1

NOx Control Supplement to Attachment 2 of January 31, 2011 Response To Request for Reasonable 

Progress Information – Colstrip Generating Plant Units 3&4 

Executive Summary 

 EPA Region 8 has requested additional information to supplement already submitted Reasonable 

Progress information for Colstrip Generating Plant Units 3&4. This current submittal is in response to 

USEPA Region 8’s May 18, 2011 follow-up letter (in which the Agency clarified its November 5, 2010 

request). PPL Montana responded to EPA’s November 5, 2010 request on January 31, 2011, and that 

response provided details of a Best Available Retrofit Technology (BART) analysis performed by PPL to 

satisfy a PSD permit condition to install BART for NOx on Colstrip Units 3&4. The response included a 

description of the low-NOx concentric firing system (LNCFS) Level III with Separated Overfire Air 

(SOFA) NOx control system and the Digital Process Control System (DPCS). These controls were 

installed under a Consent Decree and were installed and in operation by June 15, 2007 for Unit 3 and by 

May 9, 2009 for Unit 4. Since the BART approved controls were installed and fully operational, annual 

NOx emissions have been reduced by over 14,000 tons per year (approximately a 60% reduction from 

previous levels). 

 This addendum to the January 31, 2011 report provides an analysis of postcombustion NOx 

controls for Units 3&4 at Colstrip. While the controls installed and in operation have reduced the NOx

emissions to 0.17 lbs/MMBtu, (see EPA CAMD1

 website and the PPL Montana January 31, 2011 

submittal), the previous analysis did not include an analysis of the cost-effectiveness of post combustion 

NOx controls. The Integrated Planning Model (the IPM)2

 used by EPA to analyze the national fleet of 

coal fired boilers includes the post-combustion controls known as Selective Non-Catalytic Reduction 

(SNCR) and Selective Catalytic Reduction (SCR), and therefore analysis of the application of these post 

combustion technologies to Units 3&4 is being submitted to provide a complete review of add-on control 

technologies. 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 

                                                           

1

 ‐  Environmental Protection Agency’s Clean Air Markets Division

2

  ‐ Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model (see URL)
2

earlier cost analysis methods. Documentation for and a description of the planning model and control 

technology cost calculation methodology are found at the following hyperlink: 

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

The details of the cost effectiveness calculations for each control technology are provided in Section 2 

and the associated tables. A summary is discussed below. 

Selective Non-Catalytic Reduction (SNCR) of NOx 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. It is expected that a 10% 

incremental reduction of NOx would be attainable with the addition of SNCR to the Colstrip Units 3&4 

resulting in an estimated emission rate of 0.15 lbs/MMBtu. While an estimated additional 502 tons per 

year of NOx from each unit would be reduced over the combustion controls and digital process controls 

already in place, an estimated ammonia slip of 148 tons per year per unit would enter the PM/SO2

scrubbers, cause unknown effects on the reaction chemistry and largely be emitted from the stacks. 

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 Colstrip Units 3&4 to address higher fouling of components, increased maintenance, 

and a resultant increase in forced outages. Increased forced outages to perform necessary maintenance 

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 $3,300/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 to Units 3&4, the NOx controls would be before the wet scrubbing equipment for PM and SO2. The 

addition of SCR technology to Colstrip Units 3&4 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 control technology would have significant impacts at the plant. The estimated 

ammonia slip likely would react with components of the exhaust to cause unknown effects on scrubber 

reaction chemistry and plume opacity issues as well as fine particulate issues due to reactions with other 

residuals in the scrubber exhaust. Furthermore, there would be impacts due to the limited available space, 

which is already occupied with the SO2 wet scrubbing equipment. Reagent preparation equipment, 

reagent receipt, loading and unloading equipment, and the reactors for SCR would present significant 

construction and operational difficulties. 
3

The results of this evaluation shows that the cost effectiveness of SNCR is approximately 

$10,336 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 effectiveness of SNCR 

technology by approximately $3,300/ton. 

The estimated cost effectiveness for the addition of SCR to Units 3&4 is approximately 

$9,279/ton of additional NOx controlled. This does not include any increased cost as a result of an 

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

by approximately $300/ton.3

 

The high cost per ton of additional NOx removal with these technologies leads PPL Montana to 

the conclusion that they are not appropriate technologies for retrofit application to Colstrip Units 3&4. In 

addition, we believe that no significant visibility benefit is expected from the emission reductions that 

these technologies would achieve. 

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)4

 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. Units 3&4 are not BART eligible sources and were 

not part of those previous submittals. Simultaneously, however, EPA was utilizing available planning 

tools to study the universe of environmental effects that rules such as the Clean Air Interstate Rule 

(CAIR), Best Available Retrofit Technology (BART), and other local rules would have on the utility 

industry in the USA. One such tool used by EPA is the Integrated Planning Model or the IPM. ICF 

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

                                                           

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

4

 ‐ EPA control Cost Manual, 6th ed., EPA‐452‐01‐001, January 2002
4

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. 

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

combustion control options. For tangentially fired boilers 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. Colstrip already has this technology in place as described in PPL 

Montana’s January 31, 2011 response letter. No additional cost analysis of these systems is required. 

Historical NOx emissions for Units 3&4 are shown in the table below5. The units’ emissions are 

controlled to target the permit limit6

 of 0.18 #/MMBtu, 30-day rolling average. Achieving this limit 

results in nominal estimated control efficiency achieved by the low NOx equipment and digital controls is 

81%7

. In 2010, the first year with full implementation on both units, the NOx control equipment installed 

on Units 3&4 achieved over a 14,000 ton reduction from 2006, the last year prior to installation of these 

BART level controls. Subsequent years’ reductions are expected to consistently remain near this level8

. 

In view of the NOx reductions experienced at both units last year and the permit limits on the 

units that require the use of the advanced burner design and digital process control system, the baseline, 

pre-add-on control, NOx emission rate for evaluation of SNCR and SCR costs is 0.17 lbs/MMBtu 30 day 

average. Although the Consent Decree includes alternate higher NOx control limits for operation at less 

than 400 MW of the 805 MW design maximum, Colstrip Units 3&4 are baseload plants that operate 

greater than ninety-five percent of the time at more than 90% of maximum output. As documented in 

PPL Montana’s January 31, 2011 submittal and EPA’s Clean Air Markets Division (CAMD) website 

data, NOx emissions at Colstrip Units 3 & 4 have averaged 0.17 lbs/MMBtu since the installation of the 

combustion controls for NOx on Units 3&4. Consequently, 0.17 lbs/MMBtu is the appropriate baseline 

                                                           

5 In 2009, Unit 4 was out of service for approximately seven months for turbine repairs.

6 The permit limits are: For a 30 day rolling average, 0.18 #/MMBtu (loads > 400 GMW, 0.30 #/MMBtu (Loads <=

400 GMW, 1363 #/hour; for a 24 hour average, 0.25 #/MMBtu (loads > 400 GMW, 0.30 #/MMBtu (Loads <= 400

GMW, 1893 #/hour

7 Based upon current emission rates of 0.17 #/MMBtu and an uncontrolled emission rate of 0.90 #/MMBtu used in

the Colstrip 3&4 Title V permit application.

8 It should be noted that operating hours and generation of Units 3 &4 during 2006 and 2010 was/is reflective of

normal operation as these units are baseload. In 2006, Unit 4 was in its 3‐year maintenance overhaul cycle and its

output is somewhat reduced.   
5

emission rate to use in these analyses. The following sections describe the additional add-on control 

technology options presented herein to supplement the January 31, 2011 submission. 

Year NOx Annual Average Emissions 

(#/MMBtu) 

NOx Annual Emissions (Tons) 

20109 0.17 (Unit 3); 0.17 (Unit 4) 4950 (Unit 3); 5095 (Unit 4) 

2009 0.17 (Unit 3); 0.28(Unit 4) 5036 (Unit 3); 3928 (Unit 4) 

200810 0.17 (Unit 3); 0.33 (Unit 4) 5245 (Unit 3); 11096 (Unit 4) 

2007 0.24 (Unit 3); 0.40 (Unit 4) 8172 (Unit 3); 13650 (Unit 4) 

2006 0.40 (Unit 3); 0.38 (Unit 4) 12856 (Unit 3); 11907 (Unit 4) 

1.1 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 30 to 50% reductions when used alone and up to 65% reductions in total, 

                                                           

9 2010 is the first full year of operation of Low‐Nox burners on both Units 3 &4

10 2008 is the first full year of operation of low‐Nox burners on Unit 3
6

when used in conjunction with combustion controls.11. From the CCM and specifically speaking of the 

performance of SNCR technology: 

“In typical field applications, however, it provides 30 to 50% reduction. Reductions of up to 65% have been 

reported for some field applications of SNCR in tandem with combustion control equipment such as low-NOx 

burners (LNB).” 

This means that for PPL Montana which already has achieved the reductions in NOx emissions from 0.40 

to 0.17 lbs/MMBtu in Unit 3, and from 0.38 to 0.17 lbs/MMBtu in Unit 4, representing (58% and 55% 

reductions in NOx respectively) using combustion controls, SNCR would only be able to further reduce 

the 0.17 lbs/MMBtu by about another 7% to 10% (assuming the full 65% combined LNB/SNCR 

combination control is achieved). 

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). For 

either Unit 3 or 4 this would mean that each unit would emit approximately 38 pounds per hour (148 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. 

There would also be reactions with other components of the exhaust and subsequently in the wet 

scrubbers currently in operation. 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. 

1.2 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 reduced NOx emission 

rates, the lowest emission rate attainable with the baseline emission rate of 0.17 lbs/MMBtu (see the EPA 

CAMD website and the January 31, 2011 PPL Montana submittal) at either Unit 3 or 4 is expected to be 

0.06 lbs/MMBtu, or about a 65% reduction from 0.17 lbs/MMBtu. 

 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. 

                                                           

11 EPA CCP, Section 4, NOx Controls, page 1‐3.
7

The location of the SCR unit would be downstream of the economizer and upstream of the air heater and 

wet scrubber. 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. 

2.0 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 two add-on, i.e. 

post combustion, control technologies are presented: SNCR, and SCR. 

   Two background reports are included in Attachment A that 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-1 and A-2. 

2.1 SNCR Cost Analysis Using the IPM Methodology

   Tables 2-1 and 2-2 show the results of application of the costing methodology developed for use 

by USEPA in the IPM regulatory studies. Table 2-1 presents the Colstrip specific parameters for Units 

3&4 applied within the empirical cost analysis approach developed by S&L as presented in Attachment 

A-1. 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 believes that the presence of the PM and SO2 scrubbers at Colstrip already limits the space available 

for the installation of reagent preparation equipment and reagent receipt and unloading operations. PPL 

has used a factor of 1.3 instead of the 1.0 that would characterize a more open site plan than that available 

at Colstrip. 
8

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 0.15 lbs/MMBtu the cost effectiveness is estimated to be $10,336/ton. However, the 

operation of the SNCR will likely result in an increase in air heater fouling and result in an increase in 

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

approximately $3,300/ton. This cost is not included in the $10,336 cost above. 

2.2 SCR Cost Analysis Using the IPM Methodology

 Tables 2-3 and 2-4 show the results of application of the S&L costing methodology to Colstrip 

Units 3&4 for SCR. The costs reflected in these tables reflect a retrofit factor of 2.1 based on PPL 

experience in estimating a retrofit of an SCR on a large coal-fired unit. That cost included $10 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. Residual ammonia in the exhaust (expected to be at about 2 ppmv) although less than that 

associated with SNCR, is likely to react with other components of the exhaust to generate additional fine 

particulates, or require increased maintenance to address other downstream impacts on equipment. 

Application of SCR at Colstrip Units 3&4 is estimated to cost $9,279/ton assuming an emission rate of 

0.06 lbs/MMBtu. This does not include any increased cost as a result of an increase in forced outage rate. 

Even a one-day maintenance outage would increase the cost effectiveness by approximately $300/ton.12 

3.0   Conclusion

Based on the high cost per ton of the estimated NOx removed through installation of either an 

SNCR or an SCR at Colstrip Units 3 and 4, these controls are not appropriate and further analysis is not 

warranted. In addition, no significant visibility benefit is expected from the emission reductions resulting 

from these technologies. 

                                                           

12 This is less that the equivalent forced outage cost for an SNCR as the SCR removes more tons of NOx.  
Table 2-1

SNCR COSTING DEVELOPMENT

FOR CAPITAL AND OPERATION AND MAINTENANCE COSTS

Variable Designation Units Value Equation/Input(1)

SNCR CAPITAL COST FOR COLSTRIP UNITS 3 OR 4

Unit Capacity (Gross) A (MW) 805 Input

Retrofit Factor B 1.3 Difficulty of Retrofit

Gross heat rate C Btu/KW‐hr 9,371 Input

NOx Emiss Rate D lbs/MMBtu 0.18 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 C / 10,000

Heat Input H Btu/hr 7.54E+09 A X C x 1000

Capacity Factor I (%) 89.0 Input

NOx Removal Eff J (%) 10.00 Input

NOx Removed K (lbs/hr) 135.79 D x H/106

x J/10

Urea Rate L (lbs/hr) 590.37 K /0.15/46 x 30

Water Required M (lbs/hr) 5313.36 L x 9

Dilution Water Rate O (1,000 gph) 0.64 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 ($) $4,113,565 B x F/1.05 x 200000 x (AxG)0.42

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

Balance of Plant Costs BMB ($) $4,428,115 270000 x A0.33 x K0.12

Bare Module Cost BM ($) $8,541,680 BMS + BMA + BMB

Engineering, Const Mgmt A1 ($) $854,168 10% of BM

Labor Adjustment A2 ($) $854,168 10% of BM

Contractor Profit, Fees A3 ($) $854,168 10% of BM

Cap, Eng, Const Cost CECC ($) $11,104,184 BM + A1 + A2 + A3

Owners Cost B1 ($) $555,209 5% of CECC

Total Project Cost TPC ($) $11,659,393 CECC + B1

Cost per kW ($) 14 $/kW

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

Maintenance Material FOMM ($) $102,500 1.2% of BM

Total Fixed O&M ($) $164,900 FOMO + FOMM

Urea Cost VOMR ($) $132.83 L x P

Dilution Water Cost VOMM ($) $0.64 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 9
Table 2-2

PPL BART Cost Effectiveness Analysis

SNCR NOx Control

805 Megawatt Coal Fired Steam Electric Plant

Colstrip Unit 3 and Unit 4 (each)

Maximum Gross Heat Input MM Btu/hr 7,572

Design Percent Load % 89

Uncontrolled NOx Emissions (with PRB coal) lbs/MMBtu 0.170

ExhaustTemperature, (o

F) T 405

Steam Turbine Power Output (TMW) MW 805

Capacity Factor (89%) hrs 7,796

Controlled NOx Emissions lbs/MMBtu See Note 3 0.158

Overall NOx Reduction Efficiency, (%) % 7.06

Uncontrolled NOx Emissions, (lb/hr) 1287.2

Uncontrolled NOx Emissions, (tons/yr) 5017.9

Controlled NOx Emissions, (ton/yr) 4663.7

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) 14 $11,659,393

Equipment Cost Total, (EC) EC (Adjusted by Cost Index Calcs) (2011 dollars)(2) $12,028,663

 Total Capital Costs, TCC --- $12,028,663

 Direct Annual Costs, DAC Urea Cost VOMR $1,035,626

Dilution Water Cost VOMM $4,971

Maintenance Cleanings(4) $1,320,000

Maintenance Labor FOMO $62,400

Maintenance Materials FOMM $102,500

 Total Direct Annual Costs, DAC $2,525,498

Indirect Annual Costs

 Capital Recovery CRF*TCC --- $1,135,421

 Total Indirect Annual Costs, IAC $1,135,421

 Total Annual Costs, TAC = DAC + IAC $3,660,918

Cost Effectiveness ($/ton pollutant Removed) $10,336

 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= 113.065)

3) The controlled NOx emissions are adjusted to account for 148 tons of ammonia slip

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

4) SNCR technology will cause fouling of the air preheater and require four cleanings per year at $330,000 each

Page 10
Table 2-3

SCR COSTING DEVELOPMENT

FOR CAPITAL AND OPERATION AND MAINTENANCE COSTS

Variable Designation Units Value Equation/Input(1)

SCR CAPITAL COST FOR COLSTRIP UNITS 3 OR 4

Unit Capacity (Gross) A (MW) 805 Input

Retrofit Factor B 2.1 Difficulty of Retrofit

Gross heat rate C Btu/KW‐hr 9,371 Input

NOx Emiss Rate D lbs/MMBtu 0.18 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 0.9371 C / 10,000

Heat Input I Btu/hr 7.54E+09 A X C x 1000

Capacity Factor J (%) 89.0 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) 950.50 D X I / 106 * K / 100

Urea Rate N (lbs/hr) 664.04 M x 0.525 * 60/46 *1.01/.99

Steam Required M (lbs/hr) 750.36 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 ($) $171,722,024 180000 x B X L

0.2 x (AxGxH)0.92

Base Reagent Prep Cost BMF ($) $2,276,523 410000 x M0.25

ID Fans, Anciliary Equip BMB ($) $13,229,698 380000 x B x (AxGxH)0.42

Bare Module Cost BM ($) $187,228,244 BMR + BMF + BMB

Engineering, Const Mgmt A1 ($) $18,722,824 10% of BM

Labor Adjustment A2 ($) $18,722,824 10% of BM

Contractor Profit, Fees A3 ($) $18,722,824 10% of BM

Cap, Eng, Const Cost CECC ($) $243,396,718 BM + A1 + A2 + A3

Home office Costs B1 ($) $12,169,836 5% of CECC

Construction Funds B2 ($) $15,333,993 6% of CECC+B1

Total Project Cost TPC ($) $270,900,547 CECC + B1 + B2 p $/

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 $149.41 N X R

Steam Cost VOMM $3.00 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 11
Table 2-4

PPL BART Cost Effectiveness Analysis

SCR NOx Control

805 Megawatt Coal Fired Steam Electric Plant

Colstrip Unit 3 and Unit 4 (each)

Maximum Gross Heat Input MM Btu/hr 7,572

Design Percent Load % 89

LNCFS + SOFA Controlled NOx Emissions lbs/MMBtu 0.170

ExhaustTemperature, (o

F) T 405

Steam Turbine Power Output (TMW) MW 805

Capacity Factor (89%) hrs 7,796

Controlled NOx Emissions lbs/MMBtu 0.06

Overall NOx Reduction Efficiency, (%) % 64.71

Uncontrolled NOx Emissions, (lb/hr) 1287.2

Uncontrolled NOx Emissions, (tons/yr) 5017.9

Controlled NOx Emissions, (ton/yr) 1771.0

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) Capital Cost ($/KW) 337 $270,900,547

Equipment Cost Total, (EC) EC (Adjusted by Cost Index Calcs) (2011 dollars)(2) $279,480,358

 Total Capital Costs, TCC --- $279,480,358

 Direct Annual Costs, DAC

Catalyst Cost(3) VOMW $2,196,636

Urea Cost VOMR $1,164,844

Steam Cost VOMM $23,400

Maintenance Labor FOMO $62,400

Maintenance Materials FOMM $300,000

 Total Direct Annual Costs, DAC $3,747,280

Indirect Annual Costs

 Capital Recovery CRF*TCC --- $26,380,969

 Total Indirect Annual Costs, IAC $26,380,969

 Total Annual Costs, TAC = DAC + IAC $30,128,249

Cost Effectiveness ($/ton pollutant Removed) $9,279

 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= 113.065)

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

Page 12
ATTACHMENT A-1 

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 

4 

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

rate. 

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

major systems that impact the power 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. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007 

APC Technologies August 20, 2010

SNCR Cost Development Methodology – Final 

5 

Table 1. Example of the Capital Cost Estimate Work Sheet (for T-fired boilers). 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007 

APC Technologies August 20, 2010

SNCR Cost Development Methodology – Final 

6 

Table 2. Example of the Fixed and Variable O&M Cost Estimate Work Sheet (for T-fired b
IPM Model – Revisions to Cost and Performance for Project No. 12301-007 

APC Technologies August 20, 2010

SNCR Cost Development Methodology – Final 

7 

Table 3. Example of the Capital Cost Estimate Work Sheet (for CFB boilers). 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007 

APC Technologies August 20, 2010

SNCR Cost Development Methodology – Final 

8 

Table 4. Example of the Fixed and Variable O&M Cost Estimate Work Sheet (for CFB bo
ATTACHMENT A-2 

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 

1 

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

Technologies August 20, 2010 

SCR Cost Development Methodology – Final 

2 

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

Technologies August 20, 2010 

SCR Cost Development Methodology – Final 

3 

The modules are: 

BMR = Base module SCR cost 

BMF = Base module reagent preparation cost 

BMA = Base module air pre-heater cost 

BMB = Base module balance of plan costs 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. 
IPM Model – Revisions to Cost and Performance for APC Project No. 12301-007 

Technologies August 20, 2010 

SCR Cost Development Methodology – Final 

4 

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

Technologies August 20, 2010 

SCR Cost Development Methodology – Final 

5 

Table 1. Example of the Capital Cost Estimate Work Sheet. 
IPM Model – Revisions to Cost and Performance for APC Project No. 12301-007 

Technologies August 20, 2010 

SCR Cost Development Methodology – Final 

6 

Table 2. Example of the Fixed and Variable O&M Estimate Work Sheet.