### 

	






# 		
 	






#   	

		 		
 
			 




### 


	





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


'(

)
"*

### 



# 		
 	






#   	
 		 	 	
 
			 
ES-1 EXECUTIVE SUMMARY
As part of the Best Available Retrofit Technology (BART) assessment for the Colstrip coal-fired steam electric plant, an economic cost effectivenes s analysis was performed in an initial report dated August 2007 for Units 1&2. Upon review and comment by the U.S. Environmental Protection Agency Region 8, the initial analysis was updated in an ad dendum report dated June 2008. On May 18, 2011, EPA requested any further updates to these previously submitted BART reports for Colstrip which PPL Montana believes necessary. This report is a NO x control update to the initial reports. Coal fired Units 1 & 2 at the Colstrip generating plant located in Billings, Montana, are jointly owned by Puget Sound Energy and PPL Montana LL C and operated by PPL Montana, LLC. Units 1&2 at Colstrip were determined to be BART-eligible under the Federal Regional Haze Rule by the U.S. Environmental Protection Agency Region 8. Each is a 333 MW electrical generation unit that burns low
sulfur sub-bituminous coal. Since the previous BART reports were prepar ed, new cost analysis techniques have been developed as part of the Integrated Planning Model (the IPM) under a grant from the U.S. EPA, “Documentation for EPA Base Case v.4.10 Using the In tegrated Planning Model”. See the following link
for more details:

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

ICF International (ICF) developed 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. The IPM includes cost updating to reflect significant increases in material and labor costs. In addition, we have incorporated cost updates available from PPL’s direct and indirect experiences. These costs reflect our best high level estimate based on the data currently available. This updated assessment has been prepared to incorpor ate IPM cost analysis techniques and update the cost effectiveness (CE) calculations from the referenced previous BART reports in response to a May 18, 2011 request by EPA for any necessary BART analysis updates. Consistent with the June 2008 Addendum, TRC estimated costs for the control technologies evaluated based on typical emission rates representative of a 30-day average and the maximum 24-hour emission rates based on data during the modeling year s (2001, 2002 & 2003) as requested by EPA. Even though PPL Montana believes that the actual cost effectiveness should be evaluated on a longer time basis utilizing typical emission rates (30-day average at a minimum) and that a shorter time basis and maximum emission rates are not representative of site-specific co st effectiveness, we are providing the 24-hour costES-2 calculation as requested. The 30- day running average baseline NO x emission rate is 0.35 lbs NO x /MMBtu
and the 24-hour baseline emission rate is 0.49 lbs NO x /MMBtu 1 . These emission rates are also representative of the past five years of operation. For this updated assessment, we have evaluate d three technologies for cost effectiveness in reducing nitrogen oxides (NO x ) emissions; (1) combustion controls, (2) Selective Non-Catalytic Reduction or SNCR, and (3) Selective Catalytic Reduc tion or SCR. The results of the control cost assessment based on the IPM costing approach for the three control op tions are discussed below. The
details of the CE calculations for each control techno logy are provided in S ection 4 and the associated
tables. The Colstrip Units 1&2 boilers are currently operated with NO x combustion control technology utilizing low NO x burners, close coupled overfire air, and digital controls 2 . Modifying these combustion controls through the installation of separated overfire air and more sophisticated burner controls (SOFA system) 3 is projected to reduce the NO x emission rate to 0.20 lbs/MMBtu. This value is used as the
baseline for cost effectiveness calculations because the addition of SOFA would, of necessity, accompany installation of any additional controls. The two reagent injection technologies, SNCR and SCR involve the injection of quantities of a NO x reducing agent into the exhaust for the conversion of NO x to nitrogen and water vapor. Typically either urea or aqueous ammonia is the reagent used. The reagent is injected at amounts higher than required for reaction and resu lts in residual ammonia in the exhaust known as ammonia slip. SNCR is a post combustion technology in which ammonia or urea is injected into the combustion zone of the boiler to chemically reduce NO x to nitrogen and water vapor, and carbon dioxide if urea serves as the source of ammonia. With SNCR, it is expected that a 10% incremental reduction of
NO x over that attained by modified combustion cont rols alone could be achieved, resulting in an
estimated NO x emission rate of 0.185 lbs/MMBtu. While an estimated additional 241 tons per year of
NO x would be reduced over the combustion controls and digital process controls, an estimated ammonia slip of 78 tons per year would contribute to foulin g and pluggage of the economizer and air preheater and be emitted from the stacks negating at least a portion of any visibility impacts from the NO x reduction. Fouling downstream of ammonia injection has been reported as an operating and maintenance concern in applications of this technology by other faciliti es. Consequently, PPL Montana expects that increased costs will occur at the plant to address higher foul ing of components, increased maintenance, and a resultant increase in forced outages. Increased forced outages to perform necessary maintenance

1 Although this value represents the maximum 24 hour average for the period of interest, Colstrip Units 1&2 comply with the annual Phase II Acid Rain Program standard of 0.40 #/MMBtu.

2 Alstom LNCFS Level II® system

3 Alstom LNCFS Level III® systemES-3 5HYLVHG activities would significantly increase the cost of this technology. Even a one-day maintenance outage
would increase the cost effectiveness of this technology by approximately $1,974/ton. Selective Catalytic Reduction (SCR) technology also uses urea or ammonia injection. However, that injection occurs upstream of a catalyst that produces higher reduction efficiencies. SCRs have a significantly higher capital cost and have comparativel y lower ammonia slip. In the case of application of SCR, the NO x controls would be located after the econom izer and upstream of the air preheater and scrubbers. The addition of SCR technology is estimated to reduce NO x emissions to an estimated 0.06 lbs/MMBtu from the significant reductions al ready attained by combustion controls. Each add-on post combustion control technology woul d have significant impacts at the plant. The estimated ammonia slip likely would contribute to fouling and pluggage of the economizer and air preheater and be emitted from the stacks and contribute to a visible plume. Furthermore, there would be impacts due to the limited available space. Reagent preparation equipment, reagent receipt, loading and unloading equipment, and the reactors for SCR would present significant construction and operational difficulties, due to limited space.
The estimated cost effectiveness of modifi ed combustion controls (SOFA system) is approximately $551 per ton of NO x removed on an annualized basis. The cost effectiveness of SNCR is approximately $8,194 per ton of NO x removed on an annualized basis. This estimate includes increased maintenance costs to address the fouling downstream of ammonia injection, but does not include any
other costs related to increased fo rced outages, such as lost generation, which would involve additional costs. As noted above, even a one-day maintenanc e outage would increase the cost of SNCR technology by approximately $1,974/ton.
The estimated cost effectiveness for the addition of SCR to Colstrip Units 1 or 2 is approximately $7,300/ton of additional NO x controlled. This does not include any increased cost as a result of an increase in forced outage rate. This cost includes a dry sorbent injection system for control of SO 3 . Even a one-day maintenance outage would increase the cost by approximately $212/ton. 4 For this report, PPL Montana determined that is was not necessary to update any of the June 2008 visibility assessments as the range of NO x emission reductions achieved by the evaluated control technologies in this addendum is within the range of NO x reduction previously evaluated. The high cost per ton of additional NO x removal with these technologies leads PPL Montana to the conclusion that these are not appropriate technologies for retrofit application to Colstrip Units 1&2. In addition, we believe that no significant visibility benefit is expected from the emission reductions that these technologies
would achieve.

4 This is less than the equivalent forced outage cost for an SNCR as the SCR removes more tons of NO x .ii TABLE OF CONTENTS

SECTION PAGE

EXECUTIVE SUMMARY ............................................................................................................. ....... ES-1
1.0 Recent Developments in Control Technology Cost Analysis ........................................................... 1 1.1 Reduction of NO x Using Combustion Controls ............................................................................ 1 1.2 Selective Non-Catalytic Reduction of NO x ................................................................................... 2 1.3 Selective Cata lytic Reduction ............................................................................................. .......... 2
2.0 Combustion Controls, SNCR and SCR Costing Using the IPM Methodology ................................ 3 2.1 Combustion Controls Cost Analysis Using the IPM Methodology .............................................. 3 2.2 SNCR Cost Analysis Using the IPM Methodology ...................................................................... 4 2.3 SCR Cost Analysis Us ing the IPM Methodology ......................................................................... 4

3.0 Conclusion ................................................................................................................ ........................ 5

TABLES

2-1a Combustion Controls Cost Effec tiveness Analysis 30 Day Average ........................................... 6 2-1b Combustion Controls Cost Effectiv eness Analysis 24 Hour Average .......................................... 7 2-2a SNCR Costing Devel opment 30 Day Average ............................................................................. 8 2-2b SNCR Cost Effectiveness Analysis 30 Day Average ................................................................... 9 2-2c SNCR Costing Developm ent 24 Hour Average ......................................................................... 10 2-2d SNCR Cost Effectiveness An alysis 24 Hour Average ............................................................... 11 2-3a SCR Costing Development 30 Day Average .............................................................................. 12 2-3b SCR Cost Effectiveness An alysis 30 Day Average .................................................................... 13 2-3c SCR Costing Developm ent 24 hour Average ............................................................................. 14 2-3d SCR Cost Effectiveness An alysis 24 Hour Average .................................................................. 151 1.0 RECENT DEVELOPMENTS IN CONTROL TECHNOLOGY COST ANALYSIS 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 USEPA Control Cost Manual (the CCM) 5 published in January 2002. For NO x , the electric utility control costing techniques were limited to Selective Non-Catalytic Reduction (SNCR) and Selective Catalytic Reduction (SCR). Utility applications of combustion controls were installed and operating in the USA, however, no compilation of the cost of such utility sized systems was av ailable other than as provided in the CCM. Using costing tools available at that time, analy ses of BART were submitted to regional offices of USEPA as required and reviews of the reports, such as those submitted by PPL Montana in August 2007 and subsequently amended in 2008, were performed. Simultaneously, howev er, EPA was utilizing available planning tools to study the cumulative effects that rul es such as the Clean Air Interstate Rule (CAIR), Best Available Retrofit Technology (BART), and other local rules would have on the utility industry in the USA. One such tool used by EPA is the Integrated Planning Model or the IPM. ICF International (ICF) developed
the IPM to assess the combined effect that air rules have on the electric utility industry as a whole. This platform has also been used by EPA’s Clean Air Mark ets Division for analyzing recent air policy decisions. Based upon currently available information, the control technology cost estimation techniques developed for the IPM appear to be more robust than earlier cost analysis methods.

1.1 Reduction of NO x Using Combustion Controls The IPM includes cost estimating methodology for the various low-NO x burner and overfire air combustion control options. For a tangentially fired boile r such as those at Colstrip, cost estimation methods and empirical equations for low NO x coal-and-air nozzles with close coupled and separated overfire air are also included. The Colstrip boilers are currently operated with NO x combustion control technology utilizing
low NO x burners, close coupled overfire air, and digital controls 6 and already have a relatively low NO x emission rate without application of any additional co mbustion controls. Modifying the combustion controls is possible through the installation of separated overfi re air and more sophisticated burner controls (SOFA system) 7 , but the ability of the SOFA system to reduce emissions from the current level of 0.35 lbs/MMBtu
is limited to a reduction of no more than about 43% , resulting in an estimated emission rate of 0.20
lbs/MMBtu.

5 ‐ EPA control Cost Manual, 6th ed., EPA-452-01-001, January 2002 6 Alstom LNCFS Level II® system 7 Alstom LNCFS Level III® system2 1.2 Selective Non-Catalytic Reduction of NO x SNCR is a post combustion technology in which a mmonia or urea is injected into the combustion zone of the boiler where the temper ature is in a range of 1600 deg F to 2000 deg F. It is called “post combustion” because unlike the control options that prevent or reduce the formation of thermal and fuel
NO x , SNCR injects a chemical to chemically reduce NO x to nitrogen and water vapor (and carbon dioxide if urea serves as the source of ammonia). The chemical reactions, which are not presented here, occur between nitric oxide (NO) and ammonia, i.e., NH 3 or CO(NH 2 ) 2 to form carbon dioxide, water vapor, and nitrogen. Not all of the injected ammonia results in NO x reduction reactions. Unreacted ammonia may react with SO 2 or SO 3 to form ammonium bisulfite and/or ammonium sulfate which will contribute to fouling economizer and air preheater surfaces and also contribute to plume vi sibility concerns. The application of this technique involves injecting the reactant in a stream of water or steam into a region in the boiler where reaction temperatures are in the correct range. Multiple injectors are typically utilized and the technique can provide
35% reduction in the NO x . Greater reductions are limited by the low NO x emissions rate already being achieved at Colstrip units 1&2. Operation of SNCR also results in ammonia slip. Ammonia slip is residual ammonia that does not
react with NO x and typically this can be lim ited to about 10 parts per million by volume (ppmv). This would result in approximately 20 pounds per hour (78 tons per year) of unreacted ammonia, which can cause adverse visibility impacts. In SNCR the reactive reag ent, in this case urea, would be injected into the
combustion zone of the boiler and react with NO x . In addition, there is likely to be significant fouling of the economizer and air heater surfaces. These impacts would require increased maintenance activities for cleaning the ammonium bisulfite and sulfate ammonia slip byproducts from the economizer and air preheater surfaces, which would likely result in an increase in forced outages.

1.3 Selective Catalytic Reduction In SCR technology, the exhaust is also injected with ammonia or urea, however the reactant is injected upstream of a bed of catalyst that is utilized to allow the reactions to occur at lower temperatures. The more intimate contact between the exhaust and the reagent in the catalyst bed also produces higher reduction efficiencies. While SCR will perform better than SNCR w ith the already low NO x emission rate,
the lowest emission rate attainable with the 0.20 lbs/MM Btu at Colstrip Unit 1 or 2 is expected to be 0.06 lbs/MMBtu, or about a 70% reduction. Operation of the SCR also results in ammonia slip . Just as in SNCR, a slight excess of reagent is required to reduce NO x emissions and both technologies are expected to have ammonia slip emissions. The
location of the SCR unit would be downstream of the economizer and upstream of the air heater and precipitator. While ammonia slip from SCR should be lower than with SNCR, increased forced outages to address downstream sulfite/sulfate fouling impacts from by products of ammonia slip could occur.3 2.0 COMBUSTION CONTROLS, SNCR AND SCR COSTING USING THE IPM METHODOLOGY ICF International (ICF) developed a proprietary tool known as the IPM to assess the combined effect that air rules have on the utility industry as a whole. Th is platform has also been used by EPA’s Clean Air Markets Division for analyzing air policy decisions. One aspect of the IPM is the capital, operating, and maintenance cost of air pollution control equipment. These costing analytical techniques were summarized in reference 1, available from the US EPA Clean Ai r Markets Division or through the link provided in the executive summary of th is report. For NO x , APCE cost analyses for the combustion controls, and for the two add-on, i.e. post combustion, control technologies are presented; SNCR, and SCR. Pages 5-7 and 5-8 from the documentation document fo r the IPM model are presented in Attachment
A-1. The data in Table 5-5 summarizes the costs fo r the several combustion controls techniques in 2007 dollars. While the costs are presented for a 300 MW coal boiler, scaling factors are included that allow the cost data to be scaled to any coal fired boiler greater than 25 MW in gross power output. Table 5-7 lists the assumptions used in the IPM model for NO x emission control efficiencies for SNCR and SCR technologies. Two additional background reports are included in Attachment A which describe the costing approach to SNCR and SCR. Each report was prepar ed by Sargent & Lundy, LLC under contract to the USEPA. Based upon a proprietary database of control in stallation costs, this engineering firm developed empirical equations which were used to estimate the co sts of controls as applied to all types of coal-fired boiler plants. This costing aspect of the IPM allowed an alysis of the effect of rules such as BART on the utility generating fleet. The cost equations developed for the IPM contain both capital and operating and maintenance costs. Just as EPA used cost factors as percentages of the capital equipment cost, S&L u sed the same approach to develop their capital costs for an installed retrofit project . More details regarding this approach are provided
in Attachments A-2 and A-3.

2.1 Combustion Controls Cost Analysis Using the IPM Methodology As shown in Attachment A-1, Table 5-5, ther e are several combustion controls options for tangentially-fired coal boilers like the boilers at Co lstrip. PPL Montana used the cost data for Low-NO x Coal-and Air Nozzles with Close-Coupled and Separate d Overfire Air which would be similar to those installed and in operation at other PPL plants. Due to the already low emission rate of NO x at Colstrip 1&2 resulting from the combustion controls already installed, about a 43% reduction is expected from application of SOFA system combustion control technology. Detaile d cost calculations are presented in Tables 2-1a and
2-1b.4 5HYLVHG 2.2 SNCR Cost Analysis Using the IPM Methodology Tables 2-2a through 2-2d show the results of app lication of the costing methodology developed for use by EPA in the IPM regulatory studies. Tables 2-2a and 2-2c present the Colstrip specific parameters for the boilers applied within the empirical cost analysis approach developed by S&L as presented in
Attachment A-2. The use of the “retrofit factor” is provided in the analytical co st equations to allow for particularly difficult sites where application of retrofit technology would be more di fficult due to site specific
factors. PPL Montana believes that the PM and SO 2 scrubbers already limit the space available for the installation of reagent preparation equipment and re agent receipt and unloading operations, which will make the application of SNCR difficult at the Colstrip site. PPL Montana has used a factor of 1.5 instead of the 1.0 that would characterize a more open site plan than th at available at Colstrip Units 1&2. Tables 2-2b and 2-2d show the calculations of the $/ton of NO x for SNCR.
SNCR uses urea that is injected into the combus tion zone where it breaks down into two moles of
ammonia and one mole of CO 2 per mole of urea injected. Excess reagent is always required to attain acceptable NO x reductions; however, the reductions that are attainable are higher when the uncontrolled NO x is higher. At a typical ammonia slip concentration in the exhaust of 10 ppm, the unreacted ammonia would
enter the PM/SO 2 scrubbers and cause unknown effects on the reaction chemistry. This could lead to higher fouling of scrubber components, increased maintenan ce, and more frequent breakdowns of the scrubbing equipment. Using the IPM methodology, and assuming that installation of an SNCR will result in an
emission rate of 0.185 lbs/MMBtu the cost effectiveness is estimated to be $8,194/ton. This does not include cost of lost generation for an in crease in outages. Even a one-day maintenance outage would increase the cost by approximately $1,974/ton.

2.3 SCR Cost Analysis Using the IPM Methodology Tables 2-3a through and 2-3d show the results of application of the S&L costing methodology to Colstrip units 1 or 2 for SCR. The costs reflected in these tables reflect a retrofit factor of 2.0 based on PPL experience in estimating a retrofit of an SCR on a large coal-fired unit. That cost included $5 million capital cost for installation of a dry sorbent system to reduce sulfuric acid that may be increased as a byproduct of the SCR catalyst converting a small portion of the SO 2 to SO 3 and creating the potential for a visible plume. Application of SCR at Colstrip Units 1&2 is est imated to cost $7,300/ton assuming an emission rate
of 0.06 lbs/MMBtu. This does not in clude any increased cost as a result of lost generation from an increase in forced outage rate. Even a one-day maintenance outage would increase the cost effectiveness by approximately $212/ton. 8

8 This is less that the equivalent forced outage cost for an SNCR as the SCR removes more tons of NO x .5 3.0 CONCLUSION The cost per ton of the estimated NO x removed through installation of any of the available NO x reduction technologies at Colstrip vary considerably, but are not warranted where no significant visibility benefit is expected from the resulting emission reducti ons. For this report, PPL Montana determined that it was not necessary to update the June 2008 visibility assessments as the range of NO x emission reductions achieved by the evaluated control technologies in this addendum is within the range of NO x reductions previously evaluated. Because there are no significant visibility benefits, the additional analysis of costs provided by this addendum does not change the conc lusion that PPL Montana reached for Colstrip Units 1&2 in its August 2007 BART Assessment or the J une 2008 Addendum that implementation of further NO x control is not warranted.Table 2-1a PPL BART Cost Effectiveness Analysis Combustion Controls for NOx Colstrip Units 1&2 Two 333 MW Coal Fired Boilers (Each) 30

­ day avera g e emission NOx rat e Maximum Gross Heat Input MM Btu/hr 3,982 Design Percent Load % 92 Uncontrolled NOx Emissions lbs/MMBtu 0.350 Steam Turbine Power Output (TMW) MW 333 Capacity Factor (92%) hrs 8,059 Controlled NOx Emissions lbs/MMBtu 0.20 Overall NOx Reduction Efficiency, (%) % 42.86 Uncontrolled NOx Emissions, (lb/hr) 1393.7 Uncontrolled NOx Emissions, (tons/yr) 5616.1 Controlled NOx Emissions, (ton/yr) 3209.2 Annual Interest Rate, (%) 7 Equipment Life, (yrs) yr 20 Capital Recovery Factor, CRF CRF 0.0944

Unit Item Cost Item Suggested Factor Cost Cost

From EPA Documentation Study (Reference 1) Capital Cost ($/KW) 38 $12,188,686 Equipment Cost Total, (EC) EC (Adjusted by Cost Index Calcs) (2011 dollars) (2) $12,992,396
Total Capital Costs, TCC --- $12,992,396

Direct Annual Costs, DA C Fixed O& M Costs 0.3 $/kW

‐ yr $99,900

Total Direct Annual Costs, DAC $99,900

Indirect Annual Costs Capital Recovery CRF*TCC

--- $1,226,390

Total Indirect Annual Costs, IAC $1,226,390

Total Annual Costs, TAC = DAC + IA C $1,326,290
Cost Effectiveness ($/ton pollutant Removed) $551

Cost data references:
1) Cost analysis equations from "Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model, " August 2010, pg 5

‐ 7 2) Cost indices used to adjust 2007 costs to 2011 costs (2007 CI= 106.098, 2011 CI= 113.094)

Page 6Table 2-1b PPL BART Cost Effectiveness Analysis Combustion Controls for NOx Colstrip Units 1&2 Two 333 MW Coal Fired Boilers (Each) 24

­ hour avera g e emission NOx rat e Maximum Gross Heat Input MM Btu/hr 3,982 Design Percent Load % 92 Uncontrolled NOx Emissions lbs/MMBtu 0.490 Steam Turbine Power Output (TMW) MW 333 Capacity Factor (92%) hrs 8,059 Controlled NOx Emissions lbs/MMBtu 0.2600 Overall NOx Reduction Efficiency, (%) % 46.94 Uncontrolled NOx Emissions, (lb/hr) 1951.2 Uncontrolled NOx Emissions, (tons/yr) 7862.5 Controlled NOx Emissions, (ton/yr) 4171.8 Annual Interest Rate, (%) 7 Equipment Life, (yrs) yr 20 Capital Recovery Factor, CRF CRF 0.0944

Unit Item Cost Item Suggested Factor Cost Cost

From EPA Documentation Study (Reference 1) Capital Cost ($/KW) 38 $12,188,686 Equipment Cost Total, (EC) EC (Adjusted by Cost Index Calcs) (2011 dollars) (2) $12,992,396
Total Capital Costs, TCC --- $12,992,396

Direct Annual Costs, DA C Fixed O& M Costs 0.3 $/kW

‐ yr $99,900

Total Direct Annual Costs, DAC $99,900

Indirect Annual Costs Capital Recovery CRF*TCC

--- $1,226,390

Total Indirect Annual Costs, IAC $1,226,390

Total Annual Costs, TAC = DAC + IA C $1,326,290
Cost Effectiveness ($/ton pollutant Removed) $359

Cost data references:
1) Cost analysis equations from "Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model, " August 2010, pg 5

‐ 7 2) Cost indices used to adjust 2007 costs to 2011 costs (2007 CI= 106.098, 2011 CI= 113.094)

Page 7

### Table 2-2a SNCR COSTING DEVELOPMENT FOR CAPITAL AND OPERATION AND MAINTENANCE COSTS Variable Designation Units Value Equation/Input (1)
SNCR CAPITAL COST FOR COLSTRIP 1 OR 2 (EACH) 30 DAY AVERAGE NOx Unit Capacity (Gross) A (MW) 333 Input Retrofit Factor B 1.5 Difficulty of Retrofit Gross heat rate C Btu/KW

‐ hr 11,958 Input NOx Emiss Rate D lbs/MMBtu 0.2 Uncontrolled
SO 2 Emiss Rate E lbs/MMBtu 1.8 Input Type of Coal E Input Coal Factor F 1 1 Input Heat Rate Factor G 1 1.20 C / 10,000 Heat Input H Btu/hr 3.98E+09 A X C x 1000 Capacity Factor I (%) 92.0 Input NOx Removal Eff J (%) 10.00 Input
NOx Removed K (lbs/hr) 79.64 D x H/10 6 x J/10
Urea Rate L (lbs/hr) 346.26 K /0.15/46 x 30 Water Required M (lbs/hr) 3116.35 L x 9 Dilution Water Rate O (1,000 gph) 0.37 M x 0.12/1000 Urea Cost 50% wgt Soln P ($/ton) 450 Input Dilution Water Cost R ($/kgal) 1 Input Operating Labor Rate S ($/hr) 60 Input

SNCR Injectors, DCS BMS ($) $3,531,624 B x F/1.05 x 200000 x (AxG) 0.42

Air Heater Mods (not reqd) BMA ($) $0 Balance of Plant Costs BMB ($) $3,103,888 270000 x A 0.33 x K 0.12

Bare Module Cost BM ($) $6,635,513 BMS + BMA + BMB
Engineering, Const Mgmt A1 ($) $663,551 10% of BM Labor Adjustment A2 ($) $663,551 10% of BM
Contractor Profit, Fees A3 ($) $663,551 10% of BM Cap, Eng, Const Cost CECC ($) $8,626,166 BM + A1 + A2 + A3
Owners Cost B1 ($) $431,308 5% of CECC Total Project Cost TPC ($) $9,057,475 CECC + B1
Cost per kW ($) 27 $/kW

Fixed Operator Cost FOMO ($) $62,400 2,080 hrs ‐ 1 ‐ half time Maintenance Material FOMM ($) $79,626 1.2% of BM Total Fixed O&M ($) $142,026 FOMO + FOMM Urea Cost VOMR ($) $77.91 L x P Dilution Water Cost VOMM ($) $0.37 O x R

Notes: 1) Cost analysis equations from "IPM Model

‐ Revisions to Cost And Performance for APC Technologies

‐ SNCR 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 8Table 2-2b PPL BART Cost Effectiveness Analysis SNCR NOx Control Colstrip Units 1&2 Two 333 MW Coal Fired Boilers (Each) 30

­ day avera g e emission NOx rat e

Maximum Gross Heat Input MM Btu/hr 3,982 Design Percent Load % 92 Uncontrolled NOx Emissions (with PRB coal) lbs/MMBtu 0.200 ExhaustTemperature, ( o F) T 314 Steam Turbine Power Output (TMW) MW 333 Capacity Factor (92%) hrs 8,059 Controlled NOx Emissions lbs/MMBtu Note 3 0.185 Overall NOx Reduction Efficiency, (%) % 7.50 Uncontrolled NOx Emissions, (lb/hr) 796.4 Uncontrolled NOx Emissions, (tons/yr) 3209.2 Controlled NOx Emissions, (ton/yr) 2968.5 Annual Interest Rate, (%) 7 Equipment Life, (yrs) yr 20 Capital Recovery Factor, CRF CRF 0.0944

Unit Item Cost Item Suggested Factor Cost Cost

IPM Model, August 20, 2010 (1) Capital Cost ($/KW) 27 $9,057,475 Equipment Cost Total, (EC) EC (Adjusted by Cost Index Calcs) (2011 dollars) (2) $9,316,133
Total Capital Costs, TCC

--- $9,316,133

Direct Annual Costs, DA C Urea Cost VOMR $627,882 Dilution Water Cost VOMM $3,014 Air Preheater Cleaning Four at $80,000 each $320,000

Maintenance Labor FOMO $62,400 Maintenance Materials FOMM $79,626

Total Direct Annual Costs, DAC $1,092,922

Indirect Annual Costs Capital Recovery CRF*TCC

--- $879,377

Total Indirect Annual Costs, IAC $879,377

Total Annual Costs, TAC = DAC + IA C $1,972,299
Cost Effectiveness ($/ton pollutant Removed) $8,194

Cost data references:
1) Cost analysis equations from "IPM Model

‐ Revisions to Cost And Performance for AP C Technologies

‐ SNCR Cost Development Methodology

‐ FINAL", August 2010 Project 12301

‐ 007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC 2) Cost indices used to adjust 2009 costs to 2011 costs (2009 CI= 109.594, 2011 CI= 113.094) 3) The controlled NOx emissions are adjusted to account for 78 tons of ammonia slip assuming that ammonia emissions are equivalent to NOx emissions on a ton for ton basis.

Page 9

### Table 2-2c SNCR COSTING DEVELOPMENT FOR CAPITAL AND OPERATION AND MAINTENANCE COSTS
Variable Designation Units Value Equation/Input (1)
SNCR CAPITAL COST FOR COLSTRIP 1 OR 2 (EACH) 24 HOUR AVERAGE NOx Unit Capacity (Gross) A (MW) 333 Input Retrofit Factor B 1.5 Difficulty of Retrofit Gross heat rate C Btu/KW

‐ hr 11,958 Input NOx Emiss Rate D lbs/MMBtu 0.26 Uncontrolled
SO 2 Emiss Rate E lbs/MMBtu 1.8 Input Type of Coal E Input Coal Factor F 1 1 Input Heat Rate Factor G 1 1.20 C / 10,000 Heat Input H Btu/hr 3.98E+09 A X C x 1000 Capacity Factor I (%) 92.0 Input NOx Removal Eff J (%) 10.00 Input
NOx Removed K (lbs/hr) 103.53 D x H/10 6 x J/10
Urea Rate L (lbs/hr) 450.14 K /0.15/46 x 30 Water Required M (lbs/hr) 4051.25 L x 9 Dilution Water Rate O (1,000 gph) 0.49 M x 0.12/1000 Urea Cost 50% wgt Soln P ($/ton) 450 Input Dilution Water Cost R ($/kgal) 1 Input Operating Labor Rate S ($/hr) 60 Input

SNCR Injectors, DCS BMS ($) $3,531,624 B x F/1.05 x 200000 x (AxG) 0.42

Air Heater Mods (not reqd) BMA ($) $0 Balance of Plant Costs BMB ($) $3,203,165 270000 x A 0.33 x K 0.12

Bare Module Cost BM ($) $6,734,789 BMS + BMA + BMB
Engineering, Const Mgmt A1 ($) $673,479 10% of BM Labor Adjustment A2 ($) $673,479 10% of BM
Contractor Profit, Fees A3 ($) $673,479 10% of BM Cap, Eng, Const Cost CECC ($) $8,755,226 BM + A1 + A2 + A3
Owners Cost B1 ($) $437,761 5% of CECC Total Project Cost TPC ($) $9,192,987 CECC + B1
Cost per kW ($) 28 $/kW

Fixed Operator Cost FOMO ($) $62,400 2,080 hrs ‐ 1 ‐ half time Maintenance Material FOMM ($) $80,817 1.2% of BM Total Fixed O&M ($) $143,217 FOMO + FOMM Urea Cost VOMR $/hr $101.28 L x P Dilution Water Cost VOMM $/hr $0.49 O x R Notes: 1) Cost analysis equations from "IPM Model

‐ Revisions to Cost And Performance for APC Technologies

‐ SNCR 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 10Table 2-2d PPL BART Cost Effectiveness Analysis SNCR NOx Control Colstrip Units 1&2 Two 333 MW Coal Fired Boilers (Each) 24

­ hour avera g e emission NOx rat e

Maximum Gross Heat Input MM Btu/hr 3,982 Design Percent Load % 92 Uncontrolled NOx Emissions (with PRB coal) lbs/MMBtu 0.260 ExhaustTemperature, ( o F) T 314 Steam Turbine Power Output (TMW) MW 333 Capacity Factor (92%) hrs 8,059 Controlled NOx Emissions lbs/MMBtu Note 3 0.239 Overall NOx Reduction Efficiency, (%) % 8.08 Uncontrolled NOx Emissions, (lb/hr) 1035.3 Uncontrolled NOx Emissions, (tons/yr) 4171.9 Controlled NOx Emissions, (ton/yr) 3835.0 Annual Interest Rate, (%) 7 Equipment Life, (yrs) yr 20 Capital Recovery Factor, CRF CRF 0.0944

Unit Item Cost Item Suggested Factor Cost Cost

IPM Model, August 20, 2010 (1) SNCR Capital Cost ($/KW) 28 $9,192,987 Equipment Cost Total, (EC) EC (Adjusted by Cost Index Calcs) (2011 dollars) (2) $9,455,515 Total Capital Costs, TCC

--- $9,455,515

Direct Annual Costs, DA C Urea Cost VOMR $816,246 Dilution Water Cost VOMM $3,918 Air Preheater Cleaning F our at $80,000 eac h $320,000

Maintenance Labor FOMO $62,400 Maintenance Materials FOMM $80,817

Total Direct Annual Costs, DAC $1,283,382

Indirect Annual Costs Capital Recovery CRF*TCC --- $892,534

Total Indirect Annual Costs, IAC $892,534

Total Annual Costs, TAC = DAC + IA C $2,175,915
Cost Effectiveness ($/ton pollutant Removed) $6,457

Cost data references:
1) Cost analysis equations from "IPM Model

‐ Revisions to Cost And Performance for AP C Technologies

‐ SNCR Cost Development Methodology

‐ FINAL", August 2010 Project 12301

‐ 007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC 2) Cost indices used to adjust 2009 costs to 2011 costs (2009 CI= 109.594, 2011 CI= 113.094) 3) The controlled NOx emissions are adjusted to account for 78 tons of ammonia slip assuming that ammonia emissions are equivalent to NOx emissions on a ton for ton basis.

Page 11

### Table 2-3a SCR COSTING DEVELOPMENT FOR CAPITAL AND OPERATION AND MAINTENANCE COSTS
Variable Designation Units Value Equation/Input (1)
SCR CAPITAL COST FOR COLSTRIP 1 OR 2 (EACH) 30 DAY AVERAGE NOx Unit Capacity (Gross) A (MW) 333 Input Retrofit Factor B 2 Difficulty of Retrofit Gross heat rate C Btu/KW

‐ hr 11,958 Input NO x E m i ss R a t e D lb s / MMBtu 0.2 Uncontro ll e d SO 2 E m i ss R a t e E lb s / MMBtu 1.8 Uncontro ll e d Type of Coal F Input Coal Factor G 1.05 Input Heat Rate Factor H 1.20 C / 10,000 Heat Input I Btu/hr 3.98E+09 A X C x 1000 Capacity Factor J (%) 92.0 Input NOx Removal Eff K (%) 70.00 Input NOx Removal Factor L (2) (lbs/hr) 0.875 (Based on Model Plant) NOx Removed M (lbs/hr) 557.48 D X I / 10 6 * K / 100 Urea Rate N (lbs/hr) 389.46 M x 0.525 * 60/46 *1.01/.99 Steam Required M (lbs/hr) 440.10 N x 1.13 Urea Cost 50% wgt Soln R ($/ton) 450 Input Catalyst Cost S ($/m3) 8000 Input Steam Cost U ($/klbs) 4 Input Operating Labor Rate V ($/hr) 60 Input

SCR Ducts, Reactor Island BMR ($) $90,425,605 180000 x B X L 0.2 x (AxGxH) 0.92

Base Reagent Prep Cost BMF ($) $1,992,238 410000 x M 0.25

ID Fans, Anciliary Equip BMB ($) $9,588,609 380000 x B x (AxGxH) 0.42

Bare Module Cost BM ($) $102,006,452 BMR + BMF + BMB Engineering, Const Mgmt A1 ($) $10,200,645 10% of BM Labor Adjustment A2 ($) $10,200,645 10% of BM
Contractor Profit, Fees A3 ($) $10,200,645 10% of BM Cap, Eng, Const Cost CECC ($) $132,608,387 BM + A1 + A2 + A3
Home office Costs B1 ($) $6,630,419 5% of CECC Construction Funds B2 ($) $8,354,328 6% of CECC+B1 Total Project Cost TPC ($) $147,593,135 CECC + B1 + B2 Cost per kW 443 $/kW

Fixe d Operator Cost FOMO $ 62,400 2,080 h rs ‐ 1 ‐ h a lf time Maintenance Materia l FOMM $ 300,000 Fixe d Annua l Cost Tota l Fixe d O & M FOM $ 362,400 FOMO + FOMM Urea Cost VOMR $ 87.63 N X R Steam Cost VOMM $ 1.76 O x U C ata l yst cost (3) VOMW $ 0.35 $/ MW h r Notes: 1) Cost analysis equations from "IPM Model

‐ Revisions to Cost And Performance for APC Technologies

‐ SCR Cost Development Methodology

‐ FINAL", August 2010 Project 12301

‐ 007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC 2) S&L lists this variable as = to "I x J"; this is the model plant removal efficiency for PRB coal 3) S&L lists this to be a discrete function of A, G, J, K, and S in $/MW

‐ hr PRB

CAPITAL EQUIPMENT COSTS

OPERATING AND MAINTENANCE COSTS

Page 12 5HYLVHGTable 2-3b PPL BART Cost Effectiveness Analysis SCR NOx Control Colstrip Units 1&2 Two 333 MW Coal Fired Boilers (Each) 30

­ day avera g e emission NOx rat e Maximum Gross Heat Input MM Btu/hr 3,982 Design Percent Load % 92 Uncontrolled Emissions lbs/MMBtu 0.200 ExhaustTemperature, ( o F) T 314 Steam Turbine Power Output (TMW) MW 333 Capacity Factor (92%) hrs 8,059 Controlled NOx Emissions lbs/MMBtu 0.06 Overall NOx Reduction Efficiency, (%) % 70.00 Uncontrolled NOx Emissions, (lb/hr) 796.4 Uncontrolled NOx Emissions, (tons/yr) 3209.2 Controlled NOx Emissions, (ton/yr) 962.8 Annual Interest Rate, (%) 7 Equipment Life, (yrs) yr 20 Capital Recovery Factor, CRF CRF 0.0944

Unit Item Cost Item Suggested Factor Cost Cost

IPM Model, August 20, 2010 (1) Capital Cost ($/KW) 443 $147,593,135 Equipment Cost Total, (EC) EC (Adjusted by Cost Index Calcs) (2011 dollars) (2,3) $152,306,678
Total Capital Costs, TCC --- $152,306,678

Direct Annual Costs, DA C Catalyst Cost (4) VOMW $939,300 Urea Cost VOMR $706,224 Steam Cost VOMM $14,187 Maintenance Labor FOMO $62,400 Maintenance Materials FOMM $300,000

Total Direct Annual Costs, DAC $2,022,111

Indirect Annual Costs Capital Recovery CRF*TCC --- $14,376,673

Total Indirect Annual Costs, IAC $14,376,673

Total Annual Costs, TAC = DAC + IA C $16,398,784
Cost Effectiveness ($/ton pollutant Removed) $7,300

Cost data references:
1) Cost analysis equations from "IPM Model

‐ Revisions to Cost And Performance for AP C Technologies

‐ SCR Cost Development Methodology

‐ FINAL", August 2010 Project 12301

‐ 007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC 2) Cost indices used to adjust 2009 costs to 2011 costs (2009 CI= 109.594, 2011 CI= 113.094) 3) This includes a dry sorbent system for control of SO 3 4) Cost is for replacement and disposal based on S&L cost estimate in $/MW-hr for PRB coal

Page 13 5HYLVHG

### Table 2-3c SCR COSTING DEVELOPMENT FOR CAPITAL AND OPERATION AND MAINTENANCE COSTS
Variable Designation Units Value Equation/Input (1)
SCR CAPITAL COST FOR COLSTRIP 1 OR 2 (EACH) 24 HOUR AVERAGE NOx Unit Capacity (Gross) A (MW) 333 Input Retrofit Factor B 2 Difficulty of Retrofit Gross heat rate C Btu/KW

‐ hr 11,958 Input NO x E m i ss R a t e D lb s / MMBtu 0.26 Uncontro ll e d SO 2 E m i ss R a t e E lb s / MMBtu 1.8 Uncontro ll e d Type of Coal F Input Coal Factor G 1.05 Input Heat Rate Factor H 1.20 C / 10,000 Heat Input I Btu/hr 3.98E+09 A X C x 1000 Capacity Factor J (%) 89.0 Input NOx Removal Eff K (%) 76.92 Input NOx Removal Factor L (2) (lbs/hr) 0.875 (Based on Model Plant) NOx Removed M (lbs/hr) 796.40 D X I / 10 6 * K / 100 Urea Rate N (lbs/hr) 556.38 M x 0.525 * 60/46 *1.01/.99 Steam Required M (lbs/hr) 628.71 N x 1.13 Urea Cost 50% wgt Soln R ($/ton) 450 Input Catalyst Cost S ($/m3) 8000 Input Steam Cost U ($/klbs) 4 Input Operating Labor Rate V ($/hr) 60 Input

SCR Ducts, Reactor Island BMR ($) $90,425,605 180000 x B X L 0.2 x (AxGxH) 0.92

Base Reagent Prep Cost BMF ($) $2,178,044 410000 x M 0.25

ID Fans, Anciliary Equip BMB ($) $9,588,609 380000 x B x (AxGxH) 0.42

Bare Module Cost BM ($) $102,192,258 BMR + BMF + BMB Engineering, Const Mgmt A1 ($) $10,219,226 10% of BM Labor Adjustment A2 ($) $10,219,226 10% of BM
Contractor Profit, Fees A3 ($) $10,219,226 10% of BM Cap, Eng, Const Cost CECC ($) $132,849,936 BM + A1 + A2 + A3
Home office Costs B1 ($) $6,642,497 5% of CECC Construction Funds B2 ($) $8,369,546 6% of CECC+B1 Total Project Cost TPC ($) $147,861,978 CECC + B1 + B2 Cost per kW 444 $/kW

Fixe d Operator Cost FOMO $ 62,400 2,080 h rs ‐ 1 ‐ h a lf time Maintenance Materia l FOMM $ 300,000 Fixe d Annua l Cost Tota l Fixe d O & M FOM $ 362,400 FOMO + FOMM Urea Cost VOMR $ 125.19 N X R Steam Cost VOMM $ 2.51 O x U C ata l yst cost (3) VOMW $ 0.35 $/ MW h r Notes: 1) Cost analysis equations from "IPM Model

‐ Revisions to Cost And Performance for APC Technologies

‐ SCR Cost Development Methodology

‐ FINAL", August 2010 Project 12301

‐ 007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC 2) S&L lists this variable as = to "I x J"; this is the model plant removal efficiency for PRB coal 3) S&L lists this to be a discrete function of A, G, J, K, and S in $/MW

‐ hr PRB

CAPITAL EQUIPMENT COSTS

OPERATING AND MAINTENANCE COSTS

Page 14Table 2-3d PPL BART Cost Effectiveness Analysis SCR NOx Control Colstrip Units 1&2 Two 333 MW Coal Fired Boilers (Each) 24

­ hour avera g e emission NOx rat e Maximum Gross Heat Input MM Btu/hr 3,982 Design Percent Load % 92 Uncontrolled Emissions lbs/MMBtu 0.260 ExhaustTemperature, ( o F) T 314 Steam Turbine Power Output (TMW) MW 333 Capacity Factor (92%) hrs 8,059 Controlled NOx Emissions lbs/MMBtu 0.06 Overall NOx Reduction Efficiency, (%) % 76.92 Uncontrolled NOx Emissions, (lb/hr) 1035.3 Uncontrolled NOx Emissions, (tons/yr) 4171.9 Controlled NOx Emissions, (ton/yr) 962.8 Annual Interest Rate, (%) 7 Equipment Life, (yrs) yr 20 Capital Recovery Factor, CRF CRF 0.0944

Unit Item Cost Item Suggested Factor Cost Cost

IPM Model, August 20, 2010 (1) Capital Cost ($/KW) 444 $147,861,978 Equipment Cost Total, (EC) EC (Adjusted by Cost Index Calcs) (2011 dollars) (2,3) $152,584,107
Total Capital Costs, TCC --- $152,584,107

Direct Annual Costs, DA C Catalyst Cost (4) VOMW $939,300 Urea Cost VOMR $1,008,892 Steam Cost VOMM $20,268 Maintenance Labor FOMO $62,400 Maintenance Materials FOMM $300,000

Total Direct Annual Costs, DAC $2,330,859

Indirect Annual Costs Capital Recovery CRF*TCC --- $14,402,860

Total Indirect Annual Costs, IAC $14,402,860

Total Annual Costs, TAC = DAC + IA C $16,733,719
Cost Effectiveness ($/ton pollutant Removed) $5,214

Cost data references:
1) Cost analysis equations from "IPM Model

‐ Revisions to Cost And Performance for AP C Technologies

‐ SCR Cost Development Methodology

‐ FINAL", August 2010 Project 12301

‐ 007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC 2) Cost indices used to adjust 2009 costs to 2011 costs (2009 CI= 109.594, 2011 CI= 113.094) 3) This includes a dry sorbent system for control of SO 3 4) Cost is for replacement and disposal based on S&L cost estimate in $/MW-hr for PRB coal

Page 15

# ATTACHMENT A-1
COMBUSTION CONTROLS COST TABLES5-7 

### 5.2 Nitrogen Oxides Control Technology The EPA Base Case v.4.10 includes two categories of NO x reduction technologies: combustion and post-combustion controls. Combustion controls reduce NO x emissions during the combustionprocess by regulating flame characteristics such as temperature and fuel-air mixing. Postcombustion controls operate downstream of the combustion process and remove NO x emissions from the flue gas. All the specific combustion and post-combustion technologies included in EPA Base Case v.4.10 are commercially available and currently in use in numerous power plants.

5.2.1 Combustion Controls The EPA Base Case v.4.10 representation of combustion controls uses equations that are tailored to the boiler type, coal type, and combustion controls already in place and allow appropriate additional combustion controls to be exogenously applied to generating units based on the NO x emission limits they face. Characterizations of the emission reductions provided by combustion controls are presented in Table 3-1.3 in Appendix 3-1. The EPA Base Case v.4.10 cost assumptions for NO x Combustion Controls are summarized in Table 5-5. Table 5-6 provides a mapping of existing coal unit configurations and incremental combustion controls applied in EPA Base Case v.4.10 to achieve state-of-the-art combustion control configuration.
Table 5-5 Cost (2007$) of NO x Combustion Controls for Coal Boilers (300 MW Size)

Boiler Type Technology Capital ($/kW) Fixed O&M($/kWyr) Variable O&M (mills/kWh)

Low NO x Burner without Overfire Air (LNB without OFA) 45 0.3 0.07Dry Bottom WallFired Low NO x Burner with Overfire Air (LNB with OFA) 61 0.4 0.09
Low NO x Coal-and-Air Nozzles with Close-Coupled Overfire Air (LNC1) 24 0.2 0.00
Low NO x Coal-and-Air Nozzles with Separated Overfire Air (LNC2) 33 0.2 0.03 Tangentially- Fired Low NO x Coal-and-Air Nozzles with Close-Coupled and Separated Overfire Air (LNC3) 38 0.3 0.03

Vertically-Fired NO x Combustion Control 29 0.2 0.06 Scaling Factor The following scaling factor is used to obtain the capital and fixed operating and maintenance costs applicable to the capacity (in MW) of the unit taking on combustion controls. No scaling factor is applied in calculating the variable operating and maintenance cost. LNB without OFA & LNB with OFA = ($ for X MW Unit) = ($ for 300 MW Unit) x (300/ X

) 0.359 LNC1, LNC2 and LNC3 = ($ for X MW Unit) = ($ for 300 MW Unit) x (300/ X

) 0.359 Vertically-Fired = ($ for X MW Unit) = ($ for 300 MW Unit) x (300/ X

) 0.553 where ($ for 300 MW Unit) is the value obtained using the factors shown in the above table and X

is the capacity (in MW) of the unit taking on combustion controls.5-8 Table 5-6 Incremental Combustion NO x Controls in EPA Base Case v.4.10 Boiler Type Existing NO x Combustion Control Incremental Combustional Control
LNB OFA Cell NGR LNB AND OFA Cyclone -- OFA Stoker/SPR -- OFA

-- LNC3 LA LNC3 LNB CONVERSION FROM LNC1 TO LNC3 LNB + OFA CONVERSION FROM LNC1 TO LNC3 LNC1 CONVERSION FROM LNC1 TO LNC3 LNC2 CONVERSION FROM LNC2 TO LNC3 OFA LNC1 Tangential

ROFA LNB

Vertical -- NO x Combustion Control - Vertically Fired Units

-- LNB AND OFA LA LNB AND OFA LNB OFA LNF OFA Wall

OFA LNB

5.2.2 Post-combustion Controls The EPA Base Case v.4.10 includes two post-combustion retrofit control technologies for existing coal units: Selective Catalytic Reduction (SCR) and Selective Non-Catalytic Reduction (SNCR). In EPA Base Case v.4.10 oil/gas steam units are eligible for SCR only. NO x reduction in an SCR system takes place by injecting ammonia (NH 3 ) vapor into the flue gas stream where the NO x is reduced to nitrogen (N2) and water H 2 O abetted by passing over a catalyst bed typically containing titanium, vanadium oxides, molybdenum, and/or tungsten. As its name implies, SNCR operates without a catalyst. In SNCR a nitrogenous reducing agent (reagent), typically ammonia or urea, is injected into, and mixed with, hot flue gas where it reacts with the NO x in the gas stream reducing it to nitrogen gas and water vapor. Due to the presence of a catalyst, SCR can achieve greater NO x reductions than SNCR. However, SCR costs are higher.
Table 5-7 summarizes the performance and applicability assumptions in EPA Base Case v.4.10 for each NO x post-combustion control technology and provides a cross reference to information on cost assumptions.
Table 5-7 Summary of Retrofit NO x Emission Control Performance Assumptions

Control Performance Assumptions Selective Catalytic Reduction (SCR) Selective Non-Catalytic Reduction

(SNCR) Unit Type Coal Oil/Gas Coal Pulverized Coal: 35% Percent Removal 90% down to 0.06 lb/MMBtu 80% Fluidized Bed: 50% Size Applicability Units 25 MW Units 25 MW Units 25 MW

Costs (2007$) See Table 5-8 See Table 5-9 See Table 5-8

# ATTACHMENT A-2
SNCR COST DEVELOPMENT METHODOLOGY – SARGENT & LUNDY, LLC, AUGUST 2010

## IPM Model – Revisions to Cost a nd Performance for APC Technologies

SNCR 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 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 

### SNCR Cost Development Methodology – Final

1 

### Establishment of Cost Basis The formulation of the SNCR cost estimating model is based upon a proprietary Sargent & Lundy LLC (S&L) in-house data base of recent (2009) quotes for both lump sum contracts and EPC. The S&L data was analyzed in detail regarding project specifics such as coal type, boiler type, and NOx reduction efficiency. The S&L in-house data includes projects that involved cyclone boilers, T-fire d and wall fired systems with multiple levels of injection. The cyclone boile r costs include rich reagent in jection (RRI). The data was the basis for the cost estimate formulations developed.
The S&L data was fitted with a least squares curve to establish the trend in $/kW as a function of gross MW. The EPA/IPM SNCR co st model parameters were adjusted to account for market changes and escalation, and then the model output was compared to the S&L data. The EPA/IPM model output fo llowed a $/kW correlation very similar to the S&L in-house data, once the adjust ments were made to the model.
The rapid rise in project cost s at the lower end of the MW range is due primarily to economies of scale. Additionally, older power plants in the 50 MW range tend to have plant sites that are more compact and ther efore difficult to accommodate the reagent storage areas and piping, injection mixing/dilu tion equipment and construction activities. The smaller power plants also tend to have older control systems which may require upgrades to accommodate the new SNCR control system.
The S&L data includes SNCR projects with variou s types of boilers, coals, sulfur levels and retrofit complexities. The data represents an average of boiler effects, such as cyclone, wall fired or CFB. The least squa res curve fits were based upon the following assumptions:

• Retrofit Factor =1

• Gross Heat Rate = 10,000

• SO 2 

### Rate = < 3 lb/MMBtu

• Type of Coal = PRB

• Project Execution = Multiple lump sum contracts



### Methodology Inputs To predict future retrofit costs several input variables are required. The unit size in MW and NOx levels are the major variables for the capital cost estimation followed by the type of fuel (high sulfur Bituminous). The fu el type affects the ai r pre-heater costs if sulfuric acid or ammonium bisu lfate deposition poses a problem. In general, if the level of SO 2 

### is above 3 lb/MMBtu, it is assumed that air heater modificati ons will be required. The unit heat rate factors into the amount of NOx generated and ultimately the size of the

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

### SNCR Cost Development Methodology – Final

2 SNCR reagent preparation system. A retrofit factor that equates to difficulty in construction of the system must be defined. The NO x 

### rate and removal efficiency will impact the amount of urea required and si ze of the reagent handling equipment.
The inputs that impact the variable O&M co sts are based primarily on the plant capacity factor and the removal efficiency. The NOx removal efficiency specifically affects the reagent and dilution water costs.
Outputs Total Project Costs (TPC)


### The base module costs are calculated for each required module (BM). The base module costs include:

• Equipment;

• Installation;

• Buildings;

• Foundations;

• Electrical; and

• Retrofit factor.

The base module costs do not include:

• Engineering and Construction Management

• Owner's cost; and

• AFUDC.

The base modules are:

BMS = Base module SNCR cost. BMA = Base module air pre-heater cost.

BMB = Base module balance of plant costs including: piping, electrical, site upgrades, etc...

BM = BMS + BMA + BMB

The total base module cost (BM) is increased by:

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

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

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

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

### SNCR Cost Development Methodology – Final

3 A capital, engineering, and construction cost subt otal (CECC) is established as the sum of the BM and the additional engi neering and construction fees.
Additional expenditures fo r the project are computed based on the CECC. The additional project costs include:

• Owner's home office costs (owner's engineering, management, and procurement) at 5% of the CECC.
The total project cost is ba sed on a multiple lump sum co ntract approach. Should a turnkey engineering procurement constructi on (EPC) contract be executed, the total project cost could be 10 to 15% higher than what is currently estimated.
Escalation is not included in the estimate. The total project cost (TPC) is the sum of the CECC and the Owner’s home office costs. An example of the capital cost estimation is included in Table 1.

Fixed O&M (FOM) 

### The fixed operating and maintenance cost is a function of the additi onal operations staff (FOMO) and maintenance labor and materi als (FOMM) associated with the SNCR installation. The FOM is the su m of the FOMO and the FOMM.
The following factors and assumptions underlie calculations of the FOM:

• In general, 1 additional oper ator is required for all inst allations. The FOMO is based on the number of additional operations staff required; and

• The fixed costs for maintenance materials and labor are a direct function of the base module cost (BM) at a retrofit factor of 1.0.

Variable O&M (VOM) 

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

• Reagent consumption;

• Dilution water consumption.
All of the VOM costs must be adju sted for the plant capacity factor.
The reagent consumption rate is a function of unit size, NO x 

### feed rate and removal efficiency. A utilization factor of 15% is used for units with an inlet NOx of 0.3 lb/MMBtu or lower and 25% for units with an inlet NOx greater than 0.3 lb/MMBtu. For CFB boilers a utilization factor of 25% is used. A reagent cost of $620 per ton of 100%

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

### SNCR Cost Development Methodology – Final

4 urea is used in the model. The dilution water usage is based upon reagent consumption rate.
The auxiliary power required for the SNCR system is not included in the VOM. The major systems that impact the power re quirements are compressed air or blower requirements for the urea injection sy stem and the reagent supply system.

The variables that contribut e to the overall VOM are:

VOMR = Variable O&M costs for urea reagent.
VOMM = Variable O&M costs for dilution water.
VOM = VOMR + VOMM.Project No. 12301-007IPM Model – Revisions toCost and Performance forAPC TechnologiesAugust 20, 2010SNCR Cost Development Methodology – Final5Table 1. Example of the Capital Cost Estimate Work Sheet (for T-fired boilers).Project No. 12301-007IPM Model – Revisions toCost and Performance forAPC TechnologiesAugust 20, 2010SNCR Cost Development Methodology – Final6Table 2. Example of the Fixed and Variable O&M Cost Estimate Work Sheet (for T-fired boilers).Project No. 12301-007IPM Model – Revisions toCost and Performance forAPC TechnologiesAugust 20, 2010SNCR Cost Development Methodology – Final7Table 3. Example of the Capital CostEstimate Work Sheet (for CFB boilers).Project No. 12301-007IPM Model – Revisions toCost and Performance forAPC TechnologiesAugust 20, 2010SNCR Cost Development Methodology – Final8Table 4. Example of the Fixed and Variable O&M Cost Estimate Work Sheet (for CFB boilers).

# ATTACHMENT A-3
SCR COST DEVELOPMENT METHODOLOGY – SARGENT & LUNDY, LLC, AUGUST 2010

## IPM Model – Revisions to Cost a nd Performance for APC Technologies

SCR 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 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 

### SCR Cost Developmen t Methodology – Final

1 

### Establishment of Cost Basis The formulation of the SCR cost estimating mo del is based upon two data bases of actual SCR projects. The data bases used we re those of the 2004 to 2006 industry cost estimates for SCR units published in th e “ANALYSIS OF MOG AND LADCO’S FGD AND SCR CAPACITY AND COST ASSUMP TIONS IN THE EVALUATION OF PROPOSED EGU 1 AND EGU 2 EMISSI ON CONTROLS” report prepared for Midwest Ozone Group (MOG) and a Sargent & Lundy LLC (S&L) prop rietary in-house database. The available data was analyzed in detail regarding projec t specifics such as coal type, NOx reduction efficiency and ai r pre-heater requirements, and updated to include the cost of SCR projects av ailable with both data sets.
The data sets were escalated to update the MOG information to 2009 and all of the data was cross referenced with current 2009 proj ects. The MOG and S&L cost data were updated to reflect the changes in equipment a nd labor rates. The CEPCI index for power plants was used to escalate the costs. The Handy-Witman index was also used to escalate the project costs to account for regional e ffects; the results were compared with the CEPCI index and were within 2% for total project costs.
The comparison between the two sets of data was refined by fitting each data set with a least squares curve to obtain an average $/kW project cost as a function of unit size. The data set was then collectively used to generate an average least-squares curve fit. The curve fit indicated that both sets of data pr oduced similar average co sts (within 4%) at the 200 MW range, but deviate as the unit size in creases to approximately 11% at 600 MW and 13% at 900MW. The costs for retrofit ting a plant smaller than 100 MW increase rapidly due to the economy of size. The olde r units which comprise a large proportion of the plants in this range generally have more compact sites with very short flue gas ducts running from the boiler house to the chimney. Because of the limited space, the SCR reactor and new duct work can be expensive to design and install. Additionally, the plants might not have enough margins in the fans to overcome the pressure drop due to the duct work configuration and SCR reactor and theref ore new fans may be required.
The least squares curv e fit was based upon an average of the SCR retrofit projects. Retrofit difficulties associated with an SCR ma y result in capital co st increases of 30 to 50% over the base model. The least squa res curve fits were based upon the following assumptions:

• Retrofit Factor =1

• Gross Heat Rate = 9880

• SO 2 

### Rate = < 3 lb/MMBtu

• Type of Coal = Bituminous

• Project Execution = Multiple lump sum contractsProject No. 12301-007 IPM Model – Revisions to Cost and Performance for APC Technologies August 20, 2010 

### SCR Cost Developmen t Methodology – Final

2 

### Methodology Inputs To predict future SCR retrofit costs several i nput variables are required. The unit size in MW is the major variable for the capital cost estimation followed by the type of fuel (Bituminous, PRB, or Lignite) which will influe nce the flue gas quantities as a result of the moisture content. The fuel type also affects the air pre-heater costs if ammonium bisulfate or sulfuric acid depos ition poses a problem. The un it heat rate factors into the amount of flue gas generated and ultimately the size of the SCR reactor and reagent preparation. A retrofit factor th at equates to difficulty in c onstruction of the system must be defined. The NO x 

### rate and removal efficiency will impact the amount of catalyst required and size of the reagent handling equipm ent. The elevation of the site must be considered separately and factored into the unit MW size accordingly due to its effects on the flue gas volume.
The inputs that impact the variable O&M co sts are based primarily on the plant capacity factor and the removal efficiency. The NOx removal efficiency specifically affects the SCR catalyst, reagent and steam costs. The lower level of NOx removal is recommended

as:

• 0.07 NOx lb/mmBtu – Bituminous

• 0.05 NOx lb/mmBtu – PRB

• 0.05 NOx lb/mmBtu – Lignite
Outputs Total Project Costs (TPC)


### First the bare costs are calculated for each required module (BM). The bare module costs include:

• Equipment

• Installation

• Buildings

• Foundations

• Electrical

• Retrofit factor

The bare module costs do not include:

• Engineering and Construction Management

• Owner's cost

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

### SCR Cost Developmen t Methodology – Final

3 The modules are:

BMR = Base module SCR cost BMF = Base module reagent preparation cost BMA = Base module air pre-heater cost
BMB = Base module balance of plan costs in cluding: ID or booster fans, piping, etc...

BM = BMR + BMF + BMA + BMB

The total bare module cost (B M) is then increased by:

• Engineering and construction manageme nt costs at 10% of the BM cost.

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

• Contractor profit and fees at 10% of the BM cost.
A capital, engineering, and construction cost subt otal (CECC) is established as the sum of the BM and the additional engi neering and construction fees.
Additional costs and financing expenditures for the project are computed based on the CECC. Financing and additional project costs include:

• Owner's home office costs (owner's engineering, management, and procurement) at 5% of the CECC; and

• Allowance for Funds Used During C onstruction (AFUDC) at 6% of the CECC and owner's costs. The AFUDC is based on a two-year engineering and construction cycle.
The total project cost is ba sed on a multiple lump sum co ntract approach. Should a turnkey engineering procurement constructi on (EPC) contract be executed, the total project cost could be 10 to 15% higher than what is currently estimated.
Escalation is not included in the estimate. The total project cost (TPC) is the sum of the CECC and the additional costs and financing ex penditures. Table 1 contains an example of the capital cost estimation.

Fixed O&M (FOM) 

### The fixed operating and maintenance cost is a function of the additi onal operations staff (FOMO) and maintenance labor and materi als (FOMM) associated with the SCR installation. The FOM is the su m of the FOMO and the FOMM.Project No. 12301-007 IPM Model – Revisions to Cost and Performance for APC Technologies August 20, 2010 

### SCR Cost Developmen t Methodology – Final

4 In general, 1 additional operator is required for all installati ons. The FOMO is based on the number of additional operations staff required.

The fixed maintenance materials and labor is a direct function of the bare module cost (BM) at a retrof it factor of 1.0.

Variable O&M (VOM) 

### Variable O&M is a function of catalyst require d and disposal costs, reagent consumption, and steam consumption. All of the VOM costs must be adjusted for plant capacity factor.
The reagent consumption rate is a function of unit size, NO x 

### feed rate and removal efficiency. The steam usage is based upon reagent consumption rate.
The power required for the SCR system was not included in the variable O&M costs. The power requirements include increased fa n power to overcome the added pressure drop across the catalyst and ductwor k and the reagent supply system.

The variables that contribut e to the overall VOM are:

VOMR = Variable O&M costs for urea reagent VOMW = Variable O&M costs for catalyst replacement & disposal
VOMM = Variable O&M costs for steam

VOM = VOMR + VOMW + VOMM.Project No. 12301-007IPM Model – Revisions to Cost and Performance for APCTechnologiesAugust 20, 2010SCR Cost Development Methodology – Final5Table 1. Example of the Capital Cost Estimate Work Sheet.Project No. 12301-007IPM Model – Revisions to Cost and Performance for APCTechnologiesAugust 20, 2010SCR Cost Development Methodology – Final6Table 2. Example of the Fixed andVariable O&M Estimate Work Sheet.