### 

	






# 		

	





#   	

		 	
		
			 




### 


	





!
"#"# $
%
"#"#&


'(

)
"*

### 



# 		
 	





# 	
 		 	 
		
			 
ES-1 EXECUTIVE SUMMARY

As part of the Best Available Retrofit Tec hnology (BART) assessment for the J.E. Corette (Corette) coal-fired steam electric plant, an economi c cost effectiveness analysis was performed in an initial report dated August 2007. U pon 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 SO 2 controls for Corette. This Addendum to the initial reports provides an updated assessment to address SO 2 control costs.

The Corette power plant, located in Billings, Mo ntana, is owned and operated by PPL Montana, LLC. The coal-fired boiler at the plant was determin ed 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 analys is 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 M odel”. See the following link for more details:

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

ICF International (ICF) developed the IPM to assess th e 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 curren tly available information, the control technology cost estimation techniques developed for the IPM app ear 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 fo r dry injection, spray dryer absorption, and wet flue gas desulfurization control technologies. These cost s 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 m odeling 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 repres entative of site-specific cost effectiveness, weES-2 

### are providing the 24-hour cost calculation as requested. The 30-day running average SO 2 

### emission

rate is 0.46 lbs SO 2 

### /MMBtu and the 24-hour emission rate is 0.60 lbs SO 2 

### /MMBtu.

For this updated assessment, we have evaluate d three technologies for cost effectiveness in reducing sulfur dioxide (SO 2 ) emissions. The results are discussed below. The details of the cost

effectiveness calculations for each c ontrol 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 scrubbe r would decrease plume buoyancy significantly. Consequently, a significant amount of reheat would need to be applied in orde r to meet stipulated SO 2 and plume buoyancy requirements. In addition to the high cost for FGD, there are significant site constraints that effectively eliminate this technology from any fu rther 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 SO 2 . These injected reagents, plus the sulfates formed from the SO 2 absorption, will result in increased particulate loading to and emissions from the cont rol device which is currently an electrostatic precipitator. Controlling the additional particulat e will likely require particulate control equipment upgrades. SDA will also likely require plume reheat, wh ich 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 plum e 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 sy stem is estimated to reduce SO 2 emissions to about 0.26 lbs

SO 2 /MMBtu with a cost effectiveness of approximately $10,920 per ton of SO 2 removed on an annualized basis. The spray dryer absorptio n - SDA system is estimated to reduce emissions to about 0.13 lbs

SO 2 /MMBtu with a cost effectiveness of approximately $18,839 per ton of SO 2 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 SO 2 emission reductions achieved by the evaluated control technologies in this addendum is within the range of SO 2 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 SO 2 controls is not warranted.ii TABLE OF CONTENTS

SECTION PAGE

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

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

2.0 RECENT DE VELOPMENTS ...................................................................................................... 2 2.1 The IPM Approach to the Costing of Air Pollution Controls ....................................................... 2 2.2 Spray Dryer Absorbers and We t 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 ................................................................................................................ ........... 26iii TABLE OF CONTENTS (Continued)

FIGURES

2.0-1 Illustrative Dry Sc rubber 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 SO 2 Control – Design Case for Capital Cost ........................................................ 11 4-2b Dry Injection SO 2 Control – 30-day Average SO 2 Operational Parameters ............................... 12 4-2c Dry Injection SO 2 Control – Max 24-hr Average SO 2 Operational Parameters ......................... 13 4-2d Dry Injection SO 2 Control – 30-day Rolling Average SO 2 – Cost Effectiveness Calculations .. 14 4-2e Dry Injection SO 2 Control – Max 24-hr Average SO 2 - Cost Effectiveness Calculations ......... 15 4-3a SDA SO 2 Control – Design Case for Capital Cost ..................................................................... 16 4-3b SDA SO 2 Control – 30-day Average SO 2 Operational Parameters ............................................ 17 4-3c SDA SO 2 Control – Max 24-hr Average SO 2 Operational Parameters ...................................... 18 4-3d SDA SO 2 Control – 30-day Rolling Average SO 2 – Cost Effectiveness Calculations ............... 19 4-3e SDA SO 2 Control – Max 24-hr Average SO 2 - Cost Effectiveness Calculations ....................... 20 4-4a Wet FGD SO 2 Control – Design Case for Capital Cost.............................................................. 21 4-4b Wet FGD SO 2 Control – 30-day Average SO 2 Operational Parameters ..................................... 22 4-4c Wet FGD SO 2 Control – Max 24-hr Average SO 2 Operational Parameters ............................... 23 4-4d Wet FGD SO 2 Control – 30-day Rolling Average SO 2 – Cost Effectiveness Calculations ........ 24 4-4e Wet FGD SO 2 Control – Max 24-hr Average SO 2 - 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 20101 

### 1.0 BACKGROUND

In August 2007, TRC prepared a BART analysis for PPL Montana, LLC that contained cost analyses for potential control of SO 2 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 t echnologies. 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 in formation 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 SO 2 control, EPA requested revisions to the capital cost amortization from 11 to 15 years, and analysis of higher SO 2 control efficiencies. No additional references for developing the cost of SO 2 control equipment were identified in the EPA letter or in the TRC response to the EPA request. EPA suggested th at 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 g as 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 SO 2 controls for Corette. The results of the cost development for the IPM study show s that costs have increased for the installation of retrofit control equipment and the more robust anal ytical 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 SO 2 , the gas absorber costing techniques were limited to industrial applications with up to approximately 200,000 acfm of exhaust flow. Utility a pplications of flue gas desulfurization (FGD) using wet scrubbing were inst alled and operating on utilit y boilers in the USA, however, no compilation of the cost of su ch utility sized systems was available.

Using costing tools available at that time, anal yses 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 availa ble planning tools to study the universe of

environmental effects that rules such as the Clean Ai r 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 illust rative 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 th e cost analysis techniques to coal-fired plants of 5 values of gross power output from 100 to 1,000 megawa tts (MW). Figure 2.0-1 is the total capital cost for equipment and installation and Figure 2.0-2 s hows 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 sma ll capacity plants. Appendices to the EPA summary document contain the detailed equations used in the co st 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 w hole. 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 cont rol 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 su mmary of this report. For SO 2 , APCE cost analyses for two control technologies are presented; lime spray dryer absorp tion (SDA), and wet flue gas desulfurization (wet
FGD).3 

### Figure 2.0-1 Illustrative Dr y Scrubber Capital Costs4 

### Figure 2.0-2 Illustrative Dry Scrubber O&M Costs5 Greater detail regarding the IPM is included in th ree appendices to this document. Each appendix includes the analytical equations used by the e ngineering firm Sargent & Lundy (S&L) in their background studies upon which EPA based their contro l cost analyses. These appendices allow users to calculate cost estimations for plant specific data. Th erefore, using the S&L equations, cost estimations were compiled for the Corette boiler.

2.2 Dry Sorbent Injection, Spray Dryer Absorb ers, 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 de vice. The chemical reagent reacts with SO 2 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 SO 2 to form solid sulfates. Unreacted lime a nd sulfate solids together with coal fly ash are then collected in the particul ate APCD. System performance is limited by the capacity and type of particulate control equipment which is either an elect rostatic 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 to tally evaporate into the gas stream. In a wet FGD system, a solution of limestone in water is intimately placed in contact with the SO 2 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 su m to provide the total capital and engineering cost of an installation.
These include the absorber island, th e 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 SO 2 

### control in 2012. This technology is not commercially available at this time and any perfo rmance/costs estimates that are published are specifically related to a pilo t study conducted at Martin Dr ake #7. Full scale, commercial numbers on performance and cost will not be availabl e until after 2012.6 

### 3.0 APPENDICES TO THE IPM COST APPROACH

The IPM costing approach to SO 2 control includes more detailed analytical tools for cost determinations than is provided in the summa ry 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 th e 162 MW Corette Powder River Basin (PRB) coalfired steam generating unit.

Each document provides a concise summary of the a pproach to the cost development analysis, the empirical equations used in the approach, and an exam ple 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 insta llation 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 pr ovided 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 assum es 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 SO 2 control technologies. Specifically, this s ite is constrained by a river to the east, a railroad to the west, and a small plant footprin t. 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 em issions from that control device will increase if either

SO 2 control option is installed. This will likely requ ire an upgrade to the particulate control device to accompany one of those control options. In the Janua ry 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 in creases the $/ton estimates of cost effectiveness for each of these possible SO 2 control options. Although su ch unintended consequences of secondary pollutant generation and the necessity of particulate control equipment upgra des were not considered in application of the IPM7 model cost analyses by Sargent & Lundy , LLC for these SO 2 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 SO 2 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 SO 2 (1% as S). Therefore, any SO 2 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 SO 2 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 SO 2 can be attained if a fabric filter is used for particulate control. However, at lower inlet SO 2 loadings this efficiency is reduced and for purposes of this evaluation, we have estimated that an outlet emission rate of 0.26 lbs SO 2 /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 lik e Corette, the S&L model de velopment document seems

to indicate that a maximum of 40 to 50% SO 2 removal can be realized wit hout an increase in particulate emissions. However, for purposes of this evaluati on, 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 th e 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 so rbent of choice where greater than 50% control of

SO 2 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 injec tion 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 SO 2 concentration. Therefore, the empirical equations from S&L show that the capital costs are directly related to the trona8 injection rate. This technology op tion in particular must be oversi zed to accommodate potential inlet SO 2 concentrations up to the allowable limit of 2 lb s/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 met hod includes a spray chamber, a lime/water mixing module, and waste handling equipment. While th e costing analysis is based on 2 lbs/MMBtu SO 2 , as in the case of dry injection, the operation of a system sized for 2 lbs/MMBtu SO 2 will be less cost effective when operated at the actual 30-day rolling average or even the maximum 24-hr SO 2 emission rate.

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

to reduce SO 2 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 SO 2 exhaust. As in the case of dry sorbent injection, particulate control using fabric filtr ation allows higher absorption of SO 2 by the effect of the filter cake on the absorption. Application of this technology wi ll 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 temp erature. The water injected partially saturates the exhaust, but only to within 50 degrees of the satura tion 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 th e 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 deve lopment of the cost estimation techniques in the EPA Fact Sheet used in the previous co st analyses by PPL. The cost an alysis development for the IPM by S&L uses industry cost estimates not available un til after the Srivastava studies that only produced the very broad ranges of costs.

Local SO 2 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 exha ust gas stack. Added retrofit costs to address plume buoyancy and the space required will significantly in crease the cost of this technology making it

infeasible for the Corette Plant.

The cost assessment has b een based on a LSFO outlet SO 2 emission rate of 0.06 lbs/MMBtu.9 

### 4.0 COSTING ANALYSIS TABLES

Table 4-1 summarizes the equations used to calcula te the control costs for each control technique as developed by S&L for the IPM. The cost develo pment for each control technology is described by 5 spreadsheets labeled “a” through “e”. The first thr ee 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 re present 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 SO 2 . Although Corette uses 0.3% S PRB coal, the allowable sulfur content is 1% and therefore any SO 2 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 co al 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 SO 2 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 SO 2 concentration and the maximum 24-hr average SO 2 inlet values of 0.46 and 0.60 lbs/MMBtu respectively.

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

lbs/MMBtu SO 2 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 10 3 gals/hr} 

### 4 Basic spray dryer equipment = $566,000 x A 0.716 x B x (1.18) 0.6 x (D/4) 0.01 

### 5 Reagent prep equip cost = $300,000 x A 0.716 x B x (D x G) 0.2 

### 6 Balance of SDA equipment = $799,000 x A 0.716 x B x (F x G) 0.6


### 7 Aux power to run equipment = (0.000547 x D 2 + 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 10 3 gals/hr) 

### 4 Basic absorber cost = $550,000 x A 0.716 x B x (F X G) 0.6 x (D/2) 0.02 

### 5 Reagent prep equip cost = $190,000 x A 0.716 x (D x G) 0.3 

### 6 Basic waste handling cost = $100,000 x A 0.716 x B x (D x G) 0.45


### 7 Balance of plant cost = $1,010,000 x B x A 0.716 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 SO 2 Unit Capacity (Gross) A (MW) 162 Input Retrofit Factor B 2 Difficulty of Retrofit
Gross heat rate C Btu/KW

‐ hr 11,982 Input
SO 2 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 SO 2 Unit Capacity (Gross) A (MW) 162 Input Retrofit Factor B 2 Difficulty of Retrofit
Gross heat rate C Btu/KW

‐ hr 11,982 Input
SO 2 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 SO 2 

### OPERATIONAL PARAMETERS

Variable Designation Units Value Equation/Input (1)

DRY INJECTION OPERATING VARIABLES ‐ ACTUAL OPERATION AT 0.60 LBS/MMBTU SO 2 Unit Capacity (Gross) A (MW) 162 Input Retrofit Factor B 2 Difficulty of Retrofit
Gross heat rate C Btu/KW

‐ hr 11,982 Input
SO 2 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 13Table 4-2d PPL BART Cost Effectiveness Analysi s Dry Injection (With Low Sulfur Coal) Sulfur Dioxide Control 162 Megawatt Coal Fired Steam Electric Plant Trona Injection With Precipitator Replacement at J.E. Corett e SO 2 =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 AP C Technologies

‐ Dry Sorbent Injection Cost Development Methodology

‐ FINAL", August 201 0 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 14Table 4-2e PPL BART Cost Effectiveness Analysi s Dry Injection (With Low Sulfur Coal) Sulfur Dioxide Control 162 Megawatt Coal Fired Steam Electric Plant Trona Injection With Precipitator Replacement at J.E. Corett e SO 2 =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 AP C Technologies

‐ Dry Sorbent Injection Cost Development Methodology

‐ FINAL", August 201 0 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 SO 2 Unit Capacity (Gross) A (MW) 162 Input Retrofit Factor B 2 Difficulty of Retrofit
Gross heat rate C Btu/KW

‐ hr 11,982 Input
SO 2 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 10 3 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 $/10 3 gal 1 Input Operating Labor Rate T ($/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 SO 2 

### OPERATING PARAMETERS
Variable Designation Units Value Equation/Input (1)

LIME SPRAY DRYER OPERATING VARIABLES ‐ ACTUAL OPERATION AT 0.46 LBS/MMBTU SO 2 Unit Capacity (Gross) A (MW) 162 Input Retrofit Factor B 2 Difficulty of Retrofit
Gross heat rate C Btu/KW

‐ hr 11,982 Input
SO 2 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 10 3 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 $/10 3 gal 1 Input Operating Labor Rate T ($/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 SO 2 

### OPERATING PARAMETERS
Variable Designation Units Value Equation/Input (1)

LIME SPRAY DRYER OPERATING VARIABLES ‐ ACTUAL OPERATION AT 0.60 LBS/MMBTU SO 2 Unit Capacity (Gross) A (MW) 162 Input Retrofit Factor B 2 Difficulty of Retrofit
Gross heat rate C Btu/KW

‐ hr 11,982 Input
SO 2 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 10 3 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 $/10 3 gal 1 Input Operating Labor Rate T ($/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 18Table 4-3d PPL BART Cost Effectiveness Analysi s Lime Spray Drying (With Low Sulfur Coal) Sulfur Dioxide Contro l 162 Megawatt Coal Fired Steam Electric Plant Lime Spray Drying With Precipitator Replacement at J.E. Corett e SO 2 =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 300 o 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 AP C Technologies

‐ Dry Sorbent Injection Cost Development Methodology

‐ FINAL", August 201 0 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 19Table 4-3e PPL BART Cost Analysi s Lime Spray Drying (With Low Sulfur Coal) Sulfur Dioxide Contro l 162 Megawatt Coal Fired Steam Electric Plant Lime Spray Drying With Precipitator Replacement at J.E. Corett e SO 2 =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 300 o 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 AP C Technologies

‐ Dry Sorbent Injection Cost Development Methodology

‐ FINAL", August 201 0 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 SO 2 Unit Capacity (Gross) A (MW) 162 Input Retrofit Factor B 2 Difficulty of Retrofit
Gross heat rate C Btu/KW

‐ hr 11,982 Input SO 2 E m i ss R a t e D lb s / MMBtu 2 Uncontro ll e d 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 10 3 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 $/10 3 gal 1 Operating Labor Rate T ($/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 SO 2 

### OPERATING PARAMETERS
Variable Designation Units Value Equation/Input (1)

WET FGD OPERATING VARIABLES ‐ ACTUAL OPERATION AT 0.46 LBS/MMBTU SO 2 Unit Capacity (Gross) A (MW) 162 Input Retrofit Factor B 2 Difficulty of Retrofit
Gross heat rate C Btu/KW

‐ hr 11,982 Input SO 2 E m i ss R a t e D lb s / MMBtu 0.46 Uncontro ll e d 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 10 3 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 $/10 3 gal 1 Operating Labor Rate T ($/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 SO 2 

### OPERATING PARAMETERS
Variable Designation Units Value Equation/Input (1)

WET FGD OPERATING VARIABLES ‐ ACTUAL OPERATION AT 0.60 LBS/MMBTU SO 2 Unit Capacity (Gross) A (MW) 162 Input Retrofit Factor B 2 Difficulty of Retrofit
Gross heat rate C Btu/KW

‐ hr 11,982 Input SO 2 E m i ss R a t e D lb s / MMBtu 0.6 Uncontro ll e d 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 10 3 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 $/10 3 gal 1 Operating Labor Rate T ($/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 23Table 4-4d PPL BART Cost Analysi s Wet FGD (With Low Sulfur Coal) Sulfur Dioxide Control 162 Megawatt Coal Fired Steam Electric Plant Wet FGD at J.E. Corette

SO 2 =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 300 o 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 AP C Technologies

‐ Wet FGD Cost Development Methodology

‐ FINAL", August 201 0 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 24Table 4-4e PPL BART Cost Analysi s Wet FGD (With Low Sulfur Coal) Sulfur Dioxide Control 162 Megawatt Coal Fired Steam Electric Plant Wet FGD at J.E. Corette

SO 2 =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 300 o 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 AP C Technologies

‐ Wet FGD Cost Development Methodology

‐ FINAL", August 201 0 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 2526 

### 5.0 REFERENCES

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

2) Srivastava, Ravi K., SO 2 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 Impact s of Environmental Regulations on the U.S. Generation Fleet, ICF International, January 2011, pg. 33.

5) EPA Control Cost Manual, 6 th 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 a nd 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 • Ch icago, 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 • Chic ago, IL 60603 USA • 312-269-2000LEGAL 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.

### Project No. 12301-007 IPM Model – Revisions to Cost and Performance for APC Technologies August 20, 2010 

### Wet FGD Cost Development Methodology – Final

Page 1 

### Establishment of Cost Basis The 2004 to 2006 industry cost estimat es for wet FGD units from the " 

### Analysis of MOG and Ladco's FGD and SCR Capacity and Cost Assump tions 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 simila r trends versus genera ting capacity. Escalation based on the CEPI was deemed acceptable. All th ree 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 SO 2 

### 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;

• SO 2 

### Rate = 3.0 lb/MMBtu;

• Type of Coal = Bituminous;

• Project Execution = Multiple lump sum contracts; and

• Recommended SO 2 

### 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 accomplishe d by; treating smaller units at a single site with one wet FGD system, switching to a lower sulfur coal, repower ing 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 premis e that these will be combined.

### Project No. 12301-007 IPM Model – Revisions to Cost and Performance for 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 retrof it costs. The gross unit size in MW (equivalent acfm) and sulfur content of th e fuel are the major variables for the capital estimation. A retrofit factor that equates to difficulty in constr uction of the system must be defined. The costs herein could increase signific antly for congested sites. The gross unit heat rate will factor into the amount of flue gas generated and ultima tely the size of the absorber, reagent preparation, wast e handling, and balance of plant costs. The SO 2 

### rate will have the greatest influence on the reagent handling and wa ste handling facilities. The type of fuel (Bituminous, PRB, or Lignite) will influence the fl ue gas quantities as a result of the different typical heating values.

The evaluation includes a user se lected 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 fo r each required module (BM_). The base installed costs include:

• All equipment;

• Installation;

• Buildings;

• Foundations;

• Electrical;

• Minor physical and chemical wast ewater 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

### Project No. 12301-007 IPM Model – Revisions to Cost and Performance for 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 prem ium, per diem, etc., at 10% of the BM cost; and

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

A capital, engineering, and construc tion cost subtotal (CECC) is established as the sum of the BM and the additional engin eering 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 engine ering, management, and procurement) at 5% of the CECC; and

• Allowance for Funds Used During Constr uction (AFUDC) at 10% of the CECC and owner's costs. The AFUDC is based on a three-year engineer ing and construction cycle.

The total project cost is base d on a multiple lump sum contract approach. Should a turnkey engineering procurement constructio n (EPC) contract be executed, th e 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 fina ncing expenditures. Table 1 c ontains an example capital cost estimation.Project No. 12301-007IPM Model – Revisions toCost and Performance forAPC TechnologiesAugust 20, 2010Wet FGD Cost Development Methodology – FinalPage 4Table 1. Example Capital Cost Estimate for the Wet FGD System (Costs are all based on 2009 dollars)

### Project No. 12301-007 IPM Model – Revisions to Cost and Performance for 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 extensiv e wastewater treatment facility. At this time, the wastewater treatment fixed O&M (FOM WW) 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 larg er 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 f unction of the FOMO and FOMM.

Variable O&M (VOM) 

### Variable O&M is a function of:

• Reagent use and unit costs;

• Waste production and un it disposal costs;

• Additional power required and unit power cost; and

• Makeup water required and unit water cost.

### Project No. 12301-007 IPM Model – Revisions to Cost and Performance for 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 func tion of gross unit size, SO 2 

### feed rate, and removal efficiency. The estimated reagent usage was based on a sulfur removal efficiency of 98% and a calcium-to-sulf ur stoichiometric ratio of 1.03. The basis for the limestone purity was 90% CaCO 3 

### 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 re quirement 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 ba se 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 (incl uding all benefits) in $/hr.

### Project No. 12301-007 IPM Model – Revisions to Cost and Performance for APC Technologies August 20, 2010 

### Wet FGD Cost Development Methodology – Final

Page 7 The variables that contribut e 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 incl uded to account for an extensive wastewater treatment facility. At this time, the wastewater treatment variable O&M (VOMWW) is not estimated and is incl uded at zero dollars.

The total VOM is the sum of VOMR, VOM W, VOMP, VOMM, and VOMWW. Table 2 contains an example O&M cost estimate, wh ile Table 3 is a complete capital and O&M cost estimate worksheet.Project No. 12301-007IPM Model – Revisions toCost and Performance forAPC TechnologiesAugust 20, 2010Wet FGD Cost Development Methodology – FinalPage 8Table 2. Example O&M Cost Estimate for the WetFGD System (Costs are all based on 2009 dollars)Project No. 12301-007IPM Model – Revisions toCost and Performance forAPC TechnologiesAugust 20, 2010Wet FGD Cost Development Methodology – FinalPage 9Table 3. Example Complete Cost Estimate for theWet FGD System (Costs are all based on 2009 dollars)Project No. 12301-007IPM Model – Revisions toCost and Performance forAPC TechnologiesAugust 20, 2010Wet FGD Cost Development Methodology – FinalPage 10LEGAL 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.

### Project No. 12301-007 IPM Model – Revisions to Cost and Performance for 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 li mited than that for the wet FGD systems. A similar trend with generating capacity is genera lly 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 th e inlet sulfur. It should be noted that the lowest available SO 2 

### emission guarantees, from the original equipm ent 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;

• SO 2 

### Rate = 2.0 lb/MMBtu;

• Type of Coal = PRB; and

• Project Execution = Multiple lump sum contracts; and

• Recommended SO 2 

### 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 accomplishe d by; treating smaller units at a single site with one SDA FGD system, switching to a lower sulfur coal, repower ing 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 t echnology should not be applied to fuels with more than 3 lb SO 2 

### /MMBtu and the cost estimator should be limited to fuels with less than 3 lb SO 2 

### /MMBtu.

An alternate dry technology, circulating dry sc rubber (CDS), can meet removals of 98% or greater over a large range of inle t sulfur concentrations. It sh ould be noted that the lowest SO 2 

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



### Methodology Inputs Several input variables are required in order to predict future retrof it costs. The gross unit size in MW (equivalent acfm) and sulfur content of th e fuel are the major variables for the capital estimation. A retrofit factor th at equates to difficulty in cons truction of the system must be defined. The costs herein could increase signific antly for congested sites. The unit gross heat rate will factor into the amount of flue gas generated and ultima tely the size of the absorber, reagent preparation, wast e handling, and balance of plant costs. The SO 2 

### rate will have the greatest influence on the reagent handling and wa ste handling facilities. The type of fuel (Bituminous, PRB, or Lignite) will influence the fl ue gas quantities as a result of the different typical heating values.

### Project No. 12301-007 IPM Model – Revisions to Cost and Performance for 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 fo r 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 prem ium, per diem, etc., at 10% of the BM cost; and

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

A capital, engineering, and construc tion cost subtotal (CECC) is established as the sum of the BM and the additional engin eering 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 engine ering, management, and procurement) at 5% of the CECC; and

• Allowance for Funds Used During Constr uction (AFUDC) at 10% of the CECC and owner's costs. The AFUDC is based on a three-year engineer ing and construction cycle.

### Project No. 12301-007 IPM Model – Revisions to Cost and Performance for APC Technologies August 20, 2010 

### SDA FGD Cost Development Methodology – Final

Page 3 The total project cost is base d on a multiple lump sum contract approach. Should a turnkey engineering procurement constructio n (EPC) contract be executed, th e 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 fina ncing expenditures. Table 1 c ontains an example capital cost estimation.Project No. 12301-007IPM Model – Revisions toCost and Performance forAPC TechnologiesAugust 20, 2010SDA FGD Cost Development Methodology – FinalPage 4Table 1. Example Capital Cost Estimate for the SDA FGD System (Costs are all based on 2009 dollars)

### Project No. 12301-007 IPM Model – Revisions to Cost and Performance for 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 ar e 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 f unction of the FOMO and FOMM.

Variable O&M (VOM) 

### Variable O&M is a function of:

• Reagent use and unit costs;

• Waste production and un it 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 func tion of gross unit size, SO 2 

### 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 satura tion of 30°F. The calcium-to-sulfur stoichiometric ratio varies based on inlet sulfur. The variation in stoichiometric ratio was accounted fo r in the estimation. The economic estimation is only valid up to 3 lb SO 2 

### /MMBtu inlet. The basis for the lime purity was 90% CaO with the ba lance being inert material.

### Project No. 12301-007 IPM Model – Revisions to Cost and Performance for 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 a ccounted 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 re quirement 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 ba se 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 (incl uding all benefits) in $/hr.

The variables that contribut e 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.Project No. 12301-007IPM Model – Revisions toCost and Performance forAPC TechnologiesAugust 20, 2010SDA FGD Cost Development Methodology – FinalPage 7Table 2. Example O&M Cost Estimate for the SDAFGD System (Costs are all based on 2009 dollars)Project No. 12301-007IPM Model – Revisions toCost and Performance forAPC TechnologiesAugust 20, 2010SDA FGD Cost Development Methodology – FinalPage 8Table 3. Example Complete Cost Estimate for theSDA FGD System (Costs are all based on 2009 dollars)Project No. 12301-007IPM Model – Revisions toCost and Performance forAPC TechnologiesAugust 20, 2010SDA FGD Cost Development Methodology – FinalPage 9

## IPM Model – Revisions to Cost a nd 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 • Ch icago, IL 60603 USA • 312-269-2000LEGAL 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 degr ee 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.

### Project No. 12301-007 IPM Model – Revisions to Cost and Performance for APC Technologies August 20, 2010 

### Dry Sorbent Injection Cost De velopment Methodology – Final

Page 3 

### Technology Description Dry sorbent injection (DSI) is a viable technology for moderate SO 2 

### reduction on coal fired boilers. Demonstrations and r ecent utility testing have shown SO 2 

### 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 particulat e capture device. NS R is defined as:

The target removal efficiency is a requiremen t from the utility and is independent of unit size. The costs for a DSI system are primaril y dependant on sorbent fe ed rate which is a function of NSR and SO 2 

### mass feed rate per hour. Ther efore, the cost estimation was based on sorbent feed ra te and not on unit size.

The sorbent solids can be collected in either an ESP or a baghouse. Baghouses generally achieve greater SO 2 

### 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 effi ciency with Trona, the NSR is reduced when a baghouse is used for particulate capture.

The dry sorbent capture ability is also a functi on of particle surface area. To increase the particle surface area, the sorb ent must be heated. Heati ng the solids produ ces micropores on the particle surface which greatly improve the sulfur capture ability. For Trona, the sorbent should be injected into flue ga s 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 μ m. Commercial testing has shown that the reactivity of the Trona can be incr eased when the sorbent is ground to less than 30 μ m. In the cost estimati ng 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 delivere d cost of the Trona will not change, only the reactivity and usage changes as the Trona is milled.

### Project No. 12301-007 IPM Model – Revisions to Cost and Performance for APC Technologies August 20, 2010 

### Dry Sorbent Injection Cost De velopment Methodology – Final

Page 4 Ultimately, the NSR required for a given removal is a function of Trona particle size and particulate capture equi pment. Either as delivered Trona (around 30 μ m average size) or in-line milled Trona (around 15 μ m average size) can be chosen for injection in the cost program. The average Trona particle size and the type of particulat e removal both contribute to the predic ted 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. W ith 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 sorb ent feed rate is a f unction of su lfur rate, particulate collection device, a nd removal efficiency. To account for all of the variables, the capital cost was established based on a sorb ent feed rate. The sorbent feed rate is calculated from user input variables. Cost data for several DSI systems was reviewed and a relationship was de veloped for the capital costs of the system on a sorbent feed rate basis.



### Methodology Inputs Several input variables are required in order to predict fu ture retrofit costs. The sulfur feed rate and NSR are the major variables fo r 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 fa ctor into the amount of sulfur generated.

Based on commercial testing, remo val efficiencies with DSI ar e limited by the particulate capture device employed. Wh en the sorbent is captured in an ESP, a 40 to 50% SO 2 

### 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 sulf ur content of greater than 2 lb SO 2 

### /MMBtu.

### Project No. 12301-007 IPM Model – Revisions to Cost and Performance for APC Technologies August 20, 2010 

### Dry Sorbent Injection Cost De velopment Methodology – Final

Page 5 The equations provided in the cost methodology spreadsheet a llow the user to input the required removal efficiency, within the limits of the t echnology. 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 increas e 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 sel ection of in-line milling equipment. The base installed cost is then increased by:

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

• Labor adjustment for 6 x 10 hour shift pr emium, per diem, etc., at 5% of the BM cost; and

• Contractor profit and fees at 5% of the BM cost.

### Project No. 12301-007 IPM Model – Revisions to Cost and Performance for APC Technologies August 20, 2010 

### Dry Sorbent Injection Cost De velopment Methodology – Final

Page 6 A capital, engineering, and cons truction cost subtotal (CECC) is established as the sum of the BM and the additional engi neering and construction fees.

Additional costs and financi ng expenditures for the project are computed based on the CECC. Financing and additi onal 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 (A FUDC) 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 procurem ent construction (EPC) contra ct 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 main tenance (O&M) cost is a function of the additional operations staff (FOMO), main tenance labor and materials (FOMM), and administrative labor (FOMA) associated with the DSI inst allation. The FOM is the sum of the FOMO, FOMM, and FOMA.

The following factors and assumptions underlie calc ulations 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 numb er of additional opera tions staff required.

• The fixed maintenance materi als and labor is a direct function of the process capital cost (BM).

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

### Project No. 12301-007 IPM Model – Revisions to Cost and Performance for APC Technologies August 20, 2010 

### Dry Sorbent Injection Cost De velopment 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 require d and unit power cost.

The following factors and assumptions underlie calc ulations 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 SO 2 

### feed rate. The gross unit size and gross heat rate factor multiplied by the SO 2 

### rate determine the SO 2 

### feed rate. The estimated NSR is a function of removal efficien cy required. The basis for the total reagent ra te is a Trona purity of 98%.

• The waste generation rate is a function of the Trona fe ed rate and is adjusted for the excess sorbent fed. The wast e generation ra te is based on reaction products of Na 2 

### SO 4 

### and unreacted dr y sorbent as Na 2 

### CO 3


### .

• With the addition of a sodium sorb ent, 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 producti on is added to the sorbent waste to account for a total waste st ream 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 ba se 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 be nefits) in $/hr.

### Project No. 12301-007 IPM Model – Revisions to Cost and Performance for APC Technologies August 20, 2010 

### Dry Sorbent Injection Cost De velopment 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 co ntains an example of the complete capital and O&M cost estimate worksheet.Project No. 12301-007IPM Model – Revisions toCost and Performance forAPC TechnologiesAugust 20, 2010Dry Sorbent Injection Cost Development Methodology – FinalPage 9Table 1. Example Complete Cost Estimate for a DSI System(Costs are all based on 2009 dollars)Project No. 12301-007IPM Model – Revisions toCost and Performance forAPC TechnologiesAugust 20, 2010Dry Sorbent Injection Cost Development Methodology – FinalPage 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 10 3 gals/hr} 

### 4 Basic spray dryer equipment = $566,000 x A 0.716 x B x (1.18) 0.6 x (D/4) 0.01 

### 5 Reagent prep equip cost = $300,000 x A 0.716 x B x (D x G) 0.2 

### 6 Balance of SDA equipment = $799,000 x A 0.716 x B x (F x G) 0.6


### 7 Aux power to run equipment = (0.000547 x D 2 + 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 10 3 gals/hr) 

### 4 Basic absorber cost = $550,000 x A 0.716 x B x (F X G) 0.6 x (D/2) 0.02 

### 5 Reagent prep equip cost = $190,000 x A 0.716 x (D x G) 0.3 

### 6 Basic waste handling cost = $100,000 x A 0.716 x B x (D x G) 0.45


### 7 Balance of plant cost = $1,010,000 x B x A 0.716 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 SO 2 Unit Capacity (Gross) A (MW) 162 Input Retrofit Factor B 2 Difficulty of Retrofit
Gross heat rate C Btu/KW

‐ hr 11,982 Input
SO 2 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 SO 2 Unit Capacity (Gross) A (MW) 162 Input Retrofit Factor B 2 Difficulty of Retrofit
Gross heat rate C Btu/KW

‐ hr 11,982 Input
SO 2 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 SO 2 

### OPERATIONAL PARAMETERS

Variable Designation Units Value Equation/Input (1)

DRY INJECTION OPERATING VARIABLES ‐ ACTUAL OPERATION AT 0.60 LBS/MMBTU SO 2 Unit Capacity (Gross) A (MW) 162 Input Retrofit Factor B 2 Difficulty of Retrofit
Gross heat rate C Btu/KW

‐ hr 11,982 Input
SO 2 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 13Table 4-2d PPL BART Cost Effectiveness Analysi s Dry Injection (With Low Sulfur Coal) Sulfur Dioxide Control 162 Megawatt Coal Fired Steam Electric Plant Trona Injection With Precipitator Replacement at J.E. Corett e SO 2 =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 AP C Technologies

‐ Dry Sorbent Injection Cost Development Methodology

‐ FINAL", August 201 0 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 14Table 4-2e PPL BART Cost Effectiveness Analysi s Dry Injection (With Low Sulfur Coal) Sulfur Dioxide Control 162 Megawatt Coal Fired Steam Electric Plant Trona Injection With Precipitator Replacement at J.E. Corett e SO 2 =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 AP C Technologies

‐ Dry Sorbent Injection Cost Development Methodology

‐ FINAL", August 201 0 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 SO 2 Unit Capacity (Gross) A (MW) 162 Input Retrofit Factor B 2 Difficulty of Retrofit
Gross heat rate C Btu/KW

‐ hr 11,982 Input
SO 2 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 10 3 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 $/10 3 gal 1 Input Operating Labor Rate T ($/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 SO 2 

### OPERATING PARAMETERS
Variable Designation Units Value Equation/Input (1)

LIME SPRAY DRYER OPERATING VARIABLES ‐ ACTUAL OPERATION AT 0.46 LBS/MMBTU SO 2 Unit Capacity (Gross) A (MW) 162 Input Retrofit Factor B 2 Difficulty of Retrofit
Gross heat rate C Btu/KW

‐ hr 11,982 Input
SO 2 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 10 3 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 $/10 3 gal 1 Input Operating Labor Rate T ($/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 SO 2 

### OPERATING PARAMETERS
Variable Designation Units Value Equation/Input (1)

LIME SPRAY DRYER OPERATING VARIABLES ‐ ACTUAL OPERATION AT 0.60 LBS/MMBTU SO 2 Unit Capacity (Gross) A (MW) 162 Input Retrofit Factor B 2 Difficulty of Retrofit
Gross heat rate C Btu/KW

‐ hr 11,982 Input
SO 2 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 10 3 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 $/10 3 gal 1 Input Operating Labor Rate T ($/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 18Table 4-3d PPL BART Cost Effectiveness Analysi s Lime Spray Drying (With Low Sulfur Coal) Sulfur Dioxide Contro l 162 Megawatt Coal Fired Steam Electric Plant Lime Spray Drying With Precipitator Replacement at J.E. Corett e SO 2 =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 300 o 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 AP C Technologies

‐ Dry Sorbent Injection Cost Development Methodology

‐ FINAL", August 201 0 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 19Table 4-3e PPL BART Cost Analysi s Lime Spray Drying (With Low Sulfur Coal) Sulfur Dioxide Contro l 162 Megawatt Coal Fired Steam Electric Plant Lime Spray Drying With Precipitator Replacement at J.E. Corett e SO 2 =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 300 o 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 AP C Technologies

‐ Dry Sorbent Injection Cost Development Methodology

‐ FINAL", August 201 0 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 SO 2 Unit Capacity (Gross) A (MW) 162 Input Retrofit Factor B 2 Difficulty of Retrofit
Gross heat rate C Btu/KW

‐ hr 11,982 Input SO 2 E m i ss R a t e D lb s / MMBtu 2 Uncontro ll e d 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 10 3 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 $/10 3 gal 1 Operating Labor Rate T ($/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 SO 2 

### OPERATING PARAMETERS
Variable Designation Units Value Equation/Input (1)

WET FGD OPERATING VARIABLES ‐ ACTUAL OPERATION AT 0.46 LBS/MMBTU SO 2 Unit Capacity (Gross) A (MW) 162 Input Retrofit Factor B 2 Difficulty of Retrofit
Gross heat rate C Btu/KW

‐ hr 11,982 Input SO 2 E m i ss R a t e D lb s / MMBtu 0.46 Uncontro ll e d 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 10 3 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 $/10 3 gal 1 Operating Labor Rate T ($/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 SO 2 

### OPERATING PARAMETERS
Variable Designation Units Value Equation/Input (1)

WET FGD OPERATING VARIABLES ‐ ACTUAL OPERATION AT 0.60 LBS/MMBTU SO 2 Unit Capacity (Gross) A (MW) 162 Input Retrofit Factor B 2 Difficulty of Retrofit
Gross heat rate C Btu/KW

‐ hr 11,982 Input SO 2 E m i ss R a t e D lb s / MMBtu 0.6 Uncontro ll e d 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 10 3 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 $/10 3 gal 1 Operating Labor Rate T ($/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 23Table 4-4d PPL BART Cost Analysi s Wet FGD (With Low Sulfur Coal) Sulfur Dioxide Control 162 Megawatt Coal Fired Steam Electric Plant Wet FGD at J.E. Corette

SO 2 =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 300 o 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 AP C Technologies

‐ Wet FGD Cost Development Methodology

‐ FINAL", August 201 0 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 24Table 4-4e PPL BART Cost Analysi s Wet FGD (With Low Sulfur Coal) Sulfur Dioxide Control 162 Megawatt Coal Fired Steam Electric Plant Wet FGD at J.E. Corette

SO 2 =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 300 o 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 AP C Technologies

‐ Wet FGD Cost Development Methodology

‐ FINAL", August 201 0 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