (CECC+B1) $20,663,608

Total Project Cost $227,299,686

1,403 $/kW

Fixed Operator Cost FOMO $1,497,600 2,080 hrs‐ 12 operators

Maintenance Material $4,541,452 1.5% of BM Capital Cost

Admin Labor Cost $99,425

Auxiliary Power $140.92 $/hr

Water Cost $15.43 $/hr

Limestone Cost $96.92 Limestone cost in $/hr

Waste Disposal Cost $92.38 Waste Cost in $/hr

Notes:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐Wet FGD Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

PRB

CAPITAL EQUIPMENT COSTS

OPERATING AND MAINTENANCE COSTS

Page 23
Table 4-4d

PPL BART Cost Analysis

Wet FGD (With Low Sulfur Coal) Sulfur Dioxide Control

162 Megawatt Coal Fired Steam Electric Plant

Wet FGD at J.E. Corette

SO2 =0.46 lbs/MMBtu

Stack Exhaust Volumetric Flowrate, (acfm) Q 726,262

Maximum Gross Heat Input MM Btu/hr 1,941

Design Percent Load % 89

Uncontrolled SO2 Emissions (with low S coal) lbs/MMBtu 0.460

ExhaustTemperature, (o

F) T 405

Steam Turbine Power Output (TMW) MW 162

Capacity Factor (89%) hrs 7,796

Controlled SO2 Emissions lbs/MMBtu 0.06

Overall SO2 Reduction Efficiency, (%) % 86.96

Uncontrolled SO2 Emissions, (lb/hr) 892.9

Uncontrolled SO2 Emissions, (tons/yr) 3480.7

Controlled SO2 Emissions, (ton/yr) 454.0

Annual Interest Rate, (%) 7

Equipment Life, (yrs) yr 15

Capital Recovery Factor, CRF CRF 0.1098

Unit Item

Cost Item Suggested Factor Cost Cost

IPM Model, August 20, 2010(1) Capital Cost ($/KW)(2) 1,511 $244,719,232

Equipment Cost Total, (EC) EC (Adjusted by Cost Index Calcs) (2011 dollars)(3) $252,469,843

 Total Capital Costs, TCC --- $252,469,843

 Direct Annual Costs, DAC Limestone Cost $579,327

Waste disposal Cost $552,190

Parasitic power cost $1,075,062

Lost Ash Revenue $11.74/ton $352,200

Stack Reheat Penalty reheat to 300o

F $10,965,447

Operator and Admin Labor $1,596,306

Maintenance Materials $4,481,488

 Total Direct Annual Costs, DAC $19,602,020

Indirect Annual Costs

 Capital Recovery CRF*TCC --- $27,719,832

 Total Indirect Annual Costs, IAC $27,719,832

 Total Annual Costs, TAC = DAC + IAC $47,321,852

Cost Effectiveness ($/ton pollutant Removed) $15,635

 Cost data references:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐Wet FGD Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

2) $/kW in 2009 dollars

3) Cost indices used to adjust 2009 costs to 2011 costs (2009 CI= 109.954, 2011 CI= 113.065)

Page 24
Table 4-4e

PPL BART Cost Analysis

Wet FGD (With Low Sulfur Coal) Sulfur Dioxide Control

162 Megawatt Coal Fired Steam Electric Plant

Wet FGD at J.E. Corette

SO2 =0.60 lbs/MMBtu

Stack Exhaust Volumetric Flowrate, (acfm) Q 726,262

Maximum Gross Heat Input MM Btu/hr 1,941

Design Percent Load % 89

Uncontrolled SO2 Emissions (with low S coal) lbs/MMBtu 0.600

ExhaustTemperature, (o

F) T 405

Steam Turbine Power Output (TMW) MW 162

Capacity Factor (89%) hrs 7,796

Controlled SO2 Emissions lbs/MMBtu 0.06

Overall SO2 Reduction Efficiency, (%) % 90.00

Uncontrolled SO2 Emissions, (lb/hr) 1164.7

Uncontrolled SO2 Emissions, (tons/yr) 4540.1

Controlled SO2 Emissions, (ton/yr) 454.0

Annual Interest Rate, (%) 7

Equipment Life, (yrs) yr 15

Capital Recovery Factor, CRF CRF 0.1098

Unit Item

Cost Item Suggested Factor Cost Cost

IPM Model, August 20, 2010(1) Capital Cost ($/KW)(2) 1,511 $244,719,232

Equipment Cost Total, (EC) EC (Adjusted by Cost Index Calcs) (2011 dollars)(3) $252,469,843

 Total Capital Costs, TCC --- $252,469,843

 Direct Annual Costs, DAC Limestone Cost $755,644

Waste disposal Cost $720,248

Parasitic power cost $1,098,646

Lost Ash Revenue $11.74/ton $352,200

Stack Reheat Penalty reheat to 300o

F $10,965,447

Operator and Admin Labor $1,596,306

Maintenance Materials $4,541,452

 Total Direct Annual Costs, DAC $20,029,943

Indirect Annual Costs

 Capital Recovery CRF*TCC --- $27,719,832

 Total Indirect Annual Costs, IAC $27,719,832

 Total Annual Costs, TAC = DAC + IAC $47,749,775

Cost Effectiveness ($/ton pollutant Removed) $11,686

 Cost data references:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐Wet FGD Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

2) $/kW in 2009 dollars

3) Cost indices used to adjust 2009 costs to 2011 costs (2009 CI= 109.954, 2011 CI= 113.065)

Page 25
26 

5.0 REFERENCES

1) Documentation for EPA EPA Base Case v.4.10 Using the Integrated Planning Model (see URL). 

2) Srivastava, Ravi K., SO2 Scrubbing Technologies – A Review, Environmental Progress, 

December 2001 

3) EPA, Air Pollution Control Technology Fact Sheet, US EPA, EPA-452/F-03-034Final Report, 

Steven, Fine, et.al, January 2011, Page 33, Table of Retrofit Cost and Performance. 

4) Edison Electric Institute (EEI), Potential Impacts of Environmental Regulations on the U.S. 

Generation Fleet, ICF International, January 2011, pg. 33. 

5) EPA Control Cost Manual, 6th ed., EPA-452-02-001 
ATTACHMENT A-1 

DRY SORBENT INJECTION COST METHODOLOGY 

DEVELOPMENT – SARGENT & LUNDY, LLC, 

AUGUST 2010 
ATTACHMENT A-2 

SDA FDG COST DEVELOPMENT METHODOLOGY – 

SARGENT & LUNDY, LLC, AUGUST 2010 
 

IPM Model – Revisions to Cost and Performance for APC Technologies

SDA FGD Cost Development Methodology

FINAL

August 2010 

Project 12301-007 

Perrin Quarles Associates, Inc. 

Prepared by

55 East Monroe Street • Chicago, IL 60603 USA • 312-269-2000 
 

IPM Model – Revisions to Cost and Performance for APC Technologies

Wet FGD Cost Development Methodology

FINAL

August 2010

Project 12301-007 

Perrin Quarles Associates, Inc.

Prepared by

55 East Monroe Street • Chicago, IL 60603 USA • 312-269-2000
 

LEGAL NOTICE 

This analysis ("Deliverable") was prepared by Sargent & Lundy, L.L.C. ("S&L"), expressly for the sole use 

of Perrin Quarles Associates, Inc. ("Client") in accordance with the agreement between S&L and Client. 

This Deliverable was prepared using the degree of skill and care ordinarily exercised by engineers 

practicing under similar circumstances. Client acknowledges: (1) S&L prepared this Deliverable subject to 

the particular scope limitations, budgetary and time constraints, and business objectives of the Client; (2) 

information and data provided by others may not have been independently verified by S&L; and (3) the 

information and data contained in this Deliverable are time sensitive and changes in the data, applicable 

codes, standards, and acceptable engineering practices may invalidate the findings of this Deliverable. Any 

use or reliance upon this Deliverable by third parties shall be at their sole risk. 

This work was funded and reviewed by the U.S. Environmental Protection Agency under the supervision of 

William A. Stevens, Senior Advisor – Power Technologies. Additional input and review was provided by 

Dr. Jim Staudt, President of Andover Technology Partners. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

Wet FGD Cost Development Methodology – Final 

Page 1 

Establishment of Cost Basis 

The 2004 to 2006 industry cost estimates for wet FGD units from the "Analysis of MOG and 

Ladco's FGD and SCR Capacity and Cost Assumptions in the Evaluation of Proposed EGU 1 

and EGU 2 Emission Controls" prepared for Midwest Ozone Group (MOG) were compared to 

the Sargent & Lundy LLC (S&L) in-house database. Agreement of the data was confirmed 

between the industry estimates and the S&L data. 

The MOG and S&L cost data from 2004 to 2006 were converted to 2007 dollars based on the 

Chemical Engineering Plant Index (CEPI) data. Additional proprietary S&L in-house data from 

2007 were included to confirm the index validity. 

Cost data from the various sources showed similar trends versus generating capacity. Escalation 

based on the CEPI was deemed acceptable. All three data sources were combined so as to 

provide a representative wet FGD cost basis. 

The 2004 through 2007 data were escalated to 2009 to represent market conditions. 

The least squares curve fit of the data was defined as a "typical" wet FGD retrofit for removal of 

98% of the inlet sulfur. It should be noted that the lowest available SO2 emission guarantees, 

from the original equipment manufactures of wet FGD systems, are 0.04 lb/MMBtu. The typical 

wet FGD retrofit was based on: 

• Retrofit Difficulty =1 (Average retrofit difficulty) ; 

• Gross Heat Rate = 9500 Btu/kWh; 

• SO2 Rate = 3.0 lb/MMBtu; 

• Type of Coal = Bituminous; 

• Project Execution = Multiple lump sum contracts; and 

• Recommended SO2 emission floor = 98% removal efficiency or 0.06 lb/MMBtu. 

Units below 100 MW will typically not install a wet FGD system. Sulfur reductions for the 

small units would be accomplished by; treating smaller units at a single site with one wet FGD 

system, switching to a lower sulfur coal, repowering with natural gas, dry sorbent injection, 

and/or a reduction in operating hours. Capital costs of approximately $750/kW may be used for 

units below 100 MW under the premise that these will be combined. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

Wet FGD Cost Development Methodology – Final 

Page 2 

Methodology 

Inputs 

Several input variables are required in order to predict future retrofit costs. The gross unit size in 

MW (equivalent acfm) and sulfur content of the fuel are the major variables for the capital 

estimation. A retrofit factor that equates to difficulty in construction of the system must be 

defined. The costs herein could increase significantly for congested sites. The gross unit heat 

rate will factor into the amount of flue gas generated and ultimately the size of the absorber, 

reagent preparation, waste handling, and balance of plant costs. The SO2 rate will have the 

greatest influence on the reagent handling and waste handling facilities. The type of fuel 

(Bituminous, PRB, or Lignite) will influence the flue gas quantities as a result of the different 

typical heating values. 

The evaluation includes a user selected option for a wastewater treatment facility. The base 

capital cost includes minor physical and chemical wastewater treatment. However, in the future 

more extensive wastewater handling may be required. Although an option for wastewater 

treatment is provided, no logic has been developed to accommodate the additional wastewater 

treatment costs. 

Outputs 

Total Project Costs (TPC) 

First the base installed costs are calculated for each required module (BM_). The base installed 

costs include: 

• All equipment; 

• Installation; 

• Buildings; 

• Foundations; 

• Electrical; 

• Minor physical and chemical wastewater treatment (WWT); and 

• Average retrofit difficulty. 

The modules are: 

BMR = Base absorber island cost 

BMF = Base reagent preparation cost 

BMW = Base waste handling cost 

BMB = Base balance of plan costs including: ID or booster fans, new wet chimney, piping, 

ductwork, minor WWT, etc. 

BMWW = Base wastewater treatment facility for future use. 

BM = BMR + BMF + BMW + BMB 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

Wet FGD Cost Development Methodology – Final 

Page 3 

The total base installed cost (BM) is then increased by: 

• Engineering and construction management costs at 10% of the BM cost; 

• Labor adjustment for 6 x 10 hour shift premium, per diem, etc., at 10% of the BM 

cost; and 

• Contractor profit and fees at 10% of the BM cost. 

A capital, engineering, and construction cost subtotal (CECC) is established as the sum of the 

BM and the additional engineering and construction fees. 

Additional costs and financing expenditures for the project are computed based on the CECC. 

Financing and additional project costs include: 

• Owner's home office costs (owner's engineering, management, and procurement) at 

5% of the CECC; and 

• Allowance for Funds Used During Construction (AFUDC) at 10% of the CECC and 

owner's costs. The AFUDC is based on a three-year engineering and construction 

cycle. 

The total project cost is based on a multiple lump sum contract approach. Should a turnkey 

engineering procurement construction (EPC) contract be executed, the total project cost could be 

10 to 15% higher than what is currently estimated. 

Escalation is not included in the estimate. The total project cost (TPC) is the sum of the CECC 

and the additional costs and financing expenditures. Table 1 contains an example capital cost 

estimation.
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

Wet FGD Cost Development Methodology – Final 

Page 4 

Table 1. Example Capital Cost Estimate for the Wet FGD System (Costs are all based on 2009 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

Wet FGD Cost Development Methodology – Final 

Page 5 

Fixed O&M (FOM) 

The fixed operating and maintenance (O&M) cost is a function of the additional 

operations staff (FOMO), maintenance labor and materials (FOMM), and administrative 

labor (FOMA) associated with the wet FGD installation. A future fixed O&M cost 

category is included to account for an extensive wastewater treatment facility. At this 

time, the wastewater treatment fixed O&M (FOMWW) is not estimated and is included at 

zero dollars. The FOM is the sum of the FOMO, FOMM, FOMA, and FOMWW. 

The following factors and assumptions underlie calculations of the FOM: 

• All of the FOM costs were tabulated on a per kilowatt-year (kW yr) basis. 

• In general, 12 additional operators are required for a 500 MW or smaller 

installation. Units larger than 500 MW require a total of 16 additional 

operators. The FOMO was based on the number of additional operations staff 

required as a function of generating capacity. 

• The fixed maintenance materials and labor is a direct function of the process 

capital cost (BM). 

• The administrative labor is a function of the FOMO and FOMM. 

Variable O&M (VOM) 

Variable O&M is a function of: 

• Reagent use and unit costs; 

• Waste production and unit disposal costs; 

• Additional power required and unit power cost; and 

• Makeup water required and unit water cost. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

Wet FGD Cost Development Methodology – Final 

Page 6 

The following factors and assumptions underlie calculations of the VOM: 

• All of the VOM costs were tabulated on a per megawatt-hour (MWh) basis. 

• The reagent usage is a function of gross unit size, SO2 feed rate, and removal 

efficiency. The estimated reagent usage was based on a sulfur removal 

efficiency of 98% and a calcium-to-sulfur stoichiometric ratio of 1.03. The 

basis for the limestone purity was 90% CaCO3 with the balance being inert 

material. 

• The waste generation rate is directly proportional to the reagent usage and is 

estimated based on 10% moisture in the by-product. 

• The additional power required includes increased fan power to account for the 

added wet FGD pressure drop. This requirement is a function of gross unit 

size (actual gas flow rate) and sulfur rate. 

• The makeup water rate is a function of gross unit size (actual gas flow rate) 

and sulfur feed rate. 

Input options are provided for the user to adjust the variable O&M costs per unit. 

Average default values are included in the base estimate. The variable O&M costs per 

unit options are: 

• Limestone cost in $/ton; 

• Waste disposal costs in $/ton; 

• Auxiliary power cost in $/kWh; 

• Makeup water costs in $/1000 gallon; and 

• Operating labor rate (including all benefits) in $/hr. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

Wet FGD Cost Development Methodology – Final 

Page 7 

The variables that contribute to the overall VOM are: 

VOMR = Variable O&M costs for limestone reagent 

VOMW = Variable O&M costs for waste disposal 

VOMP = Variable O&M costs for additional auxiliary power 

VOMM = Variable O&M costs for makeup water 

VOMWW = Variable O&M costs for wastewater treatment 

A future variable O&M cost category is included to account for an extensive wastewater 

treatment facility. At this time, the wastewater treatment variable O&M (VOMWW) is 

not estimated and is included at zero dollars. 

The total VOM is the sum of VOMR, VOMW, VOMP, VOMM, and VOMWW. Table 2 

contains an example O&M cost estimate, while Table 3 is a complete capital and O&M 

cost estimate worksheet.
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

Wet FGD Cost Development Methodology – Final 

Page 8 

Table 2. Example O&M Cost Estimate for the Wet FGD System (Costs are all based on 2009 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

Wet FGD Cost Development Methodology – Final 

Page 9 

Table 3. Example Complete Cost Estimate for the Wet FGD System (Costs are all based on 200
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

Wet FGD Cost Development Methodology – Final 

Page 10 
 

LEGAL NOTICE 

This analysis ("Deliverable") was prepared by Sargent & Lundy, L.L.C. ("S&L"), expressly for the sole use 

of Perrin Quarles Associates, Inc. ("Client") in accordance with the agreement between S&L and Client. 

This Deliverable was prepared using the degree of skill and care ordinarily exercised by engineers 

practicing under similar circumstances. Client acknowledges: (1) S&L prepared this Deliverable subject to 

the particular scope limitations, budgetary and time constraints, and business objectives of the Client; (2) 

information and data provided by others may not have been independently verified by S&L; and (3) the 

information and data contained in this Deliverable are time sensitive and changes in the data, applicable 

codes, standards, and acceptable engineering practices may invalidate the findings of this Deliverable. Any 

use or reliance upon this Deliverable by third parties shall be at their sole risk. 

This work was funded and reviewed by the U.S. Environmental Protection Agency under the supervision of 

William A. Stevens, Senior Advisor – Power Technologies. Additional input and review was provided by 

Dr. Jim Staudt, President of Andover Technology Partners. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

SDA FGD Cost Development Methodology – Final 

Page 1 

Establishment of Cost Basis 

Cost data for the SDA FGD systems was more limited than that for the wet FGD systems. A 

similar trend with generating capacity is generally seen between the wet and SDA system. The 

same generating capacity relationship was used for the wet and SDA cost estimation. 

A least squares curve fit of proprietary in-house cost data was defined as a "typical" SDA FGD 

retrofit for removal of 95% of the inlet sulfur. It should be noted that the lowest available SO2

emission guarantees, from the original equipment manufactures of SDA FGD systems, are 0.06 

lb/MMBtu. The typical SDA FGD retrofit was based on: 

• Retrofit Difficulty = 1 (Average retrofit difficulty); 

• Gross Heat Rate = 9800 Btu/kWh; 

• SO2 Rate = 2.0 lb/MMBtu; 

• Type of Coal = PRB; and 

• Project Execution = Multiple lump sum contracts; and 

• Recommended SO2 emission floor = 0.08 lb/MMBtu. 

Units below 50 MW will typically not install an SDA FGD system. Sulfur reductions for the 

small units would be accomplished by; treating smaller units at a single site with one SDA FGD 

system, switching to a lower sulfur coal, repowering with natural gas, dry sorbent injection, 

and/or a reduction in operating hours. Capital costs of approximately $800/kW may be used for 

units below 50 MW under the premise that these will be combined. 

Based on the typical SDA FGD performance, the technology should not be applied to fuels with 

more than 3 lb SO2/MMBtu and the cost estimator should be limited to fuels with less than 3 lb 

SO2/MMBtu. 

An alternate dry technology, circulating dry scrubber (CDS), can meet removals of 98% or 

greater over a large range of inlet sulfur concentrations. It should be noted that the lowest SO2

emission guarantees for a CDS FGD system are 0.04 lb/MMBtu. 

Methodology 

Inputs 

Several input variables are required in order to predict future retrofit costs. The gross unit size in 

MW (equivalent acfm) and sulfur content of the fuel are the major variables for the capital 

estimation. A retrofit factor that equates to difficulty in construction of the system must be 

defined. The costs herein could increase significantly for congested sites. The unit gross heat 

rate will factor into the amount of flue gas generated and ultimately the size of the absorber, 

reagent preparation, waste handling, and balance of plant costs. The SO2 rate will have the 

greatest influence on the reagent handling and waste handling facilities. The type of fuel 

(Bituminous, PRB, or Lignite) will influence the flue gas quantities as a result of the different 

typical heating values. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

SDA FGD Cost Development Methodology – Final 

Page 2 

Outputs 

Total Project Costs (TPC) 

First the base installed costs are calculated for each required module (BM_). The base installed 

costs include: 

• All equipment; 

• Installation; 

• Buildings; 

• Foundations; 

• Electrical; and 

• Average retrofit difficulty. 

The modules are: 

BMR = Base absorber island cost 

BMF = Base reagent preparation and waste recycle/handling cost 

BMB = Base balance of plan costs including: ID or booster fans, piping, ductwork, electrical, etc. 

BM = BMR + BMF + BMB 

The total base installed cost (BM) is then increased by: 

• Engineering and construction management costs at 10% of the BM cost; 

• Labor adjustment for 6 x 10 hour shift premium, per diem, etc., at 10% of the BM 

cost; and 

• Contractor profit and fees at 10% of the BM cost. 

A capital, engineering, and construction cost subtotal (CECC) is established as the sum of the 

BM and the additional engineering and construction fees. 

Additional costs and financing expenditures for the project are computed based on the CECC. 

Financing and additional project costs include: 

• Owner's home office costs (owner's engineering, management, and procurement) at 

5% of the CECC; and 

• Allowance for Funds Used During Construction (AFUDC) at 10% of the CECC and 

owner's costs. The AFUDC is based on a three-year engineering and construction 

cycle. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

SDA FGD Cost Development Methodology – Final 

Page 3 

The total project cost is based on a multiple lump sum contract approach. Should a turnkey 

engineering procurement construction (EPC) contract be executed, the total project cost could be 

10 to 15% higher than what is currently estimated. 

Escalation is not included in the estimate. The total project cost (TPC) is the sum of the CECC 

and the additional costs and financing expenditures. Table 1 contains an example capital cost 

estimation.
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

SDA FGD Cost Development Methodology – Final 

Page 4 

Table 1. Example Capital Cost Estimate for the SDA FGD System (Costs are all based on 200
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

SDA FGD Cost Development Methodology – Final 

Page 5 

Fixed O&M (FOM) 

The fixed operating and maintenance (O&M) cost is a function of the additional 

operations staff (FOMO), maintenance labor and materials (FOMM), and administrative 

labor (FOMA) associated with the SDA FGD installation. The FOM is the sum of the 

FOMO, FOMM, and FOMA. 

The following factors and assumptions underlie calculations of the FOM: 

• All of the FOM costs were tabulated on a per kilowatt-year (kW yr) basis. 

• In general, 8 additional operators are required for a SDA FGD system. The 

FOMO was based on the number of additional operations staff required. 

• The fixed maintenance materials and labor is a direct function of the process 

capital cost (BM). 

• The administrative labor is a function of the FOMO and FOMM. 

Variable O&M (VOM) 

Variable O&M is a function of: 

• Reagent use and unit costs; 

• Waste production and unit disposal costs; 

• Additional power required and unit power cost; and 

• Makeup water required and unit water cost. 

The following factors and assumptions underlie calculations of the VOM: 

• All of the VOM costs were tabulated on a per megawatt-hour (MWh) basis. 

• The reagent usage is a function of gross unit size, SO2 feed rate, and removal 

efficiency. The estimated reagent usage was based on a sulfur removal 

efficiency of 95% with a flue gas temperature into the SDA FGD of 300°F 

and an adiabatic approach to saturation of 30°F. The calcium-to-sulfur 

stoichiometric ratio varies based on inlet sulfur. The variation in 

stoichiometric ratio was accounted for in the estimation. The economic 

estimation is only valid up to 3 lb SO2/MMBtu inlet. The basis for the lime 

purity was 90% CaO with the balance being inert material. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

SDA FGD Cost Development Methodology – Final 

Page 6 

• The waste generation rate is a function of inlet sulfur and calcium to sulfur 

stoichiometry. Both variables are accounted for in the waste generation 

estimation. The waste disposal rate is based on 10% moisture in the byproduct. 

• The additional power required includes increased fan power to account for the 

added SDA FGD pressure drop. This requirement is a function of gross unit 

size (actual gas flow rate) and sulfur rate. 

• The makeup water rate is a function of gross unit size (actual gas flow rate) 

and sulfur feed rate. 

Input options are provided for the user to adjust the variable O&M costs per unit. 

Average default values are included in the base estimate. The variable O&M costs per 

unit options are: 

• Limestone cost in $/ton; 

• Waste disposal costs in $/ton; 

• Auxiliary power cost in $/kWh; 

• Makeup water costs in $/1000 gallon; and 

• Operating labor rate (including all benefits) in $/hr. 

The variables that contribute to the overall VOM are: 

VOMR = Variable O&M costs for lime reagent 

VOMW = Variable O&M costs for waste disposal 

VOMP = Variable O&M costs for additional auxiliary power 

VOMM = Variable O&M costs for makeup water 

The total VOM is the sum of VOMR, VOMW, VOMP, and VOMM. Table 2 contains an 

example O&M cost estimate, while Table 3 is a complete capital and O&M cost estimate 

worksheet.
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

SDA FGD Cost Development Methodology – Final 

Page 7 

Table 2. Example O&M Cost Estimate for the SDA FGD System (Costs are all based on 2009 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

SDA FGD Cost Development Methodology – Final 

Page 8 

Table 3. Example Complete Cost Estimate for the SDA FGD System (Costs are all based on 200
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

SDA FGD Cost Development Methodology – Final 

Page 9 
 

IPM Model – Revisions to Cost and Performance for APC Technologies

Dry Sorbent Injection Cost Development Methodology

FINAL

August 2010 

Project 12301-007 

Perrin Quarles Associates, Inc. 

Prepared by

55 East Monroe Street • Chicago, IL 60603 USA • 312-269-2000 
 

LEGAL NOTICE 

This analysis (“Deliverable”) was prepared by Sargent & Lundy, L.L.C. ("S&L"), expressly for the sole 

use of Perrin Quarles Associates, Inc. ("Client") in accordance with the agreement between S&L and 

Client. This Deliverable was prepared using the degree of skill and care ordinarily exercised by engineers 

practicing under similar circumstances. Client acknowledges: (1) S&L prepared this Deliverable subject to 

the particular scope limitations, budgetary and time constraints, and business objectives of the Client; (2) 

information and data provided by others may not have been independently verified by S&L; and (3) the 

information and data contained in this Deliverable are time sensitive and changes in the data, applicable 

codes, standards, and acceptable engineering practices may invalidate the findings of this Deliverable. Any 

use or reliance upon this Deliverable by third parties shall be at their sole risk. 

This work was funded and reviewed by the U.S. Environmental Protection Agency under the supervision of 

William A. Stevens, Senior Advisor – Power Technologies. Additional input and review was provided by 

Dr. Jim Staudt, President of Andover Technology Partners. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

Dry Sorbent Injection Cost Development Methodology – Final 

Page 3 

Technology Description 

Dry sorbent injection (DSI) is a viable technology for moderate SO2 reduction on coal 

fired boilers. Demonstrations and recent utility testing have shown SO2 removals greater 

than 80% for systems using sodium based sorbents. The most common sodium based 

sorbent is Trona. 

The level of removal for Trona can vary from 0 to 90% depending on the Normalized 

Stoichiometric Ratio (NSR) and particulate capture device. NSR is defined as: 

The target removal efficiency is a requirement from the utility and is independent of unit 

size. The costs for a DSI system are primarily dependant on sorbent feed rate which is a 

function of NSR and SO2 mass feed rate per hour. Therefore, the cost estimation was 

based on sorbent feed rate and not on unit size. 

The sorbent solids can be collected in either an ESP or a baghouse. Baghouses generally 

achieve greater SO2 removal efficiencies than ESPs by virtue of the filter cake on the 

bags, which allows for longer reaction time between the sorbent solids and the flue gas. 

For a given removal efficiency with Trona, the NSR is reduced when a baghouse is used 

for particulate capture. 

The dry sorbent capture ability is also a function of particle surface area. To increase the 

particle surface area, the sorbent must be heated. Heating the solids produces micropores 

on the particle surface which greatly improve the sulfur capture ability. For Trona, the 

sorbent should be injected into flue gas above 275°F to maximize the micropore 

structure. However, if the flue gas is too hot (greater than 800°F), the solids may sinter 

and surface area is reduced. 

Another way to increase surface area is to mechanically reduce the particle size by 

grinding the sorbent. Typical Trona is delivered unmilled. The ore is ground such that 

the unmilled product has an average size around 30 μm. Commercial testing has shown 

that the reactivity of the Trona can be increased when the sorbent is ground to less than 

30 μm. In the cost estimating methodology, the Trona is always delivered in the 

unmilled state. To mill the Trona, in-line mills are continuously used during the Trona 

injection process. Therefore, the delivered cost of the Trona will not change, only the 

reactivity and usage changes as the Trona is milled. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

Dry Sorbent Injection Cost Development Methodology – Final 

Page 4 

Ultimately, the NSR required for a given removal is a function of Trona particle size and 

particulate capture equipment. Either as delivered Trona (around 30 μm average size) or 

in-line milled Trona (around 15 μm average size) can be chosen for injection in the cost 

program. The average Trona particle size and the type of particulate removal both 

contribute to the predicted Trona feed rate. 

Establishment of Cost Basis 

For the wet or SDA FGD systems, the sulfur removal is generally specified at the 

maximum achievable level. With those systems, costs are primarily a function of plant 

size and sulfur rate. However, the DSI systems are quite different. The major cost for 

the DSI system is the sorbent itself. The sorbent feed rate is a function of sulfur rate, 

particulate collection device, and removal efficiency. To account for all of the variables, 

the capital cost was established based on a sorbent feed rate. The sorbent feed rate is 

calculated from user input variables. Cost data for several DSI systems was reviewed 

and a relationship was developed for the capital costs of the system on a sorbent feed rate 

basis. 

Methodology 

Inputs 

Several input variables are required in order to predict future retrofit costs. The sulfur 

feed rate and NSR are the major variables for the cost estimate. The NSR is a function 

of: 

• Removal efficiency; 

• Trona particle size; and 

• Particulate capture device. 

A retrofit factor that equates to difficulty in construction of the system must be defined. 

The gross unit size and gross heat rate will factor into the amount of sulfur generated. 

Based on commercial testing, removal efficiencies with DSI are limited by the particulate 

capture device employed. When the sorbent is captured in an ESP, a 40 to 50% SO2

removal is typically achieved without an increase in particulate emissions. A higher 

efficiency (70 – 75%) is generally achieved with a baghouse. The DSI technology should 

not be applied to fuels with a sulfur content of greater than 2 lb SO2/MMBtu. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

Dry Sorbent Injection Cost Development Methodology – Final 

Page 5 

The equations provided in the cost methodology spreadsheet allow the user to input the 

required removal efficiency, within the limits of the technology. To simplify the 

correlation, the removal with an ESP should be set at 50% and 70% with a baghouse. 

The simplified sorbent NSR would then be: 

For an ESP at the target 50% removal: 

Unmilled Trona NSR = 2.85 

Milled Trona NSR = 1.40 

For a baghouse at the target 70% removal: 

Unmilled Trona NSR = 2.00 

Milled Trona NSR = 1.55 

The correlation could be further simplified by assuming that only milled Trona is used. 

The current trend in the industry is to use in-line milling of the Trona to improve the 

utilization. For a minor increase in capital, the milling can greatly reduce the variable 

operating expenses. It is recommended that only milled Trona be considered in the 

simplified model. 

Outputs 

Total Project Costs (TPC) 

First the base installed cost for the complete DSI system is calculated (BM). The base 

installed cost includes: 

• All equipment; 

• Installation; 

• Buildings; 

• Foundations; 

• Electrical; and 

• Average retrofit difficulty. 

The base module cost is adjusted by the selection of in-line milling equipment. The base 

installed cost is then increased by: 

• Engineering and construction management costs at 5% of the BM cost; 

• Labor adjustment for 6 x 10 hour shift premium, per diem, etc., at 5% of the 

BM cost; and 

• Contractor profit and fees at 5% of the BM cost. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

Dry Sorbent Injection Cost Development Methodology – Final 

Page 6 

A capital, engineering, and construction cost subtotal (CECC) is established as the sum of 

the BM and the additional engineering and construction fees. 

Additional costs and financing expenditures for the project are computed based on the 

CECC. Financing and additional project costs include: 

• Owner’s home office costs (owner’s engineering, management, and 

procurement) at 5% of the CECC; and 

• Allowance for Funds Used During Construction (AFUDC) at 0% of the 

CECC and owner’s costs as these projects are expected to be completed in 

less than a year. 

The total project cost is based on a multiple lump sum contract approach. Should a 

turnkey engineering procurement construction (EPC) contract be executed, the total 

project cost could be 10 to 15% higher than what is currently estimated. 

Escalation is not included in the estimate. The total project cost (TPC) is the sum of the 

CECC and the additional costs and financing expenditures. 

Fixed O&M (FOM) 

The fixed operating and maintenance (O&M) cost is a function of the additional 

operations staff (FOMO), maintenance labor and materials (FOMM), and administrative 

labor (FOMA) associated with the DSI installation. The FOM is the sum of the FOMO, 

FOMM, and FOMA. 

The following factors and assumptions underlie calculations of the FOM: 

• All of the FOM costs were tabulated on a per kilowatt-year (kW-yr) basis. 

• In general, 2 additional operators are required for a DSI system. The FOMO 

was based on the number of additional operations staff required. 

• The fixed maintenance materials and labor is a direct function of the process 

capital cost (BM). 

• The administrative labor is a function of the FOMO and FOMM. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

Dry Sorbent Injection Cost Development Methodology – Final 

Page 7 

Variable O&M (VOM) 

Variable O&M is a function of: 

• Reagent use and unit costs; 

• Waste production and unit disposal costs; and 

• Additional power required and unit power cost. 

The following factors and assumptions underlie calculations of the VOM: 

• All of the VOM costs were tabulated on a per megawatt-hour (MWh) basis. 

• The reagent usage is a function of NSR and SO2 feed rate. The gross unit size 

and gross heat rate factor multiplied by the SO2 rate determine the SO2 feed 

rate. The estimated NSR is a function of removal efficiency required. The 

basis for the total reagent rate is a Trona purity of 98%. 

• The waste generation rate is a function of the Trona feed rate and is adjusted 

for the excess sorbent fed. The waste generation rate is based on reaction 

products of Na2SO4 and unreacted dry sorbent as Na2CO3. 

• With the addition of a sodium sorbent, any fly ash produced must be 

landfilled. Typical ash contents for each fuel are used to calculate a total fly 

ash production rate. The fly ash production is added to the sorbent waste to 

account for a total waste stream in the O&M analysis. 

• The additional power required includes air blowers for the injection system, 

drying equipment for the transport air, and in-line Trona milling equipment as 

needed. 

Input options are provided for the user to adjust the variable O&M costs per unit. 

Average default values are included in the base estimate. The variable O&M costs per 

unit options are: 

• Trona cost in $/ton; 

• Waste disposal costs in $/ton; 

• Auxiliary power cost in $/kWh; 

• Operating labor rate (including all benefits) in $/hr. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

Dry Sorbent Injection Cost Development Methodology – Final 

Page 8 

The variables that contribute to the overall VOM are: 

VOMR = Variable O&M costs for trona reagent 

VOMW = Variable O&M costs for waste disposal 

VOMP = Variable O&M costs for additional auxiliary power 

The total VOM is the sum of VOMR, VOMW, and VOMP. Table 1 contains an example 

of the complete capital and O&M cost estimate worksheet.
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

Dry Sorbent Injection Cost Development Methodology – Final 

Page 9 

Table 1. Example Complete Cost Estimate for a DSI System (Costs are all based on 2009 dol
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

Dry Sorbent Injection Cost Development Methodology – Final 

Page 10 
ATTACHMENT A-3 

WET FGD COST DEVELOPMENT METHODOLOGY – 

SARGENT & LUNDY, LLC, AUGUST 2010 
TABLE 4-1 EMPIRICAL EQUATIONS USED IN THE IPM MODEL CONTROL COSTING ANALYSES

The written descriptions below are presented to represent the S&L empirical equations used in 

their cost analysis methodology. The note numbers are found on worksheets in this section. 

DRY SORBENT INJECTION 

(Notes)

1 NSR or "K" = 0.353 x EXP(0.028 x H) {assumes ESP control and milled trona}

2 Trona feed rate or "M"= 1.2011 x 10-6 x K x A x C x D, {units are in tons/hour}

3 Sorbent waste rate or "N" = (0.7035 - 0.00073696 x H / K) x M {units are in tons/hour}

4 Fly ash waste rate or "P" = (A x C) x 0.06 ash in PRB coal x (1 - 0.2) / (2 x 8,400 Btu/lb)

5 Basic module cost = $7,516000 x B x (M)0.284

6 Auxiliary power to run equipment = M x 20 / A {percent of gross plant power}

SPRAY DRYER ABSORBER

(Notes)

1 Lime rate = (0.6702 x (D)2 + 13.42 x D) x A x C /10,000 / 2000 {units are in tons per hour} 

2 Waste rate = (0.8016 x (D)2

 + 31.1917 x D) x A x C /10,000/2000 {units are in tons per hour}

3 Water rate = (0.04898 x (D) 2

 +0.5925 x D + 55.11) x A X 1.05 x C/10,000/1000 {units are in 103 gals/hr}

4 Basic spray dryer equipment = $566,000 x A0.716 x B x (1.18)0.6 x (D/4)0.01 

5 Reagent prep equip cost = $300,000 x A0.716 x B x (D x G)0.2

6 Balance of SDA equipment = $799,000 x A0.716 x B x (F x G)0.6

7 Aux power to run equipment = (0.000547 x D2

 + 0.00649 x D + 1.3) x 1.18

WET FLUE GAS DESULFURIZATION

(Notes)

1 Limestone rate or "K" = 17.52 x A x D x G /2000 {units are in tons per hour}

2 Waste rate = limestone rate x 1.811 {units are in tons per hour}

3 Water rate = (1.674 x D + 74.68) x A x F x G / 1000 {units are in 103

 gals/hr)

4 Basic absorber cost = $550,000 x A0.716 x B x (F X G)0.6 x (D/2)0.02 

5 Reagent prep equip cost = $190,000 x A0.716 x (D x G)0.3

6 Basic waste handling cost = $100,000 x A0.716 x B x (D x G)0.45

7 Balance of plant cost = $1,010,000 x B x A0.716 x (F X G)0.4

8 Aux power to run equipment = 1.05e^(0.155 x D) x F x G

Page 10
Table 4-2a

DRY SORBENT INJECTION COSTING DEVELOPMENT

DESIGN CASE FOR CAPITAL COST

Variable Designation Units Value Equation/Input(1)

DRY INJECTION CAPITAL COST DESIGN BASIS FOR 2 LBS/MMBTU SO2

Unit Capacity (Gross) A (MW) 162 Input

Retrofit Factor B 2 Difficulty of Retrofit

Gross heat rate C Btu/KW‐hr 11,982 Input

SO2 Emiss Rate D lbs/MMBtu 2 Uncontrolled

Type of Coal E Input

Particulate Control F ESP Input

Trona Milling G Yes Input

Removal Target H 70

Heat input J MM Btu/hr 1941.1 A X C x 1000

NSR K 2.51 See Note DSI Note 1

Trona Feed rate M (tons/hr) 11.69 See Note DSI Note 2

Sorbent Waste Rate N (tons/hr) 7.98 See Note DSI Note 3

Fly Ash Waste Rate P (tons/hr) 5.55 See Note DSI Note 4

Aux Power Q (%) 1.44 See Note DSI Note 6

Trona Cost R ($/ton) 150

Waste Disposal Cost S ($/ton) 50

Aux Power Cost T ($/kWhr) 0.06

Operating Labor Rate U ($/hr) 60

Capital Cost BM ($) $30,215,380 Base DSI Module See note 5

Engineering, Construction Mgmt 5% $1,510,769

Construction Labor 5% $1,510,769

Contractor Profit and Fees 5% $1,510,769

Owners Cost 5% $1,737,384

Total Project Cost $36,485,071

225 $/kW

Fixed Operator Cost $124,800 2,080 hrs‐ one operator

Maintenance Material $302,154 1% of BM Capital Cost

Admin Labor Cost $7,370

Trona Cost $1,752.82 Trona cost in $/hr

Waste Disposal Cost $676.31 Total Waste Cost in $/hr

Notes:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐Dry Sorbent Injection Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

PRB

CAPITAL EQUIPMENT COSTS

OPERATING AND MAINTENANCE COSTS

Page 11
Table 4-2b

DRY SORBENT INJECTION COSTING DEVELOPMENT

30-DAY ROLLING AVERAGE OPERATIONAL PARAMETERS

Variable Designation Units Value Equation/Input(1)

DRY INJECTION OPERATING VARIABLES ‐ ACTUAL OPERATION AT 0.46 LBS/MMBTU SO2

Unit Capacity (Gross) A (MW) 162 Input

Retrofit Factor B 2 Difficulty of Retrofit

Gross heat rate C Btu/KW‐hr 11,982 Input

SO2 Emiss Rate D lbs/MMBtu 0.46 Uncontrolled

Type of Coal E Input

Particulate Control F ESP Input

Trona Milling G Yes Input

Removal Target H 53

Heat input J MM Btu/hr 1941.1 A X C x 1000

NSR K 1.56 See Note DSI Note 1

Trona Feed rate M (tons/hr) 1.67 See Note DSI Note 2

Sorbent Waste Rate N (tons/hr) 1.13 See Note DSI Note 3

Fly Ash Waste Rate P (tons/hr) 5.55 See Note DSI Note 4

Aux Power Q (%) 0.21 See Note DSI Note 6

Trona Cost R ($/ton) 150 Corrected to 2011 $

Waste Disposal Cost S ($/ton) 50

Aux Power Cost T ($/kWhr) 0.06

Operating Labor Rate U ($/hr) 60

Capital Cost BM ($) $17,387,979 Base DSI Module

Engineering, Construction Mgmt 5% $869,399

Construction Labor 5% $869,399

Contractor Profit and Fees 5% $869,399

Owners Cost 5% $999,809

Total Project Cost $20,995,984

130 $/kW

Fixed Operator Cost $124,800 2,080 hrs‐ one operator

Maintenance Material $173,880 1% of BM Capital Cost

Admin Labor Cost $5,831

Trona Cost $250.46 Trona cost in $/hr

Waste Disposal Cost $333.94 Total Waste Cost in $/hr

Notes:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐Dry Sorbent Injection Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

PRB

CAPITAL EQUIPMENT COSTS

OPERATING AND MAINTENANCE COSTS

Page 12
Table 4-2c

DRY SORBENT INJECTION COSTING DEVELOPMENT

MAX 24-HR SO2 OPERATIONAL PARAMETERS

Variable Designation Units Value Equation/Input(1)

DRY INJECTION OPERATING VARIABLES ‐ ACTUAL OPERATION AT 0.60 LBS/MMBTU SO2

Unit Capacity (Gross) A (MW) 162 Input

Retrofit Factor B 2 Difficulty of Retrofit

Gross heat rate C Btu/KW‐hr 11,982 Input

SO2 Emiss Rate D lbs/MMBtu 0.6 Uncontrolled

Type of Coal E Input

Particulate Control F ESP Input

Trona Milling G Yes Input

Removal Target H 57

Heat input J MM Btu/hr 1941.1 A X C x 1000

NSR K 1.74 See Note DSI Note 1

Trona Feed rate M (tons/hr) 2.44 See Note DSI Note 2

Sorbent Waste Rate N (tons/hr) 1.65 See Note DSI Note 3

Fly Ash Waste Rate P (tons/hr) 5.55 See Note DSI Note 4

Aux Power Q (%) 0.30 See Note DSI Note 6

Trona Cost R ($/ton) 150 Corrected to 2011 $

Waste Disposal Cost S ($/ton) 50

Aux Power Cost T ($/kWhr) 0.06

Operating Labor Rate U ($/hr) 60

Capital Cost BM ($) $19,356,858 Base DSI Module

Engineering, Construction Mgmt 5% $967,843

Construction Labor 5% $967,843

Contractor Profit and Fees 5% $967,843

Owners Cost 5% $1,113,019

Total Project Cost 5% $23,373,406

144 $/kW

Fixed Operator Cost $124,800 2,080 hrs‐ one operator

Maintenance Material $193,569 1% of BM Capital Cost

Admin Labor Cost $6,067

Trona Cost $365.41 Trona cost in $/hr

Waste Disposal Cost $360.05 Waste Cost in $/hr

Notes:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐Dry Sorbent Injection Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

PRB

CAPITAL EQUIPMENT COSTS

OPERATING AND MAINTENANCE COSTS

Page 13
Table 4-2d

PPL BART Cost Effectiveness Analysis

Dry Injection (With Low Sulfur Coal) Sulfur Dioxide Control

162 Megawatt Coal Fired Steam Electric Plant

Trona Injection With Precipitator Replacement at J.E. Corette

SO2 =0.46 lbs/MMBtu

Stack Exhaust Volumetric Flowrate, (acfm) Q 726,262

Maximum Gross Heat Input MM Btu/hr 1,941

Design Percent Load % 89

Uncontrolled SO2 Emissions (with low S coal) lbs/MMBtu 0.460

ExhaustTemperature, (o

F) T 405

Steam Turbine Power Output (TMW) MW 162

Capacity Factor (89%) hrs 7,796

Controlled SO2 Emissions lbs/MMBtu 0.26

Overall SO2 Reduction Efficiency, (%) % 43.48

Uncontrolled SO2 Emissions, (lb/hr) 892.9

Uncontrolled SO2 Emissions, (tons/yr) 3480.7

Controlled SO2 Emissions, (ton/yr) 1967.4

Annual Interest Rate, (%) 7

Equipment Life, (yrs) yr 15

Capital Recovery Factor, CRF CRF 0.1098

Unit Item

Cost Item Suggested Factor Cost Cost

IPM Model, August 20, 2010(1) Capital Cost ($/KW)(2) 225 $36,485,071

Cost for Pulse-Jet Fabric Filter Capital Cost ($/KW)(3) 379 $61,398,000

Equipment Cost Total, (EC) EC (Adjusted by Cost Index Calcs) (2011 dollars)(4) $101,615,582

 Total Capital Costs, TCC --- $101,615,582

 Direct Annual Costs, DAC Trona Cost $1,952,695

Total waste disposal Cost $2,603,502

Parasitic power cost $156,216

Lost Ash Revenue $11.74/ton $352,200

Maintenance Labor $130,631

Maintenance Materials $173,880

 Total Direct Annual Costs, DAC $5,369,123

Indirect Annual Costs

 Capital Recovery CRF*TCC --- $11,156,845

 Total Indirect Annual Costs, IAC $11,156,845

 Total Annual Costs, TAC = DAC + IAC $16,525,967

Cost Effectiveness ($/ton pollutant Removed) $10,920

 Cost data references:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐Dry Sorbent Injection Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

2) $/kW in 2009 dollars

3) $/kW in 2008 dollars (See Edison Electric Institute reference on page 26)

4) Cost indices used to adjust 2008 and 2009 costs to 2011 costs (2008, 2009 CI= 108.302, 109.594 2011 CI= 113.065)

Page 14
Table 4-2e

PPL BART Cost Effectiveness Analysis

Dry Injection (With Low Sulfur Coal) Sulfur Dioxide Control

162 Megawatt Coal Fired Steam Electric Plant

Trona Injection With Precipitator Replacement at J.E. Corette

SO2 =0.60 lbs/MMBtu

Stack Exhaust Volumetric Flowrate, (acfm) Q 726,262

Maximum Gross Heat Input MM Btu/hr 1,941

Design Percent Load % 89

Uncontrolled SO2 Emissions (with low S coal) lbs/MMBtu 0.600

ExhaustTemperature, (o

F) T 405

Steam Turbine Power Output (TMW) MW 162

Capacity Factor (89%) hrs 7,796

Controlled SO2 Emissions lbs/MMBtu 0.26

Overall SO2 Reduction Efficiency, (%) % 56.67

Uncontrolled SO2 Emissions, (lb/hr) 1164.7

Uncontrolled SO2 Emissions, (tons/yr) 4540.1

Controlled SO2 Emissions, (ton/yr) 1967.4

Annual Interest Rate, (%) 7

Equipment Life, (yrs) yr 15

Capital Recovery Factor, CRF CRF 0.1098

Unit Item

Cost Item Suggested Factor Cost Cost

IPM Model, August 20, 2010(1) Capital Cost ($/KW)(2) 225 $36,485,071

Cost for Pulse-Jet Fabric Filter Capital Cost ($/KW)(3) 379 $61,398,000

Equipment Cost Total, (EC) EC (Adjusted by Cost Index Calcs) (2011 dollars)(4) $101,615,582

 Total Capital Costs, TCC --- $101,615,582

 Direct Annual Costs, DAC Trona Cost $2,848,845

Total waste disposal Cost $2,807,072

Parasitic power cost $227,908

Lost Ash Revenue $11.74/ton $352,200

Maintenance Labor $130,867

Maintenance Materials $193,569

 Total Direct Annual Costs, DAC $6,560,460

Indirect Annual Costs

 Capital Recovery CRF*TCC --- $11,156,845

 Total Indirect Annual Costs, IAC $11,156,845

 Total Annual Costs, TAC = DAC + IAC $17,717,304

Cost Effectiveness ($/ton pollutant Removed) $6,887

 Cost data references:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐Dry Sorbent Injection Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

2) $/kW in 2009 dollars

3) $/kW in 2008 dollars (See Edison Electric Institute reference on page 26)

4) Cost indices used to adjust 2008 and 2009 costs to 2011 costs (2008, 2009 CI= 108.302, 109.594 2011 CI= 113.065)

Page 15
Table 4-3a

SPRAY DRYER ABSORBER COSTING DEVELOPMENT

DESIGN CASE FOR CAPITAL COSTS 

Variable Designation Units Value Equation/Input(1)

LIME SPRAY DRYER CAPITAL COST DESIGN BASIS FOR 2 LBS/MMBTU SO2

Unit Capacity (Gross) A (MW) 162 Input

Retrofit Factor B 2 Difficulty of Retrofit

Gross heat rate C Btu/KW‐hr 11,982 Input

SO2 Emiss Rate D lbs/MMBtu 2 Uncontrolled

Type of Coal E Input

Coal Factor F PRB Coal 1.05 Input

Heat Rate Factor G 1.20 C / 10000

Heat input H MM Btu/hr 1941.1 A X C x 1000

Lime Rate K (tons/hr) 2.87 See SDA Note 1

Waste Rate L (tons/hr) 6.37 See SDA Note 2

Aux Power M (%) 1.65 See SDA Note 7

Make Up Water N 103 gph 11.51 See SDA Note 3

Lime Cost P ($/ton) 135.00 Input

Waste Disposal Cost S ($/ton) 50 Input

Aux Power Cost R ($/kWhr) 0.06 Input

Makeup Water Cost S $/103 gal 1 Input

Operating Labor Rate T ($/hr) 60 Input

Basic Absorber BMR ($) $49,281,061 See SDA Note 4

Reagent Preparation BMF ($) $27,294,545 See SDA Note 5

ID Fan, Other Costs BMB ($) $66,907,834 See SDA Note 6

Capital Cost BM Sum ($) $143,483,440 Base LSD Module

Engineering, Construction Mgmt 10% $14,348,344

Construction Labor 10% $14,348,344

Contractor Fees 10% $14,348,344

CECC $186,528,472 Capital, Eng, and Const

Owners Cost B1 5% $9,326,424 Various home office fees

AFUDC 10% of (CECC+B1) $19,585,490

Total Project Cost $215,440,385

1,330 $/kW

Fixed Operator Cost $998,400 2,080 hrs‐ 8 operators

Maintenance Material $4,304,503 1.5% of BM Capital Cost

Admin Labor Cost $81,606

Lime Cost $386.79 Lime cost in $/hr

Waste Disposal Cost $318.29 Waste Cost in $/hr

Notes:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐SDA FDG Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

PRB

CAPITAL EQUIPMENT COSTS

OPERATING AND MAINTENANCE COSTS

Page 16
Table 4-3b

SPRAY DRYER COSTING DEVELOPMENT

30-DAY ROLLING AVERAGE SO2 OPERATING PARAMETERS

Variable Designation Units Value Equation/Input(1)

LIME SPRAY DRYER OPERATING VARIABLES ‐ ACTUAL OPERATION AT 0.46 LBS/MMBTU SO2

Unit Capacity (Gross) A (MW) 162 Input

Retrofit Factor B 2 Difficulty of Retrofit

Gross heat rate C Btu/KW‐hr 11,982 Input

SO2 Emiss Rate D lbs/MMBtu 0.46 Uncontrolled

Type of Coal E Input

Coal Factor F PRB Coal 1.05 Input

Heat Rate Factor G 1.20 C / 10000

Heat input H MM Btu/hr 1941.1 A X C x 1000

Lime Rate K (tons/hr) 0.61 See SDA Note 1

Waste Rate L (tons/hr) 1.41 See SDA Note 2

Aux Power M (%) 1.64 See SDA Note 7

Make Up Water N 103 gph 11.29 See SDA Note 3

Lime Cost P ($/ton) 135.00 Input

Waste Disposal Cost S ($/ton) 50 Input

Aux Power Cost R ($/kWhr) 0.06 Input

Makeup Water Cost S $/103 gal 1 Input

Operating Labor Rate T ($/hr) 60 Input

Basic Absorber BMR ($) $48,562,085 See SDA Note 4

Reagent Preparation BMF ($) $20,343,301 See SDA Note 5

ID Fan, Other Costs BMB ($) $66,907,834 See SDA Note 6

Capital Cost BM Sum ($) $135,813,220 Base LSD Module

Engineering, Construction Mgmt 10% $13,581,322

Construction Labor 10% $13,581,322

Contractor Fees 10% $13,581,322

CECC $176,557,186 Capital, Eng, and Const

Owners Cost B1 5% $8,827,859 Various home office fees

AFUDC 10% of (CECC+B1) $18,538,505

Total Project Cost $203,923,550

1,259 $/kW

Fixed Operator Cost $998,400 2,080 hrs‐ 8 operators

Maintenance Material $4,074,397 1.5% of BM Capital Cost

Admin Labor Cost $78,845

Lime Cost $82.74 Lime cost in $/hr

Waste Disposal Cost $70.45 Waste Cost in $/hr

Notes:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐SDA FDG Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

PRB

CAPITAL EQUIPMENT COSTS

OPERATING AND MAINTENANCE COSTS

Page 17
Table 4-3c

SPRAY DRYER ABSORBER COSTING DEVELOPMENT

MAXIMUM 24-HR AVERAGE SO2 OPERATING PARAMETERS

Variable Designation Units Value Equation/Input(1)

LIME SPRAY DRYER OPERATING VARIABLES ‐ ACTUAL OPERATION AT 0.60 LBS/MMBTU SO2

Unit Capacity (Gross) A (MW) 162 Input

Retrofit Factor B 2 Difficulty of Retrofit

Gross heat rate C Btu/KW‐hr 11,982 Input

SO2 Emiss Rate D lbs/MMBtu 0.6 Uncontrolled

Type of Coal E Input

Coal Factor F PRB Coal 1.05 Input

Heat Rate Factor G 1.20 C / 10000

Heat input H MM Btu/hr 1941.1 A X C x 1000

Lime Rate K (tons/hr) 0.80 See SDA Note 1

Waste Rate L (tons/hr) 1.84 See SDA Note 2

Aux Power M (%) 1.64 See SDA Note 7

Make Up Water N 103 gph 11.31 See SDA Note 3

Lime Cost P ($/ton) 135.00 Input

Waste Disposal Cost S ($/ton) 50 Input

Aux Power Cost R ($/kWhr) 0.06 Input

Makeup Water Cost S $/103 gal 1 Input

Operating Labor Rate T ($/hr) 60 Input

Basic Absorber BMR ($) $48,691,288 See SDA Note 4

Reagent Preparation BMF ($) $21,453,597 See SDA Note 5

ID Fan, Other Costs BMB ($) $66,907,834 See SDA Note 6

Capital Cost BM Sum ($) $137,052,718 Base LSD Module

Engineering, Construction Mgmt 10% $13,705,272

Construction Labor 10% $13,705,272

Contractor Fees 10% $13,705,272

CECC $178,168,534 Capital, Eng, and Const

Owners Cost B1 5% $8,908,427 Various home office fees

AFUDC 10% of (CECC+B1) $18,707,696

Total Project Cost $205,784,657

1,270 $/kW

Fixed Operator Cost $998,400 2,080 hrs‐ 8 operators

Maintenance Material $4,111,582 1.5% of BM Capital Cost

Admin Labor Cost $79,291

Lime Cost $108.66 Lime cost in $/hr

Waste Disposal Cost $92.22 Waste Cost in $/hr

Notes:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐SDA FDG Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

PRB

CAPITAL EQUIPMENT COSTS

OPERATING AND MAINTENANCE COSTS

Page 18
Table 4-3d

PPL BART Cost Effectiveness Analysis

Lime Spray Drying (With Low Sulfur Coal) Sulfur Dioxide Control

162 Megawatt Coal Fired Steam Electric Plant

Lime Spray Drying With Precipitator Replacement at J.E. Corette

SO2 =0.46 lbs/MMBtu

Stack Exhaust Volumetric Flowrate, (acfm) Q 726,262

Maximum Gross Heat Input MM Btu/hr 1,941

Design Percent Load % 89

Uncontrolled SO2 Emissions (with low S coal) lbs/MMBtu 0.460

ExhaustTemperature, (o

F) T 405

Steam Turbine Power Output (TMW) MW 162

Capacity Factor (89%) hrs 7,796

Controlled SO2 Emissions lbs/MMBtu 0.13

Overall SO2 Reduction Efficiency, (%) % 71.74

Uncontrolled SO2 Emissions, (lb/hr) 892.9

Uncontrolled SO2 Emissions, (tons/yr) 3480.7

Controlled SO2 Emissions, (ton/yr) 983.7

Annual Interest Rate, (%) 7

Equipment Life, (yrs) yr 15

Capital Recovery Factor, CRF CRF 0.1098

Unit Item

Cost Item Suggested Factor Cost Cost

IPM Model, August 20, 2010(1) Capital Cost ($/KW)(2) 1,330 $215,440,385

Cost for Pulse-Jet Fabric Filter Capital Cost ($/KW)(3) 379 $61,398,000

Equipment Cost Total, (EC) EC (Adjusted by Cost Index Calcs) (2011 dollars)(4) $285,634,195

 Total Capital Costs, TCC --- $285,634,195

 Direct Annual Costs, DAC Lime $645,084

Total waste disposal Cost $549,262

Parasitic power cost $1,242,388

Lost Ash Revenue $11.74/ton $352,200

Stack Reheat Penalty reheat to 300o

F $7,740,315

Maintenance labor $1,077,245

Maintenance materials $4,074,397

 Total Direct Annual Costs, DAC $15,680,890

Indirect Annual Costs

 Capital Recovery CRF*TCC --- $31,361,099

 Total Indirect Annual Costs, IAC $31,361,099

 Total Annual Costs, TAC = DAC + IAC $47,041,990

Cost Effectiveness ($/ton pollutant Removed) $18,839

 Cost data references:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐Dry Sorbent Injection Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

2) $/kW in 2009 dollars

3) $/kW in 2008 dollars (See Edison Electric Institute reference on page 26)

4) Cost indices used to adjust 2008 and 2009 costs to 2011 costs (2008, 2009 CI= 108.302, 109.594 2011 CI= 113.065)

Page 19
Table 4-3e

PPL BART Cost Analysis

Lime Spray Drying (With Low Sulfur Coal) Sulfur Dioxide Control

162 Megawatt Coal Fired Steam Electric Plant

Lime Spray Drying With Precipitator Replacement at J.E. Corette

SO2 =0.60 lbs/MMBtu

Stack Exhaust Volumetric Flowrate, (acfm) Q 726,262

Maximum Gross Heat Input MM Btu/hr 1,941

Design Percent Load % 89

Uncontrolled SO2 Emissions (with low S coal) lbs/MMBtu 0.600

ExhaustTemperature, (o

F) T 405

Steam Turbine Power Output (TMW) MW 162

Capacity Factor (89%) hrs 7,796

Controlled SO2 Emissions lbs/MMBtu 0.13

Overall SO2 Reduction Efficiency, (%) % 78.33

Uncontrolled SO2 Emissions, (lb/hr) 1164.7

Uncontrolled SO2 Emissions, (tons/yr) 4540.1

Controlled SO2 Emissions, (ton/yr) 983.7

Annual Interest Rate, (%) 7

Equipment Life, (yrs) yr 15

Capital Recovery Factor, CRF CRF 0.1098

Unit Item

Cost Item Suggested Factor Cost Cost

IPM Model, August 20, 2010(1) Capital Cost ($/KW)(2) 1,330 $215,440,385

Cost for Pulse-Jet Fabric Filter Capital Cost ($/KW)(3) 379 $61,398,000

Equipment Cost Total, (EC) EC (Adjusted by Cost Index Calcs) (2011 dollars)(4) $285,634,195

 Total Capital Costs, TCC --- $285,634,195

 Direct Annual Costs, DAC Lime $847,165

Total waste disposal Cost $718,976

Parasitic power cost $1,243,331

Lost Ash Revenue $11.74/ton $352,200

Stack Reheat Penalty reheat to 300o

F $7,740,315

Maintenance labor $1,077,691

Maintenance materials $4,111,582

 Total Direct Annual Costs, DAC $16,091,260

Indirect Annual Costs

 Capital Recovery CRF*TCC --- $31,361,099

 Total Indirect Annual Costs, IAC $31,361,099

 Total Annual Costs, TAC = DAC + IAC $47,452,359

Cost Effectiveness ($/ton pollutant Removed) $13,343

 Cost data references:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐Dry Sorbent Injection Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

2) $/kW in 2009 dollars

3) $/kW in 2008 dollars (See Edison Electric Institute reference on page 26)

4) Cost indices used to adjust 2008 and 2009 costs to 2011 costs (2008, 2009 CI= 108.302, 109.594 2011 CI= 113.065)

Page 20
Table 4-4a

WET FGD COSTING DEVELOPMENT

DESIGN BASIS FOR CAPITAL COST

Variable Designation Units Value Equation/Input(1)

WET FGD CAPITAL COST DESIGN BASIS FOR 2 LBS/MMBTU SO2

Unit Capacity (Gross) A (MW) 162 Input

Retrofit Factor B 2 Difficulty of Retrofit

Gross heat rate C Btu/KW‐hr 11,982 Input

SO2 Emiss Rate D lbs/MMBtu 2 Uncontrolled

Type of Coal E Input

Coal Factor F PRB Coal 1.05 Input

Heat Rate Factor G 1.20 C / 10000

Heat input H MM Btu/hr 1941.1 A X C x 1000

Limestone Rate K (tons/hr) 3.40 See FGD Note 1

Waste Rate L (tons/hr) 6.16 See FGD Note 2

Aux Power M (%) 1.80 See FGD Note 8

Make Up Water N 103 gph 15.90 See FGD Note 3

Limestone Cost P ($/ton) 15.00

Waste Disposal Cost S ($/ton) 50

Aux Power Cost R ($/kWhr) 0.06

Makeup Water Cost S $/103 gal 1

Operating Labor Rate T ($/hr) 60

Basic Absorber BMR ($) $48,221,043 See FGD Note 4

Reagent Preparation BMF ($) $18,865,318 See FGD Note 5

Waste Handling Cost BMW ($) $11,319,948 See FGD Note 6

ID Fan, Other Costs BMB ($) $84,576,862 See FGD Note 7

Capital Cost BM Sum ($) $162,983,172 Base Wet FGD Module

Engineering, Construction Mgmt 10% $16,298,317

Construction Labor 10% $16,298,317

Contractor Fees 10% $16,298,317

CECC $211,878,123 Capital, Eng, and Const

Owners Cost B1 5% $10,593,906 Various home office fees

AFUDC 10% of (CECC+B1) $22,247,203

Total Project Cost $244,719,232

1,511 $/kW

Fixed Operator Cost FOMO $1,497,600 2,080 hrs‐ 12 operators

Maintenance Material $4,889,495 1.5% of BM Capital Cost

Admin Labor Cost $103,602

Auxiliary Power $175.07 $/hr

Water Cost $15.90 $/hr

Limestone Cost $323.07 Limestone cost in $/hr

Waste Disposal Cost $307.94 Waste Cost in $/hr

Notes:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐Wet FGD Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

PRB

CAPITAL EQUIPMENT COSTS

OPERATING AND MAINTENANCE COSTS

Page 21
Table 4-4b

WET FGD COSTING DEVELOPMENT

30-DAY ROLLING AVERAGE SO2 OPERATING PARAMETERS

Variable Designation Units Value Equation/Input(1)

WET FGD OPERATING VARIABLES ‐ ACTUAL OPERATION AT 0.46 LBS/MMBTU SO2

Unit Capacity (Gross) A (MW) 162 Input

Retrofit Factor B 2 Difficulty of Retrofit

Gross heat rate C Btu/KW‐hr 11,982 Input

SO2 Emiss Rate D lbs/MMBtu 0.46 Uncontrolled

Type of Coal E Input

Coal Factor F PRB Coal 1.05 Input

Heat Rate Factor G 1.20 C / 10000

Heat input H MM Btu/hr 1941.1 A X C x 1000

Limestone Rate K (tons/hr) 0.78 See FGD Note 1

Waste Rate L (tons/hr) 1.42 See FGD Note 2

Aux Power M (%) 1.42 See FGD Note 8

Make Up Water N 103 gph 15.38 See FGD Note 3

Limestone Cost P ($/ton) 15.00

Waste Disposal Cost S ($/ton) 50

Aux Power Cost R ($/kWhr) 0.06

Makeup Water Cost S $/103 gal 1

Operating Labor Rate T ($/hr) 60

Basic Absorber BMR ($) $46,824,286 See FGD Note 4

Reagent Preparation BMF ($) $12,138,988 See FGD Note 5

Waste Handling Cost BMW ($) $5,842,813 See FGD Note 6

ID Fan, Other Costs BMB ($) $84,576,862 See FGD Note 7

Capital Cost BM Sum ($) $149,382,948 Base Wet FGD Module

Engineering, Construction Mgmt 10% $14,938,295

Construction Labor 10% $14,938,295

Contractor Fees 10% $14,938,295

CECC $194,197,833 Capital, Eng, and Const

Owners Cost B1 5% $9,709,892 Various home office fees

AFUDC 10% of (CECC+B1) $20,390,772

Total Project Cost $224,298,497

1,385 $/kW

Fixed Operator Cost FOMO $1,497,600 2,080 hrs‐ 12 operators

Maintenance Material $4,481,488 1.5% of BM Capital Cost

Admin Labor Cost $98,706

Auxiliary Power $137.89 $/hr

Water Cost $15.38 $/hr

Limestone Cost $74.31 Limestone cost in $/hr

Waste Disposal Cost $70.83 Waste Cost in $/hr

Notes:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐Wet FGD Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

PRB

CAPITAL EQUIPMENT COSTS

OPERATING AND MAINTENANCE COSTS

Page 22
Table 4-4c

WET FGD COSTING DEVELOPMENT

MAXIMUM 24-HR AVERAGE SO2 OPERATING PARAMETERS

Variable Designation Units Value Equation/Input(1)

WET FGD OPERATING VARIABLES ‐ ACTUAL OPERATION AT 0.60 LBS/MMBTU SO2

Unit Capacity (Gross) A (MW) 162 Input

Retrofit Factor B 2 Difficulty of Retrofit

Gross heat rate C Btu/KW‐hr 11,982 Input

SO2 Emiss Rate D lbs/MMBtu 0.6 Uncontrolled

Type of Coal E Input

Coal Factor F PRB Coal 1.05 Input

Heat Rate Factor G 1.20 C / 10000

Heat input H MM Btu/hr 1941.1 A X C x 1000

Limestone Rate K (tons/hr) 1.02 See FGD Note 1

Waste Rate L (tons/hr) 1.85 See FGD Note 2

Aux Power M (%) 1.45 See FGD Note 8

Make Up Water N 103 gph 15.43 See FGD Note 3

Limestone Cost P ($/ton) 15.00

Waste Disposal Cost S ($/ton) 50

Aux Power Cost R ($/kWhr) 0.06

Makeup Water Cost S $/103 gal 1

Operating Labor Rate T ($/hr) 60

Basic Absorber BMR ($) $47,073,775 See FGD Note 4

Reagent Preparation BMF ($) $13,146,209 See FGD Note 5

Waste Handling Cost BMW ($) $6,584,897 See FGD Note 6

ID Fan, Other Costs BMB ($) $84,576,862 See FGD Note 7

Capital Cost BM Sum ($) $151,381,743 Base Wet FGD Module

Engineering, Construction Mgmt 10% $15,138,174

Construction Labor 10% $15,138,174

Contractor Fees 10% $15,138,174

CECC $196,796,265 Capital, Eng, and Const

Owners Cost B1 5% $9,839,813 Various home office fees

AFUDC 10% of (CECC+B1) $20,663,608

Total Project Cost $227,299,686

1,403 $/kW

Fixed Operator Cost FOMO $1,497,600 2,080 hrs‐ 12 operators

Maintenance Material $4,541,452 1.5% of BM Capital Cost

Admin Labor Cost $99,425

Auxiliary Power $140.92 $/hr

Water Cost $15.43 $/hr

Limestone Cost $96.92 Limestone cost in $/hr

Waste Disposal Cost $92.38 Waste Cost in $/hr

Notes:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐Wet FGD Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

PRB

CAPITAL EQUIPMENT COSTS

OPERATING AND MAINTENANCE COSTS

Page 23
Table 4-4d

PPL BART Cost Analysis

Wet FGD (With Low Sulfur Coal) Sulfur Dioxide Control

162 Megawatt Coal Fired Steam Electric Plant

Wet FGD at J.E. Corette

SO2 =0.46 lbs/MMBtu

Stack Exhaust Volumetric Flowrate, (acfm) Q 726,262

Maximum Gross Heat Input MM Btu/hr 1,941

Design Percent Load % 89

Uncontrolled SO2 Emissions (with low S coal) lbs/MMBtu 0.460

ExhaustTemperature, (o

F) T 405

Steam Turbine Power Output (TMW) MW 162

Capacity Factor (89%) hrs 7,796

Controlled SO2 Emissions lbs/MMBtu 0.06

Overall SO2 Reduction Efficiency, (%) % 86.96

Uncontrolled SO2 Emissions, (lb/hr) 892.9

Uncontrolled SO2 Emissions, (tons/yr) 3480.7

Controlled SO2 Emissions, (ton/yr) 454.0

Annual Interest Rate, (%) 7

Equipment Life, (yrs) yr 15

Capital Recovery Factor, CRF CRF 0.1098

Unit Item

Cost Item Suggested Factor Cost Cost

IPM Model, August 20, 2010(1) Capital Cost ($/KW)(2) 1,511 $244,719,232

Equipment Cost Total, (EC) EC (Adjusted by Cost Index Calcs) (2011 dollars)(3) $252,469,843

 Total Capital Costs, TCC --- $252,469,843

 Direct Annual Costs, DAC Limestone Cost $579,327

Waste disposal Cost $552,190

Parasitic power cost $1,075,062

Lost Ash Revenue $11.74/ton $352,200

Stack Reheat Penalty reheat to 300o

F $10,965,447

Operator and Admin Labor $1,596,306

Maintenance Materials $4,481,488

 Total Direct Annual Costs, DAC $19,602,020

Indirect Annual Costs

 Capital Recovery CRF*TCC --- $27,719,832

 Total Indirect Annual Costs, IAC $27,719,832

 Total Annual Costs, TAC = DAC + IAC $47,321,852

Cost Effectiveness ($/ton pollutant Removed) $15,635

 Cost data references:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐Wet FGD Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

2) $/kW in 2009 dollars

3) Cost indices used to adjust 2009 costs to 2011 costs (2009 CI= 109.954, 2011 CI= 113.065)

Page 24
Table 4-4e

PPL BART Cost Analysis

Wet FGD (With Low Sulfur Coal) Sulfur Dioxide Control

162 Megawatt Coal Fired Steam Electric Plant

Wet FGD at J.E. Corette

SO2 =0.60 lbs/MMBtu

Stack Exhaust Volumetric Flowrate, (acfm) Q 726,262

Maximum Gross Heat Input MM Btu/hr 1,941

Design Percent Load % 89

Uncontrolled SO2 Emissions (with low S coal) lbs/MMBtu 0.600

ExhaustTemperature, (o

F) T 405

Steam Turbine Power Output (TMW) MW 162

Capacity Factor (89%) hrs 7,796

Controlled SO2 Emissions lbs/MMBtu 0.06

Overall SO2 Reduction Efficiency, (%) % 90.00

Uncontrolled SO2 Emissions, (lb/hr) 1164.7

Uncontrolled SO2 Emissions, (tons/yr) 4540.1

Controlled SO2 Emissions, (ton/yr) 454.0

Annual Interest Rate, (%) 7

Equipment Life, (yrs) yr 15

Capital Recovery Factor, CRF CRF 0.1098

Unit Item

Cost Item Suggested Factor Cost Cost

IPM Model, August 20, 2010(1) Capital Cost ($/KW)(2) 1,511 $244,719,232

Equipment Cost Total, (EC) EC (Adjusted by Cost Index Calcs) (2011 dollars)(3) $252,469,843

 Total Capital Costs, TCC --- $252,469,843

 Direct Annual Costs, DAC Limestone Cost $755,644

Waste disposal Cost $720,248

Parasitic power cost $1,098,646

Lost Ash Revenue $11.74/ton $352,200

Stack Reheat Penalty reheat to 300o

F $10,965,447

Operator and Admin Labor $1,596,306

Maintenance Materials $4,541,452

 Total Direct Annual Costs, DAC $20,029,943

Indirect Annual Costs

 Capital Recovery CRF*TCC --- $27,719,832

 Total Indirect Annual Costs, IAC $27,719,832

 Total Annual Costs, TAC = DAC + IAC $47,749,775

Cost Effectiveness ($/ton pollutant Removed) $11,686

 Cost data references:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for APC

Technologies‐Wet FGD Cost Development Methodology‐FINAL", August 2010

Project 12301‐007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

2) $/kW in 2009 dollars

3) Cost indices used to adjust 2009 costs to 2011 costs (2009 CI= 109.954, 2011 CI= 113.065)

Page 25