1 NO x 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 informa tion 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 wh ich the Agency clarified its November 5, 2010 request). PPL Montana responded to EPA’s Novemb er 5, 2010 request on January 31, 2011, and that response provided details of a Best Available Retrof it Technology (BART) analysis performed by PPL to satisfy a PSD permit condition to install BART for NO x on Colstrip Units 3&4. The response included a description of the low-NO x concentric firing system (LNCFS) Level III with Separated Overfire Air (SOFA) NO x control system and the Digital Process Control System (DPCS). These controls were
installed under a Consent Decree and were installed a nd in operation by June 15, 2007 for Unit 3 and by May 9, 2009 for Unit 4. Since the BART approved c ontrols were installed a nd fully operational, annual
NO x emissions have been reduced by over 14,000 t ons per year (approximately a 60% reduction from previous levels).
This addendum to the January 31, 2011 repor t provides an analysis of postcombustion NO x controls for Units 3&4 at Colstrip. While the cont rols installed and in operation have reduced the NO x emissions to 0.17 lbs/MMBtu, (see EPA CAMD 1 website and the PPL Montana January 31, 2011 submittal), the previous analysis did not include an analysis of the cost-effectiveness of post combustion
NO x controls. The Integrated Planning Model (the IPM) 2 used by EPA to analyze the national fleet of coal fired boilers includes the post-combustion c ontrols known as Selective Non-Catalytic Reduction (SNCR) and Selective Catalytic Reduction (SCR), and th erefore 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 IP M to assess the combined eff ect that air rules have on the electric utility industry as a whole. This platfo rm 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 devel oped 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/e pa-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 su mmary is discussed below.
Selective Non-Catalytic Reduction (SNCR) of NO x is a post combustion technology in which ammonia or urea is injected into the combusti on zone of the boiler to chemically reduce NO x to nitrogen and water vapor, and carbon dioxide if urea serves as the source of ammonia. It is expected that a 10%
incremental reduction of NO x would be attainable with the additi on 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 NO x from each unit would be reduced over the com bustion controls and digital process controls already in place, an estimated ammonia slip of 148 tons per year per unit would enter the PM/SO 2 scrubbers, cause unknown effects on the reaction chemis try 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 faciliti es. Consequently, PPL Montana expects that increased costs will occur at Colstrip Units 3&4 to address hi gher 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 comparativel y lower ammonia slip. In the case of application of SCR to Units 3&4, the NO x controls would be before the we t scrubbing equipment for PM and SO 2 . The addition of SCR technology to Colstrip Units 3&4 is estimated to reduce NO x 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 fi ne particulate issues due to reactions with other
residuals in the scrubber exhaust. Fu rthermore, there would be impacts due to the limited available space, which is already occupied with the SO 2 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 NO x removed on an annualized basis. This estimate includes increased maintenance costs to address the fouling downstream of ammonia injection, but does not include any other costs related to increased forced outages, such as lost gene ration, 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 add ition of SCR to Units 3&4 is approximately $9,279/ton of additional NO x controlled. This does not include any increased cost as a result of an increase in forced outage rate. Even a one-day ma intenance outage would increase the cost effectiveness by approximately $300/ton. 3

The high cost per ton of additional NO x 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 bene fit 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 NO x , the electric utility control costing techniques were limited to Selective Non-Catalytic Reduction (SNCR) and Selective Catalytic Reduction (SCR). Utility applications of combustion controls we re installed and operating in the USA, however, no compilation of the cost of such utility sized system s was available other than as provided in the CCM. Using costing tools available at that time, anal yses 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. Simultane ously, 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 comb ined 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 NO x .

4 ‐ EPA control Cost Manual, 6 th ed., EPA

‐ 452

‐ 01

‐ 001, January 20024 utility industry as a whole. This platform has also been used by EPA’s Clean Air Markets Division for analyzing recent air policy decisions. Based upon curren tly available information, the control technology cost estimation techniques developed for the IPM app ear to be more robust than earlier cost analysis
methods. The IPM includes cost estimating methodology for the various low-NO x burner and overfire air combustion control options. For tangentially fired bo ilers such as those at Colstrip, cost estimation methods and empirical equations for low NO x coal-and-air nozzles with close coupled and separated overfire air are also included. Colstrip already has this technology in place as described in PPL Montana’s January 31, 2011 response letter. No add itional cost analysis of these systems is required.
Historical NO x emissions for Units 3&4 are shown in the table below 5 . The units’ emissions are controlled to target the permit limit 6 of 0.18 #/MMBtu, 30-day rolling average. Achieving this limit
results in nominal estimated contro l efficiency achieved by the low NO x equipment and digital controls is
81% 7 . In 2010, the first year with full implementation on both units, the NO x 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 ar e expected to consistently remain near this level 8

. In view of the NO x reductions experienced at both units last year and the permit limits on the units that require the use of the advanced burner d esign and digital process control system, the baseline, pre-add-on control, NO x emission rate for evaluation of SNCR and SCR costs is 0.17 lbs/MMBtu 30 day average. Although the Consent Decree includes alternate higher NO x control limits for operation at less than 400 MW of the 805 MW design maximum, Colstr ip 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, NO x emissions at Colstrip Units 3 & 4 have averag ed 0.17 lbs/MMBtu since the installation of the
combustion controls for NO x 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 follo wing sections describe the additional add-on control technology options presented herein to s upplement the January 31, 2011 submission.



### Year NO x 

### Annual Average Emissions (#/MMBtu) NO x 

### Annual Emissions (Tons)

2010 9 

### 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)

2008 10 

### 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 NO x SNCR is a post combustion technology in which amm onia or urea is injected into the combustion zone of the boiler where the temperature is in a ra nge of 1600 deg F to 2000 deg F. It is called “post combustion” because unlike the control options that pr event or reduce the formation of thermal and fuel
NO x , SNCR injects a chemical to chemically reduce NO x to nitrogen and wate r vapor (and carbon dioxide if urea serves as the source of ammonia). The chemical reactions, which are not presented here, occur between nitric oxide (NO) and ammonia, i.e., NH 3 or CO(NH 2 ) 2 to form carbon dioxide, water vapor, and nitrogen. Not all of the injected ammonia results in NO x reduction reactions. Unreacted ammonia may
react with SO 2 or SO 3 to form ammonium bisulfite and/or am monium 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 reac tant in a stream of water or steam into a region in the boiler where reaction temperatures are in the corr ect 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 36 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 al ready has achieved the reductions in NO x 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 NO x 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 NO x 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 a dverse visibility impacts. In SNCR the reactive reagent, in this case urea, would be injected into the combustion zone of the boiler and react with NO x . There would also be reactions with other compone nts 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 requi re increased maintenance activities for cleaning the ammonium bisulfite and sulfate ammonia slip byprod ucts from the economizer a nd 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 catalys t bed also produces higher reduction efficiencies. While SCR will perform better than SNCR with the already reduced NO x 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, 20 11 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 NO x emissions and both technologies are expect ed to have ammonia slip emissions.

11 EPA CCP, Section 4, NO x 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 impact s 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 w hole. This platform has also been used by EPA’s Clean Air Markets Division for analyzing air policy decisions. One aspect of the IPM is the capital, operating, and maintenance cost of air pollution cont rol equipment. These costing analytical techniques were summarized in reference 1, available from the US EPA Clean Air Markets Division or through the link provided in the executive summary of this report. For NO x , APCE cost analyses for two add-on, i.e. post combustion, control technologies are presented: SNCR, and SCR. Two background reports are included in Attachme nt A that describe the costing approach to SNCR and SCR. Each report was prepared by Sa rgent & Lundy, LLC under contract to the USEPA. Based upon a proprietary database of control installati on 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 c ontain both capital and operating and maintenance costs. Just as EPA used cost factors as percenta ges of the capital equipment cost, S&L used the same approach to develop their capital co sts 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 applica tion of the costing methodology developed for use by USEPA in the IPM regulatory studies. Table 2-1 presents the Colstrip speci fic parameters for Units 3&4 applied within the empirical cost analysis appr oach developed by S&L as presented in Attachment A-1. The use of the “retrofit factor” is provided in th e analytical cost equations to allow for particularly difficult sites where application of retrofit technology woul d be more difficult due to site specific factors. PPL believes that the presence of the PM and SO 2 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 combus tion zone where it breaks down into two moles of
ammonia and one mole of CO 2 per mole of urea injected. Excess reagent is always required to attain acceptable NO x reductions; however, the reductions that are attainable are higher when the uncontrolled
NO x is higher. At a typical ammonia slip concentra tion in the exhaust of 10 ppm, the unreacted ammonia
would enter the PM/SO 2 scrubbers and cause unknown effects on the reaction chemistry. This could lead to higher fouling of scrubber components, increased maintenance, and more fr equent breakdowns of the scrubbing equipment. Using the IPM methodology, and assuming that inst allation of an SNCR will result
in an emission rate of 0.15 lbs/MMBtu the cost effect iveness 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 maintenan ce 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 applica tion 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 la rge 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 SO 2 to SO 3 and creating the potential for a visible plume. Residual ammonia in the exhaust (expect ed 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 estimat ed 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 th e cost effectiveness by approximately $300/ton. 12

3.0 Conclusion

Based on the high cost per ton of the estimated NO x removed through installation of either an SNCR or an SCR at Colstrip Units 3 and 4, these contro ls are not appropriate and further analysis is not warranted. In addition, no significant visibility benef it 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 NO x .

### 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
SO 2 Emiss Rate E lbs/MMBtu 1.8 Input Type of Coal E Input Coal Factor F 1 1 Input Heat Rate Factor G 1 1 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/10 6 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 A 0.33 x K 0.12

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 9Table 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, DA C 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 + IA C $3,660,918
Cost Effectiveness ($/ton pollutant Removed) $10,336

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

‐ Revisions to Cost And Performance for AP C Technologies

‐ SNCR Cost Development Methodology

‐ FINAL", August 2010 Project 12301

‐ 007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC 2) Cost indices used to adjust 2009 costs to 2011 costs (2009 CI= 109.594, 2011 CI= 113.065) 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 NO x E m i ss R a t e D lb s / MMBtu 0.18 Uncontro ll e d SO 2 E m i ss R a t e E lb s / MMBtu 1.8 Uncontro ll e d Type of Coal F Input Coal Factor G 1.05 Input Heat Rate Factor H 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 / 10 6 * 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 M 0.25

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 $/

Fixe d Operator Cost FOMO $ 62,400 2,080 h rs ‐ 1 ‐ h a lf time Maintenance Materia l FOMM $ 300,000 Fixe d Annua l Cost Tota l Fixe d O & M FOM $ 362,400 FOMO + FOMM Urea Cost VOMR $ 149.41 N X R Steam Cost VOMM $ 3.00 O x U C ata l yst cost (3) VOMW $ 0.35 $/ MW h r

Notes: 1) Cost analysis equations from "IPM Model

‐ Revisions to Cost And Performance for APC Technologies

‐ SCR Cost Development Methodology

‐ FINAL", August 2010 Project 12301

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

‐ hr PRB

CAPITAL EQUIPMENT COSTS

OPERATING AND MAINTENANCE COSTS



### Page 11Table 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, DA C 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 + IA C $30,128,249
Cost Effectiveness ($/ton pollutant Removed) $9,279

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

‐ Revisions to Cost And Performance for AP C Technologies

‐ SCR Cost Development Methodology

‐ FINAL", August 2010 Project 12301

‐ 007, Perrin Quarles Associates, Inc., prepared by Sargent & Lundy, LLC 2) Cost indices used to adjust 2009 costs to 2011 costs (2009 CI= 109.594, 2011 CI= 113.065) 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 a nd Performance for APC Technologies

SNCR Cost Development Methodology

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

Prepared by

55 East Monroe Street • Ch icago, IL 60603 USA • 312-269-2000LEGAL NOTICE
This analysis ("Deliverable") was prepared by Sargent & Lundy, L.L.C. ("S&L"), expressly for the sole use of Perrin Quarles Associates, Inc. ("Client") in accordance with the agreement between S&L and Client. This Deliverable was prepared using the degree of skill and care ordinarily exercised by engineers practicing under similar circumstances. Client acknowledges: (1) S&L prepared this Deliverable subject to the particular scope limitations, budgetary and time constraints, and business objectives of the Client; (2) information and data provided by others may not have been independently verified by S&L; and (3) the information and data contained in this Deliverable are time sensitive and changes in the data, applicable codes, standards, and acceptable engineering practices may invalidate the findings of this Deliverable. Any use or reliance upon this Deliverable by third parties shall be at their sole risk.

This work was funded and reviewed by the U.S. Environmental Protection Agency under the supervision of William A. Stevens, Senior Advisor – Power Technologies. Additional input and review was provided by Dr. Jim Staudt, President of Andover Technology Partners.

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

### SNCR Cost Development Methodology – Final

1 

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

• Retrofit Factor =1

• Gross Heat Rate = 10,000

• SO 2 

### Rate = < 3 lb/MMBtu

• Type of Coal = PRB

• Project Execution = Multiple lump sum contracts



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

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

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

### SNCR Cost Development Methodology – Final

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

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

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

• Equipment;

• Installation;

• Buildings;

• Foundations;

• Electrical; and

• Retrofit factor.

The base module costs do not include:

• Engineering and Construction Management

• Owner's cost; and

• AFUDC.

The base modules are:

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

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

BM = BMS + BMA + BMB

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

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

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

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

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

### SNCR Cost Development Methodology – Final

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

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

Fixed O&M (FOM) 

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

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

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

Variable O&M (VOM) 

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

• Reagent consumption;

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

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

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

### SNCR Cost Development Methodology – Final

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

The variables that contribut e to the overall VOM are:

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

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

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

SCR Cost Development Methodology

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

Prepared by

55 East Monroe Street • Ch icago, IL 60603 USA • 312-269-2000LEGAL NOTICE
This analysis ("Deliverable") was prepared by Sargent & Lundy, L.L.C. ("S&L"), expressly for the sole use of Perrin Quarles Associates, Inc. ("Client") in accordance with the agreement between S&L and Client. This Deliverable was prepared using the degree of skill and care ordinarily exercised by engineers practicing under similar circumstances. Client acknowledges: (1) S&L prepared this Deliverable subject to the particular scope limitations, budgetary and time constraints, and business objectives of the Client; (2) information and data provided by others may not have been independently verified by S&L; and (3) the information and data contained in this Deliverable are time sensitive and changes in the data, applicable codes, standards, and acceptable engineering practices may invalidate the findings of this Deliverable. Any use or reliance upon this Deliverable by third parties shall be at their sole risk.

This work was funded and reviewed by the U.S. Environmental Protection Agency under the supervision of William A. Stevens, Senior Advisor – Power Technologies. Additional input and review was provided by Dr. Jim Staudt, President of Andover Technology Partners.Project No. 12301-007 IPM Model – Revisions to Cost and Performance for APC Technologies August 20, 2010 

### SCR Cost Developmen t Methodology – Final

1 

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

• Retrofit Factor =1

• Gross Heat Rate = 9880

• SO 2 

### Rate = < 3 lb/MMBtu

• Type of Coal = Bituminous

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

### SCR Cost Developmen t Methodology – Final

2 

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

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

as:

• 0.07 NOx lb/mmBtu – Bituminous

• 0.05 NOx lb/mmBtu – PRB

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


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

• Equipment

• Installation

• Buildings

• Foundations

• Electrical

• Retrofit factor

The bare module costs do not include:

• Engineering and Construction Management

• Owner's cost

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

### SCR Cost Developmen t Methodology – Final

3 The modules are:

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

BM = BMR + BMF + BMA + BMB

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

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

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

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

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

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

Fixed O&M (FOM) 

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

### SCR Cost Developmen t Methodology – Final

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

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

Variable O&M (VOM) 

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

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

The variables that contribut e to the overall VOM are:

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

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