.lames M Parker Manager
- Compliance Services, Env PPL Montana, LLC 303N. Broadway. Suite 400 Billings, MT 59101 Tel. 406.740.9998 Fax406.237.6901 jmparker@pplweb.com PPL MONTANA,,,



### September23, 2011 

### Ms. Vanessa Hinkle (8P-AR) US EnvironmentalProtectionAgency Region VIII 1595 Wynkoop Street Denver, CO 80202-1129

Re: NOx Control CostUpdatestoPPLMontana'sColstrip Units 1&2BARTAnalyses DearMs. Hinkle: 

### Enclosedplease find PPLMontana's submittal ofa Nitrogen Oxides (NOx) Control cost update to ourAugust2007 and June 2008 BARTanalyses for our Colsrip Generating Station Units 1&2. EPA'sMay 18,2011 correspondence provided PPL Montana the opportunity to update informationrelated to these BART analyses. This update is provided pursuant to that correspondence and the subsequent discussions between EPA and PPLMontana, and the schedulefor target submittal dates agreed upon on June 27, 2011. Thisreportprovides updated costeffectiveness analyses for reducing NOxemissions through the application ofcombustion controls. selective non catalytic reduction (SNCR) and SelectiveCatalyticReduction (SCR) technologies. This submittal completesPPLMontana's updating ofthe original August 2007 report and the subsequent June 2008 Addendum. Today's submittal only updates the NOx control cost. We have not updated the particulate or 

### S02 control cost as we determined that it was not necessary. The very high cost (dollars perton) ofparticulate or

### S02 removed and the previously modeled absence ofvisibility improvementresultingfrom furtherparticulate or

### S02controls did notjustify any updatingto these control costs. Also. please note that PPLMontana has not updated any ofits previous visibility modeling analyses because we determined that therange ofemissions impacts at issue are within the range ofemissions impacts previously modeled. Accordingly, the visibility modeling results should be unaffected. In 

### addition, please note that we used the 2001-2003 NOx emissions data (0.35 lbs NoxlMMBtu

- 30 day average) for the baseline for this update to be consistent with the August 2007 and June 2008 BARTanalyses. However, the present emissions (approximately 0.311bs Nox/MMBtu- 30day average) are below that baseline. This is because inpreparation for the 2008 amended Phase II Acid Rain standard, the Colstrip Units 1&2 combustion controls existing at that time were optimized to give an adequate compliance margin under the new standard.- 2 ­


### Becausethere are no significantvisibilitybenefits, the additional analysis ofcosts providedbythis addendum does not change the conclusion that PPLMontanareached for ColstIipUnits 1&2in its August2007BARTAssessment orthe June 2008 Addendum that implementation offurther NOx 

### control is not warranted. Please contact me at 406-237-6932 orReid Clemmerat 610-774-5475 with any questions

.

.**Sirlc~rely,** 

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### September 2011

### EXECUTIVE SUMMARY As part ofthe Best Available Retrofit Technology (BART) assessment for the Colstrip coal-fired steam electric plant, an economic cost effectiveness 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 addendum report dated June 2008. On May 18, 20II, EPA requested any further updates to these previously submitted BART reports for Colstrip which PPL Montana believes necessary. This report is a NOx

### control update to the initial reports. Coal fired Units I & 2 at the Colstrip generating plant located in Billings, Montana, arejointly owned by Puget Sound Energy and PPL Montana LLC 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 bums low sulfur sub-bituminous coal. Since the previous BART reports were prepared, new cost analysis techniques have been developed as part of the Integrated Planning Model (the IPM) under a grant from the U.S. EPA, "Documentation for EPA Base Case v.4.l0 Using the Integrated Planning Model". See the following link for more details:
http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html#documentation)

ICF International (ICF) developed IPM to assess the combined effect that air rules have on the utility industry as a whole. This platform has also been used by EPA's Clean Air Markets Division for analyzing recent air policy decisions. Based upon currently available information, the control technology cost estimation techniques developed for the IPM appear to be more robust than those used in the previous BART reports prepared by PPL Montana. 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 incorporate 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 ofa 30-day average and the maximum 24-hour emission rates based on data during the modeling years (2001,2002 & 2003) as requested by EPA. Even though PPL Montanabelieves that the actual cost effectiveness should be evaluated on a longertime basis utilizing typical emission rates (30-day average at a minimum) and that a shortertime basis and maximum emission rates are not representative ofsite-specific cost effectiveness, we are providing the 24-hour cost ES-I

### calculation as requested. The 3D-day running average baseline NOxemission rate is 0.35 Ibs NOx/MMBtu and the 24-hour baseline emission rate is 0.49 Ibs NOx/MMBtu'. These emission rates are also representative ofthe past five years ofoperation. For this updated assessment, we have evaluated three technologies for cost effectiveness in reducing nitrogen oxides (NOx ) emissions; (I) 

### combustion controls, (2) Selective Non-Catalytic Reduction or SNCR, and (3) Selective Catalytic Reduction or SCR. The results of the control cost assessment based on the IPM costing approach for the three control options are discussed below. The details ofthe CE calculations for each control technology are provided in Section 4 and the associated tables. The Colstrip Units 1&2 boilers are currently operated with NOxcombustion control technology utilizing low NOxburners, close coupled overfire air, and digital controls2• 

### Modifying these combustion controls through the installation ofseparated overfire air and more sophisticated burner controls (SOFA systemi is projected to reduce the NOx emission rate to 0.20 Ibs/MMBtu. This value is used as the baseline for cost effectiveness calculations because the addition ofSOFA would, ofnecessity, accompany installation ofany additional controls. The two reagent injection technologies, SNCR and SCR involve the injection ofquantities ofa NOxreducing agent into the exhaust for the conversion ofNOxto 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 results 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 ofthe boiler to chemically reduce NOxto nitrogen and water vapor, and carbon dioxide ifurea serves as the source ofammonia. With SNCR, it is expected that a 10% incremental reduction of NOx over that attained by modified combustion controls alone could be achieved, resulting in an estimated NOx 

### emission rate of 0.185 Ibs/MMBtu. While an estimated additional 241 tons per year of NOxwould be reduced over the combustion controls and digital process controls, an estimated ammonia slip of78 tons per year would contribute to fouling and pluggage ofthe economizer and air preheater and be emitted from the stacks negating at least a portion ofany visibility impacts from the NOx 

### reduction. Fouling downstream ofammonia injection has been reported as an operating and maintenance concern in applications ofthis technology by other facilities. Consequently, PPL Montana expects that increased costs will occur at the plant to address higher fouling of components, increased maintenance, and a resultant increase in forced outages. Increased forced outages to perform necessary maintenance

1 Although thisvalue represents the maximum 24 hour average forthe period of interest, Colstrip Units 1&2 complywith the annual Phase II Acid Rain Program standard of0.40 #/MMBtu.

2 Alstom LNCFS Level Ill!> system

3 Alstom LNCFS Levelllll!> system 

### ES-2

### activities would significantly increase the cost ofthis technology. Even a one-day maintenance outage would increasethe costeffectiveness ofthis 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 comparatively lower ammonia slip. In the case ofapplication of SCR, the NOx 

### controls would be located after the economizer and upstream of the air preheater and scrubbers. The addition ofSCR technology is estimated to reduce NOx 

### emissions to an estimated 0.06 Ibs/MMBtu from the significant reductions already attained by combustion controls. Each add-on post combustion control technology would 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 modified combustion controls (SOFA system) is approximately $551 per ton ofNOx 

### removed on an annualized basis. The cost effectiveness ofSNCR is approximately $8,194 per ton ofNOx 

### 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 forced outages, such as lost generation, which would involve additional costs. As noted above, even a one-day maintenance outage would increase the cost ofSNCRtechnology by approximately $1,974/ton. 

### The estimated cost effectiveness for the addition ofSCRto Colstrip Units 1or 2 is approximately $7,300Iton 

### of additional NOx 

### 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 ofS03. 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 oftheJune 2008 visibility assessments as the range of NOx 

### emission reductions achieved by the evaluated control technologies in this addendum is within the range ofNOx 

### reduction previously evaluated. The high cost perton ofadditional NOx 

### removal with these technologies leads PPL Montanato 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 moretons of NOx' 

### ES-3 Revised

### TABLE OF CONTENTS SECTION EXECUTIVE SUMMARY ES-I 1.0 Recent Developments in Control Technology Cost Analysis 1 1.1 Reduction ofNOx

### Using Combustion Controls I 1.2 SelectiveNon-Catalytic Reduction ofNOx""""'",,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,

### 2 1.3 Selective Catalytic Reduction 2 2.0 Combustion Controls, SNCR and SCR Costing Using the IPM Methodology 3 2.1 Combustion Controls CostAnalysis Using the IPM Methodology 3 2.2 SNCR CostAnalysis Using the IPM Methodology 4 2.3 SCR CostAnalysis Using the IPM Methodology 4 3.0 Conclusion 5

TABLES 2-1a Combustion Controls Cost Effectiveness Analysis 30 Day Average 6 2-1b Combustion Controls Cost Effectiveness Analysis 24 HourAverage 7 2-2a SNCR Costing Development 30 Day Average 8 2-2b SNCR Cost Effectiveness Analysis 30 Day Average 9 2-2c SNCR Costing Development 24 HourAverage 10 2-2d SNCR Cost Effectiveness Analysis 24 HourAverage 11 

### 2-3a SCR Costing Development 30 Day Average 12 2-3b SCR CostEffectiveness Analysis 30 Day Average 13 2-3c SCR Costing Development 24 hourAverage 14 2-3d SCR Cost Effectiveness Analysis 24 Hour Average 15

ii

### 1.0 RECENT DEVELOPMENTS IN CONTROLTECHNOLOGY COSTANALYSIS 

### When the final rule was promulgated in 2005 

### (see FR Vol. 70, 

### No. 128, 

### July 6, 2005), 

### much ofthe 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 NOx, 

### the electric utility control costing techniques
were limited to Selective Non-Catalytic Reduction (SNCR) and Selective Catalytic Reduction (SCR). Utility applications ofcombustion controls were installed and operating in the USA, however, no compilation ofthe cost ofsuch utility sized systems was available otherthan as provided in the CCM. Using costing tools available at that time, analyses ofBART were submitted to regional offices of USEPA as required and reviews ofthe reports, such as those submitted by PPL Montana in August 2007 

### and subsequently amended in 2008, 

### were performed. Simultaneously, however, EPA was utilizing available planning tools to study the cumulative effects that rules such as the Clean Air Interstate Rule (CAIR), Best Available Retrofit Technology (BART), and other local rules would have on the utility industry in the USA. One such tool used by EPA is the Integrated Planning Model or the IPM. ICF International (lCF) 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 Markets Division for analyzing recent air policy decisions. Based upon currently available information, the control technology cost estimation techniques developed for the IPM appear to be more robust than earlier cost analysis methods.

1.1 Reduction of**NO~** 

### Using Combustion Controls The IPM includes cost estimating methodology for the various 10w-NOx 

### burner and overfire air combustion control options. For atangentially fired boiler such as those at Colstrip, cost estimation methods and empirical equations for low NOx 

### coal-and-air nozzles with close coupled and separated overfire air are also included. The Colstrip boilers are currently operated with NOx 

### combustion control technology utilizing low NOx 

### burners, close coupled overfire air, and digital controls6 

### and already have a relatively low NOx 

### emission rate without application ofany additional combustion controls. Modifyingthe combustion controls is possible through the installation of separated overfire air and more sophisticated burner controls (SOFA system)7, but the ability of the SOFA system to reduce emissions from the current level of0.35 

### Ibs/MMBtu is limited to a reduction of no more than about 43%, 

### resulting in an estimated emission rate of 0.20 

### Ibs/MMBtu.

5 _EPA control Cost Manual, 6th 

### ed., EPA-452-01-001, January 2002 6 Alstom LNCFS Level I1® system 7Alstom LNCFS Level II1® system

### 1.2 SelectiveNon-Catalytic Reduction ofNOy SNCR is a post combustion technology in which ammonia or urea is injected into the combustion
zone ofthe boiler where the temperature 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 ofthermal and fuel NOx, 

### SNCR injects a chemical to chemically reduce NOx 

### to nitrogen and water vapor (and carbon dioxide if
urea serves as the source ofammonia). The chemical reactions, which are not presented here, occurbetween nitric oxide (NO) and ammonia, i.e., NH3or CO(NH2 )2 to form carbon dioxide, water vapor, and nitrogen. Not all ofthe injected ammonia results in NOx 

### reduction reactions. Unreacted ammonia may react with S02
or S03 to form ammonium bisulfite and/or ammonium sulfate which will contribute to fouling economizer and air preheater surfaces and also contribute to plume visibility concerns. The application ofthis 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 NOx' 

### Greater reductions are limited by the low NOx 

### emissions rate already being achieved at Colstrip units 1&2. Operation ofSNCR also results in ammonia slip. Ammonia slip is residual ammonia that does not react with NOx 

### andtypically this can be limitedto about 10 parts permillion 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 reagent, in this case urea, would be injected into the combustion zone ofthe boiler and react with NOx' 

### In addition, there is likely to be significant fouling ofthe economizer and air heater surfaces. These impacts would require increased maintenance activities for cleaning the ammonium bisulfite and sulfate ammonia slip byproducts from the economizerand 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 ofa bed ofcatalyst 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 with the already low NOx 

### emission rate, the lowest emission rate attainable with the 0.20 Ibs/MMBtu at Colstrip Unit I or 2 is expected to be 0.06 Ibs/MMBtu, orabout a 70% reduction. Operation ofthe SCR also results in ammonia slip. Just as in SNCR, a slight excess ofreagent is required to reduce NOx 

### 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 byproducts ofammonia slip could occur. 2

### 2.0 COMBUSTION CONTROLS, SNCRAND SCRCOSTING 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. This platform has also been used by EPA's Clean Air Markets Division for analyzing air policy decisions. One aspect ofthe IPM is the capital, operating, and maintenance cost ofair pollution control equipment. These costing analytical techniques were summarized in reference I, available from the US EPA Clean Air Markets Division or through the link provided in the executive summary ofthis report. For NO" APCE cost analyses for the combustion controls, and for the two add-on, Le. post combustion, control technologies are presented; SNCR, and SCR. Pages 5-7 and 5-8 from the documentation document for the IPM model are presented in Attachment A-I. The data in Table 5-5 summarizes the costs for 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 datato be scaled to any coal fired boiler greaterthan 25 MW in gross power output. Table 5-7 lists the assumptions used in the IPM model for NOx 

### emission control efficiencies for SNCR and SCRtechnologies. Two additional background reports are included in Attachment A which describe the costing approach to SNCR and SCR. Each report was prepared by Sargent & Lundy, LLC under contract to the USEPA. Based upon a proprietary database ofcontrol installation costs, this engineering firm developed empirical equations which were used to estimate the costs ofcontrols as applied to all types ofcoal-fired boiler plants. This costing aspect ofthe IPM allowed analysis ofthe effect ofrules 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 ofthe capital equipment cost, S&L used the same approach to develop their capital costs for an installed retrofit project. More details regarding this approach are provided in AttachmentsA-2 and A-3.

2.I Combustion Controls Cost Analysis Usingthe IPM Methodology As shown in Attachment A- I, Table 5-5, there are several combustion controls options for tangentially-fired coal boilers like the boilers at Colstrip. PPL Montana used the cost data for Low-NOx 

### Coal-and Air Nozzles with Close-Coupled and Separated Overfire Air which would be similar to those installed and in operation at other PPL plants. Due to the already low emission rate ofNOx 

### at Colstrip 1&2 resulting from the combustion controls already installed, about a 43% reduction is expected from application ofSOFA system combustion control technology. Detailed cost calculations are presented in Tables 2-1a and 2-1b.

3

### 2.2 SNCR CostAnalysis Using the IPM Methodology Tables 2-2a through 2-2d show the results ofapplication ofthe 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 ofthe "retrofit factor" is provided in the analytical cost equations to allow for particularly difficult sites where application ofretrofit technology would be more difficult due to site specific factors. PPL Montana believes that the PM and S02 scrubbers already limit the space available for the installation ofreagent preparation equipment and reagent receipt and unloading operations, which will make the application ofSNCR difficult at the Colstrip site. PPL Montana has used a factor of 1.5 instead ofthe 1.0 that would characterize a more open site plan than that available at Colstrip Units 1&2. Tables 2-2b and 2-2d show the calculations ofthe $/ton ofNOx 

### for SNCR. SNCR uses urea that is injected into the combustion zone where it breaks down into two mples of ammonia and one mole of CO2 per mole of urea injected. Excess reagent is always required to attain acceptable NOx 

### reductions; however, the reductions that are attainable are higher when the uncontrolled NOx 

### is higher. At a typical ammonia slip concentration in the exhaust of 10 ppm, the unreacted ammonia would enterthe PM/S02scrubbers and cause unknown effects on the reaction chemistry. This could lead to higher fouling of scrubber components, increased maintenance, 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 of0.185 Ibs/MMBtu the cost effectiveness is estimated to be $8,I94/ton. This does not include cost oflost generation for an increase 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 ofapplication ofthe S&L costing methodology to Colstrip units I or 2 for SCR. The costs reflected in these tables reflect a retrofit factor of2.0based 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 ofa dry sorbent system to reduce sulfuric acid that may be increased as a byproduct ofthe SCR catalyst converting a small portion ofthe S02 to S03 and creatingthe potential for a visible plume. Application ofSCR at Colstrip Units I&2 is estimated to cost $7,300/ton assuming an emission rate of0.06 Ibs/MMBtu. This does not include any increased cost as a result oflost generation from an increase in forced outage rate. Even a one-day maintenance outage would increase the cost effectiveness by approximately $2I2/ton.8

8 This is less that the equivalentforced outage cost for an SNCR as the SCR removes moretons of NOx• 

### 4 Revised

### 3.0 CONCLUSION 

### The cost per ton of the estimated NOx 

### removed through installation of any of the available NOx 

### reduction technologies at Colstrip vary considerably, but are not warranted where no significant visibility benefit is expected from the resulting emission reductions. For this report, PPL Montana determined that it
was not necessary to update the June 2008 visibility assessments as the range ofNOx 

### emission reductions achieved by the evaluated control technologies in this addendum is within the range of NOx 

### reductions previously evaluated. Because there are no significant visibility benefits, the additional analysis of costs provided by this addendum does not change the conclusion that PPL Montana reached for Colstrip Units 1&2 in its August 2007 BART Assessment orthe June 2008 Addendum that implementation offurther NOx 

### control is not warranted.



### 5Table 2-1a PPL BART Cost Effectiveness Analysis Combustion Controls for NOx Colstrip Units 1&2 Two 333 MW Coal Fired Boilers (Each) 30-dayaverageemission NOx rate Maximum Gross Heat Input MM Btu/hr Design Percent Load % Uncontrolled NOx Emissions Ibs/MMBtu Steam Turbine Power Output (TMW) MW Capacity Factor (92%) hrs Controlled NOx Emissions IbslMMBtu Overall NOx Reduction Efficiency, (%) % Uncontrolled NOx Emissions, (Iblhr) Uncontrolled NOx Emissions, (tons/yr) Controlled NOx Emissions, (tonlyr) Annual Interest Rate, (%) Equipment Life, (yrs) yr Capital Recovery Factor, CRF CRF 3,982 92 0.350

333 8,059

0.20 42.86 1393.7 5616.1 3209.2 7 20 0.0944

Cost Item Suggested Factor Unit Cost Item Cost

From EPA Documentation StUdy (Reference 1) Equipment Cost Total, (EG) Total Capital Costs, TCC DirectAnnual Costs, DAC

Total DirectAnnual Costs, DAC IndirectAnnual Costs

Capital Recovery

Total IndirectAnnual Costs, lAC Total Annual Costs, TAC =DAC + lAC Cost Effectiveness ($/ton pollutant Removed) Capital Cost ($/KW) EC (Adjusted by Cost Index Cales)

Fixed 0& M Costs

CRFOTCC 38 (2011 dollars)!2)

0.3 S/kW-yr $12,188,686 $12,992,396 $12,992,396
$99,900 $99,900
$1,226,390 $1,226,390 $1,326,290 $551

Cost data references: 1) Cost analysis equations from "Documentation for EPA Base Case v.4.10 Usingthe 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-houraverageemissionNOx rate Maximum Gross Heat Input MM Btu/hr Design Percent Load % Uncontrolled NOx Emissions Ibs/MMBtu Steam Turbine Power Output (TMW) MW Capacity Factor (92%) hrs Controlled NOx Emissions IbslMMBtu Overall NOx Reduction Efficiency, (%) % Uncontrolled NOx Emissions, (Ib/hr) Uncontrolled NOx Emissions, (tonslyr) Controlled NOx Emissions, (tonlyr) Annual Interest Rate, (%) Equipment Life, (yrs) yr Capital Recovery Factor, CRF CRF 3,982 92 0.490

333 8,059 0.2600 46.94 1951.2 7862.5 4171.8 7 20 0.0944

Cost Item Suggested Factor Unit Cost Item Cost

From EPA Documentation Study (Reference 1) Equipment Cost Total, (EC) Total Capital Costs, TCC DirectAnnual Costs, DAC

Total DirectAnnual Costs. DAC IndirectAnnual Costs

Capital Recovery

Total IndirectAnnual Costs, lAC Total Annual Costs, TAC = DAC + lAC Cost Effectiveness ($lton pollutant Removed) Capital Cost ($/KW) EC (Adjusted by Cost Index Cales)

Fixed 0& M Costs

CRF*TCC 38 (2011 dollars)!2)

0.3 $/kW-yr $12,188,686 $12,992,396 $12,992,396
$99,900 $99,900
$1,226,390 $1,226,390 $1,326,290 $359

Cost data references: 1) Cost analysis equationsfrom "Documentation for EPA Base Case v.4.l0 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 Equation/lnput!ll SNCR CAPITAL COST FOR COLSTRIP 1 OR 2 (EACH) 30 DAY AVERAGE NOx Variable Designation Units Value
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 Ibs/MMBtu 0.2 Uncontrolled S02 Emiss Rate E Ibs/MMBtu 1.8 Input Type ofCoal E PRB 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 (Ibs/hr) 79.64 D x H/106xJ/10 Urea Rate L (Ibs/hr) 346.26 K/0.15/46 x 30 Water Required M (Ibs/hr) 3116.35 Lx 9 Dilution Water Rate 0 (1,000 gph) 0.37 M x 0.12/1000 Urea Cost 50% wgt Soln P ($/ton) 450 Input Dilution WaterCost R ($/kgal) 1 Input Operating Labor Rate S ($/hr) 60 Input CAPITAL EQUIPMENT COSTS SNCR Injectors, DCS BMS ($) $3,531,624 B xF/1.0S x200000 x (AxGjO.42 Air Heater Mods (not reqd) BMA ($) $0 Balance of Plant Costs BMB ($) $3,103,888 270000 x A 0.33 XKO.12 Bare Module Cost BM ($) $6,635,513 BMS+BMA+BMB Engineering, Const Mgmt A1 ($) $663,551 10% ofBM Labor Adjustment A2 ($) $663,551 10% ofBM Contractor Profit, Fees A3 ($) $663,551 10% ofBM Cap, Eng, Const Cost CECC ($) $8,626,166 BM +Al +A2 +A3 Owners Cost B1 ($) $431,308 5% ofCECC Total Project Cost TPC ($) $9,057,475 CECC + B1 Cost per kW ($) 27 $/kW OPERATING AND MAINTENANCE COSTS Fixed Operator Cost FOMO ($) $62,400 2,080 hrs- 1- halftime Maintenance Material FOMM ($) $79,626 1.2% of BM Total Fixed O&M ($) $142,026 FOMO + FOMM Urea Cost VOMR ($) $77.91 Lx P Dilution WaterCost VOMM ($) $0.37 OxR

Notes: 1) Cost analysis equations from "IPM Model-Revisions to Cost And PerformanceforAPC Technologies-SNCR Cost Development Methodology-FINAL", August 2010 Project 12301-007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC


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

Maximum Gross Heat Input MM Btu/hr 3,982 Design Percent Load % 92 Uncontrolled NOx Emissions (with PRB coal) Ibs/MMBtu 0.200 ExhaustTemperature, (oF) T 314 Steam Turbine Power Output (TMW) MW 333 Capacity Factor (92%) hrs 8,059 Controlled NOx Emissions Ibs/MMBtu Note 3 0.185 Overall NOx Reduction Efficiency, (%) % 7.50 Uncontrolled NOx Emissions, (Ib/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

Cost Item Suggested Factor Unit Cost Item Cost

IPM Model, August 20,2010(1) Equipment CostTotal, (EC) Total Capital Costs, TCC DirectAnnual Costs, DAC

Total DirectAnnual Costs, DAC IndirectAnnual Costs

Capital Recovery

Total IndirectAnnual Costs,IAC Total Annual Costs, TAC = DAC + lAC Cost Effectiveness ($/ton pollutant Removed) Capital Cost ($/KW) EC (Adjusted by Cost Index Cales)

Urea Cost Dilution Water Cost Air Preheater Cleaning

Maintenance Labor Maintenance Materials

CRF*TCC 27 (2011 dollars)12)

VOMR VOMM Four at $60,000each FOMO FOMM $9,057,475 $9,316,133 $9,316,133

$627,882

$3,014 $320,000

$62,400 $79,626 $1,092,922

$879,377 $879,317 $1,972,299 $8,194

Cost data references: 1) Cost analysis equationsfrom "IPM Model-Revisionsto 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 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 ofammonia 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 Equation/Input!!) SNCR CAPITAL COST FOR COLSTRIP 1 OR 2 (EACH) 24 HOUR AVERAGE NOx Unit Capacity (Gross) Variable Designation Units Value
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 Ibs/MMBtu 0.26 Uncontrolled S02 Emiss Rate E Ibs/MMBtu 1.8 Input Type ofCoal E PRB 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 D x H/106xJ/10 Urea Rate 103.53 K (Ibs/hr) L (Ibs/hr) 450.14 K/0.15/46 x 30 Water Required M Lx 9 Dilution Water Rate (Ibs/hr) 4051.25 (1,000 gph) 0 0.49 M x 0.12/1000 Urea Cost 50% wgt Solr P ($/ton) 450 Input Dilution Water Cost R 1 Input Operating Labor Rate ($/kgal) Input CAPITAL EQUIPMENT COSTS SNCR Injectors, DCS S ($/hr) 60

B x F /1.05 x 200000 x(AxGj"·42 BMS ($) $3,531,624 ($) Air Heater Mods (not reqd) BMA $0



### . 270000 x A 0.33 X KO. 12 BMB ($) $3,203,165 Bare Module Cost Balance of Plant Costs ($) BM $6,734,789 BMS+BMA+BMB Engineering, Const Mgmt ($) $673,479 10% ofBM LaborAdjustment A1 10% ofBM Contractor Profit, Fees ($) $673,479 A2 A3 ($) $673,479 10% ofBM Cap, Eng, Const Cost ($) $8,755,226 BM +Al+A2 +A3 Owners Cost CECC ($) 5% ofCECC Total Project Cost B1 $437,761 ($) CECC + B1 Cost per kW TPC $9,192,987 ($) 28 $/kW OPERATING AND MAINTENANCE COSTS Fixed Operator Cost 2,080 hrs- 1- halftime Maintenance Material FOMO ($) $62,400 1.2% of BM Total Fixed O&M ($) $80,817 FOMM $143,217 FOMO+ FOMM Urea Cost ($) $101.28 Lx P Dilution WaterCost VOMR $/hr OxR VOMM $0.49 $/hr Notes: 1) Cost analysis equations from "IPM Model-Revisions to Cost And Performance forAPC Technologies-SNCR Cost Development Methodology-FINAL", August 2010 Project 12301-007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC

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

Maximum Gross Heat Input MM Btu/hr 3,982 Design Percent Load % 92 Uncontrolled NOx Emissions (with PRB coal) Ibs/MMBtu 0.260 ExhaustTemperature, CF) T 314 Steam Turbine Power Output (TMW) MW 333 Capacity Factor (92%) hrs 8,059 Controlled NOx Emissions IbslMMBtu Note 3 0.239 Overall NOx Reduction Efficiency, (%) % 8.08 Uncontrolled NOx Emissions, (Ib/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

Cost Item Suggested. Factor Unit Cost Item Cost

IPM Model, August 20,2010(1) Equipment Cost Total, (EG) Total Capital Costs, TCC DirectAnnual Costs, DAC

Total DirectAnnual Costs, DAC IndirectAnnual Costs

Capital Recovery

Total IndirectAnnual Costs, lAC Total Annual Costs, TAC = DAC + lAC Cost Effectiveness ($/ton pollutant Removed) SNCR Capital Cost ($/KW) EC (Adjusted by Cost Index Cales)

Urea Cost Dilution Water Cost Air Preheater Cleaning

Maintenance Labor Maintenance Materials

CRF*TCC 28 (2011 dollars)!2)

VOMR VOMM Fourat $80,000 each FOMO FOMM $9,192,987 $9,455,515 $9,455,515

$816,246

$3,918 $320,000

$62,400 $80,817 $1,283,382

$892,534 $892,534 $2,175,915 $6,457

Cost data references: 1) Cost analysis equations from "IPM Model-Revisionsto 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 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 ofammonia 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 Equation/lnput(1) SCR CAPITAL COST FOR COLSTRIP 1 OR 2 (EACH) 30 DAY AVERAGE NOx Variable Designation Units Value
Unit Capacity (Gross) A (MW) 333 Input Retrofit Factor B 2 Difficulty of Retrofit Gross heat rate C Btu/KW-hr 11,958 Input INUXtmlss Kate D IlbsjMMBtu 0.2 --Uncontrolled I::>U2 tmlss Kate E IlbsjMMBtu 1.8 Uncontrolled Type ofCoal F PRB Input Coal Factor G 1.05 Input Heat Rate Factor H 1.20 

### C/lO,OOO Heat Input I Btu/hr 3.98E+09 AX C x 1000 Capacity Factor J (%) 92.0 Input NOx Removal Eff K (%) 70.00 Input NOx Removal Factor L 'L1 (Ibs/hr) 0.875 (Based on Model Plant) NOx Removed M (Ibs/hr) 557.48 D

### xI / lOb * K/ 100 Urea Rate N (Ibs/hr) 389.46 M x0.525 * 60/46 *1.01/.99 Steam Required M (Ibs/hr) 440.10 N x 1.13 Urea Cost 50% wgt 50ln R ($/ton) 450 Input CataIyst Cost S ($/m3) 8000 Input Steam Cost U ($/klbs) 4 Input Operating Labor Rate V ($/hr) 60 Input CAPITAL EQUIPMENT COSTS 5CR Ducts, Reactor Island BMR ($) $90,425,605 180000x B X L O

.2X (AxGxH)o.92 Base Reagent Prep Cost BMF ($) $1,992,238 410000 x MO.25 ID Fans, Anciliary Equip BMB ($) $9,588,609 380000 x B x (AxGxH)O.42 Bare Module Cost BM ($) $102,006,452 BMR+BMF+BMB Engineering, Const Mgmt A1 ($) $10,200,645 10% ofBM Labor Adjustment A2 ($) $10,200,645 10% ofBM Contractor Profit, Fees A3 ($) $10,200,645 10% ofBM Cap, Eng, Const Cost CECC ($) $132,608,387 BM + A1 + A2 + A3 Home office Costs B1 ($) $6,630,419 5% ofCECC Construction Funds B2 ($) $8,354,328 6% ofCECC+Bl Total Project Cost TPC ($) $147,593,135 CECC + B1 + B2 Cost per kW 443 $/kW OPERATING AND MAINTENANCE COSTS II-IXed uperator Lost FOMO S62,400 2,080 hrs- 1- halftime IMalntenance Matenal FOMM S300,OOO Fixed Annual Cost Total Fixed O&M FUM S362,400 FOMO+ tUMM lurea Lost VUMK S87.63 NXR ISteam Cost VUMM Sl.76 OxU ILatalyst cost' VUMW SO.35 :;>/IVlvvr r Notes: 1) Cost analysis equations from "IPM Model-Revisions to Cost And PerformanceforAPC 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 "( X

### J"; this is the model plant removal efficiencyfor PRB coal 3) S&L lists this to be a discrete function ofA, G, 

### J, K, and Sin $/MW-hr
Page 12 RevisedTable 2-3b PPL BART Cost Effectiveness Analysis SCR NOx Control Colstrip Units 1&2 Two 333 MW Coal Fired Boilers (Each) 30-dayaverage emission NOx rate Maximum Gross Heat Input MM Btu/hr Design Percent Load % Uncontrolled Emissions Ibs/MMBtu ExhaustTemperature, (oF) T Steam Turbine Power Output (TMW) MW Capacity Factor (92%) hrs Controlled NOx Emissions Ibs/MMBtu Overall NOx Reduction Efficiency, (%) % Uncontrolled NOx Emissions, (Ib/hr) Uncontrolled NOx Emissions, (tons/yr) Controlled NOx Emissions, (tonlyr) Annual Interest Rate, (%) Equipment Life, (yrs) yr Capital Recovery Factor, CRF CRF 3,982 92 0.200

314 333 8,059

0.06 70.00 796.4 3209.2

962.8 7 20 0.0944

Cost Item Suggested Factor Unit Cost Item Cost
(PM Model, August 20,2010(1) Equipment Cost Total, (EC) Total Capital Costs, TCC DirectAnnual Costs, DAC

Total DirectAnnual Costs, DAC IndirectAnnual Costs

Capital Recovery

Total IndirectAnnual Costs, lAC Total Annual Costs, TAC = DAC + lAC Cost Effectiveness ($/ton pollutant Removed) Capital Cost ($/KW) EC (Adjusted by Cost Index Cales)

Catalyst Cost(4)

Urea Cost Steam Cost Maintenance Labor Maintenance Materials

CRPTCC 443 (2011 dollars)(2,3)

VOMW VOMR VOMM FOMO FOMM $147,593,135 $152,306,678 $152,306,678

$939,300 $706,224

$14,187 $62,400 $300,000 $2,022,111
$14,376,673 $14,376,673 $16,398,784 $7,300

Cost data references: 1) Cost analysis equations from "IPM Model-Revisionsto Cost And Performance for APC Technologies-SCR Cost Development Methodology-FINAL", August 2010 Project 12301-007, Perrin QuarlesAssociates, 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 sarbent system for control of S03 4) Cost is for replacement and disposal based on S&L cost estimate in $/MW-hrfor PRB coal

Page 13 Revised

### Table 2-3c SCR COSTING DEVELOPMENT FOR CAPITAL AND OPERATION AND MAINTENANCE COSTS Equation/lnput(!) SCR CAPITAL COST FOR COLSTRIP lOR 2 (EACH) 24 HOUR AVERAGE NOx Variable Designation Units Value
Unit Capacity (Gross) A (MW) 333 Input Retrofit Factor B 2 Difficulty of Retrofit Gross heat rate C Btu/KW-hr 11,958 Input INUX tmlss Kate D Ilbs/MMBtu 0.26 Uncontrollea I::>U2 tmlss Kate E Ilbs/MMBtu 1.8 Uncontrollea Type ofCoal F PRB Input Coal Factor G 1.05 Input Heat Rate Factor H 1.20 C/10,000 Heat Input I Btu/hr 3.98E+09 AXCx 1000 Capacity Factor 

### J (%) 89.0 Input NOx Removal Eff K (%) 76.92 Input NOx Removal Factor ll"l (Ibs/hr) 0.875 (Based on Model Plant) NOx Removed M (Ibs/hr) 796.40 D

## xI / lOb * K/ 100 Urea Rate N (Ibs/hr) 556.38 Mx0.525 * 60/46 *1.01/.99 Steam Required M (Ibs/hr) 628.71 

### NXl.13 Urea Cost 50% wgt 50ln R ($/ton) 450 Input Catalyst Cost S ($/m3) 8000 Input Steam Cost U ($/klbs) 4

. Input Operating labor Rate V ($/hr) 60 Input CAPITAL EQUIPMENT COSTS 5CR Ducts, Reactor Island BMR ($) $90,425,605 180000xB XLO.2X(AxGxHjo.92 Base Reagent Prep Cost BMF ($) $2,178,044 410000x MO.2S ID Fans, Anciliary Equip BMB ($) $9,588,609 380000 x B x (AxGxH)O.42 Bare Module Cost BM ($) $102,192,258 BMR+BMF+BMB Engineering, Const Mgmt Al ($) $10,219,226 10% ofBM Labor Adjustment A2 ($) $10,219,226 10% ofBM Contractor Profit, Fees A3 ($) $10,219,226 10% ofBM Cap, Eng, Const Cost CECC ($) $132,849,936 BM + Al + A2 + A3 Home office Costs B1 ($) $6,642,497 5% ofCECC Construction Funds B2 ($) $8,369,546 6% ofCECC+Bl Total Project Cost TPC ($) $147,861,978 CECC + B1 + B2 Cost per kW 444 $/kW OPERATING AND MAINTENANCE COSTS II-Ixed uperator Lost FOMO -S62,400 2,080 hrs-1- halftime 

### IMamtenance Material FOMM 5300,000 Fixed Annual Cost Total Fixed O&M FUM 5362,400 FOMU+ FOMM lurea Lost VUMK 5125.19 NXR ISteam Cost VUMM 52.51 OxU ICatalyst cost VUIVlW -SU35 ::>/IVlwnr Notes: 1) Cost analysis equations from "IPM Model-Revisions to Cost And PerformanceforAPC 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 XJ"; this is the model plant removal efficiencyfor PRB coal 3) S&llists this to be a discretefunction ofA, G, 

### J, K, and Sin $/MW-hr
Page 14Table 2-3d PPL BART Cost Effectiveness Analysis SCR NOx Control Colstrip Units 1&2 Two 333 MW Coal Fired Boilers (Each) 24-houraverage emission NOx rate Maximum Gross Heat Input MM Btu/hr Design Percent Load % Uncontrolled Emissions Ibs/MMBtu ExhaustTemperature, (OF) T Steam Turbine Power Output (TMW) MW Capacity Factor (92%) hrs Controlled NOx Emissions Ibs/MMBtu Overall NOx Reduction Efficiency, (%) % Uncontrolled NOx Emissions, (Ib/hr) Uncontrolled NOx Emissions, (tons/yr) Controlled NOx Emissions, (ton/yr) Annual Interest Rate, (%) Equipment Life, (yrs) yr Capital Recovery Factor, CRF CRF 3,982 92 0.260

314 333 8,059

0.06 76.92 1035.3 4171.9

962.8 7 20 0.0944

Cost Item Suggested Factor Unit Cost Item Cost

IPM Model, August 20, 2010(1) Equipment Cost Total, (EC) Total Capital Costs, TCC DirectAnnual Costs, DAC

Total DirectAnnual Costs, DAC IndirectAnnual Costs

Capital Recovery

Total IndirectAnnual Costs, lAC Total Annual Costs, TAC = DAC + lAC Cost Effectiveness ($/ton pollutant Removed) Capital Cost ($/KW) EC (Adjusted by Cost Index Cales)

Catalyst Cost(4)

Urea Cost Steam Cost Maintenance Labor Maintenance Materials

CRF*TCC 444 (2011 dollars)12,3)

VOMW VOMR VOMM FOMO FOMM $147,861,978 $152,584,107 $152,584,107
$939,300 $1,008,892 $20,268 $62,400 $300,000 $2,330,859
$14,402,860 $14,402,860 $16,733,719 $5,214

Cost data references: 1) Cost analysis equations from "IPM Model-Revisionsto Cost And Performance forAPC Technologies-SCR Cost Development Methodology-FINAL", August 2010 Project 12301-007, Perrin QuarlesAssociates, Inc., prepared bySargent &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 S03 4) Cost is for replacement and disposal based on S&L cost estimate in $/MW-hr for PRB coal

Page 15

# ATTACHMENTA-I COMBUSTION CONTROLS COSTTABLES

### 5.2 Nitrogen Oxides Control Technology The EPA Base Case v.4.10 includes two categories of NO. reduction technologies: combustion and post-combustion controls. Combustion controls reduce NO. emissions during the combustion process by regulating flame characteristics such as temperature and fuel-air mixing. Postcombustion controls operate downstream ofthe combustion process and remove NO. 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.4.1 0 representation of combustion controls uses equations that are tailored to the boilertype, 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. emission limits they face. Characterizations ofthe 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. Combustion Controls are summarized in Table 5-5. Table 5-6 provides a mapping ofexisting 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$) of NO. Combustion Controls for Coal Boilers (300 MW Size) Fixed Capital O&M Variable O&M BoilerType Technology ($/kW) ($/kW- (mills/kWh) vr) Low NO. Burnerwithout Overfire Air 45 0.3 0.07 Dry Bottom Wall­ (LNB without OFA) Fired Low NO. Burnerwith Overfire Air 61 0.4 0.09 (LNB with OFA) Low NO. Coal-and-Air Nozzles with 24 0.2 0.00 Close-Coupled Overfire Air (LNC1) Low NO. Coal-and-Air Nozzles with Tangentially­ 33 0.2 0.03 Separated Overfire Air (LNC2) Fired Low NO. Coal-and-Air Nozzles with Close-Coupled and Separated 38 0.3 0.03 Overfire Air (LNC3) Vertically-Fired NO. Combustion Control 29 0.2 0.06 Scaling FactQr The following scaling factor is used to obtain the capital and fixed operating and maintenance costs applicable to the capacity (in MW) ofthe unit taking on combustion controls. No scaling factor is applied in calculating the variable operating and maintenance cost. LNB without OFA & LNB with OFA

# =($ forX MW Unit)

# =($ for 300 MW Unit) x (300/X)°·359 LNC1, LNC2 and LNC3

# =($ forX MW Unit)

# =($ for 300 MW Unit) x (300/X)°·359 Vertically-Fired

# =($ forX MW Unit)

# =($ for 300 MW Unit) x (300/X)°·553 where ($ for 300 MW Unit) is the value obtained using the factors shown in the above table and Xis the capacity (in MW) ofthe unit taking on combustion controls.

5-7Table 5-6 Incremental Combustion NOx Controls in EPA Base Case v.4.10 BoilerType Existing NOx Combustion Control Incremental Combustional Control Cell LNB NGR OFA LNBAND OFA Cyclone



## -­ OFA Stoker/SPR



## -­ OFA

Tangential 

# -­ LA LNB LNB + OFA LNC1 LNC2 OFA ROFA LNC3 LNC3 CONVERSION FROM LNC1 TO LNC3 CONVERSION FROM LNC1 TO LNC3 CONVERSION FROM LNC1 TO LNC3 CONVERSION FROM LNC2 TO LNC3 LNC1 LNB Vertical 

# -- NOxCombustion Control
- Vertically Fired Units

Wall 

## -­ LA LNB LNF OFA LNBAND OFA LNBAND OFA OFA 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. NOx reduction in an SCR system takes place by injecting ammonia (NH3) vapor into the flue gas stream where the NOx is reduced to nitrogen (N2) and water H2

### 0 abetted by passing over a catalyst bed typically containing titanium, vanadium oxides, molybdenum, and/ortungsten. 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, hotflue gas where it reacts with the NOx in the gas stream reducing itto nitrogen gas and water vapor. Due to the presence ofa catalyst, SCR can achieve greater NOxreductions 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 NOx post-combustion control technology and provides a cross reference to information on cost assumptions. Table 5-7 Summary 0f Retrofi It NO 'x Emission ControI P erformance

### Assumptlons Control Selective Catalytic Reduction Selective Non-Catalytic Performance Reduction Assumptions (SCR) (SNCR) Unit Type Coal Oil/Gas Coal Percent Removal 90% down to 0.06 80% Pulverized Coal: 35% Ib/MMBtu Fluidized Bed: 50% Size Applicability Units 2: 25 MW Units 2: 25 MW Units 2: 25 MW

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

5-8

# ATTACHMENTA-2 SNCRCOSTDEVELOPMENTMETHODOLOGY­ SARGENT & 

# LUNDY, LLC,AUGUST 2010

## IPMModel

- Revisions to Cost and Performance for APC Technologies

SNCRCostDevelopmentMethodology FINAL August 2010 Project 12301-007 Perrin Quarles Associates, Inc.
Prepared by



## Sarge LundyllC

55 East Monroe Street· Chicago, IL 60603 USA· 312-269-2000LEGAL NOTICE This analysis ("Deliverable") waspreparedbySargent 

### &Lundy, L.L.C. ("S&L**'~,** expressly for the sole use ofPerrin QuarlesAssociates, Inc.**("Client'~** in accordance with the agreement between S&L and Client. This Deliverable was prepared using the degree ofskill and care ordinarily exercised by engineers practicing undersimilar circumstances. Client acknowledges: (I) S&Lpreparedthis Deliverable subject to theparticular scope limitations, budgetary andtime constraints, andbusiness objectives of the Client; (2) information and data provided by others may not have been independently verified by S&L; and (3) the information anddata contained in this Deliverable are time sensitive andchanges in the data, applicable codes, standards, andacceptable engineeringpracticesmay invalidate thefindings of this Deliverable. Any
use or reliance upon this Deliverable by thirdpartiesshall b(/attheirsole risk.

This workwas fundedandreviewedby the 

## us. Environmental ProtectionAgency under the supervision of William A. Stevens, SeniorAdvisor

- Power Technologies. Additional input and review wasprovided by Dr. Jim Staudt, President of Andover Technology Partners.SEIIrgent & Lundy' ,.


### IPM Model- Revisions to Cost and Performance for ProjectNo. 12301-007 APC Technologies August 20, 20I0 

## SNCRCostDevelopmentMethodology

- Final Establishment ofCostBasis The formulation ofthe SNCRcost estimating model is based upon a proprietary Sargent & Lundy LLC (S&L) in-house data base ofrecent (2009) quotes for both lump sum contracts and EPe. The S&L data was analyzed in detail regarding project specifics such as coal type, boilertype, and NOx reduction efficiency. The S&L in-house data includes projects that involved cyclone boilers, T-fired and wall fired systems with multiple levels ofinjection. The cyclone boilercosts include rich reagent injection (RRI). The data was the basis for the costestimate formulations developed. The S&L data was fitted with a least squares curve to establishthe trend in $/kW as a function ofgross MW. The EPA/IPM SNCRcost model parameters were adjusted to account for market changes and escalation, and then the model outputwas compared to the S&L data. The EPA/IPM model output followed a $/kW correlation very similarto the S&L in-house data, once the adjustments were made to the model. The rapid rise in projectcosts at the lower end ofthe MW range is due primarily to economies ofscale. Additionally, older power plants in the 50 MW range tend to have plant sites that are more compactand therefore difficult to accommodate the reagent storage areas and piping, injection mixing/dilution equipment and construction activities. The smallerpowerplants also tend to have oldercontrol systems which may require upgrades to accommodate the new SNCRcontrol system. The S&L data includes SNCRprojects with various types ofboilers, coals, sulfur levels and retrofit complexities. The data represents an average ofboilereffects, such as cyclone, wall fired orCFB. The least squares curve fits were based upon the following assumptions:

• Retrofit Factor =1 • Gross Heat Rate 

## = 10,000 • SOz Rate 

## = < 3 Ib/MMBtu • Type ofCoal 

## =PRB • Project Execution = 

### Multiple lump sum contracts 

## Methodology Inputs Topredict future retrofit costs several input variables are required. The unit size in MW and NOx levels are the majorvariables for the capital costestimation followed by the type offuel (high sulfurBituminous). The fuel type affects the airpre-heatercosts if sulfuric acid orammonium bisulfate deposition poses a problem. In general, ifthe level ofSOz is above 3 Ib/MMBtu, it is assumed that airheatermodifications will be required. The unit heatrate factors into the amount ofNOx generated and ultimately the size oftheSargent & Lundy'"


### IPM Model- Revisions to Cost and Performance for ProjectNo. 12301-007 APC Technologies August 20, 2010 

## SNCRCost DevelopmentMethodology

- Final SNCRreagent preparation system. A retrofit factor that equates to difficulty in construction ofthe system must be defined. The NOx 

### rate and removal efficiency will impactthe amount ofurea required and size ofthe reagent handling equipment. The inputs that impactthe variable O&M costs are based primarily on the plant capacity factor andthe removal efficiency. The NOx removal efficiency specifically affects the reagent and dilution watercosts. 

### Outputs TotalProject 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 SNCRcost. BMA= Base module air pre-heatercost. Base module balance ofplant costs including: piping, electrical, site BMB= upgrades, etc
... BM= BMS+BMA+BMB
The total base module cost (BM) is increased by:

• Engineering and construction management costs at 10% ofthe BM cost; • Labor adjustment for 6 x 10 hour shift premium, perdiem, etc., at 10% ofthe BM cost; and • Contractor profit and fees at 10%ofthe BM cost. 2Sargenl: & Lundy'" 

### (PM Model- Revisions to Cost and Performance for ProjectNo. 12301-007 APC Technologies August 20,2010 

## SNCRCostDevelopmentMethodology

- Final

A capital, engineering, and construction cost subtotal (CECC) is established as the sum of the BM and the additional engineering and construction fees. Additional expenditures for the project are computed based on the CECCo The additional projectcosts include:

• Owner's home office costs (owner's engineering, management, and procurement) at 5% ofthe CECCo The total projectcostis based on a multiple lump sum contract approach. Should a turnkey engineering procurementconstruction (EPC) contract be executed, the total projectcost could be 10 to 15% higherthan what is currently estimated. Escalation is not included in the estimate. The total project cost (TPC) is the sum ofthe CECC andthe Owner's home office costs. An example ofthe capital cost estimation is included in Table I.
FixedO&M(FOM) 

### The fixed operating and maintenance cost is a function ofthe additional operations staff (FOMO) and maintenance labor and materials (FOMM) associated with the SNCR installation. The FOM is the sum ofthe FOMO and the FOMM. The following factors and assumptions underlie calculations ofthe FOM:

• In general, I additional operator is required for all installations. The FOMO is based on the number ofadditional operations staffrequired; and

• The fixed costs for maintenance materials and labor are a direct function ofthe base module cost (BM) ata retrofit factor of 1.0.
Variable O&M(VOM) 

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

• Reagent consumption; • Dilution water consumption. All ofthe VOM costs must be adjusted for the plantcapacity factor. The reagent consumption rate is a function ofunit size, NOx 

### feed rate and removal efficiency. A utilization factor of 15% is used for units with an inletNOx of0.3 Ib/MMBtu or lower and 25% for units with an inletNOx greaterthan 0.3 Ib/MMBtu. For CFB boilers a utilization factor of25% is used. A reagent cost of$620 perton of 100% 

### 3Sargent: & Lundy" C


### IPM Model

- Revisions to Cost and Performance for ProjectNo. 12301-007 APC Technologies August 20, 2010 

## SNCRCostDevelopmentMethodology

- Final

urea is used in the model. The dilution water usage is based upon reagent consumption rate. The auxiliary powerrequired for the SNCRsystem is not included in the YOM. The major systems that impactthe power requirements are compressed air orblower requirements for the urea injection system and the reagent supply system. The variablesthatcontribute to the overall YOM are: VOMR Variable O&M costs for urea reagent. VOMM Variable O&Mcosts for dilution water. YOM VOMR+VOMM.



### 4sargent & Lundy' ,.


### IPM Model- Revisions to Cost and Performance for ProjectNo. 12301-007 APC Technologies August 20, 2010 

## SNCRCostDevelopmentMethodology

- Final Table 1. 

### ExampleoftheCapitalCostEstimateWorkSheet (forT-fired boilers). DesignatIon nits value I. ariable T.nqenb.oI OilerTvee A MW 300 nit Size 1 etrofit Factor B**(ljtulkw~** 100uO eat Rate L (Ib1MMBtu) 0.22 Ox Rate D (Ib1MMBtu) 2 02 Rate E BltummUOU5 

# ... Irvoe ofCoal E 1

O3ll'"actor I'" lj rteat Hate I'"actor 1 H (Btulhr) 3.00E+OS Heat InPut (VA.)

apacity Factor I 85 l{, z:> ox Removal Efficiencv J 1.65E+02 K IbIh ox Removed (Iblhr) 717 rea Rate 100% L 6457 ater Required M /Ib1hr ('lit) _Power 0_05 N .Iution Water Rate 1000aoh 0.77 0 rea Cost !>U% wt solutIon (:l>/ton) 310 t-' Q U.Ub ux ,",ower Cost (:l>/kWn R ($lkoal 1 ilution Water Cost 6(J )peratino Labor Rate Slhr

Includes
- EqUIpment, installation. buildings, foundations, electrical, and retrofit difficulty Lalcu ation

... <--- User Inout

<--- User Inout <--- User lnout An "avera<:le" retrofit has a factor
- 1.0) < - User Input <-- User Input

<-- User Inout Bit 1.0. t-'HI::l' 1.0t>. Lig 1.07 CJl .OOC A*C*10oo <--- User Input**D'Hll0~6°J/l00** KlUF/46°30; IF Boller Type CFB OR 0 > 0.3 THEN UF 025: ELSE UF 015 LOS Auxiliauv Poweris not used in1heVariable O&M Costs M'O.1211OO0

Labor cost IOclud,nQ all bene Its 

### Costs are all based on 2009 dollars Capital Cost Calculation BMS S)­ B*F/1.05*200000* A*Gl"0.42 BMA Sl II'" e 2; 3 IHeN 6!:>OC0' B 0 A'GjAO. 8; ELSe BMB Sl­ 270000·(A\"033*(K)AO.12 BM($

- BMS + BMA+ BMB BM $JKW

- Total Project Cost Al
­ 10% ofBM AL lu"Jb of IjM A3
­ 10% ofBM CECC $ = BM+A1+A2+A3 CECC ($lkW)

­ B I = 5% of CECC
TPC ($1

­ CECC + 61 TPC SIkWl= ExamDie Comments $ 2,090,000 SNCR In·ectors. Blowers, DCS, Reaaent SYStem Cost :> - Air Heater Modi lcation I :>U,j Control (ljituminousonly & > ,jlb!mmljtu $ 3,273,000 Balance of PlantCost PiDino, Includino Site Upgrades) $ 5,363.000 Total bare module cost includino retrofitfactor 18 Base cost eer kW
$ 536,000 Engineering and Construction Management costs $ 536,000 Laborad'ustment for 6 x 10 hour shift Drermum, per diem, etc

... $ 536,000 Contractor orofit andfees $ 6971 000 Caoital. enoineerino and construciton cost subtotal 23 Caoital, enoineerino and construciton cost subtotal Der kW Owners costs inclUding all "homeoffice" costs (owners engineenng. $ 34S,OOO manaoement, and procurementactivities) $ 7.320,000 Total oroiectcost 24 Total oroiect cost per kW



### 5Sargent: & Lundy'"


### IPM Model- Revisions to Cost and Performance for ProjectNo. 12301-007 APC Technologies August 20, 20I0 

## SNCRCostDevelopmentMethodology

- Final Table2. ExampleoftheFixed and Variable O&M CostEstimateWorkSheet (forT-fired boilers).

Wariable Desianation Units I Walue I Calculation BoilerTvoe T"I19enti.ol

... <-- User Input Unit Size A (MWl 300 <--- User Input Retrofit Factor B 1 <--- User Input (An "average" retrofit has afactor
- 1.0\ Heat Rate C (BtulkVVhl 10000 <--- User lnout NOxRate 0 IIb1MMBtu) 0.22 <-- User Input S02Rate E (lblMMBtul 2 Tvve ofCoal E**6It:WlllrlUDU~** 

# ... <--- User Input I{,;oal Factor F 1 Bit=1.0. Pf.lli=1.05, lig=1.Ur Heat Rate Factor G 1 Cllo,ooo Heat Inout H IBtulhrl 3.ooE+09 A"C"lOoo I\,;apacity Factor I (l'o) 85 <-- User Input Nox Removal Efficiencv J % 25 Nox Removed K Iblh 1.65E+02 O'HllQJ16'Jlloo Urea Rate 1100%1 L (Ib1hr) 717 KlUF/46'30; IF BoilerType
­ CFB OR 0 >0.3 THEN UF =0.25; ELSE UF =0.15 lWater Reouired M (Iblhr) b4t>7**L'~** N t%) 0.05 IAuxiIiarYPowerisnotusedintheVariable O&M Costs Dilution Water Rate 0 (1000 aohl 0.77 M"0.12/1000 Urea Cost 50% wt solution P ($lton) 310 IAux Power Cost 

## a ($/kWh) 0.06 Dilution Water Cost R I$fkaall 1 Ooeratina labor Rate S ($fhr) 60 Laborcost includma all benefits 

### Costs are all based on 2009 dollars
Fixed O&M Cost FOMO l$lkWVT\-' (1/2 ooeratortime assumed)'2080'SIIA*1OOM FOMMI$lkWVi'I- 0.012·BMlA/l0D0 FOM ISlkWvrl FOMO + FOMM Variable O&M Cost V = L'PiA/l000 VOMM ISlMWh) =O'RiA**VOMI~I-VOMR+VOMM** $ 0.21 Fixed O&M additional ooeratina labor costs $ 0.21 Fixed O&M additional maintenance material and labor costs S 0.42 T olal Fixed O&M costs
$ u.r4 Variable O&M costs for Urea $ 0.00 Variable O&M costs for dilution water S 0.74



### 6anaDle BotlerTvoe Unit Size Retrofit Facto< Deslanaton A Units MW B Heat Rate NOx Rate S02Rate

ypeofCoal C (Eltulk'A'h D IblMMBtu E IblMMBtu) E oal t-actor eat Rate Factor F G eat Input apacitv Factor H Btulhr I (%) ox**~emoval** t:.lhciency J Nox Removed K IbIh Urea Rate 100% L (Ib1hr) Water Reouired M 'Iblhr IWlCPower DIlution Water Rate N % 0 1000aoh Urea (,;ost !:>U% wtsolutIon

ux
....ower ..;cst Dilution Water Cost P R (:lillon) {s/kWh: ($IkQal) JDerat,oo aDOr Kate S (ll>Ihr Sargent: & Lundy" t


### IPM Model

- Revisions to Cost and Performance for ProjectNo. 12301-007 APC Technologies August 20, 2010 

## SNCRCost DevelopmentMethodology

- Final Table3. Exampleofthe Capital CostEstimateWork Sheet (forCFB boilers). Value Caculation CFB

.. 300

1 1uOoo 0.15 0.2 8o/t:ummuous 

# ... 1 1 3.00E+09 85 25 1.13E+02

293 2641 0.05 0.32 31u .06 1 60 <--- User Input < -- User Input <--- User Input An "averaae" retrofit has a factor 1.0\ < - User Input < - User Inout

<-- User Input Bit-l.0. PRB' 1.05, Lig 1.07 C/1C.OOO A·C·l000 < - User nput D"H/l O"S"J/l 00 KlUF/4S"30; IF Boller Type CFB OR D > 0.3THEN UF
- 025: ELSE UF L"9 IAuxiiarvPower isnott.-din1heVariable O&MCosts M"0.12/1ooo

abor cost ,nclUd,nQ all bene Its

Example Comments $ 1,568,000 SNCR In'ectors, Blowers, DCS, Reaaent Svstem Cost :) Air Heater Modification I S03 ontrol ituminousonlv & > .:lIDfmmtllu $ 2,344,000 Balance of Plant Cost Pipina, Includina Site Uoorades $ 3,912,000 Total bare module cost includina retrofitfactor 13 Base cost oar kW
$ 391,000 Enaineenna and Construction Management costs :Ii**:3~1,UUU** Labor ad'ustrnentfor t) x 10 hour shin prem,um, oar diem, etc. $ 391,000 Contractor orofitand fees $ 5085000 aoila!' enoineenna and construciton cost subtotal 17 Capital, enaineenna and construciton cost subtotal per kW Owners costs including all "home office" costs (owners engineenng. $ 254,000 manaaement, and orocurementactivltlesl $ 5.339.000 Tolal orotect cost 18 Total nrniect cost oar kW 0.15

Costs are all based on 2009 dollars Cooital CostCalculation Includes
- EqUIpment, installation, buildings, foundations, electrical, an BMS S - B·F/1.05"200000" A"G)"(].42 ElMA(:51 It- t:. "':3 Ht:.N t)!:>UUU"(tl:"(A"(j)"U.fl:l;**t:.L~l:** u BMB S - 270000" Al"C .33" KY'O.12 BM $ BMS + BMA + BMB BMIS/KW
- Total Pro eet Cost A1-10%ofBM A2-10%ofBM A3-10%ofBM CECC ($)- BM+A1+A2+A3 CECC ($lkWlBI = 5°,{, ofCECC
TPC 1$1

­ CECC + B1 TPC (SlkWld retrofit difficulty



### 7Sargent&**~ncty··<**


### IPM Model- Revisions to Cost and Performance for ProjectNo. 12301-007 APC Technologies August 20,2010 

## SNCRCostDevelopmentMethodology

- Final Table4. ExampleoftheFixed and VariableO&MCostEstimateWorkSheet (forCFB boilers). lVanable Designation Units I Value I Calculation loiler Tvee CFB • <--- User Input nit Size A (MW) 300 <--- User Input etrofit Factor B 1 <--- User Inout (An "averaoe" retrofit has a factor
- 1.0\ eat Rate C (BtulkWh) 10000 <--- User Inout Ox Rate 0 (Ib1MMBtu) 0.15 <--- User Inout 02 Rate E (Ib1MMBtu) 0.2 

### ITvoe ofCoal E Bltumlnvous 

## • <-- User Input**~oal** Factor F 1 Bit-10, PRB=1.05, Lig-1.07 lHeat Rate Factor G 1 C/1u.uUU lHeat Inout H (Btulhr) 3.ooE+09 A'C'1000**~apacity** Factor I (l\,) 85 <--- User Input

ox Removal Efficlencv J % 25 ox Removed K Iblh 1.13E+02 O'Hl10"6'J/100 rea Rate (100%) L (Iblhrl 293 KlUF/46'30; IF BoilerTvoe
- CFB OR 0 :> 0.3 THEN UF

## = 0.25; ELSE UF

## = 0.15 ater Reouired M (Iblhr) 2641 L'9 mPower N ,%) 0.05 IAI.darvPowerisnotusedin !heVariable O&MCosts lIution Water Rate 0 (1000oohl 032 M'O.1211000 rea Cost 50% WI solution p ($/ton) 310 lUX Power Cost Q ($!kWh) 0.06 ilution Water Cost R ($/koal\ 1 )oeratina Labor Rate S ($Jhr) 60 Labor cost includino all benefits 

### Costs are all based on 2009 dollars
Fixed O&M Cost FOMO ($IkWvr)

### =(1/2 ooeratortime assumed)'2080'S/(A'l000l FOMM ($IkWvr\
- 0.012'BMIA110OO $ $ 0.21 0.16 Fixed O&M additional oeeratina labor costs Fixed O&M additional maintenance material and laborcosts FOM ISIkWvrl
­ FOMO + FOMM S 0.37 Total Fixed O&M costs VariableO&M Cost VOMRI$lMWhI

- L'P/AI1000 VOMM (SIMWhI

### = O'RlA $ $ 0.30 0.00 Variable O&M costs for Urea Variable O&M costs for dilutionwater**VOMI~T=VOMR+VOMM** S 0.30



### 8

# ATTACHMENTA-3 SCRCOSTDEVELOPMENTMETHODOLOGY­ SARGENT & LUNDY, LLC,AUGUST 2010

## IPM Model- Revisions to Cost andPerformance for APC Technologies

SCRCost Development Methodology FINAL August 2010 Project 12301-007 Perrin Quarles Associates, Inc.
Prepared by

# sargeri~ic$. Lundy L L C**'-:.~;~** ,"1;1'

55 East Monroe Street· Chicago, IL 60603 USA· 312·269·2000LEGAL NOTICE This analysis**("Deliverable'~** waspreparedbySargent & 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 ofskill and care ordinarily exercised by engineers practicing undersimilarcircumstances. Client acknowledges: (1) S&Lpreparedthis Deliverable subject to theparticular scope limitations, budgetary andtime constraints, andbusiness objectives of the Client; (2) information and dataprovided by others may not have been independently verified by S&L; and (3) the information anddata contained in this Deliverable are time sensitive andchanges in the data, applicable codes, standards, andacceptable engineeringpractices may invalidate thefindings of this Deliverable. Any
use orreliance upon this Deliverable by thirdpartiesshall be at theirsole risk.

This work wasfundedandreviewedby the 

## u.s. EnvironmentalProtectionAgency under the supervision of William A. Stevens, Senior Advisor

- Power Technologies. Additional input and review wasprovided by Dr. Jim Staudt, President of Andover Technology Partners.Sargent& Lundy'"

IPM Model- Revisions to Cost and Perfonnance forAPC ProjectNo. 12301-007 Technologies August 20, 2010 

### SCRCostDevelopmentMethodology

- Final 

## EstablishmentofCost Basis The formulation ofthe SCRcostestimating model is based upon two databases ofactual SCRprojects. The data bases used were those ofthe 2004 to 2006 industry cost estimates for SCR units published in the "ANALYSIS OF MOG AND LADCO'S FGD AND SCRCAPACITY AND COST ASSUMPTIONS IN THEEVALUATION OF PROPOSED EGU I AND EGU 2 EMISSION CONTROLS"report prepared for Midwest Ozone Group (MOG) and a Sargent& Lundy LLC (S&L) proprietary in-house database. The available data was analyzed in detail regarding project specifics such as coal type, NOx reduction efficiency and air pre-heater requirements, and updated to include the cost ofSCR projects available with both data sets. The data sets were escalatedto update the MOG information to 2009 and all ofthe data was cross referenced with current 2009 projects. The MOG and S&L costdata were updated to reflect the changes in equipment and 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 effects; the results were compared with the CEPCI index and were within 2%for total project costs. The comparison between the two sets ofdata was refined by fitting each data set with a least squares curve to obtain an average $/kW projectcost as a function ofunit size. The data set was then collectively used to generate an average least-squares curve fit. The curve fit indicatedthat both sets ofdataproduced similar average costs (within 4%) at the 200 MW range, but deviate as the unit size increasesto approximately II% at 600 MW and 13% at 900MW. The costs for retrofitting a plant smallerthan 100 MW increase rapidly due to the economy ofsize. The older 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 boilerhouse to the chimney. Because ofthe limited space, the SCR reactor and new duct workcan be expensiveto design and install. Additionally, the plants might not have enough margins in the fans to overcomethepressure drop due to the duct work configuration and SCRreactor and therefore new fans may be required. The least squares curve fit was based upon an average ofthe SCRretrofit projects. Retrofit difficulties associated with an SCR may result in capital cost increases of30to 50%overthe base model. The least squares curve fits were based upon the following assumptions:

• Retrofit Factor =1 • Gross HeatRate = 

### 9880 • S02 Rate = 

### < 3 Ib/MMBtu • Type ofCoal = 

### Bituminous • Project Execution = 

### Multiple lump sum contractsSergenl: & Lundy" <

IPM Model

- Revisions to Cost and Perfonnance for APC ProjectNo. 12301-007 Technologies August 20, 2010 

### SCRCostDevelopmentMethodology

- Final 

## Methodology Inputs To predictfuture SCRretrofit costs several input variables are required. The unit size in MW is the majorvariable for the capital cost estimation followed by the type offuel (Bituminous, PRB, orLignite) which will influence the flue gasquantities as a result of the moisture content. The fuel type also affects the airpre-heatercosts ifammonium bisulfate or sulfuric acid deposition poses a problem. The unit heatrate factors into the amount offlue gas generated and ultimatelythe size ofthe SCRreactor and reagent preparation. A retrofit factor that equatesto difficulty in construction ofthe system must be defined. TheNOx 

### rate and removal efficiency will impactthe amount ofcatalyst required and size ofthe reagent handling equipment. The elevation ofthe site mustbe considered separately and factored into the unit MW size accordingly due to its effects on the flue gas volume. The inputs that impactthe variable O&M costs are based primarily on the plant capacity factor and the removal efficiency. TheNOx removal efficiency specifically affects the SCRcatalyst, reagent and steam costs. The lower level ofNOx removal is recommended as:

• 0.07 NOx Ib/mmBtu

- Bituminous • 0.05 NOx Ib/mmBtu

- PRB • 0.05 NOx Ib/mmBtu

- Lignite 

### Outputs Total Project Costs (TPC) 

### Firstthe 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 • AFUDC
2sargent: & Lundy" <

IPM Model- Revisions to Cost and Performance for APC ProjectNo. 12301-007 Technologies August 20, 20I0 

### SCRCostDevelopmentMethodology

- Final The modules are:
BMR= Base module SCRcost BMF = 

### Base module reagent preparation cost BMA= Base module airpre-heatercost BMB= Base module balance ofplan costs including: 10orboosterfans, piping, etc
... BM = 

### BMR+BMF+BMA+BMB
The total bare module cost (BM) is then increased by:

• Engineering and construction managementcosts at 10%ofthe BMcost. • Labor adjustment for 6 x 10 hour shift premium, perdiem, etc., at 10% ofthe BM cost. • Contractorprofit and fees at 10% ofthe BM cost. A capital, engineering, and construction cost subtotal (CECC) is established as the sum of the BM and the additional engineering and construction fees. Additional costs and financing expenditures for the project are computedbased on the CECCo Financing and additional projectcosts include:

• Owner's home office costs (owner's engineering, management, and procurement) at 5%ofthe CECC; and • Allowance for Funds Used During Construction (AFUDC) at 6%ofthe CECC and owner's costs. The AFUDC is based on a two-yearengineering and construction cycle. The total projectcost is based on a multiple lump sum contract approach. Should a turnkey engineering procurement construction (EPC) contract be executed, the total project cost could be 10 to 15%higherthan what is currently estimated. Escalation is not included in the estimate. The total project cost (TPC) is the sum ofthe CECC and the additional costs and financing expenditures. Table 1contains an example ofthe capital costestimation.
Fixed O&M (FOM) 

### The fixed operating and maintenance cost is a function ofthe additional operations staff (FOMO) and maintenance labor and materials (FOMM) associated with the SCR installation. The FOM is the sum ofthe FOMO and the FOMM.



### 3Sergent & Lundy'"

IPM Model

- Revisions to Cost and Perfonnance for APC Project No. 12301-007 Technologies August 20, 2010 

### SCRCostDevelopmentMethodology

- Final In general, 1additional operator is required for all installations. The FOMO is based on the number ofadditional operations staffrequired. The fixed maintenance materials and labor is a direct function ofthe bare module cost (8M) at a retrofit factor of 1.0.
Variable O&M (VOM) 

### Variable O&M is a function ofcatalyst required and disposal costs, reagentconsumption, and steam consumption. All ofthe YOM costs must be adjusted for plantcapacity factor. The reagent consumption rate is a function ofunit size, NOx 

### 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 fan powerto overcomethe added pressure drop across the catalyst and ductwork and the reagent supply system. The variables that contribute to the overall YOM 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
YOM VOMR

### + VOMW

### + VOMM.



### 4Sargent & Lundy'"

IPM Model- Revisions to Cost and Perfonnance forAPC Project No. 12301-007 Technologies August 20, 2010 

### SCRCostDevelopmentMethodology

- Final Table 1. 

### ExampleoftheCapitalCostEstimateWork Sheet. ariabe uesignation Units Vaue a cu at on Unit ::>ize A (MW) 600 <­ User Input Retrofit Factor tl 1 <­ User Inp\.t An "averaoe" retrofit has a factor 1.0 Heat Rate C Btu/kWh 9880 <-- User Inout Nox Rate D (lblMMtltu) 0.21 <­ User Input :SUL Kate E IblMMBtu 1.71 Type ofCoal F ORB 

# ... <-- User Inout Coal Factor G 1.05 Bit-1.0, PRB 1.05. LiQ' 1.07 Heat Rate Factor H 0.988 CltOOOO Heat Input (tltulhr)**!>.93~+{)9** A"<.."1lJUU actor J Yo 85 <­ User In ut Nox Removal Efficiencv K % 70 No" Removal Factor L 0.8(5 VJ Nox Removed M Ib.'h 8.71E->{)2 D·1I1OA6·Kl100 Urea Rate 100% N (Ib1hr) 609 M*0.52S*60146·1.01/0.99 Steam ReoUlred 0 

# .. Iblhr 1""1 689 U.!>, N·1.13 IS not usecI Inme Urea Cost 50% wt solutlor R $/ton 310 Catalvst Cost S 51m3 8000 Awe

...ower (;Qst ( kWl) 0.06 ::>team ost u**l:Wkl~** 4 DoeratmQ Labor Rate V $/hr 60 Labor cost includino all benefits 

### Costs are all based on 2009 dollars**:~~ICostCaku~Uo** Includes
- Equipment. installation, bUildings. foundations, electrical, and retrofit drfficully. BMR $ 180000· B * L}AO.2*(A·G·H)"0.92 8MF S - 410000· M .25 BMA $) I N 6!>Ul.0*{tl·· A·G-H)"0.78;**~LSE** 8M8 $ 380000· 

# "' 8 * A*G*HY'O.42 BM(S) BMR

.. BMF

.. SMA

.. BMB 8M S1KW Total ProiectCost A1 1U"110 of BM A2
- 10% of 8M A3 10% of 8M CECC ($1- BM+A1+A2+AJ CECC (SlkWI
­ B1 =5%ofCECC B2 = 6% ofCECC

.. 81 TPC ($) CECC ·B1 + B2 TPC $IkWl = Example Comments S 65,199,000 SCR Inlet Ductwork. Reactor, Bypass} IslandCost S 2.228.000 Base Reaaent Preoaration Cost S . Air Heater Modification/ ::>U3 (;antral (tlituminousonly & > 31b1mmtltu $ 5.666,000 ID or boosterfans & Auxiliarv Power Modification Costs $ 73.093000 Total bare module cost includino retrofitfactor 122 Basecost oar kW
$ .309,000**~Qineerinc** and (;onstruclton Managementcosts $ 7.:ID!oJ,OOO Labor adiustmentfor 6 x 10 hourshift oremium, oardiem, etc

... $ 7.309,000 Contractororofit and fees $ 95,020,000 ::aortal, enalneerina and construciton cost subtotal 158 Cacrtal. enaineerino and construciton cost subtotal oer kW S 4.751,000 Owners costs including all "home on,ce" costs (owners engineering, manaaement. and orocuremeotactivities) $ 5.986,000 AFUDC (Based on approximately 3% per yearfor a 2 year engineenng and construction cvcle\ $ 105,757.000 Total proiec! cost 176 Total oroiect cost oar kW



### 5Sergent & Lundy'"

IPM Model- Revisions to Cost and Perfonnance for APC ProjectNo. I2301-007 Technologies August 20, 2010 

### SCRCostDevelopmentMethodology

- Final Table2o ExampleoftheFixed and Variable O&MEstimateWorkSheeto Vanable Desianation Units Value Calculation Unit Size A {MW) 600 <- User Input Retrofit Factor B 1 <- User IriDUtlAn °averaae" retrofit has afactor
- 1.0) Heat Rate C IBtulkWh\ 9880 <- User IrIDUt INOx Rate D /lblMMBtu) 0.21 < User Input S02Rate E /lblMMBtu\ 1.71**~VDeofCoal** F PIlB ..... <- User InDut Coal Factor G 1.05 Bit=1.0. PRB=1.05. Lia=1.07 Heat Rate Factor H 0.988 Cll0000 IHeat Input I (Btulhr) 5:93E+W AOC'fO{l(f Caoacitv Factor J /'Yo) 85 <- User IriDUt Nox Removal Efficiency K % 70 Nox Removal Factor L 0.875 IIJ Nox Hemove<l M IbIh 8.71E+02 DOl/ 0 Urea Rate /100%) N /Ib1hr\ 609 MOO.525°60/46'1.01l0.99 Steam Reauired 0 /Ib1hr) 689 N°1.13 IOUll -.­ P t'lfo\ ON O. ISnotused mmevanaDle O&M Costs. Urea Cost 50%wtsolutio! R /Slton) 310 CatalvstCost S /$Im31 8000 Aux Power Cost T (SIkWh) 0.06 Steam Cost U (S/klbl 4 Operatina Labor Rate V /Slhrl 60 Laborcost includina all benefrts 

### Costs are all based on 2009 dollars
Fixed O&M Cost FOMO ISIkW vrl"/112 ooerator time assumedl02080"V//A'10001 FOMM (S/kWyrl
- IFA <SOO then $200,00 ELSE $300,000 FOM (SlkWyrl=FOMO + FOMM Variable O&M Cost VOMR/SIMWhI- N"RlAI1000 VOMW (SIMWh\ =discrete function ofA. G, J, K, S VOMM ($IMWhI- OOUIAllooo YOM /S!MWh)

­ VOMR + VOMW + VOMM $ 0.10 $ 0.50 S 0.60
$ 0.31 S 0.35 $ 0.01 S 0.66 Fixed O&M additional operating labor costs Fixed O&M additional maintenance material and laborcosts Total Fixed O&M costs
Variable O&M costs for Urea Variable O&M costs for catalvst: reolacement &disposal Variable O&M costs for steam



### 6James M Parker Manager
- Compliance Services, Env PPL Montana, LLC 303 N. Broadway, Suite 400 Billings, MT 59101 Tel. 406.740.9998 Fax 406.237.6901 jmparker@pplweb.com PPL MONTANA",



### September23, 2011 

### Ms. Vanessa Hinkle (8P-AR) US Environmental Protection AgencyRegion VIII 1595 Wynkoop Street Denver, CO 80202-1129



### Re: NOx ControlCostUpdates to 

### PPLMontana'sColstrip Units 1&2 BART Analyses Dear

### Ms. Hinkle: Enclosed please find PPLMontana's submittal ofa Nitrogen Oxides (NOx) Control cost update to ourAugust 2007 and June 2008 BART analyses for ourColsrip Generating Station Units 1&2. EPA'sMay 18,2011 correspondence provided PPL Montana the opportunityto update infOimationrelated to these BART analyses. This updateis provided pursuantto that correspondence and the subsequentdiscussions betweenEPA and PPLMontana, and the schedule for target submittal dates agreed upon on June 27,2011. Thisreportprovides updated costeffectiveness analyses for reducingNOx emissions through the application ofcombustion controls, selective non catalytic reduction (SNCR) and Selective Catalytic Reduction (SCR) technologies. This submittal completes PPLMontana's updating ofthe original August 2007 report and the subsequentJune 2008 Addendum. Today's submittal onlyupdates the NOx controlcost. Wehave not updated the particulate orS02control cost as we determined that it was notnecessary. The very high cost (dollarsperton) ofpalticulateorS02 removed and the previously modeled absence ofvisibility improvement resulting from furtherparticulateor S02controls did notjustifyany updating tothese control costs. Also, please note that PPLMontanahas not updated any ofits previous visibility modeling analyses because we determined that the range ofemissions impacts at issue are within the range ofemissions impacts previously modeled. Accordingly, the visibility modeling results should beunaffected. 

### Inaddition, please note that we used the 2001-2003 NOx emissions data (0.351bs NoxlMMBtu

- 30dayaverage) for the baseline for this update to beconsistentwith the August2007 and June 2008 BARTanalyses. However, thepresentemissions (approximately0.311bsNoxlMMBtu

- 30day average) are below thatbaseline. This is becauseinpreparation for the 2008 amended Phase IIAcid Rain standmd, the Colstrip Units 1&2combustioncontrols existing at that timewere optimized to give an adequate compliance margin under the new standard.-2­


### Becausethere are no significantvisibilitybenefits, the additional analysis ofcosts providedbythis addendum does not change the conclusion that PPLMontana reached for Colstrip Units 1&2in its August 2007 BARTAssessmentorthe June 2008 Addendum that implementation offurther NOx

### control is not warranted. Pleasecontactme at406-237-6932orReid Clemmerat 610-774-5475 with any questions.**Sinc~rely,** 

### ... ( /

# /Id~ j 

### esM Parker:

# RaJ anager, Environmental Compliance Services JMP/rtc CC: Dave Klemp, Debbie Skibicki

- MTDEQ

### RE: Clarification on plant capacityfactor - revised Units 1&2 BART update. Parker, James M i.G Aaron Worstell 10/18/201101:15 PM Vanessa Hinkle "Parker, James M" <jmparker@pplweb.com> Aaron Worsteli/R8/USEPAlUS@EPA
2 attachments

NOX Control Updateto PPl Montana's**COlst~enerat;;ng** Station
- Revised pages(0ct2011).pdf

NOx Control Update to PPL Montana's Colstrip Generating Station BART Report (Revised).pdf

Aaron

- The capacity factor was developed in 2007, the date of our original BART submittal. The CF was derived by taking the average capacity factor of the five years 2003-2007, with the 2007 CF values used in the average being a projection to year's end (since the year wasn't complete at the time of the analysis)

. Also, pursuant to our correspondence last week, attached please find revisions for our Units 1&2 September 23, 2011 submittal. I've attached the revised pages and also a complete revised report. Please let me know if you have any questions. Thanks. Jim 406-237-6932

-----Original Message----­ From: Worstell.Aaron@epamail.epa.gov [mailto:Worstell.Aaron@epamail.epa.gov] Sent: Tuesday, October 18, 2011 8:12 AM To: Parker, James M Subject: Clarification on plant capacity factor

Hi JimIn your NOx update for Colstrip 1 and 2 (September 2011), you use a plant capacity of 92%. Can you tell me how this was derived? Thanks in advance. Aaron J. Worstell Environmental Engineer U.S. Environmental Protection Agency

- Region 8 Air Program

- Mail Code 8P-AR 1595 Wynkoop Street Denver, CO 80202 Phone: 303-312-6073Fax: 303-312-6064 The information contained in this message is intended only for the personal and confidential use of the recipient(s) named above. If the reader of this message is not the intended recipient or an agent responsible for delivering it to the intended recipient, you are hereby notified that you have received this document in error and that any review, dissemination, distribution, or copying of this message is strictly prohibited. If you have received this communication in error, please notify us immediately, and delete the original message.

### activities would significantly increase the cost ofthis technology. Even a one-day maintenance outage would increase the costeffectiveness ofthis 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 comparatively lower ammonia slip. In the case ofapplication of SCR, the NOx 

### controls would be located after the economizer and upstream of the air preheater and scrubbers. The addition of SCR technology is estimated to reduce NOx 

### emissions to an estimated 0.06 Ibs/MMBtu from the significant reductions already attained by combustion controls. Each add-on post combustion control technology would have significant impacts atthe 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 modified combustion controls (SOFA system) is approximately $551 per ton ofNOx 

### removed on an annualized basis. The cost effectiveness ofSNCR is approximately $8,194 per ton ofNOx 

### 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 forced outages, such as lost generation, which would involve additional costs. As noted above, even a one-day maintenance outage would increase the cost ofSNCR technology by approximately $1 ,974/ton. The estimated cost effectiveness for the addition ofSCRto Colstrip Units 1or 2 is approximately $7,300/ton of additional NOx 

### 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 ofSO}. Even
a one-day maintenance outage would increase the cost by approximately $212/ton.4 

### Forthis report, PPL Montana determined that is was not necessary to update any ofthe June 2008 visibility assessments as the range of NOx 

### emission reductions achieved by the evaluated control technologies in this addendum is within the range ofNOx 

### reduction previously evaluated. The high cost per ton ofadditional NOx

### removal with these technologies leads PPL Montanato 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 NOx' 

### ES-32.2 SNCR Cost Analysis Usingthe )PM Methodology Tables 2-2a through 2-2d show the results ofapplication ofthe 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 ofthe "retrofit factor" is provided in the analytical cost equations to allow for particularly difficult sites where application ofretrofittechnology would be more difficult dueto site specific factors. PPL Montana believes that the PM and S02 scrubbers already limit the space available for the installation ofreagent preparation equipment and reagent receipt and unloading operations, which will make the application ofSNCR difficult at the Colstrip site. PPL Montana has used a factor of 1.5 instead ofthe 1.0 that would characterize a more open site plan than that available at Colstrip Units 1&2. Tables 2-2b and 2-2d show the calculations ofthe $/ton ofNOx for SNCR. SNCR uses urea that is injected into the combustion zone where it breaks down into two moles of ammonia and one mole of CO2 per mole of urea injected. Excess reagent is always required to attain acceptable NOx reductions; however, the reductions that are attainable are higher whenthe uncontrolled NOx is higher. At a typical ammonia slip concentration in the exhaust of 10 ppm, the unreacted ammonia would enterthe PM/S02 scrubbers and cause unknown effects on the reaction chemistry. This could lead to higher fouling of scrubber components, increased maintenance, and more frequent breakdowns ofthe scrubbing equipment. Using the )PM methodology, and assuming that installation of an SNCR will result in an emission rate of0.185 Ibs/MMBtuthe cost effectiveness is estimated to be $8, 194/ton. This does not include cost oflost generation for an increase in outages. Even a one-day maintenance outage would increase the cost by approximately $1 ,974/ton.

2.3 SCRCost Analysis Using the )PM Methodology Tables 2-3a through and 2-3d show the results ofapplication ofthe S&L costing methodology to Colstrip units 1or 2 for SCR. The costs reflected in these tables reflect a retrofit factor of2.0 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 ofa dry sorbent system to reduce sulfuric acid that may be increased as a byproduct ofthe SCR catalyst converting a small portion ofthe S02 to S03 and creatingthe potential for a visible plume. Application ofSCR at Colstrip Units 1&2 is estimated to cost $7,300/ton assuming an emission rate of0.06 Ibs/MMBtu. This does not include any increased cost as a result oflost 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 equivalentforced outage cost for an SNCR as the SCR removes moretons of NO•. 4

### Table 2-3a SCR COSTING DEVELOPMENT FOR CAPITAL AND OPERATION AND MAINTENANCE COSTS Equation/lnput!l) SCR CAPITAL COST FOR COLSTRIP 1 OR 2 (EACH) 30 DAY AVERAGE NOx Value Designation Units Variable
Unit Capacity (Gross) A (MW) III 333 Input Retrofit Factor B 2 Difficulty of Retrofit Gross heat rate C Btu/KW-hr 11,958 Input I'IUXtmlSs**~ale** D IOS/MMBtu 0.2 Uncontrolled ;)UztmlSs**~ale** E Ibs/MMBtu 1.8 Uncontrolled Type ofCoal F PRB Input Coal Factor G 1.05 Input Heat Rate Factor H 1.20 C/l0,000 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'L' (Ibs/hr) 0.875 (Based on Model Plant) NOx Removed M (Ibs/hr) 557.48 D X1/10"* K /100 Urea Rate N (Ibs/hr) 389.46 Mx0.525 * 60/46 *1.01/.99 Steam Required M (Ibs/hr) 440.10 Nx 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 ($/hr) 60 Input CAPITAL EQUIPMENT COSTS SCR Ducts, Reactor Island BMR ($) $90,425,605 180000x B XLO.2X(AxGxH)092 Base Reagent Prep Cost BMF ($) $1,992,238 410000x MO.Z5 ID Fans, Anciliary Equip BMB ($) $9,588,609 380000x B x (AxGxH)O.42 Bare Module Cost BM ($) $102,006,452 BMR+BMF+BMB Engineering, Const Mgmt Al ($) $10,200,645 10% ofBM LaborAdjustment A2 ($) $10,200,645 10% ofBM Contractor Profit, Fees A3 ($) $10,200,645 10% ofBM Cap, Eng, Const Cost CECC ($) $132,608,387 BM +Al +A2 + A3 Home office Costs Bl ($) $6,630,419 5% ofCECC Construction Funds B2 ($) $8,354,328 6% ofCECC+Bl Total Project Cost TPC ($) $147,593,135 CECC + Bl + B2 Cost per kW 443 $/kW OPERATING AND MAINTENANCE COSTS Fixea uperator Lost I-UMU**~62,400** 2,080 hrs- 1- halttime Maintenance Matenal I-UMM :;>,jUU,OUU Hxed Annual Lost IotalHxed U&M FUM :;>.:SbL,4UU I-UMU+I-UMM urea Lost VUMH S87.63 

### NXR ISteam Cost VUIVIIVI S1.76 OxU ILatalyst cost' VOMW**~0.35** .;>/'VI vv r Notes: 1) Cost analysis equations from "IPM Model-Revisions to Cost And Performance forAPC 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 efficiencyfor PRB coal 3) S&L lists this to be a discrete function ofA, G, 

### J, K, and Sin $/MW-hr
Page 12Table 2-3b PPL BART Cost Effectiveness Analysis SCR NOx Control Colstrip Units 1&2 Two 333 MW Coal Fired Boilers (Each) 3D-dayaverageemissionNOx rate Maximum Gross Heat Input MM Btu/hr Design Percent Load % Uncontrolled Emissions Ibs/MMBtu EXhaustTemperature, (oF) T Steam Turbine Power Output (TMW) MW Capacity Factor (92%) hrs Controlled NOx Emissions Ibs/MMBtu Overall NOx Reduction Efficiency, (%) % Uncontrolled NOx Emissions, (Iblhr) Uncontrolled NOx Emissions, (tons/yr) Controlled NOx Emissions, (tonlyr) Annual Interest Rate, (%) Equipment Life, (yrs) yr Capital Recovery Factor, CRF CRF 3,982 92 0.200

314 333 8,059

0.06 70.00 796.4 3209.2 962.8 7 20 0.0944

Cost Item Suggested Factor Unit Cost Item Cost

IPM Model, August 20,2010(1) Equipment Cost Total, (EC) Total Capital Costs, TCC DirectAnnual Costs, DAC

Total DirectAnnual Costs, DAC IndirectAnnual Costs

Capital Recovery

Total IndirectAnnual Costs, lAC Total Annual Costs, TAC = DAC + lAC Cost Effectiveness ($Iton pollutant Removed) Capital Cost ($/KW) EC (Adjusted by Cost Index Cales)

Catalyst Cost(4)

Urea Cost Steam Cost Maintenance Labor Maintenance Materials

CRF*TCC 443 (2011 dollars)!2')

VOMW VOMR VOMM FOMO FOMM $147,593,135 $152,306,678 $152,306,678
$939,300 $706,224 $14,187 $62,400 $300,000 $2,022,111
$14,376.673 $14,376,673 $16,398.784 $7,300

Cost data references: 1) Cost analysis equationsfrom "IPM Model-Revisionsto Cost And Performance for APC Technologies-SCR Cost Development Methodology-FINAL",August 2010 Project 12301-007, Perrin QuarlesAssociates, 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 ofS03 4) Cost is for replacement and disposal based on S&L cost estimate in $/MW-hr for PRB coal

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