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ES-1 

EXECUTIVE SUMMARY 

As part of the Best Available Retrofit Technology (BART) assessment for the Colstrip coal-fired 

steam electric plant, an economic cost 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, 2011, 

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 1 & 2 at the Colstrip generating plant located in Billings, Montana, are jointly 

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 burns 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.4.10 Using the Integrated Planning Model”. See the following link 

for more details: 

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

ICF International (ICF) developed 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 of a 30-day average and the maximum 24-hour 

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

though PPL Montana believes that the actual cost effectiveness should be evaluated on a longer time basis 

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

emission rates are not representative of site-specific cost effectiveness, we are providing the 24-hour cost 
ES-2 

calculation as requested. The 30-day running average baseline NOx emission rate is 0.35 lbs NOx/MMBtu 

and the 24-hour baseline emission rate is 0.49 lbs NOx/MMBtu1

. These emission rates are also 

representative of the past five years of operation. 

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

reducing nitrogen oxides (NOx) emissions; (1) 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 of the 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 NOx combustion control technology 

utilizing low NOx burners, close coupled overfire air, and digital controls2

. Modifying these combustion 

controls through the installation of separated overfire air and more sophisticated burner controls (SOFA 

system)3

 is projected to reduce the NOx emission rate to 0.20 lbs/MMBtu. This value is used as the 

baseline for cost effectiveness calculations because the addition of SOFA would, of necessity, accompany 

installation of any additional controls. The two reagent injection technologies, SNCR and SCR involve 

the injection of quantities of a NOx reducing agent into the exhaust for the conversion of NOx to nitrogen 

and water vapor. Typically either urea or aqueous ammonia is the reagent used. The reagent is injected 

at amounts higher than required for reaction and 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 of the boiler to chemically reduce NOx to nitrogen and water vapor, and carbon dioxide 

if urea serves as the source of ammonia. With SNCR, it is expected that a 10% incremental reduction of 

NOx over that attained by modified combustion controls alone could be achieved, resulting in an 

estimated NOx emission rate of 0.185 lbs/MMBtu. While an estimated additional 241 tons per year of 

NOx would be reduced over the combustion controls and digital process controls, an estimated ammonia 

slip of 78 tons per year would contribute to fouling and pluggage of the economizer and air preheater and 

be emitted from the stacks negating at least a portion of any visibility impacts from the NOx reduction. 

Fouling downstream of ammonia injection has been reported as an operating and maintenance concern in 

applications of this 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 this value represents the maximum 24 hour average for the period of interest, Colstrip Units 1&2

comply with the annual Phase II Acid Rain Program standard of 0.40 #/MMBtu.

2 Alstom LNCFS Level II® system

3 Alstom LNCFS Level III® system
ES-3 5HYLVHG

activities would significantly increase the cost of this technology. Even a one-day maintenance outage 

would increase the cost effectiveness of this technology by approximately $1,974/ton. 

Selective Catalytic Reduction (SCR) technology also uses urea or ammonia injection. However, 

that injection occurs upstream of a catalyst that produces higher reduction efficiencies. SCRs have a 

significantly higher capital cost and have comparatively lower ammonia slip. In the case of application 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 

lbs/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 of NOx removed on an annualized basis. The cost effectiveness of SNCR is 

approximately $8,194 per ton of NOx 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 of SNCR technology 

by approximately $1,974/ton. 

The estimated cost effectiveness for the addition of SCR to Colstrip Units 1 or 2 is approximately 

$7,300/ton of additional 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 of SO3. Even 

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

 

For this report, PPL Montana determined that is was not necessary to update any of the June 2008 

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

technologies in this addendum is within the range of NOx reduction previously evaluated. The high cost 

per ton of additional NOx removal with these technologies leads PPL Montana to the conclusion that these 

are not appropriate technologies for retrofit application to Colstrip Units 1&2. In addition, we believe 

that no significant visibility benefit is expected from the emission reductions that these technologies 

would achieve. 

                                                           

4 This is less than the equivalent forced outage cost for an SNCR as the SCR removes more tons of NOx.  
ii 

TABLE OF CONTENTS 

SECTION PAGE

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

1.0 Recent Developments in Control Technology Cost Analysis ........................................................... 1 

1.1 Reduction of NOx Using Combustion Controls ............................................................................ 1 

1.2 Selective Non-Catalytic Reduction of NOx ................................................................................... 2 

1.3 Selective Catalytic Reduction ....................................................................................................... 2 

2.0 Combustion Controls, SNCR and SCR Costing Using the IPM Methodology ................................ 3 

2.1 Combustion Controls Cost Analysis Using the IPM Methodology .............................................. 3 

2.2 SNCR Cost Analysis Using the IPM Methodology ...................................................................... 4 

2.3 SCR Cost Analysis 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 Hour Average .......................................... 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 Hour Average ......................................................................... 10 

2-2d SNCR Cost Effectiveness Analysis 24 Hour Average ............................................................... 11 

2-3a SCR Costing Development 30 Day Average .............................................................................. 12 

2-3b SCR Cost Effectiveness Analysis 30 Day Average .................................................................... 13 

2-3c SCR Costing Development 24 hour Average ............................................................................. 14 

2-3d SCR Cost Effectiveness Analysis 24 Hour Average .................................................................. 15 
1 

1.0 RECENT DEVELOPMENTS IN CONTROL TECHNOLOGY COST ANALYSIS 

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

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

Cost Manual (the CCM)5

 published in January 2002. For NOx, the electric utility control costing techniques 

were limited to Selective Non-Catalytic Reduction (SNCR) and Selective Catalytic Reduction (SCR). Utility 

applications of combustion controls were installed and operating in the USA, however, no compilation of the 

cost of such utility sized systems was available other than as provided in the CCM. 

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

USEPA as required and reviews of the reports, such as those submitted by PPL Montana in August 2007 and 

subsequently amended in 2008, were performed. Simultaneously, 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 (ICF) developed 

the IPM to assess the combined effect that air rules have on the electric utility industry as a whole. This 

platform has also been used by EPA’s Clean Air 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 NOx Using Combustion Controls

The IPM includes cost estimating methodology for the various low-NOx burner and overfire air 

combustion control options. For a tangentially 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 of any additional combustion controls. Modifying the 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 of 0.35 lbs/MMBtu 

is limited to a reduction of no more than about 43%, resulting in an estimated emission rate of 0.20 

lbs/MMBtu. 

                                                           

5

 ‐ EPA control Cost Manual, 6th ed., EPA-452-01-001, January 2002 

6 Alstom LNCFS Level II® system 

7 Alstom LNCFS Level III® system 
2 

1.2 Selective Non-Catalytic Reduction of NOx

SNCR is a post combustion technology in which ammonia or urea is injected into the combustion 

zone of the 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 of thermal 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 of ammonia). The chemical reactions, which are not presented here, occur between 

nitric oxide (NO) and ammonia, i.e., NH3 or CO(NH2)2 to form carbon dioxide, water vapor, and nitrogen. 

Not all of the injected ammonia results in NOx reduction reactions. Unreacted ammonia may react with SO2 

or SO3 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 of this technique 

involves injecting the reactant in a stream of water or steam into a region in the boiler where reaction 

temperatures are in the correct range. Multiple injectors are typically utilized and the technique can provide 

35% reduction in the NOx. Greater reductions are limited by the low NOx emissions rate already being 

achieved at Colstrip units 1&2. 

Operation of SNCR also results in ammonia slip. Ammonia slip is residual ammonia that does not 

react with NOx and typically this can be limited to about 10 parts per million by volume (ppmv). This would 

result in approximately 20 pounds per hour (78 tons per year) of unreacted ammonia, which can cause 

adverse visibility impacts. In SNCR the reactive reagent, in this case urea, would be injected into the 

combustion zone of the boiler and react with NOx. In addition, there is likely to be significant fouling of the 

economizer and air heater surfaces. These impacts would require increased maintenance activities for 

cleaning the ammonium bisulfite and sulfate ammonia slip byproducts from the economizer and air preheater 

surfaces, which would likely result in an increase in forced outages. 

1.3 Selective Catalytic Reduction

In SCR technology, the exhaust is also injected with ammonia or urea, however the reactant is 

injected upstream of a bed of catalyst that is utilized to allow the reactions to occur at lower temperatures. 

The more intimate contact between the exhaust and the reagent in the catalyst bed also produces higher 

reduction efficiencies. While SCR will perform better than SNCR with the already low NOx emission rate, 

the lowest emission rate attainable with the 0.20 lbs/MMBtu at Colstrip Unit 1 or 2 is expected to be 0.06 

lbs/MMBtu, or about a 70% reduction. 

Operation of the SCR also results in ammonia slip. Just as in SNCR, a slight excess of reagent is 

required to reduce 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 of ammonia slip could occur. 
3 

2.0 COMBUSTION CONTROLS, SNCR AND SCR COSTING USING THE IPM METHODOLOGY

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

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

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

maintenance cost of air pollution control equipment. These costing analytical techniques were summarized 

in reference 1, available from the US EPA Clean Air Markets Division or through the link provided in the 

executive summary of this report. For NOx, APCE cost analyses for the combustion controls, and for the 

two add-on, i.e. post combustion, control technologies are presented; SNCR, and SCR. 

Pages 5-7 and 5-8 from the documentation document for the IPM model are presented in Attachment 

A-1. 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 data to be scaled to any coal fired boiler greater than 25 MW in gross power output. Table 5-7 lists the 

assumptions used in the IPM model for NOx emission control efficiencies for SNCR and SCR technologies. 

Two additional background reports are included in Attachment A which describe the costing 

approach to SNCR and SCR. Each report was prepared by Sargent & Lundy, LLC under contract to the 

USEPA. Based upon a proprietary database of control installation costs, this engineering firm developed 

empirical equations which were used to estimate the costs of controls as applied to all types of coal-fired 

boiler plants. This costing aspect of the IPM allowed analysis of the effect of rules such as BART on the 

utility generating fleet. 

The cost equations developed for the IPM contain both capital and operating and maintenance costs. 

Just as EPA used cost factors as percentages of the capital equipment cost, S&L used the same approach to 

develop their capital costs for an installed retrofit project. More details regarding this approach are provided 

in Attachments A-2 and A-3. 

2.1 Combustion Controls Cost Analysis Using the IPM Methodology

As shown in Attachment A-1, Table 5-5, 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 of NOx at Colstrip 1&2 

resulting from the combustion controls already installed, about a 43% reduction is expected from application 

of SOFA system combustion control technology. Detailed cost calculations are presented in Tables 2-1a and 

2-1b. 
4 5HYLVHG

2.2 SNCR Cost Analysis Using the IPM Methodology

Tables 2-2a through 2-2d show the results of application of the costing methodology developed for 

use by EPA in the IPM regulatory studies. Tables 2-2a and 2-2c present the Colstrip specific parameters for 

the boilers applied within the empirical cost analysis approach developed by S&L as presented in 

Attachment A-2. The use of the “retrofit factor” is provided in the analytical cost equations to allow for 

particularly difficult sites where application of retrofit technology would be more difficult due to site specific 

factors. PPL Montana believes that the PM and SO2 scrubbers already limit the space available for the 

installation of reagent preparation equipment and reagent receipt and unloading operations, which will make 

the application of SNCR difficult at the Colstrip site. PPL Montana has used a factor of 1.5 instead of the 

1.0 that would characterize a more open site plan than that available at Colstrip Units 1&2. Tables 2-2b and 

2-2d show the calculations of the $/ton of NOx 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 when the uncontrolled NOx

is higher. At a typical ammonia slip concentration in the exhaust of 10 ppm, the unreacted ammonia would 

enter the PM/SO2 scrubbers 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 of 0.185 lbs/MMBtu the cost effectiveness is estimated to be $8,194/ton. This does not include 

cost of lost generation for an 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 of application of the S&L costing methodology to 

Colstrip units 1 or 2 for SCR. The costs reflected in these tables reflect a retrofit factor of 2.0 based on PPL 

experience in estimating a retrofit of an SCR on a large coal-fired unit. That cost included $5 million 

capital cost for installation of a dry sorbent system to reduce sulfuric acid that may be increased as a byproduct of the SCR catalyst converting a small portion of the SO2 to SO3 and creating the potential for a 

visible plume. 

Application of SCR at Colstrip Units 1&2 is estimated to cost $7,300/ton assuming an emission rate 

of 0.06 lbs/MMBtu. This does not include any increased cost as a result of lost generation from an increase 

in forced outage rate. Even a one-day maintenance outage would increase the cost effectiveness by 

approximately $212/ton.8

 

                                                           

8 This is less that the equivalent forced outage cost for an SNCR as the SCR removes more tons of NOx.  
5 

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 of NOx 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 or the June 2008 Addendum that implementation of further NOx

control is not warranted. 
Table 2-1a

PPL BART Cost Effectiveness Analysis

Combustion Controls for NOx 

Colstrip Units 1&2

 Two 333 MW Coal Fired Boilers (Each)

30­day average emission NOx rate

Maximum Gross Heat Input MM Btu/hr 3,982

Design Percent Load % 92

Uncontrolled NOx Emissions lbs/MMBtu 0.350

Steam Turbine Power Output (TMW) MW 333

Capacity Factor (92%) hrs 8,059

Controlled NOx Emissions lbs/MMBtu 0.20

Overall NOx Reduction Efficiency, (%) % 42.86

Uncontrolled NOx Emissions, (lb/hr) 1393.7

Uncontrolled NOx Emissions, (tons/yr) 5616.1

Controlled NOx Emissions, (ton/yr) 3209.2

Annual Interest Rate, (%) 7

Equipment Life, (yrs) yr 20

Capital Recovery Factor, CRF CRF 0.0944

Unit Item

Cost Item Suggested Factor Cost Cost

From EPA Documentation Study (Reference 1) Capital Cost ($/KW) 38 $12,188,686

Equipment Cost Total, (EC) EC (Adjusted by Cost Index Calcs) (2011 dollars)(2) $12,992,396

 Total Capital Costs, TCC --- $12,992,396

 Direct Annual Costs, DAC

Fixed O& M Costs 0.3 $/kW‐yr $99,900

 Total Direct Annual Costs, DAC $99,900

Indirect Annual Costs

 Capital Recovery CRF*TCC --- $1,226,390

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

 Total Annual Costs, TAC = DAC + IAC $1,326,290

Cost Effectiveness ($/ton pollutant Removed) $551

 Cost data references:

1) Cost analysis equations from "Documentation for EPA Base Case v.4.10 Using the

Integrated Planning Model, " August 2010, pg 5‐7

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

Page 6
Table 2-1b

PPL BART Cost Effectiveness Analysis

Combustion Controls for NOx 

Colstrip Units 1&2

 Two 333 MW Coal Fired Boilers (Each)

24­hour average emission NOx rate

Maximum Gross Heat Input MM Btu/hr 3,982

Design Percent Load % 92

Uncontrolled NOx Emissions lbs/MMBtu 0.490

Steam Turbine Power Output (TMW) MW 333

Capacity Factor (92%) hrs 8,059

Controlled NOx Emissions lbs/MMBtu 0.2600

Overall NOx Reduction Efficiency, (%) % 46.94

Uncontrolled NOx Emissions, (lb/hr) 1951.2

Uncontrolled NOx Emissions, (tons/yr) 7862.5

Controlled NOx Emissions, (ton/yr) 4171.8

Annual Interest Rate, (%) 7

Equipment Life, (yrs) yr 20

Capital Recovery Factor, CRF CRF 0.0944

Unit Item

Cost Item Suggested Factor Cost Cost

From EPA Documentation Study (Reference 1) Capital Cost ($/KW) 38 $12,188,686

Equipment Cost Total, (EC) EC (Adjusted by Cost Index Calcs) (2011 dollars)(2) $12,992,396

 Total Capital Costs, TCC --- $12,992,396

 Direct Annual Costs, DAC

Fixed O& M Costs 0.3 $/kW‐yr $99,900

 Total Direct Annual Costs, DAC $99,900

Indirect Annual Costs

 Capital Recovery CRF*TCC --- $1,226,390

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

 Total Annual Costs, TAC = DAC + IAC $1,326,290

Cost Effectiveness ($/ton pollutant Removed) $359

 Cost data references:

1) Cost analysis equations from "Documentation for EPA Base Case v.4.10 Using the

Integrated Planning Model, " August 2010, pg 5‐7

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

Page 7
Table 2-2a

SNCR COSTING DEVELOPMENT

FOR CAPITAL AND OPERATION AND MAINTENANCE COSTS

Variable Designation Units Value Equation/Input(1)

SNCR CAPITAL COST FOR COLSTRIP 1 OR 2 (EACH) 30 DAY AVERAGE NOx

Unit Capacity (Gross) A (MW) 333 Input

Retrofit Factor B 1.5 Difficulty of Retrofit

Gross heat rate C Btu/KW‐hr 11,958 Input

NOx Emiss Rate D lbs/MMBtu 0.2 Uncontrolled

SO2 Emiss Rate E lbs/MMBtu 1.8 Input

Type of Coal E Input

Coal Factor F 1 1 Input

Heat Rate Factor G 1 1.20 C / 10,000

Heat Input H Btu/hr 3.98E+09 A X C x 1000

Capacity Factor I (%) 92.0 Input

NOx Removal Eff J (%) 10.00 Input

NOx Removed K (lbs/hr) 79.64 D x H/106

x J/10

Urea Rate L (lbs/hr) 346.26 K /0.15/46 x 30

Water Required M (lbs/hr) 3116.35 L x 9

Dilution Water Rate O (1,000 gph) 0.37 M x 0.12/1000

Urea Cost 50% wgt Soln P ($/ton) 450 Input

Dilution Water Cost R ($/kgal) 1 Input

Operating Labor Rate S ($/hr) 60 Input

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

Air Heater Mods (not reqd) BMA ($) $0

Balance of Plant Costs BMB ($) $3,103,888 270000 x A0.33 x K0.12

Bare Module Cost BM ($) $6,635,513 BMS + BMA + BMB

Engineering, Const Mgmt A1 ($) $663,551 10% of BM

Labor Adjustment A2 ($) $663,551 10% of BM

Contractor Profit, Fees A3 ($) $663,551 10% of BM

Cap, Eng, Const Cost CECC ($) $8,626,166 BM + A1 + A2 + A3

Owners Cost B1 ($) $431,308 5% of CECC

Total Project Cost TPC ($) $9,057,475 CECC + B1

Cost per kW ($) 27 $/kW

Fixed Operator Cost FOMO ($) $62,400 2,080 hrs‐ 1‐ half time

Maintenance Material FOMM ($) $79,626 1.2% of BM

Total Fixed O&M ($) $142,026 FOMO + FOMM

Urea Cost VOMR ($) $77.91 L x P

Dilution Water Cost VOMM ($) $0.37 O x R

Notes:

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

Technologies‐SNCR Cost Development Methodology‐FINAL", August 2010

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

PRB

CAPITAL EQUIPMENT COSTS

OPERATING AND MAINTENANCE COSTS

Page 8
Table 2-2b

PPL BART Cost Effectiveness Analysis

SNCR NOx Control

Colstrip Units 1&2

 Two 333 MW Coal Fired Boilers (Each)

30­day average emission NOx rate

Maximum Gross Heat Input MM Btu/hr 3,982

Design Percent Load % 92

Uncontrolled NOx Emissions (with PRB coal) lbs/MMBtu 0.200

ExhaustTemperature, (o

F) T 314

Steam Turbine Power Output (TMW) MW 333

Capacity Factor (92%) hrs 8,059

Controlled NOx Emissions lbs/MMBtu Note 3 0.185

Overall NOx Reduction Efficiency, (%) % 7.50

Uncontrolled NOx Emissions, (lb/hr) 796.4

Uncontrolled NOx Emissions, (tons/yr) 3209.2

Controlled NOx Emissions, (ton/yr) 2968.5

Annual Interest Rate, (%) 7

Equipment Life, (yrs) yr 20

Capital Recovery Factor, CRF CRF 0.0944

Unit Item

Cost Item Suggested Factor Cost Cost

IPM Model, August 20, 2010(1) Capital Cost ($/KW) 27 $9,057,475

Equipment Cost Total, (EC) EC (Adjusted by Cost Index Calcs) (2011 dollars)(2) $9,316,133

 Total Capital Costs, TCC --- $9,316,133

 Direct Annual Costs, DAC Urea Cost VOMR $627,882

Dilution Water Cost VOMM $3,014

Air Preheater Cleaning Four at $80,000 each $320,000

Maintenance Labor FOMO $62,400

Maintenance Materials FOMM $79,626

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

Indirect Annual Costs

 Capital Recovery CRF*TCC --- $879,377

 Total Indirect Annual Costs, IAC $879,377

 Total Annual Costs, TAC = DAC + IAC $1,972,299

Cost Effectiveness ($/ton pollutant Removed) $8,194

 Cost data references:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for 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 of ammonia slip

assuming that ammonia emissions are equivalent to NOx emissions on a ton for ton basis.

Page 9
Table 2-2c

SNCR COSTING DEVELOPMENT

FOR CAPITAL AND OPERATION AND MAINTENANCE COSTS

Variable Designation Units Value Equation/Input(1)

SNCR CAPITAL COST FOR COLSTRIP 1 OR 2 (EACH) 24 HOUR AVERAGE NOx

Unit Capacity (Gross) A (MW) 333 Input

Retrofit Factor B 1.5 Difficulty of Retrofit

Gross heat rate C Btu/KW‐hr 11,958 Input

NOx Emiss Rate D lbs/MMBtu 0.26 Uncontrolled

SO2 Emiss Rate E lbs/MMBtu 1.8 Input

Type of Coal E Input

Coal Factor F 1 1 Input

Heat Rate Factor G 1 1.20 C / 10,000

Heat Input H Btu/hr 3.98E+09 A X C x 1000

Capacity Factor I (%) 92.0 Input

NOx Removal Eff J (%) 10.00 Input

NOx Removed K (lbs/hr) 103.53 D x H/106

x J/10

Urea Rate L (lbs/hr) 450.14 K /0.15/46 x 30

Water Required M (lbs/hr) 4051.25 L x 9

Dilution Water Rate O (1,000 gph) 0.49 M x 0.12/1000

Urea Cost 50% wgt Soln P ($/ton) 450 Input

Dilution Water Cost R ($/kgal) 1 Input

Operating Labor Rate S ($/hr) 60 Input

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

Air Heater Mods (not reqd) BMA ($) $0

Balance of Plant Costs BMB ($) $3,203,165 270000 x A0.33 x K0.12

Bare Module Cost BM ($) $6,734,789 BMS + BMA + BMB

Engineering, Const Mgmt A1 ($) $673,479 10% of BM

Labor Adjustment A2 ($) $673,479 10% of BM

Contractor Profit, Fees A3 ($) $673,479 10% of BM

Cap, Eng, Const Cost CECC ($) $8,755,226 BM + A1 + A2 + A3

Owners Cost B1 ($) $437,761 5% of CECC

Total Project Cost TPC ($) $9,192,987 CECC + B1

Cost per kW ($) 28 $/kW

Fixed Operator Cost FOMO ($) $62,400 2,080 hrs‐ 1‐ half time

Maintenance Material FOMM ($) $80,817 1.2% of BM

Total Fixed O&M ($) $143,217 FOMO + FOMM

Urea Cost VOMR $/hr $101.28 L x P

Dilution Water Cost VOMM $/hr $0.49 O x R

Notes:

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

Technologies‐SNCR Cost Development Methodology‐FINAL", August 2010

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

PRB

CAPITAL EQUIPMENT COSTS

OPERATING AND MAINTENANCE COSTS

Page 10
Table 2-2d

PPL BART Cost Effectiveness Analysis

SNCR NOx Control

Colstrip Units 1&2

 Two 333 MW Coal Fired Boilers (Each)

24­hour average emission NOx rate

Maximum Gross Heat Input MM Btu/hr 3,982

Design Percent Load % 92

Uncontrolled NOx Emissions (with PRB coal) lbs/MMBtu 0.260

ExhaustTemperature, (o

F) T 314

Steam Turbine Power Output (TMW) MW 333

Capacity Factor (92%) hrs 8,059

Controlled NOx Emissions lbs/MMBtu Note 3 0.239

Overall NOx Reduction Efficiency, (%) % 8.08

Uncontrolled NOx Emissions, (lb/hr) 1035.3

Uncontrolled NOx Emissions, (tons/yr) 4171.9

Controlled NOx Emissions, (ton/yr) 3835.0

Annual Interest Rate, (%) 7

Equipment Life, (yrs) yr 20

Capital Recovery Factor, CRF CRF 0.0944

Unit Item

Cost Item Suggested Factor Cost Cost

IPM Model, August 20, 2010(1) SNCR Capital Cost ($/KW) 28 $9,192,987

Equipment Cost Total, (EC) EC (Adjusted by Cost Index Calcs) (2011 dollars)(2) $9,455,515

 Total Capital Costs, TCC --- $9,455,515

 Direct Annual Costs, DAC Urea Cost VOMR $816,246

Dilution Water Cost VOMM $3,918

Air Preheater Cleaning Four at $80,000 each $320,000

Maintenance Labor FOMO $62,400

Maintenance Materials FOMM $80,817

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

Indirect Annual Costs

 Capital Recovery CRF*TCC --- $892,534

 Total Indirect Annual Costs, IAC $892,534

 Total Annual Costs, TAC = DAC + IAC $2,175,915

Cost Effectiveness ($/ton pollutant Removed) $6,457

 Cost data references:

1) Cost analysis equations from "IPM Model‐Revisions to Cost And Performance for 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 of ammonia slip

assuming that ammonia emissions are equivalent to NOx emissions on a ton for ton basis.

Page 11
Table 2-3a

SCR COSTING DEVELOPMENT

FOR CAPITAL AND OPERATION AND MAINTENANCE COSTS

Variable Designation Units Value Equation/Input(1)

SCR CAPITAL COST FOR COLSTRIP 1 OR 2 (EACH) 30 DAY AVERAGE NOx

Unit Capacity (Gross) A (MW) 333 Input

Retrofit Factor B 2 Difficulty of Retrofit

Gross heat rate C Btu/KW‐hr 11,958 Input

NOx Emiss Rate D lbs/MMBtu 0.2 Uncontrolled

SO2 Emiss Rate E lbs/MMBtu 1.8 Uncontrolled

Type of Coal F Input

Coal Factor G 1.05 Input

Heat Rate Factor H 1.20 C / 10,000

Heat Input I Btu/hr 3.98E+09 A X C x 1000

Capacity Factor J (%) 92.0 Input

NOx Removal Eff K (%) 70.00 Input

NOx Removal Factor L

(2) (lbs/hr) 0.875 (Based on Model Plant)

NOx Removed M (lbs/hr) 557.48 D X I / 106 * K / 100

Urea Rate N (lbs/hr) 389.46 M x 0.525 * 60/46 *1.01/.99

Steam Required M (lbs/hr) 440.10 N x 1.13

Urea Cost 50% wgt Soln R ($/ton) 450 Input

Catalyst Cost S ($/m3) 8000 Input

Steam Cost U ($/klbs) 4 Input

Operating Labor Rate V ($/hr) 60 Input

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

0.2 x (AxGxH)0.92

Base Reagent Prep Cost BMF ($) $1,992,238 410000 x M0.25

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

Bare Module Cost BM ($) $102,006,452 BMR + BMF + BMB

Engineering, Const Mgmt A1 ($) $10,200,645 10% of BM

Labor Adjustment A2 ($) $10,200,645 10% of BM

Contractor Profit, Fees A3 ($) $10,200,645 10% of BM

Cap, Eng, Const Cost CECC ($) $132,608,387 BM + A1 + A2 + A3

Home office Costs B1 ($) $6,630,419 5% of CECC

Construction Funds B2 ($) $8,354,328 6% of CECC+B1

Total Project Cost TPC ($) $147,593,135 CECC + B1 + B2

Cost per kW 443 $/kW

Fixed Operator Cost FOMO $62,400 2,080 hrs‐ 1‐ half time

Maintenance Material FOMM $300,000 Fixed Annual Cost

Total Fixed O&M FOM $362,400 FOMO + FOMM

Urea Cost VOMR $87.63 N X R

Steam Cost VOMM $1.76 O x U

Catalyst cost(3) VOMW $0.35 $/MWhr

Notes:

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

Technologies‐SCR Cost Development Methodology‐FINAL", August 2010

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

2) S&L lists this variable as = to "I x J"; this is the model plant removal efficiency for PRB coal

3) S&L lists this to be a discrete function of A, G, J, K, and S in $/MW‐hr

PRB

CAPITAL EQUIPMENT COSTS

OPERATING AND MAINTENANCE COSTS

Page 125HYLVHG
Table 2-3b

PPL BART Cost Effectiveness Analysis

SCR NOx Control

Colstrip Units 1&2

 Two 333 MW Coal Fired Boilers (Each)

30­day average emission NOx rate

Maximum Gross Heat Input MM Btu/hr 3,982

Design Percent Load % 92

Uncontrolled Emissions lbs/MMBtu 0.200

ExhaustTemperature, (o

F) T 314

Steam Turbine Power Output (TMW) MW 333

Capacity Factor (92%) hrs 8,059

Controlled NOx Emissions lbs/MMBtu 0.06

Overall NOx Reduction Efficiency, (%) % 70.00

Uncontrolled NOx Emissions, (lb/hr) 796.4

Uncontrolled NOx Emissions, (tons/yr) 3209.2

Controlled NOx Emissions, (ton/yr) 962.8

Annual Interest Rate, (%) 7

Equipment Life, (yrs) yr 20

Capital Recovery Factor, CRF CRF 0.0944

Unit Item

Cost Item Suggested Factor Cost Cost

IPM Model, August 20, 2010(1) Capital Cost ($/KW) 443 $147,593,135

Equipment Cost Total, (EC) EC (Adjusted by Cost Index Calcs) (2011 dollars)(2,3) $152,306,678

 Total Capital Costs, TCC --- $152,306,678

 Direct Annual Costs, DAC

Catalyst Cost(4) VOMW $939,300

Urea Cost VOMR $706,224

Steam Cost VOMM $14,187

Maintenance Labor FOMO $62,400

Maintenance Materials FOMM $300,000

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

Indirect Annual Costs

 Capital Recovery CRF*TCC --- $14,376,673

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

 Total Annual Costs, TAC = DAC + IAC $16,398,784

Cost Effectiveness ($/ton pollutant Removed) $7,300

 Cost data references:

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

Technologies‐SCR Cost Development Methodology‐FINAL", August 2010

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

2) Cost indices used to adjust 2009 costs to 2011 costs (2009 CI= 109.594, 2011 CI= 113.094)

3) This includes a dry sorbent system for control of SO3

4) Cost is for replacement and disposal based on S&L cost estimate in $/MW-hr for PRB coal 

Page 135HYLVHG
Table 2-3c

SCR COSTING DEVELOPMENT

FOR CAPITAL AND OPERATION AND MAINTENANCE COSTS

Variable Designation Units Value Equation/Input(1)

SCR CAPITAL COST FOR COLSTRIP 1 OR 2 (EACH) 24 HOUR AVERAGE NOx

Unit Capacity (Gross) A (MW) 333 Input

Retrofit Factor B 2 Difficulty of Retrofit

Gross heat rate C Btu/KW‐hr 11,958 Input

NOx Emiss Rate D lbs/MMBtu 0.26 Uncontrolled

SO2 Emiss Rate E lbs/MMBtu 1.8 Uncontrolled

Type of Coal F Input

Coal Factor G 1.05 Input

Heat Rate Factor H 1.20 C / 10,000

Heat Input I Btu/hr 3.98E+09 A X C x 1000

Capacity Factor J (%) 89.0 Input

NOx Removal Eff K (%) 76.92 Input

NOx Removal Factor L

(2) (lbs/hr) 0.875 (Based on Model Plant)

NOx Removed M (lbs/hr) 796.40 D X I / 106 * K / 100

Urea Rate N (lbs/hr) 556.38 M x 0.525 * 60/46 *1.01/.99

Steam Required M (lbs/hr) 628.71 N x 1.13

Urea Cost 50% wgt Soln R ($/ton) 450 Input

Catalyst Cost S ($/m3) 8000 Input

Steam Cost U ($/klbs) 4 Input

Operating Labor Rate V ($/hr) 60 Input

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

0.2 x (AxGxH)0.92

Base Reagent Prep Cost BMF ($) $2,178,044 410000 x M0.25

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

Bare Module Cost BM ($) $102,192,258 BMR + BMF + BMB

Engineering, Const Mgmt A1 ($) $10,219,226 10% of BM

Labor Adjustment A2 ($) $10,219,226 10% of BM

Contractor Profit, Fees A3 ($) $10,219,226 10% of BM

Cap, Eng, Const Cost CECC ($) $132,849,936 BM + A1 + A2 + A3

Home office Costs B1 ($) $6,642,497 5% of CECC

Construction Funds B2 ($) $8,369,546 6% of CECC+B1

Total Project Cost TPC ($) $147,861,978 CECC + B1 + B2

Cost per kW 444 $/kW

Fixed Operator Cost FOMO $62,400 2,080 hrs‐ 1‐ half time

Maintenance Material FOMM $300,000 Fixed Annual Cost

Total Fixed O&M FOM $362,400 FOMO + FOMM

Urea Cost VOMR $125.19 N X R

Steam Cost VOMM $2.51 O x U

Catalyst cost(3) VOMW $0.35 $/MWhr

Notes:

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

Technologies‐SCR Cost Development Methodology‐FINAL", August 2010

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

2) S&L lists this variable as = to "I x J"; this is the model plant removal efficiency for PRB coal

3) S&L lists this to be a discrete function of A, G, J, K, and S in $/MW‐hr

PRB

CAPITAL EQUIPMENT COSTS

OPERATING AND MAINTENANCE COSTS

Page 14
Table 2-3d

PPL BART Cost Effectiveness Analysis

SCR NOx Control

Colstrip Units 1&2

 Two 333 MW Coal Fired Boilers (Each)

24­hour average emission NOx rate

Maximum Gross Heat Input MM Btu/hr 3,982

Design Percent Load % 92

Uncontrolled Emissions lbs/MMBtu 0.260

ExhaustTemperature, (o

F) T 314

Steam Turbine Power Output (TMW) MW 333

Capacity Factor (92%) hrs 8,059

Controlled NOx Emissions lbs/MMBtu 0.06

Overall NOx Reduction Efficiency, (%) % 76.92

Uncontrolled NOx Emissions, (lb/hr) 1035.3

Uncontrolled NOx Emissions, (tons/yr) 4171.9

Controlled NOx Emissions, (ton/yr) 962.8

Annual Interest Rate, (%) 7

Equipment Life, (yrs) yr 20

Capital Recovery Factor, CRF CRF 0.0944

Unit Item

Cost Item Suggested Factor Cost Cost

IPM Model, August 20, 2010(1) Capital Cost ($/KW) 444 $147,861,978

Equipment Cost Total, (EC) EC (Adjusted by Cost Index Calcs) (2011 dollars)(2,3) $152,584,107

 Total Capital Costs, TCC --- $152,584,107

 Direct Annual Costs, DAC

Catalyst Cost(4) VOMW $939,300

Urea Cost VOMR $1,008,892

Steam Cost VOMM $20,268

Maintenance Labor FOMO $62,400

Maintenance Materials FOMM $300,000

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

Indirect Annual Costs

 Capital Recovery CRF*TCC --- $14,402,860

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

 Total Annual Costs, TAC = DAC + IAC $16,733,719

Cost Effectiveness ($/ton pollutant Removed) $5,214

 Cost data references:

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

Technologies‐SCR Cost Development Methodology‐FINAL", August 2010

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

2) Cost indices used to adjust 2009 costs to 2011 costs (2009 CI= 109.594, 2011 CI= 113.094)

3) This includes a dry sorbent system for control of SO3

4) Cost is for replacement and disposal based on S&L cost estimate in $/MW-hr for PRB coal 

Page 15
ATTACHMENT A-1 

COMBUSTION CONTROLS COST TABLES 
5-7 

5.2 Nitrogen Oxides Control Technology 

The EPA Base Case v.4.10 includes two categories of NOx reduction technologies: combustion 

and post-combustion controls. Combustion controls reduce NOx emissions during the combustion 

process by regulating flame characteristics such as temperature and fuel-air mixing. Postcombustion controls operate downstream of the combustion process and remove NOx emissions 

from the flue gas. All the specific combustion and post-combustion technologies included in EPA 

Base Case v.4.10 are commercially available and currently in use in numerous power plants. 

5.2.1 Combustion Controls 

The EPA Base Case v.4.10 representation of combustion controls uses equations that are tailored 

to the boiler type, coal type, and combustion controls already in place and allow appropriate 

additional combustion controls to be exogenously applied to generating units based on the NOx

emission limits they face. Characterizations of the emission reductions provided by combustion 

controls are presented in Table 3-1.3 in Appendix 3-1. The EPA Base Case v.4.10 cost 

assumptions for NOx Combustion Controls are summarized in Table 5-5. Table 5-6 provides a 

mapping of existing coal unit configurations and incremental combustion controls applied in EPA 

Base Case v.4.10 to achieve state-of-the-art combustion control configuration. 

Table 5-5 Cost (2007$) of NOx Combustion Controls for Coal Boilers (300 MW Size) 

Boiler Type Technology Capital

($/kW) 

Fixed 

O&M 

($/kWyr) 

Variable O&M

(mills/kWh) 

Low NOx Burner without Overfire Air 

(LNB without OFA) 45 0.3 0.07 Dry Bottom WallFired Low NOx Burner with Overfire Air 

(LNB with OFA) 61 0.4 0.09 

Low NOx Coal-and-Air Nozzles with 

Close-Coupled Overfire Air (LNC1) 24 0.2 0.00 

Low NOx Coal-and-Air Nozzles with 

Separated Overfire Air (LNC2) Tangentially- 33 0.2 0.03 

Fired Low NOx Coal-and-Air Nozzles with 

Close-Coupled and Separated 

Overfire Air (LNC3) 

38 0.3 0.03 

Vertically-Fired NOx Combustion Control 29 0.2 0.06 

Scaling Factor 

The following scaling factor is used to obtain the capital and fixed operating and maintenance 

costs applicable to the capacity (in MW) of the unit taking on combustion controls. No scaling 

factor is applied in calculating the variable operating and maintenance cost. 

LNB without OFA & LNB with OFA = ($ for X MW Unit) = ($ for 300 MW Unit) x (300/X)

0.359

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

0.359

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

0.553

where 

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

X is the 

 capacity (in MW) of the unit taking on combustion controls. 
5-8 

Table 5-6 Incremental Combustion NOx Controls in EPA Base Case v.4.10 

Boiler Type Existing NOx

Combustion Control Incremental Combustional Control 

LNB OFA Cell NGR LNB AND OFA 

Cyclone -- OFA 

Stoker/SPR -- OFA 

-- LNC3 

LA LNC3 

LNB CONVERSION FROM LNC1 TO LNC3 

LNB + OFA CONVERSION FROM LNC1 TO LNC3 

LNC1 CONVERSION FROM LNC1 TO LNC3 

LNC2 CONVERSION FROM LNC2 TO LNC3 

OFA LNC1 

Tangential 

ROFA LNB 

Vertical -- NOx Combustion Control - Vertically Fired Units 

-- LNB AND OFA 

LA LNB AND OFA 

LNB OFA 

LNF OFA 

Wall 

OFA LNB 

5.2.2 Post-combustion Controls 

The EPA Base Case v.4.10 includes two post-combustion retrofit control technologies for existing 

coal units: Selective Catalytic Reduction (SCR) and Selective Non-Catalytic Reduction (SNCR). In 

EPA Base Case v.4.10 oil/gas steam units are eligible for SCR only. 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 H2O abetted by passing over a catalyst bed typically 

containing titanium, vanadium oxides, molybdenum, and/or tungsten. As its name implies, SNCR 

operates without a catalyst. In SNCR a nitrogenous reducing agent (reagent), typically ammonia 

or urea, is injected into, and mixed with, hot flue gas where it reacts with the NOx in the gas 

stream reducing it to nitrogen gas and water vapor. Due to the presence of a catalyst, SCR can 

achieve greater NOx reductions than SNCR. However, SCR costs are higher. 

Table 5-7 summarizes the performance and applicability assumptions in EPA Base Case v.4.10 

for each NOx post-combustion control technology and provides a cross reference to information on 

cost assumptions. 

Table 5-7 Summary of Retrofit NOx Emission Control Performance Assumptions 

Control 

Performance 

Assumptions 

Selective Catalytic Reduction 

(SCR) 

Selective Non-Catalytic 

Reduction 

(SNCR) 

Unit Type Coal Oil/Gas Coal 

Pulverized Coal: 35% Percent Removal 90% down to 0.06 

lb/MMBtu 80% Fluidized Bed: 50% 

Size Applicability Units 25 MW Units 25 MW Units 25 MW 

Costs (2007$) See Table 5-8 See Table 5-9 See Table 5-8 
ATTACHMENT A-2 

SNCR COST DEVELOPMENT METHODOLOGY – 

SARGENT & LUNDY, LLC, AUGUST 2010 
 

IPM Model – Revisions to Cost and Performance for APC Technologies

SNCR Cost Development Methodology

FINAL

August 2010 

Project 12301-007 

Perrin Quarles Associates, Inc. 

Prepared by 

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

LEGAL NOTICE 

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

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

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

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

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

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

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

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

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

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

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

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

APC Technologies August 20, 2010

SNCR Cost Development Methodology – Final 

1 

Establishment of Cost Basis 

The formulation of the SNCR cost estimating model is based upon a proprietary Sargent 

& Lundy LLC (S&L) in-house data base of recent (2009) quotes for both lump sum 

contracts and EPC. The S&L data was analyzed in detail regarding project specifics such 

as coal type, boiler type, and NOx reduction efficiency. The S&L in-house data includes 

projects that involved cyclone boilers, T-fired and wall fired systems with multiple levels 

of injection. The cyclone boiler costs include rich reagent injection (RRI). The data was 

the basis for the cost estimate formulations developed. 

The S&L data was fitted with a least squares curve to establish the trend in $/kW as a 

function of gross MW. The EPA/IPM SNCR cost model parameters were adjusted to 

account for market changes and escalation, and then the model output was compared to 

the S&L data. The EPA/IPM model output followed a $/kW correlation very similar to 

the S&L in-house data, once the adjustments were made to the model. 

The rapid rise in project costs at the lower end of the MW range is due primarily to 

economies of scale. Additionally, older power plants in the 50 MW range tend to have 

plant sites that are more compact and therefore difficult to accommodate the reagent 

storage areas and piping, injection mixing/dilution equipment and construction activities. 

The smaller power plants also tend to have older control systems which may require 

upgrades to accommodate the new SNCR control system. 

The S&L data includes SNCR projects with various types of boilers, coals, sulfur levels 

and retrofit complexities. The data represents an average of boiler effects, such as 

cyclone, wall fired or CFB. The least squares curve fits were based upon the following 

assumptions: 

• Retrofit Factor =1 

• Gross Heat Rate = 10,000 

• SO2 Rate = < 3 lb/MMBtu 

• Type of Coal = PRB 

• Project Execution = Multiple lump sum contracts 

Methodology 

Inputs 

To predict future retrofit costs several input variables are required. The unit size in MW 

and NOx levels are the major variables for the capital cost estimation followed by the 

type of fuel (high sulfur Bituminous). The fuel type affects the air pre-heater costs if 

sulfuric acid or ammonium bisulfate deposition poses a problem. In general, if the level 

of SO2 is above 3 lb/MMBtu, it is assumed that air heater modifications will be required. 

The unit heat rate factors into the amount of NOx generated and ultimately the size of the 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007 

APC Technologies August 20, 2010

SNCR Cost Development Methodology – Final 

2 

SNCR reagent preparation system. A retrofit factor that equates to difficulty in 

construction of the system must be defined. The NOx rate and removal efficiency will 

impact the amount of urea required and size of the reagent handling equipment. 

The inputs that impact the variable O&M costs are based primarily on the plant capacity 

factor and the removal efficiency. The NOx removal efficiency specifically affects the 

reagent and dilution water costs. 

Outputs 

Total Project Costs (TPC) 

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

costs include: 

• Equipment; 

• Installation; 

• Buildings; 

• Foundations; 

• Electrical; and 

• Retrofit factor. 

The base module costs do not include: 

• Engineering and Construction Management 

• Owner's cost; and 

• AFUDC. 

The base modules are: 

BMS = Base module SNCR cost. 

BMA = Base module air pre-heater cost. 

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

upgrades, etc... 

BM = BMS + BMA + BMB 

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

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

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

BM cost; and 

• Contractor profit and fees at 10% of the BM cost. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007 

APC Technologies August 20, 2010

SNCR Cost Development Methodology – Final 

3 

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 CECC. The additional 

project costs include: 

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

procurement) at 5% of the CECC. 

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

turnkey engineering procurement construction (EPC) contract be executed, the total 

project cost could be 10 to 15% higher than what is currently estimated. 

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

CECC and the Owner’s home office costs. An example of the capital cost estimation is 

included in Table 1. 

Fixed O&M (FOM) 

The fixed operating and maintenance cost is a function of the additional operations staff 

(FOMO) and maintenance labor and materials (FOMM) associated with the SNCR 

installation. The FOM is the sum of the FOMO and the FOMM. 

The following factors and assumptions underlie calculations of the FOM: 

• In general, 1 additional operator is required for all installations. The FOMO is 

based on the number of additional operations staff required; and 

• The fixed costs for maintenance materials and labor are a direct function of the 

base module cost (BM) at a retrofit factor of 1.0. 

Variable O&M (VOM) 

Variable O&M is a function of: 

• Reagent consumption; 

• Dilution water consumption. 

All of the VOM costs must be adjusted for the plant capacity factor. 

The reagent consumption rate is a function of unit size, NOx feed rate and removal 

efficiency. A utilization factor of 15% is used for units with an inlet NOx of 0.3 

lb/MMBtu or lower and 25% for units with an inlet NOx greater than 0.3 lb/MMBtu. For 

CFB boilers a utilization factor of 25% is used. A reagent cost of $620 per ton of 100% 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007 

APC Technologies August 20, 2010

SNCR Cost Development Methodology – Final 

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urea is used in the model. The dilution water usage is based upon reagent consumption 

rate. 

The auxiliary power required for the SNCR system is not included in the VOM. The 

major systems that impact the power requirements are compressed air or blower 

requirements for the urea injection system and the reagent supply system. 

The variables that contribute to the overall VOM are: 

VOMR = Variable O&M costs for urea reagent. 

VOMM = Variable O&M costs for dilution water. 

VOM = VOMR + VOMM. 
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Table 1. Example of the Capital Cost Estimate Work Sheet (for T-fired boilers). 
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Table 2. Example of the Fixed and Variable O&M Cost Estimate Work Sheet (for T-fired b
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Table 3. Example of the Capital Cost Estimate Work Sheet (for CFB boilers). 
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Table 4. Example of the Fixed and Variable O&M Cost Estimate Work Sheet (for CFB bo
ATTACHMENT A-3 

SCR COST DEVELOPMENT METHODOLOGY – 

SARGENT & LUNDY, LLC, AUGUST 2010 
 

IPM Model – Revisions to Cost and Performance for APC Technologies

SCR Cost Development Methodology

FINAL

August 2010 

Project 12301-007 

Perrin Quarles Associates, Inc. 

Prepared by 

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

LEGAL NOTICE 

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

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

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

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

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

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

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

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

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

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

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

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

Technologies August 20, 2010 

SCR Cost Development Methodology – Final 

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Establishment of Cost Basis 

The formulation of the SCR cost estimating model is based upon two data bases of actual 

SCR projects. The data bases used were those of the 2004 to 2006 industry cost 

estimates for SCR units published in the “ANALYSIS OF MOG AND LADCO’S FGD 

AND SCR CAPACITY AND COST ASSUMPTIONS IN THE EVALUATION OF 

PROPOSED EGU 1 AND EGU 2 EMISSION CONTROLS” 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 of SCR projects available with both data sets. 

The data sets were escalated to update the MOG information to 2009 and all of the data 

was cross referenced with current 2009 projects. The MOG and S&L cost data 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 of data was refined by fitting each data set with a 

least squares curve to obtain an average $/kW project cost as a function of unit size. The 

data set was then collectively used to generate an average least-squares curve fit. The 

curve fit indicated that both sets of data produced similar average costs (within 4%) at the 

200 MW range, but deviate as the unit size increases to approximately 11% at 600 MW 

and 13% at 900MW. The costs for retrofitting a plant smaller than 100 MW increase 

rapidly due to the economy of size. 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 boiler house to the chimney. Because of the limited space, the SCR 

reactor and new duct work can be expensive to design and install. Additionally, the 

plants might not have enough margins in the fans to overcome the pressure drop due to 

the duct work configuration and SCR reactor and therefore new fans may be required. 

The least squares curve fit was based upon an average of the SCR retrofit projects. 

Retrofit difficulties associated with an SCR may result in capital cost increases of 30 to 

50% over the base model. The least squares curve fits were based upon the following 

assumptions: 

• Retrofit Factor =1 

• Gross Heat Rate = 9880 

• SO2 Rate = < 3 lb/MMBtu 

• Type of Coal = Bituminous 

• Project Execution = Multiple lump sum contracts 
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Methodology 

Inputs 

To predict future SCR retrofit costs several input variables are required. The unit size in 

MW is the major variable for the capital cost estimation followed by the type of fuel 

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

the moisture content. The fuel type also affects the air pre-heater costs if ammonium 

bisulfate or sulfuric acid deposition poses a problem. The unit heat rate factors into the 

amount of flue gas generated and ultimately the size of the SCR reactor and reagent 

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

be defined. The NOx rate and removal efficiency will impact the amount of catalyst 

required and size of the reagent handling equipment. The elevation of the site must be 

considered separately and factored into the unit MW size accordingly due to its effects on 

the flue gas volume. 

The inputs that impact the variable O&M costs are based primarily on the plant capacity 

factor and the removal efficiency. The NOx removal efficiency specifically affects the 

SCR catalyst, reagent and steam costs. The lower level of NOx removal is recommended 

as: 

• 0.07 NOx lb/mmBtu – Bituminous 

• 0.05 NOx lb/mmBtu – PRB 

• 0.05 NOx lb/mmBtu – Lignite 

Outputs 

Total Project Costs (TPC) 

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

include: 

• Equipment 

• Installation 

• Buildings 

• Foundations 

• Electrical 

• Retrofit factor 

The bare module costs do not include: 

• Engineering and Construction Management 

• Owner's cost 

• AFUDC 
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The modules are: 

BMR = Base module SCR cost 

BMF = Base module reagent preparation cost 

BMA = Base module air pre-heater cost 

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

BM = BMR + BMF + BMA + BMB 

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

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

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

BM cost. 

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

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

the BM and the additional engineering and construction fees. 

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

CECC. Financing and additional project costs include: 

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

procurement) at 5% of the CECC; and 

• Allowance for Funds Used During Construction (AFUDC) at 6% of the 

CECC and owner's costs. The AFUDC is based on a two-year engineering 

and construction cycle. 

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

turnkey engineering procurement construction (EPC) contract be executed, the total 

project cost could be 10 to 15% higher than what is currently estimated. 

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

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

of the capital cost estimation. 

Fixed O&M (FOM) 

The fixed operating and maintenance cost is a function of the additional operations staff 

(FOMO) and maintenance labor and materials (FOMM) associated with the SCR 

installation. The FOM is the sum of the FOMO and the FOMM. 
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In general, 1 additional operator is required for all installations. The FOMO is based on 

the number of additional operations staff required. 

The fixed maintenance materials and labor is a direct function of the bare module cost 

(BM) at a retrofit factor of 1.0. 

Variable O&M (VOM) 

Variable O&M is a function of catalyst required and disposal costs, reagent consumption, 

and steam consumption. All of the VOM costs must be adjusted for plant capacity factor. 

The reagent consumption rate is a function of unit size, 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 power to overcome the added pressure 

drop across the catalyst and ductwork and the reagent supply system. 

The variables that contribute to the overall VOM are: 

VOMR = Variable O&M costs for urea reagent 

VOMW = Variable O&M costs for catalyst replacement & disposal 

VOMM = Variable O&M costs for steam 

VOM = VOMR + VOMW + VOMM. 
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Table 1. Example of the Capital Cost Estimate Work Sheet. 
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Table 2. Example of the Fixed and Variable O&M Estimate Work Sheet.