1 

### Discussion of OAQPS Cost Manual Method for AQCS Estimation

The purpose of this document is to expl ain why the OAQPS Cost Manual is not sufficient for estimating the cost of air qual ity control (AQC) equipment. This document will first discuss the impact of escalation on the cost of AQC projects. Next, a discussion of the scope items that are missing from th e OAQPS cost manual for SCR is included. Finally, a comparison is made between an estimate performed using the OAQPS method and the B&V estimate for PNM San Juan Generating Station (SJGS) BART analysis.2 

### 1.0 Impact of Escalation on AQC Costs The most recent revision of the OAQPS manual is the EPA Air Pollution Control

Cost Manual , Sixth Edition, EPA/452/B- 02-001, dated January 2002 (t he Cost Manual). There have been significant cost increases in AQC equipment since its release. Section 4.2, Chapter 2, Selective Cataly tic Reduction, was written in October 2000. In addition to that, on page 2-40, Article 2.4 of the SCR section, it wa s indicated that the costs presented in the manual are based on 1998 dollars. In Chapter 2 of the Introduction (Artic le 2.4.3), the Cost Manual specifically discusses the importance of escal ating the cost of equipment to the current year. Costs can and do change dramatically over time. It has been 8 years since the SCR section of
the Cost Manual was written, and the reference costs in the Cost Manua l are 10 years old. In that time, the AQC industry and the energy industry have seen signi ficant increases in the cost of equipment and construction. The Cost Manual does not take into account the significant increase in demand for equipment, commodities, contractors, and construction labor experienced over the past 9 years from the many retrofits associated with the Acid Rain Program, ozone SIP call, New Source Review (NSR), Prevention of Significant Deterioration (PSD) projects ( both new and modifications), the Clean Air Interstate Rule (CAIR) and the BART program, the new coal projects in the US and international markets. Any cost estimate, such as B&V’s cost estimate for the BART analysis, must

take into account the impact of escalation. The cost of AQC equipment has increased dramatically over the last few years (2005 to 2007 time frame). Figure 1 is taken from a press release from the Cambridge Energy Research Associates website (the enti re press release is included as Reference 1 in Appendix A of this document). This fi gure shows that between the year 2000 and the year 2007, the refinery indus try has seen a 66 percent increase in the cost of implementing large projects. Although this gr aph is focused on the re finery industry, the electric utility industry uses many of the same vendors, contractors, and raw materials on new power generation projects and AQC projects. As a result, these cost increases are indicative of cost increases being experi enced in the electr ic utility industry.3 Figure 1 IHS-CERA Capital Cost Index

Another reference that presents the dram atically changing costs associated with AQC projects is a industry pape r titled “Current Capital Cost s and Cost Effectiveness of Power Plant Emissions Control Technologies” prepared by J. Edward Cichanowicz for the Utility Air Regulatory Group (included as Reference 2 in Appendix A). Mr. Cichanowicz is a well-known utility industr y environmental control technology expert who keeps abreast of utility industry envir onmental control technology trends and costs. He is a former EPRI employee and has produc ed many publications and presentations for organizations such as Power Engineerin g magazine and the Electric Utilities
Environmental Conference (EUE C). Figure 2 shows a strong example of how the costs of SCR have doubled or tripled since the year 2000. This increase in costs is especially dramatic in the last two years.4 The paper describes four “phases” of installation of SCR systems in the US. The first phase is the early SCRs in the US. Phase 2 is the first SCRs installed in response to the OTAG SIP call rules. Phase 3 represents the majority of the SCRs installed in response to the OTAG SIP call. Phase 4 is th e current phase. Th is phase shows very high SCR costs because of the market forc es currently impacting the AQC and new generation markets.

Figure 2

Increases in SCR Costs from Cichanowicz Paper

Figure 3 is data from the U.S. Bureau of Labor Statistics showing the Producer Price Index for metals and metal products. Because SCR systems are comprised mostly
of ductwork and structural steel, the increase in price of metal a nd metal products is a reliable indicator of the price of SCR equipment. It can be seen that the price of metals and metal products has increased by 59 per cent between the years 2000 and 2007. It can also be seen that the majority of the escalation has occurred since 2004. This data can be

found on Bureau’s website at http://www.bls.gov/ppi/home.htm

.5 Figure 3

Producer Price Index for Me tals and Metal Products

The following quote from a Progress Energy Fl orida official, Thomas Cornell, is a good description of the price increases that ha ve been experienced by the utility industry:

“ the estimated costs of the new air controls have jumped 70% from what was contained in the 2006 filing.”There are several reasons for the increase," he explained. "One of the impacts of the final [federal Clean Air Interst ate Rule of 2005] was to create significant industry demand for major retrof it construction projects to engineer, procure, and install the necessary air pollution cont rol equipment. This occurred at a time when there was already significant construc tion activity due, in part, to an improving economy. The situation was exacerbated by even more construction demand in the aftermath of Hurricane Katrina and by the rising demand fo r steel, concrete and other commodities in

countries such as China and India. As a resu lt of these world-wide market conditions, PEF and the industry have seen significant in creases in costs for major construction projects, especially for SCR and scrubber equipment and installations. The increases were primarily driven by significant escalation in the cost of basic construction materials6 and in labor costs. " This quotation is from a June 2007 article in SNLi and can be found at the following website:

http://www.snl.com/InteractiveX/article.aspx?CDID=A-5838501- 12640&KPLT=2

.

It should also be noted that these cost increases are being experience by the entire industry, not just in the AQC market. New coal generati on projects have witnessed significant cost increases over th e last few years. A July 2007 article in The New York Times (included in Appendix A as Reference 3) provides the followi ng example: “In late 2004, Duke Energy, one of the coun try’s largest utilities and most experienced builders, started planning a pair of coal-fired pow er plants... In May 2005, the company told regulators it wanted to spend $2 billion to build twin 800-megawatt units. But 18 months
later, in November 2006, Duke said it woul d cost $3 billion. Then the State Utility Commission said to build only one of the plants, and in May of [2007], Duke said that would cost $1.83 billion, an incr ease of more than 80 percent from the original estimate.” These aforementioned references agree we ll with B&V’s internal database of costs. Figure 4 presents some of B&V’s estimating department’s internal indexes for various commodities used in SCR applications and other AQC applications. This data is developed by comparing prices in contract s (with similar scope) obtained in 2005 with

those obtained in 2007. As can be seen from this figure, pr ices on various AQC equipment components have increased dramatic ally in a very short period of time.7 02/11/08 TU - 50 Structural steel +44% Valves +37%

Copper wire and cable +98% Boilers and heat

exchangers

+38% Transportation costs +71% Concrete (Ready mix)

+30% 

### Dramatic changes during 2005 – 2007 

## Escalating prices in our industry pose tremendous risk

Fiberglass pipe & fittings +39% SD absorbers fabric filters

+27%

MV Switchgear +19% Fans and dampers +35% Flue gas ductwork +35% OFA & low NOx Burners +30%

Figure 4
B&V Indexes for AQC-Related Commodities8 

### 2.0 Missing Scope in OAQPS Cost Estimate
The Cost Manual presents equations to calculate the com ponents of the SCR system. The Cost Manual has costs fact ors developed for the following items:

• Reactor ductwork

• Catalyst

• Ammonia system

• SCR bypass

• Retrofit factor

• General factor for all other equipment

It should also be noted that the Cost Manual is geared more towards developing

costs for new units than retrofit ting controls on existing units. It was originally written to

assist utilities with devel oping costs for BACT analyses.

The SCR cost estimate included in th e Cost Manual is missing several key categories of equipment and construction necess ary for SCR systems. At the time of the
Cost Manual’s creation, the indus try severely underestimated th e balance of plant impacts of SCR. This is evident by the large number of SCR projects built between 2000 and 2004 that had significant cost overruns. The missing scope items are identified in th is section of the doc ument. It should

be noted that this s ection does not discuss how B&V estimated these items. The details

of B&V’s estimate will discussions in Section 3.0 of this document. These missing cost items represent real scope and costs that would be borne by PNM if they were required to install SCR on any or all of the units at SJGS. The following discussion supplements an earlier response submitted to the NMED on September 14, 2007.

2.1 Elevator PNM requires an elevator for maintena nce purposes. This would allow the maintenance staff to move more easily e quipment such as catalyst tools and NOx monitoring system supplies (such as calibrati on gas canisters) to the various SCR access platforms. The elevator is not included in the OAQPS estimate.9 2.2 SCR Bypass Although the OAQPS manual includes a cost factor for SCR bypass, it is not

accurate or sufficient for all th e costs associated with an S CR bypass. For SJGS, the cost of factor results in a cost of approximate ly $730,000. This cost does not pay for the cost of more than one damper, let alone the duc twork required for the SCR bypass. The SCR bypass dampers are not itemized in the Cost Ma nual. As previously stated, the SJGS units start up on fuel oil. As a result, th ere is a great potential for unburned fuel and unburned hydrocarbons to deposit on the catalyst during startup. Because SCR catalyst is an oxidizing catalyst, unburned fuel and unbur ned hydrocarbons pose a great risk for fires inside the catalyst. It is recommende d that the SCR be bypassed during startup operations.

2.3 NOx Monitoring System The NOx monitoring system is required to measure NOx before and after the catalyst and is an essential pa rt of the SCR system. The measurement is used to control

the ammonia feed to the SCR.

2.4 Electrical Upgrades Upgrades are required to the electri cal systems to incorporate the new SCR equipment into the existing system. The sc ope of electrical upgrades included additional
motor control centers (MCC), variable fre quency drives (VFD) controls upgrade and

substations.

2.5 Instrumentation and Control System The SCR for this project would need to be incorporated into the existing distributed control system (DCS). This is a typical requirement for an SCR system

retrofit but would not be needed for a ne w unit SCR because the SCR would simply be

included in the new DCS.10 2.6 Gross Receipt Tax B&V takes guidance from EPA’s CUECost program in developing the costs of SCR systems. The CUECost program includes gro ss receipt tax as a standard line item in

the cost estimate.

2.7 Freight B&V takes guidance from EPA’s CUECost program in developing the costs of SCR systems. The CUECost program includes fr eight as a standard line item in the cost

estimate.

2.8 Air Preheater Modifications

The air heater needs to be modified to make it resistant to ammonium bisulfate (ABS) corrosion and plugging. Ammonium bisulfate is formed from the reaction between sulfur trioxide in the flue gas and am monia slip from the SCR process. ABS is a sticky, highly corrosive substance that will conden se on the “cold end” air heater baskets.

The modifications to the air heater include installing new, enamel-coated baskets in the air heater and installing multi-media soot bl owers. This will help to minimize plugging

from ammonium bisulfate and make the air he ater easier to clean. The multi-media soot

blowers are used to clean the air heater. Th e soot blowers use air or steam during plant operation and water during outages to wash off accumulated ammonium bisulfate.

2.9 Balanced Draft Conversion As previously discussed in PNM’s Sept ember 14, 2007 submittal, a balanced draft conversion is required for the SJGS. If the SCR is added, the “zero pressure point” of the draft system would move into the region within the boiler. A balanced draft conversion will include stiffening of the boiler and modification to the fans of the draft system.

2.10 Site Preparation As previously stated in PNM’s Septembe r 14, 2007 submittal, site preparation is a lump-sum estimate for required site work such as modifying underground facilities, moving buildings, etc.11 2.11 Buildings and Enclosures An enclosure is required around the a mmonia storage system for safety and

ammonia containment.

2.12 Engineering B&V takes guidance from EPA’s CUECost program in developing the costs of SCR systems. The CUECost program provi des a more accurate method for calculating the cost for engineering services than does the OAQPS Cost Manual.

2.13 Contingency B&V takes guidance from EPA’s CUECost program in developing the costs of SCR systems. The CUECost program allows contingency costs to be calculated as 20 percent of the direct capital costs. B&V used this met hod of calculating contingency instead of the OAQPS method of using 15 percent.

2.14 Owner Costs PNM would incur a significant amount of costs to install an SCR system.

Owner’s costs include items such as staff for site co ordination during construction, equipment receiving, contract management , interface with regulatory agencies, and owner engineering costs.

2.15 Construction Management This item is applicable to both new units and retrofit units. However, with new units, the costs for construction management are difficult to identify because the AQC systems are a portion of the overall project. However, on an AQC retrofit project, all construction management expenses are attributed specifically to the AQC retrofit. Construction management cost s include the cost for engin eering support, construction oversight by PNM or their engi neer, environmental services, secretarial services, safety personnel, quality assurance personnel, drug test ing, and other services required to ensure that the construction is performed in accord ance with the scope of work, safe work12 practices, regulatory requirements, constructi on instructions, constr uction drawings, and vendor requirements.

2.16 Construction Indirects

Cost items included in construction i ndirects include cons truction equipment,

construction contractor overhead and profit, tools, site traile rs and utilities, construction supervision, and construction contractor ad ministrative support. The Cost Manual does not address these costs in any way yet these are real costs that will be incurred in order to support the direct cost of installing the SCR system.

2.17 Startup and Spare Parts This item includes costs for startup such as development of startup procedures, pre-startup safety review, star tup equipment, startup operator s, field technical services from vendors, and operations and maintenance tr aining. Spare parts are also included in this category.

2.18 Performance Test The performance testing is done to dem onstrate compliance with permits and to

demonstrate that contractual guarantees have been met.13 

### 3.0 Comparison of B&V Cost E stimate to Cost Manual Estimate

In NMED’s December 21, 2007 le tter to PNM, the NMED requested that the cost estimate for SCR be performed using the OAQPS Cost Manual. Sections 1.0 and 2.0 of this document were written to explain why B&V did not use the Cost Manual to prepare the estimate for the SJGS BART analysis. As previously stated, there are two main

reasons that the Cost Manual was not used. First, the price of SCR systems (and other AQC retrofits) has increased dramatically in th e past 10 years, and es pecially since 2005.
Second, the Cost Manual does not includ e many categories of equipment and construction that are required for the complete installation of an SCR system consistent with common industry practices. While it wa s representative of i ndustry knowledge of SCR systems in October 2000, the Cost Manual no longer provides an accurate estimate
of the actual cost of SCR. Therefore, B&V developed a cost estimate for the SJGS BART analysis based on an internal databa se of costs for recent SCR projects. Where possible, B&V scaled the costs from actual ve ndor quotations from a nother representative project.
However, in order to re spond to NMED’s request, B&V has performed a cost estimate using the Cost Manual for SJGS Unit 3. Figure 5 shows th e results of that analysis. In this analysis, B&V did not add any of the ne cessary scope items that are missing from the Cost Manual program as desc ribed in Section 2.0 to the estimate. However, in accordance with Chapter 2 of Introduction, B&V di d escalate the costs developed from Cost Manual to 2007 dollars. We used the CERA cost index shown in Figure 1 of this document. After incorporati ng the escalation, we then compared the Cost

Manual estimate to B&V’s estimate FOR A SIMILAR SCOPE . The results show that B&V’s estimate is very similar and on the same scale to the estimate developed from the

Cost Manual.14(1998 $)Cost ParameterVariable NameMultiplierEquationCost AmountEscallation to 2007B&V EstimateCommentsTotal Direct Capital CostsADCC 22,327,000 37,063,000 38,345,000Indirect Installation CostsGeneral facilities 0.05 A 1,116,000 1,853,000 1,917,000Engineering and home office fees 0.1 A 2,233,000 3,706,000 2,684,000 B&V used 7%Process contingency 0.05 A 1,116,000 1,853,000 1,917,000Total Indirect Installation Costs B 0.05A + 0.10A + 0.05A4,465,000 7,412,000 6,518,000Project ContingencyC 0.15 (A+B) 4,018,800 6,671,000 8,973,000 B&V used 20%Total Plant CostsD A + B + C 30,811,000 51,146,000 53,836,000Allowance for Funds During Construction E =0 (for SCR - OAQPS) 0 0 0Royalty Allowance F =0 (for SCR - OAQPS) 0 0 0Preproduction Cost G 0.02 (D+E) 616,000 1,023,000 1,077,000Inventory Capital H ICC 129,000 129,000 129,000Initial Catalyst and Chemical I =0 (for SCR - OAQPS) 0 0 0Total Capital Investment TCI D + E + F + G + H + I 31,556,000 52,298,000 55,042,000Figure 5SJGS Unit 3 - Comparison of Cost Manual Estimate to B&V EstimateNot Including the Necessary Scope Missing from Cost ManualFor Similar Scope, the CostManual Estimate and B&V’sEstimate are very similar15 However, the estimate shown in Figure 5 is not correct. It do es not include cost items that are necessary and appropriate to in stall an SCR system. This estimate does not represent the true costs that would be borne by PNM if they were required to install SCRs at SJGS. It is unacceptable for th e NMED to base regulatory decisions on

inaccurate costs if those decisions would re quire PNM to spend a large amount of capital in retrofitting AQC equipment to their unit. Additionally, if an inaccurate cost estimate were to be the basis of a regulatory determ ination, NMED would not be responsible for the cost overruns and additional incurred proj ect costs, these would fall on PNM. The cost items missing from the Cost Manual are de scribed in detail in Section 2.0 of this

document. If these cost items are added to th e estimate, the results are shown in Figure 6. The red boxes identify the missing cost item s. As can be seen, when the estimate developed using the Cost Manual is adjusted to reflect the true scope of work necessary for installing SCR, the Cost Manual estimate is very similar to B&V’s estimate. Since the methodologies in cost development for all the SJGS units are similar, the same conclusion on the accuracy and completeness of a cost estimate based on the Cost Manual will be applicable to the other SJGS units.16 Calculation of Capital Investment - OAQPS Method (Adjustment for Missing Scope)

Cost Parameter Variable Name Multiplier Equation Cost Amount Escallation to 2007 B&V Estimate Comments

Equipment Costs EC 18,331,000 See original est Installation Costs IC 20,806,000 See original est Total Direct Capital Costs from OAQPS A DCC 22,327,000 37,062,820 39,137,000

Additions for Missing Scope on Direct Installation Costs

Elevator J B&V Estimate Used 1,236,000 1,236,000 SCR Bypass K B&V Estimate Used 10,000,000 10,000,000 Nox Monitoring System L B&V Estimate Used 440,000 440,000 Electrical Upgrades M B&V Estimate Used 484,000 484,000 Instrumentation and Control System N B&V Estimate Used 291,000 291,000

Subtotal of Missing Direct Capital Cost CC J+K+L+M+N 12,451,000 12,451,000

Gross Receipt Tax GRT 0.062 0.062 * (EC + CC) 1,848,000 1,908,000 From CUECost Freight FR 0.05 0.05 * (EC + CC) 1,491,000 1,539,000 From CUECost

Installation Costs on Missing Scope IMS 1.135 1.135*(CC+GRT+FR) 17,922,000 18,044,000

Air Preheater Modifications Q B&V Estimate Used 8,685,000 8,685,000 Balanced Draft Conversion R B&V Estimate Used 17,122,000 17,122,000 Site Preparation S B&V Estimate Used 2,000,000 2,000,000 Buildings & Enclosures T B&V Estimate Used 500,000 500,000 Total Cost of Missing Scope MS CC+IMS+GRT+FR+Q+R+S+T 62,019,000 62,249,000

Total Direct Capital Costs with Adjustments DCC A DCC+MS 99,081,820 101,386,000

Indirect Installation Costs

General facilities 0.05 A 1,853,000 0 Engineering and home office fees 0.1 A 3,706,000 0 Engineering (B&V Calculation) 0.07 DCCA 0 7,097,000 CUECost method Process contingency 0.05 A 1,853,000 0 Total Indirect Installation Costs from OAQPS B 0.05A + 0.10A + 0.05 A 7,412,000 7,097,000

Project Contingency C 0.15 (A+CC+B) 8,539,000 0 Project Contingency (B&V Calculation) CBV 0.2 DCCA 0 20,277,000 CUECost method

Total Plant Costs D A+B+C 53,014,000 66,511,000

Allowance for Funds During Construction E =0 (for SCR - OAQPS) 0 0 Royalty Allowance F =0 (for SCR - OAQPS) 0 0 Preproduction Cost G 0.02 (D+E) 1,060,000 0 Inventory Capital H ICC 0 0 Initial Catalyst and Chemical I =0 (for SCR - OAQPS) 0 0 Total Capital Investment TCI D + E + F + G + H + I 54,074,000 66,511,000

Additions for Missing Scope on Indirect Costs

Owner's Costs OC 0.05 DCCA 4,954,000 5,069,000 Construction Management CM 0.10 DCCA 9,908,000 10,139,000 Construction Indirects CI B&V Estimate 25,498,000 25,498,000 Start-up and spare parts SU 0.03 DCCA 2,972,000 3,042,000 Performance Test PT B&V Estimate 200,000 200,000 Total Cost of Missing Indirect Costs Scope MICS OC+CM+CI+SU+PT 43,532,000 43,948,000

Subtotal of Indirect Costs IC B+C+E+F+G+H+MICS 60,543,000 71,322,000

Interest During Construction IDC 0.0741 See Note Below $17,742,000 $19,196,000 CUECost Allows Lost Generation During Outage GEN 5 weeks @ 0.06095 $/kWh 23,674,000 23,674,000

Total Capital Investment with Adjustments TCI A DCCA + IC+IDC+GEN 201,040,820 215,578,000

Figure 6 SJGS Unit 3 - Comparison of Cost Manual Estimate to B&V Estimate Including the Necessary Scope Missing from Cost Manual OAQPS Results and B&V Results are com p arable17 

### 4.0 Explanation of B&V Cost Development
NMED’s December 21, 2007 letter requests more information on the development of B&V’s cost esti mate. B&V used a scaled-factor estimate approach when developing the SCR cost estimate. A scaling factor is used in this type of high-level cost estimate by referencing equipment cost from a similar scope SCR project to that at SJGS. In this section, a detailed description on th e development of how each equipment cost

line item was calculated. In Appendix C, B&V has included many of the quotations that were used as references for the estimate. Normally, this is not something that B&V is able to do because the quotations are confidential. Ho wever, many of the quotations used to develop the SJGS cost estimate were firm bids taken from another project that was performed for a municipality (“reference SCR” ). As a result, the project had public bid openings and the proposals are considered public record. It should be noted that some of the identifying information has been redacted to make this information somewhat more difficult for our competitors (and our client’s competitors) to easily track. During the development of the SJGS-specific SCR cost based on this reference, the reference SCR project was still in the contract award stage. Several of the equipment cost line items were based on budgetary estimates for the refe rence SCR project. Since then, firm quote

have been obtained for the reference SCR project. While, the numerical value between the firm quotes and budgetary values used in the development of the SJGS SCR have changed slightly, it should be noted that the ma gnitude of costs are still very similar.

B&V’s estimate also uses the EPA CUECost program as a guide for some of the costs included in our estimate. B&V has noted in Figure 6 all areas where we use the CUECost method for calculating costs.18 As previously stated, the SCR cost es timate prepared for PNM SJGS Unit 3 was

based on firm bids from another recent SCR project (currently being built and scheduled to start operating in July 2008). Scaling factor s were used to correlate the reference cost

to an estimated value if SCR were to be installed at PNM SJGS Unit 3. The type of scaling factor utilized is de pendent on the equipment that is being evaluated. Type of scaling factors used includes:

• Unit size (MW).

• NOx removal rate (lb/mmBtu).

• Gas flow rate. The scaling factors are used in conjuncti on with a retrofit f actor, typically an exponential of 0.6. This retrofit factor acc ounts for the non-linear relationship between

costs and unit size. Lastly, for several equipment line items, a co mplexity factor was applied account for the retrofit complexity of PNM SJGS Unit 3. The retrofit complexity was applied on equipment cost line items where cost is very dependent on the retrof it efforts. Generally, if it is expected that it is more complex to retrofit in th e SCR components, greater costs should be allocated for it. Such cost categ ories for the SCR project are; SCR bypass and

structural steel. A summary of the calculation me thods and references used are described in the detail in the following subsections.194.1 Anhydrous Ammonia Injection SystemInputs:Escalation rate = 1.03 (1 year to 2007)Reference cost = $758,546 (see quotation in Appendix C)Reference unit size = 670 MWPNM unit size = 544 MWReference NOx removal = 0.34 lb/mmBtuPNM NOx removal = 0.30 lb/mmBtu – 0.07 lb/mmBtu = 0.23 lb/mmBtuCalculation:000,559$cos34.023.0670544546,758$03.1cos________cos__cos6.06.0=⎥⎦⎤⎢⎣⎡⎟⎠⎞⎜⎝⎛⎟⎠⎞⎜⎝⎛××=⎥⎦⎤⎢⎣⎡⎟⎟⎠⎞⎜⎜⎝⎛⎟⎟⎠⎞⎜⎜⎝⎛××=tPNMtPNMremovalNOxrefremovalNOxPNMsizeunitrefsizeunitPNMtreferencerateescalationtPNMNotes/Remarks:Reference cost was based on the total of the unit price breakdown asdetailed in Appendix C. Note that final contract award value was$2,945,000 for 2 units ($1,472,500 per unit) for all equipment scope(including common equipment)detailed in Section 4.1 and 4.2.204.2 Anhydrous Ammonia Vaporization SystemInputs:Escalation rate = 1.03 (1 year to 2007)Reference cost = $757,808 (see quotation in Appendix C)Reference unit size = 670 MWPNM unit size = 544 MWReference NOx removal = 0.34 lb/mmBtuPNM NOx removal = 0.30 lb/mmBtu – 0.07 lb/mmBtu = 0.23 lb/mmBtuCalculation:000,559$cos34.023.0670544808,757$03.1cos________cos__cos6.06.0=⎥⎦⎤⎢⎣⎡⎟⎠⎞⎜⎝⎛⎟⎠⎞⎜⎝⎛××=⎥⎦⎤⎢⎣⎡⎟⎟⎠⎞⎜⎜⎝⎛⎟⎟⎠⎞⎜⎜⎝⎛××=tPNMtPNMremovalNOxrefremovalNOxPNMsizeunitrefsizeunitPNMtreferencerateescalationtPNMNotes/Remarks:Reference cost was based on the total of the unit price breakdown asdetailed in Appendix C. Note that final contract award value was$2,945,000 for 2 units ($1,472,500 per unit) for all equipment scope(including common equipment)detailed in Section 4.1 and 4.2.21 4.3 Reactor Box, Breeching and Ductwork
Inputs: Escalation rate = 1.03 (1 year to 2007) Reference cost = $5,448,557 (see quotation in Appendix C) Reference gas flow rate = 3,081,500 acfm PNM gas flow rate = 3,082,200 acfm

Calculation:

000

, 613

, 5 $ cos 500

, 081

, 3 200

, 082

, 3 557

, 448

, 5 $ 03

. 1 cos _ _ _ _ _ _ cos

_ _ cos

6

. 0 6

. 0

= ⎟ ⎠ ⎞ ⎜ ⎝ ⎛

× × = ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

× × =

t PNM t PNM rate flow gas ref rate flow gas PNM t reference rate escalation t PNM

Notes/Remarks:

Reference cost was based on an estimated co st for another projec t. When the final contract was signed, the price was $9 ,754,446 for 2 units ($4,877,223 per unit).

4.4 Ductwork Expansion Joints
Inputs: Escalation rate = 1.03 (1 year to 2007) Reference cost = $360,000 (see quotation in Appendix C) Reference gas flow rate = 3,081,500 acfm PNM gas flow rate = 3,082,200 acfm

Calculation:

000

, 371 $ cos 500

, 081

, 3 200

, 082

, 3 000

, 360 $ 03

. 1 cos _ _ _ _ _ _ cos

_ _ cos

6

. 0 6

. 0

= ⎟ ⎠ ⎞ ⎜ ⎝ ⎛

× × = ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

× × =

t PNM t PNM rate flow gas ref rate flow gas PNM t reference rate escalation t PNM22 4.5 Catalyst
Inputs: PNM catalyst volume = 496 m 3
Catalyst unit price = $6,500 per m 3

Calculation:

000

, 225

, 3 $ cos 500

, 6 $ 496 cos _ _ _ _ cos

= × = × =

t PNM t PNM price unit catalyst vol catalyst PNM t PNM

4.6 Sonic Horns
Inputs: Escalation rate = 1.03 (1 year to 2007) Reference cost = $182,040 (see quotation in Appendix C)

Calculation:

000

, 188 $ cos 040

, 182 $ 03

. 1 cos cos

_ _ cos

= × = × =

t PNM t PNM t reference rate escalation t PNM

Notes/Remarks: Reference cost was based on a preliminary quota tion. The final contract award value was $275,022 for 2 units ($137,511 per unit).23 4.7 Elevator
Inputs: Escalation rate = 1.03 (1 year to 2007) Reference cost = $1,200,000 (see quotation in Appendix C)

Calculation:

000

, 236

, 1 $ cos 000

, 200

, 1 $ 03

. 1 cos cos

_ _ cos

= × = × =

t PNM t PNM t reference rate escalation t PNM

Notes/Remarks: Reference cost was based on a preliminar y quotation. Contract award price was $957,940.244.8 SCR BypassInputs:Escalation rate = 1.03 (1 year to 2007)Reference cost = $5,346,050 (see quotation in Appendix C)Reference gas flow rate = 3,081,500 acfmPNM gas flow rate = 3,082,200 acfmRetrofit complexity factor = 1.8Calculation:000,000,10$cos8.1500,081,3200,082,3050,346,5$03.1cos_______cos__cos6.06.0=×⎟⎠⎞⎜⎝⎛××=×⎟⎟⎠⎞⎜⎜⎝⎛××=tPNMtPNMfactorcomplexityrateflowgasrefrateflowgasPNMtreferencerateescalationtPNMNotes/Remarks:The complexity factor used here accountsfor the following items needed to completethe SCR bypass: sealair ductwork, damperaccess platforms, SCR bypass ductwork, SCR bypass support steel, and expansion joints.254.9 Structural SteelInputs:Escalation rate = 1.03 (1 year to 2007)Reference cost = $5,732,120 (see details in Appendix C)Reference unit size = 670 MWPNM unit size = 544 MWRetrofit complexity factor = 1.5Calculation:000,816,7$cos5.1670544120,732,5$03.1cos_____cos__cos6.06.0=×⎟⎠⎞⎜⎝⎛××=×⎟⎟⎠⎞⎜⎜⎝⎛××=tPNMtPNMfactorcomplexitysizeunitrefsizeunitPNMtreferencerateescalationtPNMNotes/Remarks:Reference cost was based on budgetary estimates of structural steel requirements and commodity prices for structural steel as detailedin Appendix C. The final contract award value was $14,074,040for 2 units ($7,037,020 per unit).The retrofit complexity factor used hereaccounts for the restrictions in the plant layout, the available laydown area, and thepotentialcrane size allowable at SJGS.26 4.10 NOx Monitoring System
Inputs: Escalation rate = 1.03 (1 year to 2007) Reference cost = $427,200 (see quotation in Appendix C)

Calculation:

000

, 440 $ cos 200

, 427 $ 03

. 1 cos cos

_ _ cos

= × = × =

t PNM t PNM t reference rate escalation t PNM

Notes/Remarks: Reference cost was based on a preliminary quotation. Final aw arded contract was $779,450. The final price also included samp ling fans at a price of $17,555 for 2 units.

4.11 Electrical System Upgrade
Inputs: Escalation rate = 1.03 (1 year to 2007) Reference cost = $532,550 (see quotation in Appendix C)

Reference unit size = 670 MW

PNM unit size = 544 MW

Calculation:

000

, 484 $ cos 670 544 550

, 532 $ 03

. 1 cos _ _ _

_ cos

_ _ cos

6

. 0 6

. 0

= ⎟ ⎠ ⎞ ⎜ ⎝ ⎛
× × = ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

× × =

t PNM t PNM size unit ref size unit PNM t reference rate escalation t PNM

Notes/Remarks: Reference cost was based on a preliminary quot ation. Final awarded contract cost was based on quotations for multiple scope items totaling to $1,431,788 for 2 units ($715,894 per unit) as detailed in Appendix C.27 4.12 Instrumentation and Control System
Inputs: Escalation rate = 1.03 (1 year to 2007) Reference cost = $288,000 (see quotation in Appendix C)

Reference unit size = 670 MW

PNM unit size = 544 MW

Calculation:

000

, 291 $ cos 670 544 000

, 288 $ 03

. 1 cos _ _ _

_ cos

_ _ cos

6

. 0 1

. 0

= ⎟ ⎠ ⎞ ⎜ ⎝ ⎛
× × = ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

× × =

t PNM t PNM size unit ref size unit PNM t reference rate escalation t PNM

Notes/Remarks: Reference cost was based on a preliminary quot ation. Final awarded contract cost was based on quotations for multiple scope items totaling to $1,008,761 for 2 units ($504,381 per unit) as detailed in Appendix C.28 4.13 Air Preheater Modifications For Units 3 or 4, enamel coated, air pr eheater basket replacement is recommended if an SCR or SNCR is installed. Air preheat er modifications for Un its 1 or 2 would also be required, but the scope of work will be different since the air preheater type is

different than that at Units 3 or 4. Materi al costs for air preheater modifications were obtained from a budgetary quotation solicited fr om an air preheater original equipment manufacturer (OEM) specifically for the PNM project. A comparison to a previous project for a confidential client was made to determine the installation price.

The total direct cost is the summation of the material and installation costs. There are one primary air preheater and tw o secondary preheaters in Unit 3.

2007 2007 400MW 544 MW Confidential PNM Units 3&4 ($ USD) ($USD) Reference

PRIMARY material per unit n/a $533,000 Vendor quote Installation per unit $707,000 $961,966

SECONDARY material per unit n/a $1,030,000 Vendor quote Installation per unit $1,886,000 $2,565,242

Total materials per unit $2,593,000 Total installation per unit $6,092,000 Total per unit $8,685,000 Notes: 1. Costs exclude contin gency and indirects.29 4.14 Balanced Draft Conversion

The attached table shows a breakdown of the cost estimate for a balanced draft conversion of the PNM SJGS Unit 3 system, requi red if an SCR were installed. The cost estimate was developed based on reference to the project cost of other reference units where B&V performed a balanced draft convers ion. A scaling and retrofit factor was used to determine the engineering & mate rial and construction labor costs. The total direct cost is the summation of the engineering and material, and

construction labor costs.

Reference Unit PNM Unit 3 or 4

Balanced Draft Conversion Engineering & Material Construction Labor Costs Engineering & Material Construction Labor Costs Boiler

Stiffening $1,800,000 $2,545,000 $1,537,000 $1,908,000 Scaffolding - - $350,000 - - $262,000 Insulation & Lagging $250,000 $1,250,000 $188,000 $1,438,000 Ductwork & Casing Repairs (Allowa nce) $545,000 $3,025,000 $182,000 $1,009,000

Air Heater Stiffening $150,000 $350,000 $125,000 $263,000

Electrostatic Precipitator

Stiffening (Excludes casing repai rs) $512,000 $2,000,000 $416,000 $1,500,000 Insulation & Lagging (Allowance) $150,000 $750,000 $113,000 $563,000

Electrical/Control Modifications $285,000 $600,000 $214,000 $450,000 New transformer (subcontract) $1,000,000

Fan Modifications

FD Fans (new motors only) $440,000 $154,000 $660,000 $116,000 ID Fans $5,410,000 $1,577,000 $3,600,000 $1,260,000

Miscellaneous Mech Commodities and Inst $325,000 - - $325,000 - -

Subtotal $8,357,000 $8,765,000 Notes: 1. Costs exclude contin gency and indirects.30 4.15 Construction Indirects

The construction indirects line item was de veloped based on the total labor costs

for the installation of the SCR equipment. In pre-2004, B&V’s estimating department

found that the total amount of construction indirect cost s typically ranged from 50 percent to 60 percent of the total installation labor costs. However, due to the tightening in labor market that has developed since 2005, construction indirect costs have risen to a range of 90 percent to 120 per cent. For the cost estimate of an SCR at PNM SJGS Unit 3, it was determined by B&V’s estimating departme nt that a construction indirect rate of 100 percent of total installation labor cost best represented the labor market situation.

The table below shows B&V’s calcula tion of construction indirects.

Direct Installation Cost Splits

Scope of installation Direct installation costs Material Labor Material Labor Foundation & supports $10, 268,000 70% 30% $7,187,600 $3,080,400 Handling & erection $13,690,000 0% 100% $0 $13,690,000 Electrical $5,134,000 40% 60% $2,053,600 $3,080,400 Piping $856,000 40% 60% $342,400 $513,600 Insulation $3,423,000 $0 $0 Painting $342,000 $0 $0 Demolition $3,423,000 0% 100% $0 $3,423,000 Relocation $1,711,000 0% 100% $0 $1,711,000 Total $38,847,000 $25,498,400

Construction Indirects = Dire ct Installation Labor X 100% = $25,498,40031 

### 5.0 Conclusions
This document shows that simply using the OAQPS Cost Manual to develop an estimate for SCR equipment does not result in an accurate estimate of th e cost of the SCR.
First, the costs in the manua l are in 1998 dollars and must be escalated to 2007 dollars. In addition, there were very few SCR’s inst alled in the United States in 1998 and very little industry experience regarding all of the work required to install an SCR system. As
a result, the Cost Manual does not include cost items in its scope that are required to install an SCR system. For these reasons, B&V developed a cost estimate based on the experience from previous SCR projects that have been implemented by B&V. Quotations from vendors were used for the cost estimates, where possible, and with B&V’s internal estimating me thods in other cases. It should be noted that B&V’s estimate is in line with industry information and represents current costs of SCR systems. Consider Reference 2, the paper written by Mr.

Cichanowicz and discussed in Section 1.0 of th is document. It indicates that the current
cost of SCR is between $180 / kW and $300 / kW, where kW references the size of the unit. Most units do not require a balance draft conversion but SJGS would require a

balanced draft conversion for each unit. Fo r comparison purposes, if the balance draft

conversion cost were to be removed from th e cost estimate of the SCRs for SJGS, the cost of the SCR for Unit 3 would be $164,309, 000. This is equivalent to $243 / kW. This is exactly in the range of costs for S CRs that are currently being built. It shows again that B&V’s costs are repr esentative of the industry at this time. It also further proves that the Cost Manual is not an accura te representation of the costs for an SCR project, without appropriate escalation and adjustments for additional equipment and cost
items. As stated before, selection of BART for a unit MUST be based on an evaluation of the real costs for a project, not on the inaccurately low cost estimate developed from

the Cost Manual.

### Appendix A
References for Cost IndicesFind ResearchAbout CERAProducts / ServicesCERAWeekEventsNewsContactsCLIENT SERVICESWelcome toCERA.comClients:LoginSearch CERA.comNews HomeVideo InterviewsResearch HighlightsPress CoverageRecent ArticlesPress ReleasesCost Drivers Predicted to ContinueRead the IHS/Cambridge Energy Research Associates (CERA) Upstream Capital Costs Index (UCCI) press release.Refinery and Petrochemical Plant Construction Costs Reach New High; IHS/CERADownstream Capital Costs Index Up 8% inLast 6 months to Record 166 PointsNOVEMBER 7, 2007Print This PageRelated Topics:Downstream,Global,OilPress ReleaseHOUSTON (November 7, 2007)-- The costs of building new oil refineries and petrochemical plants are rapidly rising and reached a newhigh in the third quarter period ending in October, according tothe first release of the new IHS/Cambridge Energy Research Associates(CERA) Downstream Capital Costs Index (DCCI). These costs are beginning to act as drags, leading to delays and postponements in thebuilding of new refineries and petrochemical plants required to keep up with growing world demand.The new DCCI complements the IHS/CERA Upstream Capital Costs Index (UCCI), which measures the costof construction of new oil andgas production projects such as platforms and pipelines. Bothindices demonstrate the dramaticimpact rapidly rising costs are having onthe energy industry.The DCCI registered a high of 166 points in October, indicatingan eight percent increase in thelast six months in the costs associated withPage 1 of 42/14/2008file://C:\DOCUME~1\fis13413\LOCALS~1\Temp\7LK6OR35.htmconstructing new refinery or petrochemical plants. The DCCI is aproprietary measure of project cost inflation similar in concept to theConsumer Price Index (CPI) It provides a benchmark for comparing costs around the world and draws upon proprietary IHS and CERAdata bases and analytic tools.All values are indexed to the year 2000. Thus, a piece of equipment that cost $100 in 2000 would cost $166 today (see chart).Downstream facilities are required to turn raw oil and gas intouseful end products such as gasoline, heating oil, plastics andfertilizer. Asthe cost of constructionrises, firms may become reluctant to invest in new plants, or delay and postpone these projects thus,in turn,constraining the growth of capacity.The DCCI has been on an upward trend since 2003 with annual increases in the last three years of seven, 17 and 14 percent, respectively.“The latest increases have been driven by continued high activity levels globally, continued tightness in the equipment and engineeringmarkets, as well as historically high levels for raw materials” saidJackie Forrest, lead researcher for the Capital Costs Analysis Forum forDownstream, an on-going research project of CERA.Page 2 of 42/14/2008file://C:\DOCUME~1\fis13413\LOCALS~1\Temp\7LK6OR35.htm“On a global basis, the refining and petrochemical sector iscurrently facing heavy strains with new builds in the Middle Eastand Asia,expansions in the United States and heavy oil projects in Alberta all occurring simultaneously,” Forrest continued.“We expect global refining capacity to expand 1.7 percent per yearfor the next five years, adjusted for expected delays and cancellations,”she added. “This is 20-30 percent more expansion activity per year than we have recorded in the recent past. This may not sound likemuch, but 1.7 percent growth in refining capacity equals about 1.5 million barrels per day and that is significant as these arecomplicatedfacilities to construct.“As a result of all of this activity, lead times for engineeredequipment has increased up to 50 percent in the last 6-12 months for someitems, and as expected, prices have increased,” Forrest added.“Further compounding the problem is the raw materials and shippingsituation. Both of these sectors have experienced recent increases, ultimatelypassing through costs to projects.”Looking forward, Forrest said: “Unless there is a sudden and dramatic change in the industry, activity and market pressures should keepthe DCCI at these levels, if not higher, for the next 12-18 months. After that period, there may be a re-balancing of the industry with eitherfewer active projects or a greater amount of delivery capacity available, or both.”# # # #About the IHS/CERA DownstreamCapital Costs Index (DCCI)The IHS/CERA DCCI tracks the costs of equipment, facilities, materials,and personnel(both skilled and unskilled) used in theconstructionof a geographically diversified portfolio of more than thirty refining and petrochemical construction projects. It is similar to the consumerprice index (CPI) in that it provides a clear, transparent benchmark tool for tracking and forecasting a complex and dynamic environment.The DCCI can be tracked on the IHS Index Web Site:www.ihsindexes.com. The DCCI is a work product of CERA’s Capital CostsAnalysis Forum for Downstream (CCAF-D). For information on the Capital Costs Analysis Forum for Downstream, contact Jackie Forrest atjforrest@cera.comor Richard Ward at rward@cera.comAbout CERA (www.cera.com)Cambridge Energy Research Associates (CERA), an IHS company, isa leading advisor to energy companies, consumers, financialinstitutions, technology providers, and governments. CERA (www.cera.com) delivers strategic knowledge and independent analysisonenergy markets, geopolitics, industry trends, and strategy. CERAis based in Cambridge, MA, and has offices in Bangkok, Beijing, Calgary,Dubai, Johannesburg, Mexico City, Moscow, Mumbai, Oslo, Paris, Rio de Janeiro, San Francisco, Tokyo and Washington, DC.About IHS (www.ihs.com)Page 3 of 42/14/2008file://C:\DOCUME~1\fis13413\LOCALS~1\Temp\7LK6OR35.htmIHS (NYSE: IHS) is one of theleading globalproviders of criticaltechnical information,decision-support tools and strategic services to customers in a number of industries including energy, defense, aerospace, construction,electronics, and automotive through two operating segments, Engineering and Energy. IHS serves customers ranging from governmentsand large multinational corporations to smaller companies and technical professionals in more than100 countries. IHS employs more than2,300 people around the world.© 2007, IHS is a registered trademark of IHS Inc. CERA isa registered trademark of Cambridge Energy ResearchAssociates, Inc. All other company and product names maybe trademarks of their respective owners. Copyright ©2007 IHS Inc. All rights reserved.About CERACareers @ CERAExpertiseContacts and LocationsRelated WebsitesNewsExpert InterviewsResearch HighlightsPress CoverageRecent ArticlesPress ReleasesHelpKey FeaturesFrequently Asked QuestionsSite MapPolicy© CERA 2008Privacy & IntegrityTerms of ServiceWeb Site PrivacyTerms of UseIHS© 2008 CERA.All Rights Reserved.Page 4 of 42/14/2008file://C:\DOCUME~1\fis13413\LOCALS~1\Temp\7LK6OR35.htm

### CURRENT CAPITAL COST AND COST-EFFECTIVENESS OF POWER PLANT EMISSION S CONTROL TECHNOLOGIES

Prepared by J. Edward Cichanowicz

Prepared for Utility Air Regulatory Group

June, 2007CURRENT CAPITAL COST AND COST-EFFECTIVENESS OF POWER PLANT EMISSION CONTROL TECHNOLOGIES



### Section/Title Page No.

SECTION 1 SUMMARY.............................................................................................................. ........... 1 SECTION 2 INTRODUCTION ......................................................................................................... ...... 3 SECTION 3 BACKGROUND ........................................................................................................... ...... 4 3.1 INTRODUCTION ............................................................................................................... ..... 4 3.2 RETROFIT OF CONTROL TECHNOLOGY......................................................................... 4 3.3 NEW GENERATING STATIONS .......................................................................................... 5 SECTION 4 MATERIAL AND LABOR ESCALATION ...................................................................... 9 4.1 BASIC MATERIALS............................................................................................................ ... 9 4.2 LABOR...................................................................................................................... ............. 13 4.2.1 Labor Cost Escalation.................................................................................................... . 13 4.2.2 Labor Pool Availability .................................................................................................. 14 4.3 FGD COST ESCALATION................................................................................................... 15 SECTION 5 FACTORS AFFECTING CAPITAL COST ESTIMATES .............................................. 17 5.1 CAPITAL COST ESTIMATING METHODOLOGY........................................................... 17 5.2 SITE AND DESIGN FACTORS............................................................................................ 19 SECTION 6 FLUE GAS DESULFURIZATION COSTS ..................................................................... 21 6.1 FGD CAPITAL COST ........................................................................................................... 21 6.1.1 Anonymous................................................................................................................ ..... 21 6.1.2 Publicly Released Studies............................................................................................... 2 2 6.2 OPERATING COST ............................................................................................................. . 24 SECTION 7 SCR NOx COST......................................................................................................... ....... 27 7.1 SCR CAPITAL COST........................................................................................................... . 27 7.2 THREE SURVEYS .............................................................................................................. .. 27 7.3 COST ESCALATION............................................................................................................ 28 7.4 OPERATING COST ............................................................................................................. . 29 7.4.1 SCR Catalyst............................................................................................................. ...... 29 7.4.2 Reagent .................................................................................................................. ......... 30 7.4.3 Example Operating Cost................................................................................................. 31 SECTION 8 IMPLICATIONS FOR Hg CONTROL............................................................................. 33 SECTION 9 CONCLUSIONS .......................................................................................................... ..... 35 SECTION 10 REFERENCES .......................................................................................................... ...... 37 SECTION 11 FGD COST REFERENCES ............................................................................................ 39Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

1 

### SECTION 1

SUMMARY

The utility industry faces numerous mandates to retrofit air emi ssion controls to existing power plants. Specifically, the Clean Air Interstate Ru le (CAIR), Clean Air Visibility Rule (CAVR), settlements with the Department of Justice over alleged NSR violati ons, and the Clean Air Mercury Rule (CAMR) all requi re retrofit of control technol ogy. Many of these rules and consent decrees requir e equipment installation and operati on on or before 2010, with mandates for more equipment retrofits shortly thereafter. The schedule for this sign ificant emission control retrofit program is coincident with the anticipated construction of approximately 80 GW of new power plants according to some estimates (Figueroa, 2006).

This demand for emission control equipmen t has strained domestic supply chains. Internationally, robust demand fo r materials and labor for petr ochemical industries, urban infrastructure, and power generati on in developing countries consum es much of the international supply. As a consequence, capital cost has escal ated for flue gas desulfurization (FGD) and selective catalytic reduction (S CR) equipment, and material/labor shortages force construction delays. Some owners of small generating uni ts simply cannot access control equipment as suppliers are overbooked – some requests-for-pr oposals for FGD receive no bids, or limited bids at a premium price. These issues complicate, if not prevent, complying with the regulations within the timeframe specified by the regulatory actions.

For example, in the case of wet FGD, prices fo r components such as elect rical transformers, flue gas stacks, and specialty stee l pipe have increased 40% and 50% between 2003 and 2007. The price of field fabricated stee l tanks, slurry pumps, reagent pulverizers, reagent conveyors, and flue gas booster fans has escalated 15-23% over the same period. The lead time from order to delivery for components such as ball mills for reagent preparation, rubber-lined recycle pumps, fans, and spray headers has more than doubled in many cases.

Consequently, FGD capital cost has escalated at a rate equivalent to 7-9% annually since 2003. The example of Allegheny Energy is instructive – firm bids recei ved in 2006 for wet FGD for Ft. Martin Units 1-2 and Hatfield Ferry Units 3-4 exceeded cost estimates developed in 2004 by an average of $100/kW. This is not an isolated event, and the cons equences are significant. For a coal with sulfur content of 6 lbs/SO 2 /MBtu, an increase in capital cost of $100/kW can translate into higher SO 2 removal cost effectiveness of seve ral hundred dollars per ton. The same escalation in FGD capital cost for a PRB coal with typical sulfur content of 0.9 lbs SO 2 /MBtu will increase SO 2 removal cost effectiveness by $800/ton.

Regarding schedule, under the best conditions a wet FGD retrofit can be completed within 36 months, but only if none of the key suppliers are overbooked for the project duration. This isCapital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

2 typically not the case – some constructors and er ectors of specialty items are booked for the next 4 years 1 . It should be noted that in 2002 EPA project ed that FGD installations for CAIR would require a 28 month schedule from inception to startup (EPA, 2002).

The cost for SCR NOx control has similarly escala ted. The most recent reports show SCR capital cost averages $200/kW because the remaining site s to be retrofit present significant challenges. Catalyst unit price has dropped fivefold since the earliest commercial applications, but the increasingly complex sites and escalation in material cost have offset any cost benefits. The cost of ammonia-based reagent, of which 80-90% is determined by the price of natural gas, now averages $400/ton. Reagent cost is now the largest SCR operating cost component.

For a typical 500 MW unit firing an eastern bitu minous coal and producing NOx at a rate of 0.38 lbs/MBtu, a $100/kW increase in SCR capital cost will elevate NOx removal cost effectiveness by $800/ton (annual operation). For a 500 MW unit firing PRB and producing NO x at a rate of 0.20 lbs/MBtu, a capital cost increa se of $100/kW will increase NOx reduction cost effectiveness by almost $2,000/ton.

Hg control plans may also be impacted by the supply and demand imbalance. EPA estimates a total of 1,900 MW of fabric filter (FF) capacity will be installed for use with mercury-specific sorbent, such as activated carbon injecti on (ACI) to meet CAMR by 2010 (EPA, 2006). The basis of EPA’s estimate is not revealed, and it is not possible to judge how realistic this prediction is. Based on the emissions control rule proposed by the st ate of Georgia, it is likely the actual installed inventory of FF re trofit will be greater than pr edicted by EPA’s analysis, which did not consider state-specific Hg regulations. Finally, EPA assumptions of co-benefits of Hg removal by SCR and FGD may be optimistic, especi ally for those applic ations involving low rank coals. These short-falls in Hg removal woul d then have to be compensated for by greater control by ACI with FF.

In summary, the converging mandates for control of SO 2 , NOx, and possibly Hg, combined with proposed new coal-fired generati on, will significantly stretch control technology supply chains. The result will be severe price escalation and threats to timely project completion.

1 According to some observers, there are three erectors of stacks in the world with qualified experience to provide a satisfactory design; all are reportedly booked through 2011.Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

3 

### SECTION 2

INTRODUCTION

The cost for capital equipment for the power indust ry is rapidly escalating. In the U.S., several environmental mandates for control of flue gas emissions that stem from the 1990 Clean Air Act Amendments (CAAA) are converging w ithin the time span of only a fe w years. In addition, the need for new, predominantly coal-fired power statio ns not only in the U.S. but around the world has increased the demand for material and labor. Internationally, the gene ral robust world-wide demand for chemical processing facilities, tr ansportation, and urban infrastructur e further absorb material and specialized construction labor. As a consequence, the capital cost for almost all power industry equipment has increased, and delivery times extended.

On the supply side, the dearth of construction in the mid 1990s for equi pment and services of this type prompted suppliers and specialized construction labor to migrate to ot her industries. Consequently, the supply field is limited, particularly for specialty items required in general chemical and industrial applications, such as rubber-lined slurry pumps, pulverization and reagent grinding equipment, and flue gas emission stacks.

The combination of higher equipment costs and schedule delays challenge s utilities implementing plans to meet emission caps or othe r emission reduction requirements for SO 2 , NOx, and Hg. Some operators may not be able to meet their co mpliance mandates on schedule without purchase of emissions allowances, or will incur escalated compliance costs.

This paper summarizes the cost trends observed in recent years for flue gas controls for both SO 2 and NOx, and the prospects for Hg controls. Sect ion 3 provides relevant background information, addressing the projected capacity to be retrofit of environmental co ntrols, and projected capacity of new coal-fired plants. Section 4 summarizes the key i ssues important to escala tion of both material and labor. Section 5 highlights the factor s affecting capital cost of both flue gas desu lfurization (FGD) and selective catalytic reduction (SCR) NOx control process equipment. Section 6 overviews recent reports of incurred and projected FGD cost, and Section 7 addresses the same for SCR NOx control. The implications of this building environment on Hg control are presented in Section 8, and a summary presented in Section 9.Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

4 

### SECTION 3

BACKGROUND

3.1 INTRODUCTION Numerous regulatory programs prompt the installa tion of environmental control equipment for the U.S. power industry. In addition to the retrofit of existing units, the large number of new units proposed impacts the availability of equipment, resources and constr uction labor. This section reviews these driving forces.

3.2 RETROFIT OF CONTROL TECHNOLOGY Retrofit of control technology to existing plants is mandated by seve ral actions subsequent to the 1990 Clean Air Act Amendment: the Clean Air Interstate Ru le (CAIR), and regional ha ze initiatives such as the Clean Air Visibility Rule (CAV R). Further, settlements with EPA and the Department of Justice (DOJ) over alleged new source review (NSR ) violations may affect plans for SO 2 and NOx reduction. Each of these is addr essed in the following.

Clean Air Interstate Rule (CAIR). This two-phase program mandates reducing NOx and SO 2 in an initial Phase 1 (2009 for NOx and 2010 for SO 2 ), and a subsequent Phase 2 (2015 for both SO 2 and NOx). The CAIR program is the key driving force behind FGD and SCR deployment.

Best Available Retrof it Technology (BART). BART requirements are part of the Clean Air Visibility Rule (CAVR). These federal regulati ons require all states to revise their State Implementation Plans (SIPs) to address visibili ty impairment in Mandatory Class I Fe deral Areas, which are specific national parks and wilderness areas across the country. One of the provisions of the fe deral regulations is the application of BART to certain existing major stati onary sources that were put into service between 1962 and 1977. The rule requires thes e facilities to conduct BART analysis (a very extensive undertaking) on each affected unit to determine the control technology and the level of emission controls representing BART. Consequently, even in the case of facilities that are not required to install additional emission controls to m eet BART requirements, states ma y require retrofit of emissions controls to implement the CAVR directive that stat es develop plans to achie ve “reasonable progress” toward eliminating manmade impairment of vi sibility in Mandatory Class I Federal Areas.

For example, the states of Illinois, Indiana, Michigan, and Wisconsin, through the Lake Michigan Air Directors Consortium (LADCO), are consider ing additional control measures for SO 2 and NOx beyond CAIR. Regulatory agencies in othe r regions in the country such as the southeast (VISTAS) and far west (WRAP) are considering similar mandates. The extent and timing of thes e mandates is uncertain, but most proposed initiatives will require control equipment by the 2014 to 2018 time period.Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

5 Settlements Regarding Alleged NSR Violations . Allegations by the U.S. EPA that provisions of the CAAA regarding New Source Review (NSR) were viol ated prompted several owners to alter FGD and SCR schedules from that required to meet CAIR.

Retrofit of FGD and SCR to a significant population of coal-fired stations is re quired to meet these existing and proposed mandates. Figures 3-1 to 3-6 de pict the inventory of we t and dry FGD, and SCR process equipment that has been announced to m eet the CAIR and other mandates. Figure 3-1 shows the annual addition as generati ng capacity (MW) of both wet and dry FGD, and Figure 3-2 the cumulative totals, both through 2010. Figures 3-3 and Figure 3-4 show the incremental and cumulative generating capacity retrofit with SCR over the same time period.

Of significance to CAMR compliance is the “co-benef it” of Hg control where oxidized Hg is removed as a consequence of SCR and wet FGD. Figures 3-5 and 3-6 show the annual and cumulative generating capacity predicted to be equipped with both SCR and wet FGD, designated by the first year of operation with both contro l systems. Figures 3-5 and 3-6 provide an estimate of generating units that can conceivably exploit NOx and SO 2 controls for mercury removal.

3.3 NEW GENERATING STATIONS The number of new coal-fired units planned fo r operation between 2009 and 2020 is unprecedented, and will further stretch resources for construction of new FGD and SCR process equipment. Approximately 80 GW of new coal-fired generati ng capacity has been proposed (Figueroa, 2006). Although it is not clear how many of these units will actually be built , even one-half of the proposed capacity will exert considerable strain on suppliers, resources and construction labor.

There is already evidence that the significant numbe r of retrofit emission cont rol technologies and new plants is straining resources. This evidence can be s een by the escalation in pri ces of basic materials, and delays in schedule to procure these basic materials. The price escalation and schedule delays are addressed in the next section.Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

6 0 5,000 10,000 15,000 20,000 25,000

Through 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Year OperationalCapacity (MW)

Figure 3-1. Historical and Proj ected Wet, Dry FGD Capacity: Installed MW per Year

0 10,000 20,000 30,000 40,000 50,000 60,000 70,000

Through 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Year OperationalCapacity (MW)

Figure 3-2. Historical and Proj ected Wet, Dry FGD Capacity: Cumulative MW per YearCapital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

7 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000

T h

roug h

20

01 20 02 2003 2004 2005 20 06 2007 2008 2009 20 10 2011 2012Annual SCR Capacity Installed (MW)

Figure 3-3. Historical and Projected SCR Ca pacity: Annual Installed Capacity (MW)

0 20,000 40,000 60,000 80,000 100,000 120,000 140,000

1 995 199 8 1 999 200 0 200 1 2002 200 3 2004 2005 2006 2007 2008 2009 2010 2012

First Year of OperationInstalled Retrofit SCR Capacity (MW)

Figure 3-4. Historical and Projected SCR Capaci ty: Cumulative Installed SCR Capacity (MW)Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

8 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 20,000

Through 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
Year OperationalCapacity (MW)

Figure 3-5. Historical and Proj ected Capacity: FGD and SCR, Annual Installed Capacity (MW)

0 10,000 20,000 30,000 40,000 50,000 60,000 70,000

Through 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Year OperationalCapacity (MW)

Figure 3-6. Historical and Projected Capacity: FGD and SCR Cumulative Installed Capacity (MW)Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

9 

### SECTION 4

MATERIAL AND LABOR ESCALATION

This section addresses the cost escal ation of material and labor, and the impact of installed equipment cost and construction schedule.

4.1 BASIC MATERIALS Among the basic materials required for both installation of retrof it of control technology and new generating equipment are structural steel, ready-mix concrete, copper wire and cable, and fabricated steel plate. These materials are broadly available in the U.S. and throughout the world, but are experiencing strong demand due to world-wide needs for process industries and infrastructure.

Figures 4-1 to 4-4 present price es calation data for these materials over the last five years, from December 2002 and into early 2007, as reported to the U.S. Bureau of Economic Analysis 2 . For three categories of these materials, prices have in creased by 40% over the December 2002 value. The exception is for Copper Cable and Wiring for which price has increased by a factor of three.

Prices for special alloys used in wet FGD reactio n vessels, and high pressure , high temperature boiler components have also escalated. Both nickel and molybdenum, key to production of corrosionresistant and high strength material s, have witnessed increased dema nd and price. Figures 4-5 and 4-6 present price trends for molybdenum and nickel, showing prices have escalated by factors of 3 to 5, respectively. Although the mass cont ent of these components in finished steel product is small, escalations of these magnitudes will have a material affect final product cost.

The impact of this escalation on the cost of components for wet a nd dry FGD and SCR is shown in Table 4-1, as witnessed from 2004 to early 2007. A lthough all of these factor s are important, perhaps most significant is stack cost – driven by both material demand and the limited supply of qualified erectors. The limited number of stac k erectors world-wide, coupled w ith the demand for new stacks for both retrofit of wet FGD and new generating units, has significantly elevated costs.

The limited supply of materials not only elevates co st but can delay construc tion schedule. Table 4-2 reports the increase in component lead time, as m easured in terms of weeks from order to delivery time. The lead time for several of these component s has more than doubled, based on comparing data for December 2006 and September 2003.

These basic materials, once procured, may incur a furt her delay to be installe d. A world-wide shortage of cranes has added to the schedule delay and cost escalation (Brat, 2007).

2 See U.S. Bureau of Economic Analysis, “Price Indices for Gross Domestic Product by Major Type of Product”, revised April 27, 2007, downloaded May 25, 2007, http://www.bea.gov/national/nipaw eb/SelectTable.asp?Selected=YCapital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

10 Figure 4-1. Structural Steel Cost Escalation

Figure 4-2. Ready-Mix Concrete Cost Escalation Cost Index for Ready-Mix Concrete Producer Price Index (Source: Bureau of Labor Statistics) (Curve from Jan 1996 to Jan 2003 Not Shown)

100.0 120.0 140.0 160.0 180.0 200.0 220.0

May-02 Dec-02 Jun-03 Jan-04 Aug-04 Feb-05 Sep-05 Mar-06 Oct-06 Apr-07
Month-YearReady Mix Concrete (1/1982 = 100)

Compound Esc. from 2003 to 2007 = 7.6%

Compound Esc. from 1996 to 2003 = 2.0% Cost Index for Structural Steel Producer Price Index (Source: Bureau of Labor Statistics) (Curve from Jan 1996 to Jan 2003 Not Shown)

100.0 120.0 140.0 160.0 180.0 200.0 220.0

May-02 Dec-02 Jun-03 Jan-04 Aug-04 Feb-05 Sep-05 Mar-06 Oct-06 Apr-07
Month-YearStructural Steel (Jan 1982 = 100)

Compound Esc. from 2003 to 2007 = 7.7%

Compound Esc. from 1996 to 2003 = 1.0%Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

11 Figure 4-3. Fabricated Steel Plate Cost Escalation

Figure 4-4. Copper Wire and Cable Cost Escalation Cost Index for Fabricated Steel Plates Producer Price Index (Source: Bureau of Labor Statistics) (Curve from Jan 1996 to Jan 2003 Not Shown)

100.0 120.0 140.0 160.0 180.0 200.0 220.0

May-02 Dec-02 Jun-03 Jan-04 Aug-04 Feb-05 Sep-05 Mar-06 Oct-06 Apr-07
Month-YearSteel Plates (Jun 1982 = 100) Compound Esc. from 2003 to 2007 = 9.4%

Compound Esc. from 1996 to 2003 = -0.3%

Cost Index for Copper Wire & Cable Producer Price Index (Source: Bureau of Labor Statistics) (Curve from Jan 1996 to Jan 2003 Not Shown)

100.0 150.0 200.0 250.0 300.0 350.0 400.0

May-02 Dec-02 Jun-03 Jan-04 Aug-04 Feb-05 Sep-05 Mar-06 Oct-06 Apr-07
Month-YearCopper Wire & Cable (Dec 1986 = 100)
Compound Esc. from 2003 to 2007 = 26.2%

Compound Esc. from 1996 to 2003 = -2.2%Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

12 Figure 4-5. Molybdenum Price Escalation

Figure 4-6. Nickel Price EscalationCapital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

13 Table 4-1. Escalation of Key Wet FGD Components: 2004 – 2007

FGD Component Price Increase, % Transformers 50+ Stack 50 Steel Pipe 40+ Field Fabricated Steel Tanks 23 Pumps 18 Pulverizers 18 Conveyors 17 Fans 16

Table 4-2. Increase in Component Lead Ti me, Weeks (December 2006 vs. September 2003)

Total Lead Time, Weeks Equipment Sept ‘03 Oct ‘05 Aug ‘06 Dec ‘06 Ball Mills 32 65 68 70 Rubber-lined Recycle Pumps 26 52 92 112 Booster Fans - 54 54 60 Oxidation Air Compressors 32 44 44 52 Internal Recycle Spray Headers 28 40 40 48 Source: Katzberger, 2007

4.2 LABOR The present cost trends and potential for shortages for qualified field la bor are discussed in this section.



### 4.2.1 Labor Cost Escalation Labor cost escalation experienced by the industry is shown in Tabl e 4-3. This data, developed by an architect/engineering firm involved in the construc tion of several new Midwestern plants, shows the annual labor escalation to be between 5.2 and 7.4% per year, averaging 6.2%.

Labor and equipment required for inst alling a control technol ogy constitutes about ha lf the total cost – with the remaining costs being due to process equipment acquisition and design. Not all installation cost is devoted to labor – cranes and other heavy equipment are requ ired – but the labor component is significant. Inevitably, escalating labor cost will tr anslate into higher inst alled emission control equipment cost.Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

14 Table 4-3. Recent Cost Escalation: Labor Rates ($ /hr) for Midwestern Coal Plant Construction

CRAFT 2005 2006 2007 Annual Escalation Rate, % Operators 28.06 29.56 31.06 5.3 Laborers 19.50 20.70 21.90 6.1 Millwright 30.00 31.85 33.70 6.2 Ironworker 25.10 26.95 28.80 7.4 Carpenter 25.65 27.50 29.35 7.2 Pipefitter 32.73 34.83 36.93 6.4 Electricians 30.73 32.58 34.43 6.0 Boilermaker 27.80 28.60 30.10 5.2 Total 6.2 Source: Black & Veatch, 2006



### 4.2.2 Labor Pool Availability The specialized labor pool required for SCR and F GD retrofit is subject to high demand and may limit equipment installation. Table 4-3 defined the ski lled labor categories required for power plant construction. As noted in Table 4- 3, labor rates for all categories are subject to cost pressure. Perhaps the most critical craft is “boilermakers” – the highly skilled me talworkers needed to fabricate the high pressure, high temperature steam tubes and supply casings. This labor pool is restricted due to a lengthy apprenticeship that is necessa ry to assure quality fabrication.

The limited boilermaker labor pool c ould restrict the installation of SCR and FGD process equipment. UARG comments submitted in 2003 a ddressing CAIR described how th e installation of SCR and FGD could be limited by boilermaker availability (U ARG, 2003); an updated version of these comments considering the revised SCR and FGD installation schedules and new pl ant construction is presented in the following section.

Supply . The International Brotherhood of Boilermak ers (IBB) reported boilermaker membership as approximately 24,000 members in 2003, with a targeted 5.3% growth rate. The IBB did attain this growth rate, as membership in early 2007 is reported to be 32,000. Assuming a continued 5% increase in membership, the boilermaker pool will expand to approximately 36,000 members by 2010, 40,000 members by 2012, and about 46,000 members by 2015. Additional resources of 6,600 members in Canada are reported in early 2007.

Labor Requirements for SCR, FGD . The labor required by approxi mately 2010 to install SCR and FGD equipment can be estimated, using knowledge of the (a) number of manhours of labor required to construct FGD and SCR, (b) generating capacity of FGD and SCR retrofitted, and (c) the sequence of labor charges over the project duration.

Wet FGD installation for a 500 MW unit re quires from 600,000 to 900,000 manhours of labor, depending on the design and site -specific conditions. The averag e value of 750,000 manhours equates to 1,500 manhours per MW of generating capacity. Fo r SCR, an average of 500,000 hours is requiredCapital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

15 for a 500 MW unit, which equates to 1,000 man-hour s per MW of capacity. These assumptions are based on discussions with F GD and SCR process suppliers.

Installing FGD and SCR i ndividually at a given site is assu med to require 36 and 28 months, respectively. The demand for boilermaker manhours re quired over the project du ration is presented in Table 4-4, based on discussions with suppliers. Us ing the preceding information, and EPA’s estimate that a typical boilermaker will work 1685 hour s per year (EPA, 2003), the total number of boilermakers can be determined.

Table 4-4. Distribution of Bo ilermaker Labor Requirements: Hypothetical Retrofits at a 500-MW Unit

Technology Q1 Q2 Q3 Q4 Q5 Q6 Q7 Q8 Q9 FGD 0 0 0 0 10 27 34 23 6 SCR 0 0 0 20 25 40 15 n/a n/a

Labor Required for New Plant Construction . Black & Veatch has estimated the labor demand to construct the 80 GW of new plant capacity (Black & Veatch, 2006). Sp ecifically, total craft labor is estimated to require more than 12,000 full-time e quivalent positions in 2008 and 2009, decreasing to 10,000 in 2010. The number of boilermakers is conservative ly estimated to constitu te half of the craft labor. This projection allows the total number of boilermaker positions to be estimated from 2007 through 2013. It should be noted these are for plants announced as of 2006; this number could decrease (due to cancellations) or increase.

Figure 4-7 shows the full time boilermaker positions required for retrofit of SCR and FGD, and new plant construction, from 2008 through 2012. The pr ojected supply of boilermakers in 2010 is approximately 31,000; thus the estimated demand of 20,000 represents a large fraction of the workforce. It should also be noted that regularly scheduled maintenance of power plants also relies upon this pool of boilermaker labor. It is unrealis tic to assume that the cumulative demand on labor expended to meet the needs of the power industry w ill be provided without significant cost escalation and delays.

4.3 FGD COST ESCALATION
The escalation in basic materials and labor costs ha s elevated the cost of FGD and all categories of control technology. One index of th is cost escalation, the Vatavuk co st index, reflec ts significant appreciation in the last 5 years. Figure 4-8 presents the trend in this cost index, showing a 50% increase since 1997.Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

16 - 5,000 10,000 15,000 20,000 25,000

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014Full-time Equivalent BoilerMaker Demand

FGDs

SCRs

New EGUs

Figure 4-7. Full Time Boilerm aker Demand: SCR, FGD, and New Coal-fired Units

Figure 4-8. Vatavuk Index for Wet FGD Scrubbers 

### Cost Index for Wet Scrubbers Vatavuk Index (Source: Chemical Engineering)

100.0 110.0 120.0 130.0 140.0 150.0 160.0 170.0 180.0 190.0 200.0 210.0 220.0

1996 1998 2000 2002 2004 2006 2008
YearWet Scrubbers (1994 = 100)

Compound Esc. From 2003 to 3rd Qtr.2006 = 9.7%

Compound Esc. From 1997 to 2003 = 1.6%Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

17 

### SECTION 5

FACTORS AFFECTING CAPIT AL COST ESTIMATES

A review of factors affecting capita l cost estimates is presented in this section. These involve the costing methodology, and site-speci fic and engineering decisions.

5.1 CAPITAL COST ESTIMATING METHODOLOGY Evaluating the capital cost of environmental contro ls requires a consistent accounting of costs. All direct and indirect costs are to be consider ed. EPRI’s Technical Assessment Guide (TAG, 1993) defines a consistent method, and has served as a model by which DOE and other organizations assess
costs.

Figure 5-1 schematically depicts the key components of a capital cost estimate. The first factors establish the capital required to fabricate, deliver , and install the equipment at the site. The capital equipment directly purchased from the supplier, a nd installed by a construction contractor comprises the Total Process Capital. Several indirect charges consequential to these direct charges are incurred: (a) engineering design, (b) general facilities, (c) owne rs costs, and (d) contingencies (usually both a process and a project). Indirect f ees should be consistent when comp aring costs from various suppliers. Table 5-1 presents typical ranges of values historically used by EP RI, DOE, and EPA. Together with the Total Process Capital, these indirect charges comprise the Total Plant Cost.

A second series of indirect charges are incurred based on project execution: fees for the prime contractor, and financing for th e construction period. Adding these costs to the Total Plant Cost determines the Total Plant Investment.

Finally, the equipment and site must be equipped with spare parts, and a supply of reagents, chemicals, or fuels, prior to operation. These pre-production ch arges and inventory capital complete the Total Capital Requirement.

Ideally, evaluating capital costs would utilize simila r charges as defined in Figure 5-1 and Table 5-1. Some but not all data presented in Section 6 have been developed on a consistent basis. However, most reported costs are derived from the same suppliers and A/E’s that use similar assumptions. These costs are inevitably scrutinized by the public utilities commissions and thus eventually tested for reasonableness. Accordingly, comparing lump-sum costs has limits but can identify trends.Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

18 Figure 5-1. Graphic Depict ion of Cost Elements

Table 5-1. Examples of Indirect Charges, Assumptions Cost Element Purpose Range, % Engineering Establish design 7-15 General Facilities Roads, buildings, shops, laboratories 2-5, based on process capital

Owner’s Cost Staff, management 5-10 Process Contingency Uncertainty in process operation 5-10, for a mature process

Project Contingency Uncertainty in site installation 5-10, if detailed engineering initially completed Prime Contractor Fees Business cost 2-8 AFDC Financing during construction 5-10

Preproduction Supply of parts, consumables 2, based on total process investment, plus 30 days fixed, variable O&M Inventory Capital Supply of consumables Based on 30 day reagent, chemicals storage Equipment fabricated and delivered

Installation

Total Process Capital Indirect Charges: • Engineering design • General facilities • Owners cost • Contingencies

Total Plant Cost • Prime contractor fees • Financing during construction

Total Plant Investment • Preproduction (reagents, chemicals) • Inventory capital

Total Capital RequirementCapital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

19 5.2 SITE AND DESIGN FACTORS Site characteristics and the opera ting philosophy, particularly the owner’s tolerance for equipment outages, affect capital cost. These and other factor s are responsible for si gnificant variation in estimates of capital cost among projects.

The key site specific factors th at define capital cost are:

Fuel Composition . The fuel defines the volume of combus tion products, content of particulates, SO 2 , and NOx production rates, and composition of fly as h. These characteristics drive process equipment cost. Most significant is the volume of flue gas produced by fuel combustion. For example, PRB or other sub-bituminous coals can genera te 30% greater volume flue gas to be treated, compared to an eastern bituminous coal, per unit generating capacity. Fo r FGD, the amount of sulfur to be processed and the disposition of the byproduct ar e factors. For SCR, the flue ga s volume, and composition of ash and trace elements such as arsenic can determine reactor volume and catalyst layout.

Site Congestion and Retrofit Difficulty . Limited space for equipment location, access for construction, and access for labor will extend installation time. Ge nerally, older units of smaller generating capacity will incur high costs due to limited access (as well as penalties due to economies-of-scale). Large generating units do not nece ssarily guarantee adequate space for equipment inst allation. For example, at Duke Power’s Belews Creek station, the large site for these two 1200 MW units was constrained, necessitating locating the pre-assembly “laydown” ar ea over 1 mile from the plant. Access for SCR retrofit requires construction near the boiler economizer ex it, and is usually more constrained than for wet FGD, typically located near the stack.

Existing Site Auxiliary and Support Facilities . FGD and SCR process equipment demand auxiliary power, steam, and compressed air. The availability of these consumables at a site varies, and additional infrastructure to supply and distribute these consum ables may be necessary. The most costly of these can be a power distribution or “motor control cen ter”. The escalation in price of copper-derived electrical subsystems has contributed to cost increases; historically electrical infrastructure has been 5- 6% of an FGD budget but now can exceed 10% for some applications.

Draft System Upgrades . The retrofit of environmental controls will change the static pressure within the ductwork, which may require upgrades to fans, new fan motors, upgraded electrical systems, and strengthening of ductwork, ESPs , and boiler walls. The upgrade a nd strengthening of ductwork and boiler walls is necessary to prevent collapse or implosion.

Water Treatment Requirements . For wet FGD, the need to treat process discharge water varies depending on permitted limits. Zero-water discharge requirements can impose significant costs on the entire FGD slurry treatment and dewatering system s, and may possibly interfere with FGD chemistry.

Stack Rebuild or Replacement . Retrofit of wet FGD process equipment can require replacement or significant rebuild of the stack. Flue gas treated by wet FGD poses co rrosion and deposition potential, due to relatively low saturation te mperature and high content of SO 3 . The least cost solution usually requires a new stack rather than retrofitting corro sion-resistant liners to an existing stack. FGD implementation can be limited by the availability of expertise and resources to erect a new stack.Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

20 Equipment Sparing Philosophy . The operating strategy of the owner, and the cost incurred for an FGD outage in terms of compliance margin and SO 2 allowances determines the equipment sparing strategy. Operators with sufficient margin in meeting the SO 2 or NOx cap, or for whom SO 2 or NOx “allowances” are available, may choose to lower capital cost by minimizing redundant equipment. Conversely, operators for whom access to SO 2 or NOx allowances is limited or costly may elect to invest in more spare equipment. Sparing philosophy can affect capital cost by 10-20%.

Materials of Construction . The use of materials that resist corrosion and erosi on, in an effort to obtain high reliability, can elevat e capital cost. Specifically, high alloy containing steels or rubber-lined absorber vessels or pumps have historically incr eased reliability. Decisions affecting materials of construction, similar to those for equipment sparing, are driven by the incurred cost for an FGD or SCR outage. For wet FGD, the use of higher alloy and lined equipment can a dd 10-20% to the project capital cost.

Capital versus Operating Cost . Many decisions revert to a tradeo ff between capital and operating cost; capital savings derived can be at the expense of higher operating cost . For SCR, a key example is the catalyst layout – the number of initia l and final layers of catalyst util ized. For example, a reactor layout of 2 initial layers and 1 spare layer (e.g., 2+1) will provide a lower capital but higher operating cost, compared to utilizing 3 initial laye rs and 1 spare layers (e.g. 3+1). Th e key difference is higher catalyst consumption over a long-term period.

Of these factors, perhaps the most important is si te complexity. Plant sites where FGD and SCR are to be retrofit have become more complex: longer du ctwork runs are required, and access for construction equipment is limited, restricting labor pr oductivity and extendi ng construction time.Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

21 

### SECTION 6

FLUE GAS DESULFURIZATION COSTS

This section presents capital and operating co sts for wet and dry FGD process equipment.

6.1 FGD CAPITAL COST Figure 6-1 depicts capital cost presented as a f unction of generating capacity, for wet FGD and dry FGD processes. The design basis for these installations is desc ribed as follows:

Wet FGD . All units employ limestone reagent, forced oxidati on, deliver at least 95% SO 2 removal, and are equipped with mist eliminators. The influe nce of design or performance conditions different from those stated will impact cost, perhaps mo st significantly due to variations in inlet SO 2 and the size of byproduct handling equipment. However, these cost variations are believed to be no greater than those due to physical differe nces between sites.

Dry FGD . The costs for all units with a lime-based spray dryer absorber (SDA) include a secondary fabric filter particulate collector. Most SDA equipment is designed for 93-95% SO 2 removal. The fly ash is removed in the existing pa rticulate control device (an ESP in all cases), so ash handling and disposition is the same as prior to retrofit. Similar to the case for we t FGD, any differences in dry FGD SDA design from those stated are not anticipated to e ffect capital cost.

Capital costs in this figure are expressed in end-of-year 2006 dollars , and represent th e owner’s best estimate for a ready-to-operate FGD process accoun ting for all direct and indirect charges. Two sources of costs are discussed: anonymous and fully disclosed. Given the competitive nature of the industry, and the of role SO 2 allowances in compliance, some owners are concerned knowledge of FGD cost will bias their allowance prices. The cost sources are discussed by category.



### 6.1.1 Anonymous Sargent & Lundy (S&L) Engineers conduc ted a detailed study for three Midwestern systems: Wet and dry FGD for System A; Dry FGD alone for System B; and Wet and Dry F GD for System C. These three systems comprise 10 wet and 24 dry FGD units for installed generating capacity varying between approximately 200 and 800 MW. Discussions with S&L staff indicate that the assumptions in Table 5-2 are generally consistent for all generating syst ems. Notably, the capital cost for System A exceeds that for Systems B and C, as the former sites are more congested than the la tter, complicating retrofit and construction.

Two units in the Southeast of 850 and 1100 MW genera ting capacity exhibit wet FGD costs of almost $300/kW and $275/kW, respectively.Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

22 0 100 200 300 400 500 600

0 200 400 600 800 1000 1200 1400 Generating Capacity, MWUnit Dry or Wet FGD Cost, $/kW (EOY 2005) Wet FGD: System A

Dry FGD and FF: System A

Belews Creek 1, 2

EW Brown, Ghent

Amos

Southeast Installation

Dallman31-32

Dry FGD/FF System B

DryFGDStation C

WetFGDStation C

FortMartin 1, 2 2004

Hatfield Ferry 1-3, 2004

Monroe 3, 4 2006

Allen 1-5 2006

Marshall

Gorgas 8-10 1999 EPA IPM Wet FGD Reference Wet FGD Curve: 2004-2005 Installations

2006 EPA IPM Wet FGD Reference

Figure 6-1. Wet, Dry FGD Process Equipment Cost: Various Sources



### 6.1.2 Publicly Released Studies Publicly released cost data are described as follows:

American Electric Power (AEP): Amos . The Amos units, at nearly 1000 MW, will require $375/kW.

Allegheny Energy: Fort Martin, Hatfield Ferry . Wet FGD for these 600 MW units was estimated in 2004 to require more than $300/kW. As will be noted subsequently, actual costs incurred in 2006 for these units significantly exceeded this value.

Detroit Edison Company: Monroe 3, 4 : These 800 MW units will incu r capital cost greater than $300/kW, despite exploiting economies of s cale in engineering and procurement.

Duke Energy has publicly released all wet FGD costs to comply with North Carolina Clean Air Legislation (Everett, 2007):Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

23 • Belews Creek 1, 2 . The wet FGD $238/kW capital cost fo r these units is one of the lowest encountered. Duke achieved this relatively lo w cost by developing a system-wide design to apply to over 4,000 MW of capacity, utilizing two generic spray towe r designs and common water management and solid processing equi pment for the entire system (McCarthy, 2004). Economies-of-scale for engineering and procurement also contribute to the lower cost, as well as the relatively early date (2002) in which Duke engaged the FGD contractor.

• Allen Units 1-4 . The relatively small generating capaci ty of these units (190 MW) imposes capital cost penalties due to scale, even t hough four units of nearly identical design are installed, utilizing the generic system spray towers (McCarthy, 2004). At more than $400/kW, these FGD installations are among the highest cost.

• Marshall Unit 1-4 . Four units at Marshall (2 x 65 0 MW and 2 x 350 MW) employ the wet FGD system design and incur slightly greater than $200/kW. This si te benefits from economies-of-scale to lower the aver age unit cost to this value.

East Kentucky Power: E.W. Brown, Ghent . These units incur relatively low costs of $300/kW. The remote location and relative good access lik ely contributes to these lower costs.

CIPS Springfield: Dallman, and South Illinois Power Co-Operative: Marion . Both of these units incur capital of less than $200/kW, for units in which contracts were signed in 2002.

WE Energies: Pleasant Prairie Units 1, 2 . The design and cost for these twin 617 MW units was established in 2004, and equipment contracted fo r mostly in 2004 and 2005. The capital cost of $218/kW (2006 dollar basis) exploi ts economies-of-scale due to two identical unit designs, and common facilities such as a new stack, waste water treatment, and reagent preparation facilities.

The “Wet FGD Curve” depicted in Figure 6-1 appr oximates the capital cost for wet FGD processes based on a system study for the former Cinergy by S&L.

Figure 6-2 compares wet FGD cost for units wher e competitive bids were received in 2006. For reference, Figure 6-2 includes a curve based on Figur e 6-1 that reflects wet FGD capital cost for units procured in 2004 and 2005. Also shown is the IPM co st curve as utilized by EPA in 2006 for regional modeling.

Revised wet FGD costs for two generating stations – Allegheny Energy’s Hatfield and St. Martin – are also presented in Figure 6-2. These data provide comp arisons to the 2004 values. Each of these stations in 2006 received bids for wet FGD that significantly exceeded engineering estimates generated in 2004, by $75-150/kW. Although details of the higher cost s are not available, the most significant contributing factors are higher inst allation costs and material prices . In addition, wet FGD capital cost for Reliant Energy’s Cheswick St ation reported in mid-2006, and for Gulf Power’s Crist Units 4-7 (April, 2007) are presented. The wet FGD design fo r Crist is reported to exceed $500/kW, and will utilize two absorber vessels to treat flue gas fr om four units, ranging from 94 MW (two units) up to 578 MW. The disparity in generating unit size and arrangement of equipm ent likely contributes to this high cost, as well as 2007-based prices for material and labor.Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

24 0 100 200 300 400 500 600

0 100 200 300 400 500 600 700 800 900 1000 Generating Capacity, MWUnit Dry or Wet FGD Cost, $/kW (EOY 2005) FortMartin 1, 2 2004

Hatfield Ferry 1-3, 2004

RecentPowerLaw

Fort Martin 1-2 2006

Hatfield Ferry 1-3 2006

Crist 4-7

2006 EPA IPM wet FGD Reference 2006 vs. 2004: Fort Martin 1, 2 2006 vs. 2004 Hatfield Ferry 1-3

Wet FGD Curve: 2004-2005 Installations

Figure 6-2. Wet, Dry FGD Process Equipment Cost: Various Sources

Of note is the disparity between co st projected by EPA a nd those actually incurred. The source of this disparity is unclear – the EPA methodology employs th e same cost accounting principles described in Section 5, and is reported to consider balance-of-p lant impacts. It is pos sible EPA projections are based on dated information, derived with budgetary-t ype analysis, as opposed to a detailed design study. It is unlikely the EPA cost algorithm reflects authentic balance-of-plant costs. For example, Duke Energy required a unique waster water manage ment system at the Belews Creek and Marshall generating stations that employed specially-constructed wetlands. Al so, Marshall required extensive duct runs to tie in the new stack. The EPA estimat es do not appear to include a complete list of balance-of-plant items.

6.2 OPERATING COST Operating cost is defined in se veral ways – total operating cost per unit of capacity per year, normalized to power generated, or pe r unit of emission species removed.

Figure 6-3 is a reproduction of a graphic presented by Sargent & Lundy at the November 2006 PowerGen conference (Sargent & Lundy, 2006). Figur e 6-3 compares (for a 500 MW plant) the various contributors to total opera ting cost for a limestone-based wet FGD process, designed for 95- 97% SO 2 . Total O&M ranges from approximately $15 to $3 8/kW/yr, and is almost equally comprisedCapital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

25 of fixed and variable components. As noted in Figur e 6-3, limestone reagent cost for this size of unit varies in direct proportion to the amount of sulfur in the coal. Othe r operating cost components directly related to sulfur conten t including operating and maintenan ce labor, and byproduct management.

Figure 6-3. Range of Wet FGD Operating Costs for 500 MW Units (after Sargent & Lundy, 2006)

The capital cost ranges in Figures 6-1 and 6-2, when combined with operating costs, provide an indicator of FGD cost-effectivenes s, or the cost per ton of SO 2 removed. Figure 6-4 presents the cost per ton of SO 2 removal for a hypothetical 500 MW unit, uti lizing a limestone based forced oxidation process. Calculations are repor ted for coal with intermediate sulfur content (6 lb SO 2 /MBtu) and for PRB (0.90 lb SO 2 /MBtu). Figure 6-4 results are based on medi an operating costs reported in Figure 6-3 for the 6 lb SO 2 coal, and minimum values for PRB. The ope rating cost estimates are consistent with published sources for wet FGD, and those derived for a 500 MW unit with EPA’s CUCOST software
program 3 . It is possible higher operating costs may be incu rred that reflect higher labor rates. Figure 6- 4 results also assume a 15-year book life (e.g., cost r ecovery period) and thus a capital recovery factor of 0.12.

3 Using CUCost Version 3, the sum of fixed and variable O&M for a wet limestone forced oxidation FGD process is within 5% of that derived using 500 MW generating basis, Ohio coal of 5.8 lbs SO2/MBtu, 85% capacity factor, and 10,000 Btu/kWh heat rate. Cost results are presented on a 2006 dollar basis using the CUCost imbedded routine to escalate costs with the CE Plant Index.Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

26 For the case of 6 lb SO 2 /MBtu coal, an increase in capital co st from $250/kW to $450/kW increases the cost of SO 2 removal from $270 to $450/ton. For PRB coal , the same capital cost increase will elevate SO 2 removal cost from approximately $1,500 to $2,300/ton. The costs will change in proportion to the sulfur content of the fuel.

- 500 1,000 1,500 2,000 2,500

200 250 300 350 400 450 500 Wet FGD Capital Cost, $/kWCalculated SO2 Removal Cost, $/Ton E. Bit Coal (6 lbs SO2)
PRB Coal (0.9 lbs SO2)

Figure 6-4. SO 2 Removal Cost per Ton ($/Ton), Year 2006 BasisCapital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

27 

### SECTION 7

SCR NOx COST

This section presents capital and ope rating costs for SCR NOx control.

7.1 SCR CAPITAL COST The capital cost for SCR process equipment has been the subject of several su rveys in the last four years. In most cases, the costs are reported as anonymous; the costs for only a few named units are publicly available. This section of the report will highlight results fr om these surveys, almost all of which were conducted prior to the cost escalation witne ssed in the last 24 months. Limited data released in the last 12 months and reflecting the cost escalation will also be presented.

7.2 THREE SURVEYS Three surveys have documented the increase in SCR capital cost: Hoskins (2003), Cichanowicz (2004), and Marano (2006). The findings from these surv eys are not directly comp arable to each other, as each utilizes a different unit population, and design features. Further, importa nt factors such as the scope of equipment supply and construction labor ra tes have not been normalized. Table 7-1 shows the average capital cost and size of generating unit in th e survey, the range of cost s incurred, and includes important observations concerning these surveys. The results of each survey are summarized as follows:

Hoskins, 2003 . This survey of 20 units determined an average cost of $120/kW , for units with an average generating capacity of 400 MW. More than 75% of these units repor ted capital costs that exceeded $100/kW. A weak relationship between capital cost and scale was not ed; that is, unit cost ($/kW) did not significantly change with increasing generating capacity.

Cichanowicz, 2004 . This survey of over forty units reveal s a relationship between cost and generating capacity. Units of small-intermediate generating capacity (100-400 MW) required $123/kW, while the largest units (800-1200 MW) required $85/kW. This su rvey compared the capital cost provided by each supplier with the order of instal lation – that is, comparing the cost of the first unit installed by a supplier versus subsequent units. Four categories of generating capacity were examined, and in every case the least cost units were among the first installed, s uggesting that either increased experience by the supplier or complexity of the unit increased the capital cost. This trend was observed prior to the recent cost escalation.

Marano, 2005. This most recent (2005) and comprehensiv e (60+ units) survey showed that most units reported costs of $100-200/kW, with units greater than 900 MW averaging $118 /kW, and those less than 300 MW averaging $167/kW. Marano noted that units from 600-900 MW appear to be the most difficult to retrofit. This observati on is consistent with the observat ion of Cichanowicz, which shows capital cost actually in crease with generating capacity in this range.Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

28 Table 7-1. SCR Capital Cost Survey Results

Reference Average Capital, MW ($/kW, 2006 Basis)) Low-High Cost Observed ($/kW) Observation

Hoskins, 2003 128 (400 MW) 80-160 Cost Basis: 2002. 15 of 20 reported unit costs exceeded $100/kW. Weak relationship of unit cost and scale. Cichanowicz, 2004 84 (600-899 MW) to 128 (100-399 MW) 56-185 Cost Basis: 2003. For four categories of generating capacity, the least cost units were among the first installed. Marano, 2006 118 (>900) to 167 (<300 MW) Most costs reported to be within 100-200 Cost Basis: 2005. “Units with a capacity of 600 to 900 MW appear to be more difficult to retrofit than those in other size ranges.”

The most significant observation from the surveys re ported in Table 7-1 is th e low number of units with reported costs <$100/kW, and the inability of units of large generating capacity to deliver low installed cost. The case of Duke Energy’s Belew’ s Creek Station, where the construction “laydown” area was one mile from the unit has been well do cumented (Power Engineering, 2002). Marano (2006) notes the early SCR adopters incu rred lower capital cost, with the year of 2003 recognized as a milestone after which cost s increased significantly.

7.3 COST ESCALATION Figure 7-1 depicts the escalation of SCR capital cost over four periods of time, spanning 15 years. This escalation is described as follows:

Phase 1 and Phase 2 installations incurred atypically lo w capital cost. It is likely these installations did not reflect the conventional SCR retrofit in te rms of access, NOx removal performance, and reactor/catalyst arrangement.

Phase 3 installations reflected increasing retrofit complexity and higher NOx control performance; process demand was robust but did not overburden th e suppliers over this time period. Over 2/3 of these units incurred capit al cost exceeding $100/kW.

Phase 4 comprises the recent applications that e ither become operational in 2006, or will start up in 2007 or 2008. These costs exceed $200/kW on a routin e basis, well above the cost historically incurred.Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

29 1993 1995 1997 1999 2001 2003 2005 2007 2009

0 50 100 150 200 250 300 350 SCR Capital Cost ($/kW)Installation Date

Phase 2: 1st -time and early applications Phase 3: mature applications and t

Phase 1: EPA, NESCAUM, and ICAC; Merrimack Unit 2 and Stanton Unit 3 Phase 4: Leftovers

Figure 7-1. Escalation of Cost for SCR Installation with Time

7.4 OPERATING COST Operating costs for SCR processes consist mostly of replacement catalyst and ammonia-based reagent. Each of these cost components has experienced si gnificant price changes in the last 10 years.



### 7.4.1 SCR Catalyst Historically, supply of catalyst co mprised the largest operating com ponent of SCR NOx control. The unit cost of catalyst has significan tly decreased since the early 1980s, as the entry of several large multi-national firms increased supply faster than demand. Further, the ability to regenerate or rejuvenate catalyst for approximately 50% of new product price further restrains price.

Figure 7-2 presents the unit price of catalyst sinc e the early 1980s, corrected to a 2006 dollar basis, showing a decrease in unit price by a factor of five since the earli est commercial bids. The minimum price of near $4,000 m 3 was witnessed in 2005; however, re cent experience suggests prices are increasing due to a large number of units for which a first catalyst addition or supplement is required.Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

30 - 5,000 10,000 15,000 20,000 25,000 30,000 35,000

1980 1985 1990 1995 2000 2005 2010
YearCatalyst Unit Price, $/Yr (2006 $ Basis)

Catalyst Unit Prices Increasing in 2007

Figure 7-2. History of SCR Cata lyst Prices (2006 Dollar Basis)

The consequence of this catalyst price decrease is that catalyst procurement does not dictate SCR cost as historically witnessed. In fact , catalyst management decisions at present can exploit low prices to insure the reactor features adequate catalyst activ ity, to confine catalyst replacement to major outages, avoiding unit shutdown for the purpose of catalyst addition or exchange.



### 7.4.2 Reagent Any savings in SCR operating cost due to catalyst price decreases has been offset by escalation in delivered price of ammonia-based reagent. SCR ope rators can choose from four types of ammoniabased reagent: anhydrous ammonia, aqueous ammonia of 19.5% NH 3 content or 29% NH 3 content, or urea. For the purposes of this discussion, anhydrous ammonia will be discussed as an example, recognizing that the alternative reag ent forms are equally viable.

The cost of anhydrous ammonia is as much as 80-90% determined by the cost of natural gas feedstock. In late 2006, typical pric es for anhydrous for agriculture were approximately $400/ton. This value exceeds the 175 to $250/ton historically noted. As natural gas prices ar e anticipated to remain high, the price of $400/ton is anticipated to represent future cost (Clark, 2006).Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

31 

### 7.4.3 Example Operating Cost The operating and maintenance cost for an SCR pr ocess can be developed (for a hypothetical 500 MW unit), based on assumptions in Table 7-2 that de fine the conditions of operation. These are:

Fixed O&M . Spare parts and support for miscellaneous duties that must be executed regardless of unit operation are assumed to require 0.50% of process capital.

Catalyst Supply . Catalyst supply cost is determined by long-term purchases from which an annualequivalent average can be calculated. The long-term purchases are dictated by catalyst addition to the empty spare layer, and replacement of existing la yers. For an SCR reactor employing a 2+1 catalyst arrangement, 3,200 1/h initial sp ace velocity, and a 16,000 hour ini tial operating guarantee, the purchase of 1 layer for every 20,000 operating hours may be required.

Reagent Cost . The purchase of anhydrous ammonia for 90% NOx removal from 0.35 lbs/MBtu, at 85% capacity factor, defines th e reagent cost. A delivered price of $400/ton is assumed.

Auxiliary Power . Auxiliary power for an additional 6 in. wa ter gauge (w.g.) flue ga s pressure drop is assumed – 5 in. w.g. for the process flange-to-flange, and an additional 1 in. w.g. across the air heater.

Catalyst Cleaning . Sootblower consumption of 0.2% of the pl ant steam output is adopted; this steam is assigned a cost of $1/MBtu.

Operating Staff . The addition of one operato r is assumed for maintenance of the above components. Also, a part time (25%) engineer to assess operation and evaluate data is assumed.

Table 7-2. Key SCR Operating Cost Components: 500 MW Reference Plant ($150/kW Capital Basis)

Operating Cost

Component Basis Annual Cost for 500 MW ($/yr) Annual Cost for 500 MW (mills/kWh) Fixed O&M 0.5% of Process Capital 150,000 0.04

Labor Operators/Part-time Engineer 125,000 0.03

Fuel Cost Auxiliary Steam 100,000 0.02 Reagent 90% NOx removal (from 0.38 lbs/MBtu) 885,000 0.25

Auxiliary power 6 in. w.g. total @ $20/MWh 265,000 0.07

Catalyst Supply 16,000 hr guarantee for 2+1 reactor 675,000 0.15

Total 2,200,000 0.59Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

32 The capital cost observed in Figur e 7-1, when combined with update d operating costs in Table 7-1, provides an indicator of SCR cost -effectiveness, or the cost pe r ton of NOx removed. Figure 7-2 presents the cost per ton of NOx removal for a hypothetical 500 MW unit, utilizing a 2+1 catalyst arrangement, with an initial NOx input of 0.38 lbs/MBtu, as a function of SCR capital cost. Calculations are reported for an eastern bitumi nous coal with approximately 0.38 lbs/MBtu furnace NOx exit, and a PRB-fired unit assumed to produce 0.20 lbs/MBtu. Results presented in Figure 7-2 for the eastern bituminous coal employ operating cost in Table 7-1, while calculations for PRB coal employ lower cost for reagent use and catalyst consis tent with lower inlet NOx. Figure 7-2 results also assume a 15-year book life (e.g., cost recovery period) and thus a capital recovery factor of 0.12.

For the eastern bituminous coal, an increase in capital cost from $100/ kW to $300/kW elevates the cost of NOx removal from $2,200 to almost $6,000/ton. For the PRB coal, with lower inlet NOx rate and lower operating costs, the same capital cost increa se elevates NOx removal cost from approximately $1,200 to $3,200/ton. The costs will change in proportion to the boiler NOx generated.

0 1,000 2,000 3,000 4,000 5,000 6,000

0 50 100 150 200 250 300 350 SCR Capital Cost, $/kWCalculated NOx Removal Cost, $/Ton (2006 Basis) PRB Coal

E. Bit Coal

Figure 7-3. NOx Removal Cost pe r Ton ($/ton), Year 2006 BasisCapital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

33 

### SECTION 8

IMPLICATIONS FOR Hg CONTROL

This report has focused on cost and schedule issues attendant to the retrofit or construction of new FGD and SCR equipment. The Clean Air Mercury Rule (CAMR) also mandates installing control technology over the same time period. Although many units are anticipated to comply with Hg removal through wet FGD, the use of sorbent or activated carbon injection (ACI) upstream of an existing ESP or fabric filter (FF) may be needed.

EPA has projected the generating capacity that co uld be retrofit with ACI in FF to meet CAMR mandates (EPA, 2006). EPA’s predictions suggest about 1,900 MW of ACI into FF could be deployed by 2010, with this amount increasing to 2,400 MW by 2015. EPA did not reveal deta ils of its analysis. More importantly, EPA’s analysis only addresse d the federal CAMR and not the numerous statespecific initiatives, all of which ar e more strict than CAMR. As an example, the state of Georgia has proposed an emission control rule th at at one site requires almost 3,300 MW of coal-fired capacity to be retrofit with fabric filters for particulate matter control (Georgia Environmental Protection Department, 2007). Consequently, EPA is likely under-p redicting the utilization of ACI in FF by the utility industry.

The need for significant ACI/FF could further burden labor demand. A UARG analysis in 2003 assumed fabrication and installa tion of a typical FF would require 300 manhours of labor per MW of generating capacity, with half of that amount being boilermakers. The total of 150,000 manhours for a 500 MW unit, of which 75,000 are boilermakers, is sm all compared to the labor demand for SCR and FGD. However, the strained labor pool may not be able to accommodate any additional demand.

Finally, it should be noted that FF cost for use with ACI has escalated significantly since first proposed for Hg control. Specifically, early cost projections by EPRI suggested a FF retrofit cost of $50-60/kW, a value widely use by EPRI and adopted by UARG. S ubsequently, experience from the Gaston trials in 2005 suggested design changes to improve Hg removal were warranted, such as using a lower air/cloth ratio (4-6 compared to 8-12) and thus higher fi lter area (Berry, 2004). This requirement, combined with a more complex equipment layout, has elevated capital estimates to more than $100/kW. The cost for 270 MW FF module for the Presque Isle station was $127/kW in 2004 dollars. This reference cost is used to project capital cost for larger units using conventio nal power-scaling law.

A recent study using Presque Isle as a reference de sign suggests typical FF costs are even higher, and approach $150/kW (EPRI, 2006). Th e degree that the design of the FF module at Presque Isle represents future applications is questioned by some, claiming the site characteristics atypically elevate cost. Presque Isle Units 7-9 do comprise a congested site, as effluent from three 90 MW units merge into one FF module. However, actual FF applications for Hg removal may incur these same challenges. In fact, the sites that could need ACI/FF for high Hg removal may be those not equipped with SCR and FGD, and be smaller, older generating units – exactly those represented by Presque Isle.Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

34 In summary, the need for at least several thous and MW and perhaps greate r of ACI/FF will further exacerbate the schedule and cost pr essures imposed by FGD and SCR.Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

35 

### SECTION 9

CONCLUSIONS

The significant demand for environmental controls fo r retrofit to existing units – combined with the construction of perhaps 80 GW of new coal-fired cap acity – has elevated capital costs, both incurred and estimated. These escalated costs, combined w ith delays in installation due to equipment and personnel shortages, will challenge the ability of some operators to meet CAIR mandates. Further, the decision to comply using either control technology versus the purchase of emissions allowance may change over the timeframe from planning to execution.

Notably for FGD, the most recent capital cost data suggest a 30% increase ove r the last two years. Worldwide demand for material and personnel res ources, combined with nu merous and overlapping utility industry mandates, is believed responsible for this escalation. As depicted by the Vatavuk index reflecting scrubber costs presented in Section 4, FGD capital costs have increased at an annual rate of 7-9% for the past three years. These same cost pre ssures apply to SCR, and will also likely impact any large deployment of FF for use with AC I for future mercury emission controls.

These capital cost pressures could affect “scrub vs. switch” decisions. Speci fically, the decision to “scrub” a coal with sulf ur content of 6 lbs SO 2 /MBtu may be based on pre liminary engineering, and may adopt a FGD capital cost of $200/kW with SO 2 reduction generated for $250/ton. If actual construction costs increase to $400/kW, SO 2 removal is provided for $375/ton which may exceed the allowance price. The conclusions can be even more distorted for PRB coal, with an escalation in capital from $250/kW to $400/kW increasing SO 2 removal costs from $1550 to more than $2100/ton. Similar trends are noted in esca lation of NOx compliance costs a nd the decision to deploy SCR NOx control versus another strategy.

This report revealed significant schedule pressure s that threaten a utility company’s prospects of complying with CAIR mandates. In 2002, EPA pres umed installation schedules for SCR and FGD were 21 and 27 months, respectively (EPA, 2002). UARG comments filed in response to this EPA claim offered more realistic schedules for SCR a nd FGD of 28 and 32 months, respectively (UARG, 2003).

The construction schedules have since been further extended. Specifically, SCR installation at present requires 36 months. Figure 9-1 presents a schedule for constructing the SCR for Associated Electric Co-Operatives New Madrid Unit 3, depicting a three- year duration from star t to unit startup (Johnson, 2006). FGD schedules similarly extend to 36 months, or more if key items such reagent or slurry pumps cannot be acquired, or stacks erected.Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

36 Figure 9-1. Project Timeline for New Madr id Unit 3 SCR Installation and Startup (after Johnson, 2006)

The combination of higher capital cost and extended installation sc hedules may prevent many owners from meeting compliance deadlines for CAIR or othe r initiatives. Particularly for smaller generating systems, access to the necessary technology may not be av ailable, or only availabl e at exorbitant costs. The case of South Mississippi Electric Power Associa tion (SMEPA) is instructive regarding this item. In late 2006, SMEPA received bids for wet FGD and SCR equipment that spec ified a combined capital cost of about $1,000/kW for each unit. Although the small generating capacity of the host units (~200 MW each for two units) contributed to these co sts, the extreme competition for resources and manpower are at least equally culpable. SMEPA is pr esently exploring alternative means to meet the CAIR mandates.

As a consequence, both the cost and schedule pl ans for FGD and SCR by many utility owners are at risk, compromising their ability to meet the numerous mandates.Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

37 

### SECTION 10

REFERENCES

Reference Author

Black & Veatch, 2006 Black & Veatch, “Building New Base load Generation in The Midwest”, presentation to MMEA, April 11, 2006.

Berry, 2004 Berry, M. et al., “Field Test Pr ogram for Long-Term Op eration of a COHPAC System For Removing Mercury from Coal-f ired Flue Gas”, Proceedings of the Combined Power Plant Air Pollutant Control Mega Symposium, August 30- September 2, 2004, Washington, DC.

Brat, 2007 Brat, I., “Crane Migration Hinders Builders”, The Wall Street Journal OnLine, June 18, 2007.

Cichanowicz, 2004 Cichanowicz, J.E., “Why are S CR Costs Still Rising”, Po wer Magazine, April, 2004.

Clark, 2006 Clark, E., “Price Predictions”, Apply, May 1, 2006.

EPA, 2002 “Engineering and Economic Factors Affecting the Installation of Control Technologies for Multi-Pollutant St rategies”, EPA Report EPA/600/R-02/073, October, 2002

EPA, 2006 Contributions of CAIR/CAMR/ CAVR to NAAQS Attainment: Focus on Control Technologies and Emission Reducti ons In The Electric Power Sector, Office of Air & Radiation, U.S. EPA, April 18, 2006. Downloaded from EPA Air & Radiation Site.

EPRI, 2006 EPRI, “Mercury Control Tec hnology Selection Guide”, EPRI Report 1012672, September, 2006.

Figueroa, 2006 “Carbon Dioxide Capture and Sequ estration Potential and Issues the U.S.”, Presentation by JD. Figueroa, DOE NETL, to the APPA New Generation meeting, June 28, 2006, Washington, DC.

Georgia EPD, 2007 www.gaepd.org/environet/1 /20070413_Amendments_CAMR.pdf

Hoskins, 2003 Hoskins, B. et al., “Uniqueness of SCR Retrofits Translat es Into Broad Cost Variations”, Power Engineering, May, 2003.Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

38 Katzberger, 2007 Katzberger, S. et al., “Impact of a Resource-Constrained FGD Market”, Electric Power 2007 Conference and E xhibition, May 1-4, 2007, Chicago, IL.

Marano, 2006 Marano, M. et al., “Estima ting SCR Installation Costs”, Power, January/February 2006.

McCarthy, 2004 McCarthy, J. et al., “Duke Po wer WFGD Retrofit Program: Achieving the Lowest Cost System-Wide Compliance”, Proceedings of the Combined Power Plant Air Pollutant Control Mega Symposium, August 30-September 2, 2004, Washington, DC.

Sargent & Lundy, 2006 Sargent & Lundy, “The Real Cost of We t FGD Retrofit Projects”, presentation to Power-Gen, November, 2007, Orlando, FL.

TAG, 1993 EPRI Technical Assessment Guid e, “Electricity Supply – 1993”, EPRI TR102275-V1R7, June, 1993.

UARG, 2003 Observations and Comments on the Report, Engineering and Economic Factors Affecting the Installation of C ontrol Technologies fo r Multi-Pollutant Strategies, submitted by the Uti lity Air Regulatory Group, May, 2003.Capital Cost and Cost-Effectiveness: Power Plant Emission Control Technologies

39 

### SECTION 11

FGD COST REFERENCES

Generating Station Citation

Duke Energy: Allen, Belews Creek, Marshall Everett, George, letter to Ms. Renne Vance, March 30, 2007, Exhibit C, downloaded from the North Carolina P ublic Utilities commission website

LG&E EW Brown, Ghent “PSC Approves Environmental Projects for LGE, KU”, press release downloaded from Kentucky Public U tilities Commission website, June 20, 2005. Ft. Martin, Hatfield 2006a Allegheny Energy’s Emission Reduction Efforts Reach New Milestone at Pleasants Station”, Allegheny Ener gy Press Release, July 20, 2006.

Ft. Martin, Hatfield 2006b “Allegheny Energy Scrubber Projects to Cost More Than Expected”, Power Engineering, September 8, 2006

Crist 7-10 “Southern Company to Install Sulfur Dioxide Controls at NW Florida Plant”, E&E Publishing, April 6, 2007

Gorgas 8-10 “Alabama Power to Install One of Worlds Largest Scrubbers”, E&E Publishing, April 12, 2007

Monroe 3, 4 “WGI to Construct Sc rubbers”, July 5, 2006, Yahoo Finance

TVA Unit Personal Communication, Rick Collins, TVA, May 6, 2007.July 10, 2007 

# Costs Surge For Building Power Plants

By MATTHEW L. WALD

General Electric called in reporters yesterday for a briefing on a nuclear plant it is trying to sell in p artnership with Hitachi, a plant it said can be bui lt faster than before, operated reliably and have a vanishingly small chan ce of an accident.

But what will it cost? After some hemming a nd hawing, company executives gave figures by the standard industry metric, dollars per kilowa tt of capacity, but in a huge range: $2,000 to $3,000.

''There's massive inflation in copper and nickel and stainless steel and concre te,'' said John Krenecki, p resident and chief executive of GE Energy. The uncertainty is not just in nuclear plants, he said; coal p lant prices are now similarly unstable.

As talk of building new power pl ants rises sharply, so does the cost. A new fleet of coal-fired power p lants and a revival of nuclear construction afte rthree decades are both looking tougher lately.

For example, in late 2004, Duke Energy, one of the country's largest utilities and most experienced builders, started planning a pair of coal-fired power plants to repl ace several built around the middle of the last century, at Cliffside, in western North Ca rolina. In May 2005, the company told regulators it wanted to spend $2 billion to build twin 800-megaw att units. But 18 months later, in November 2006, Duke said it would cost $3 billion. Then the state utility commission said to build only one of the plants, and in May of this year Duke sa id that would cost $1.83 billion, an increase of more than 80 percent from the original estimate.

Duke's experience may be extreme but it is hardly isolated.

''There's real sticker shock out there,'' Randy H. Zwirn, president of the Siemens Power Generation Group, said in an interview. He estimated that in the last 18 months, the price of a coal-fired power plant has risen 25 percent to 30 percent.

Part of the problem is huge price increases for the raw materials that plants are made from, including copper and nickel, which is what ma kes steel stainless. But the cost of finishing those commodities into components is also rising.

''There's a lack of production and ma nufacturing facilities in this count ry, and that may be partly to blame,'' said Jason Makansi, a consulta nt with Pearl Street, a consulting firm in St. Louis that specializes in electric utilities. But, he sai d, ''the bigger culprit is the incredible demand in China and the rest of Asia.'' Pa g e 1 of 3 Costs Sur g e For Buildin g Power Plants - New York Times

3/26/2008 htt p :// q uer y .n y times.com/ g st/full p a g e.html?res=9A04E4D7103EF933A25754C0A9619C8...''Basically everything is being sent over that way.''

A result of demand in China and India, he said, is that ''Duke and others want to build a new power plant based on inexpensive coal, but the capital cost to bui ld that plant is doubling before they even put a shovel in the ground.''

And other kinds of projects that use similar materials, everything fr om oil refineries to natural gas terminals, are competing for the same materials and labor, experts said. ''So many industries are at cyclical peaks at the same time,'' Mr. Krenecki of G.E. said. ''We can't forecast how long that will continue.''

Mr. Makansi and others say a result is that consumer s, already paying more for electricity because the p rice of coal and especially natural gas is up, will pay even more for new generating stations.

Duke was not surprised that prices were up, but realized when it actually took in bids from suppliers that the situation was worse than expected. Analysts say that the companies that make major plant components will gear up to meet new demand and even tually price increases will moderate. But James L. Turner, president and chief operati ng officer of Duke's United States electric and gas system, said the company could not wait fo r prices to reverse.

''Given customer needs and demand growth on our syst em, we don't have the luxury of waiting to see if it all settles down in a decade,'' he said, although the company says it would like to undertake more vigorous steps to cut demand through higher energy efficiency.

Duke was reluctant to discuss exactly what it was paying for major components. But Siemens, a supplier, gave some examples for a typical combined-cycle natural ga s power plant, one that burns the fuel in a gas turbine to drive one generator, th en makes steam from the exhaust to drive a second generator. The high-pressure pipi ng for steam, used on a 293-megawatt plant, is up about 60 percent in the last two years, to about $1.12 million, according to the company. The equipment that uses exhaust heat to make steam, used at a 590- megawatt plant, is up about 40 percent in the last two years, $15.1 million in April of this year vs. $10.7 million in May 2005, according to Siemens.

Simply moving a 435,000-pound turbine for a 198-megawatt plant from factory to the plant site now runs about $100,000, according to Siemens, up from about $50,000 two years ago.

N uclear plants still on the draw ing board are also affected.

''For nuclear and for coal, we pretty much figure it' s going to be about the same effect,'' said Revis James, an economist at the Electric Power Research Institute, a nonprofit co nsortium in Palo Alto, Calif. N o matter what the technology, he sai d, ''there's been a huge amount of change in the baseline estimates p eople are using.''

Renewable energy is not immune. ''Costs have increa sed for wind as they have for other technologies,'' said Christine Real de Azua, a spokeswoman for the American Wind Energy Association. ''While wind farm operations are not hit by fuel price volatility, steep increases in the cost of raw materials like copper and steel and other fa ctors have driven up the price of wind turbines,'' she said in an e-mail
statement.

Her association recently republished data from a utility that buys large amounts of wind power, Puget Sound Ener gy , showin g that p rices in 2006 ran g e d from about 8 cents to 10.5 cents a kilowatt-hour, u p Pa g e 2 of 3 Costs Sur g e For Buildin g Power Plants - New York Times

3/26/2008 htt p :// q uer y .n y times.com/ g st/full p a g e.html?res=9A04E4D7103EF933A25754C0A9619C8...from 2004, when it was 4.5 to 6 cents. A recen t study by the National Renewable Energy Laboratory, p art of the Department of Energy, showed a steadily declining price from 1999 to 2005, but an increase in 2006. The study said that wind power was generally comp etitive with other sources of energy but that rising costs were ''starting to erode that value.''

But the wind energy association said that competi ng technologies show even steeper increases.

All of this is bad news for efforts to slow clim ate change, experts say. Equipment to capture carbon dioxide from the smokestacks of power plants would be made of all the things that are rising in price: concrete, structural steel, steel vessels, valves and pipes. Th at equipment would require somewhat less of the most expensive components, the ones on the gene ration side that are meant to resist the highest temperatures, pressures and corrosive materials. Bu t it would all be assemb led by the same types of workers who are in short supply for building conventional power plants.

Copyright 2008 The New York Times Company Home Privacy Policy Search Corrections XML Help Con Pa g e 3 of 3 Costs Sur g e For Buildin g Power Plants - New York Times

3/26/2008 htt p :// q uer y .n y times.com/ g st/full p a g e.html?res=9A04E4D7103EF933A25754C0A9619C8...

### Appendix B
Details of Cost Calculati on Using OAQPS Cost ManualOwner: PNM Computed by: D. Fischer
Plant: San Juan Generating Station Unit: 3 Date: 2/14/2008 Project No.: 146646 File No.: Rev: B Verified by:
Black & Veatch Title: OAQPS SCR Cost Development Date:

Objective:

References: 1) EPA Air Pollution Control Cost Manual Section 4.2 NOx Post-Combustion Controls, Chapter 2 SCR, USEPA, Oct 2000

Assumptions: a) None

Inputs: Parameter Variable Name Reference Information Units Value a) Fuel HHV HV Btu/lb 9,692 b) Fuel burn rate m-dot fuel lb/hr 594,098 c) System capacity factor CF Plant % 85 d) SCR operating days t SCR days/yr 365 e) SCR inlet NOx NOx in lb/MMBtu 0.3 f) SCR outlet NOx NOx out lb/MMBtu 0.07 g) Stoichiometric ratio ASR 1.05 h) Fuel vol rate q fuel ref. OAQPS ft 3 /min-MMBtu/h r 484 i) SCR inlet temperature T F 650 j) No. of SCR chambers n SCR 1 k) Ammonial slip Slip ppm 2 l) Fuel sulfure content S % 0.77 m) Catalyst nominal height h' layer ref. OAQPS ft 3.1 n) Spare catalyst layer n empty 1 o) SCR height constant 1 c 1 ref. OAQPS 7 p) SCR height constant 2 c 2 ref. OAQPS 9 q) NH3 mol. weight M reagent 17.03 r) NOx mol. weight M NOx 46.01 s) NH3 solution concentration Csol % 29 t) NH3 sol density p sol for 29% NH3 at 60F - OAQPS lb/ft 3 56 u) NH3 sol spec. vol. v sol for 29% NH3 at 60F - OAQPS gal/ft 3 7.481 v) NH3 storage days t days 30 w) Retrofit SCR? new 1=retrofit, 2=new 1 x) SCR bypass? bypass 1=yes, 2=no 1 y) Catalyst cost per unit CC initial ceramic honeycomb - OAQPS $/ft 3 240 z) NH3 reagent cost Cost reagent $/lb 0.101 aa) Pressure drop in duct dP duct 3 ab) Pressure drop in cat. dP catalyst 1 ac) Cost of power Cost elect from PNM BART $/kWh 0.06095 ad) Catalyst replacement CC replace ceramic honeycomb - OAQPS $/ft 3 290 ae) Annual interest rate i OAQPS % 7 af) Catalyst life h catalyst OAQPS hours 24,000 ag) Payback period n years 20

Calculations:

Eqn. No. Description Variable Name Equation Units Value 2.1 not used -- --

-- -- 2.2 not used -- --

-- -- 2.3 Boiler heat input Q B HVm-dot fuel MMBtu/hr 5,758 2.4 not used -- --

-- -- 2.5 not used -- --

-- -- 2.6 System capacity factor CF Plant (given) % 85 2.7 not used -- --

-- -- 2.8 SCR capacity factor CF SCR t SCR /365 % 1
2.9 NOx removal n NOx (NOx in - NOx out )/Nox in % 0.77 2.10 Stoichiometric ratio ASR (given) 1.05 2.11 not used -- --

-- -- 2.12 Flue gas vol. flow rate q fluegas q fuel Q B (460+T)/(460+700)n SCR acfm 2,786,871 2.13 not used -- --

-- -- 2.14 not used -- --

-- -- 2.15 not used -- --

-- -- 2.16 not used -- --

-- -- 2.16a not used -- --

-- -- 2.17 not used -- --

-- -- 2.18 not used -- --

-- -- 2.19 Catalyst volume Vol catalyst 2.81Q B n adj Slip adj NOx adj S adj T adj /n SCR ft 3 22,569 2.20 Adjusted NOx removal n adj 0.2869+(1.058)(n NOx ) 1.10 2.21 Adjusted NOx inlet NOx adj 0.8524+(0.3208)(NOx in ) 0.95 2.22 Adjusted NH3 slip Slip adj 1.2835-(0.0567)(Slip) ppm 1.17 2.23 Adjusted coal sulfur S adj 0.9636+(0.0455)(S) 1.00 2.24 Adjusted flue gas temp T adj 15.16-(0.03937)(T)+(2.74x10 - 5 )(T 2 ) 1.15 2.25 Catalyst area A catalyst q fluegas /(16x60) ft 2 2,903
2.26 SCR cross-section area A SCR (1.15)(A catalyst ) ft 2 3,338 2.27 SCR length or width l = w (A SCR ) 1/2 ft 57.78 2.28 Catalyst layer number n layer Vol catalyst /(h' layer x A catalyst ) 3 2.29 Catalyst layer height h layer Vol catalyst /(n layer x A catalyst ) + 1 ft 3.59 2.30 Total catalyst layer n total n layer + n empty 4 2.31 SCR height h SCR n total (c 1 +h layer )+c 2 ft 51.37 To develop SCR costs based on the OAQPS Cost Manual calculation

OAQPS Estimate, RB.xls Page 1 of 3 Printed: 3/29/2008 9:59 PMOwner: PNM Computed by: D. Fischer
Plant: San Juan Generating Station Unit: 3 Date: 2/14/2008 Project No.: 146646 File No.: Rev: B Verified by:
Black & Veatch Title: OAQPS SCR Cost Development Date:

2.32 Reagent flow rate m-dot reagent NOx in Q B ASRn NOx M reagent /M NOx lb/hr 515 2.33 Aqueous NH3 flow rate m-dot sol m-dot reagent /C sol lb/hr 1,775 2.34 Aqueous NH3 vol rate q sol (m-dot sol /p sol )v sol gph 237
2.35 NH3 tank volume Tank Vol q sol t gal 170,709 2.36 Direct capital cost DCC Q B (3380+f(h SCR )+f(NH 3rate )+f(new)))(3500/Q B ) 0.35 +f(Vol catalyst ) $ 22,327,117 2.37 Adj for SCR height f(h SCR ) (6.12)h SCR - 187.9 $/MMBtu/hr 126.46 2.38 Adj for NH3 flow rate f(NH 3rate ) 411(m-dot reagent /Q B )-47.3 $/MMBtu/hr -10.56 2.39 Adj for retrofit SCR f(new) dependent on retrofit/new $/MMBtu/hr 0.00 2.40 not used -- --

-- -- 2.41 not used -- --

-- -- 2.42 Adj for SCR bypass f(bypass) dependent on bypass $/MMBtu/hr 127.00 2.43 Initial catalyst charge f(Vol catalyst ) Vol catalyst CC initial $ 5,416,521 2.44 Initial reagent cost ICC Vol reagent Cost reagent $ 129,065 2.45 Direct annual cost DAC AMC + ARC + AEC + ACRC $/yr 3,458,228 2.46 Annual maintenance cost AMC 0.015(TCI) $/yr 473,340 2.47 Annual reagent cost ARC q reagent Cost reag t op $/yr 1,334,742 2.47a Operation time t ops (CF plant )(8760) hr 7,446 2.48 Electric power Power 0.105Q B (NOx in n NOx +0.5(dP duct +n total dP catalyst )) kW 2,255 2.49 Annual electricity cost AEC (Power)(Cost elect )t op $/yr 1,023,449 2.50 Cat replacement cost CRC n SCR Vol catalyst CC replace /R layer $ 2,181,654 2.51 Annual cat rep cost ACRC (CRC)(FWF) $/yr 626,696 2.52 Future worth factor FWF i(1/(1+i) Y -1) % 0.29 2.53 Constant y Y h catalyst /t ops 3.22 2.54 Indirect Annual Cost IDAC (CRF)(TCI) $/yr 2,978,663 2.55 Capital Recovery Factor CRF (i(1+i) n )/((1+i) n -1) % 9.44 2.56 Total Annual Cost TAC DAC + IDAC $/yr 6,436,891 2.57 NOx removed NOx NOx in n NOx Q B t ops ton 4,931 2.58 Cost effectiveness CE TAC/NOx $/ton 1,306

OAQPS Estimate, RB.xls Page 2 of 3 Printed: 3/29/2008 9:59 PMOwner: PNM Computed by: D. Fischer
Plant: San Juan Generating Station Unit: 3 Date: 2/14/2008 Project No.: 146646 File No.: Rev: B Verified by:
Black & Veatch Title: OAQPS SCR Cost Development Date:

Calculation of Capital Investment - OAQPS Method (No Adjustments)

(1998 $) Cost Parameter Variable Name Multiplier Equation Cost Amount Escallation to 2007 B&V Estimate Comments Total Direct Capital Costs A DCC 22,327,000 37,063,000 38,345,000

Indirect Installation Costs

General facilities 0.05 A 1,116,000 1,853,000 1,917,000 Engineering and home office fees 0.1 A 2,233,000 3,706,000 2,684,000 B&V used 7% Process contingency 0.05 A 1,116,000 1,853,000 1,917,000 Total Indirect Installation Costs B 0.05A + 0.10A + 0.05A 4,465,000 7,412,000 6,518,000

Project Contingency C 0.15 (A+B) 4,018,800 6,671,000 8,973,000 B&V used 20%

Total Plant Costs D A + B + C 30,811,000 51,146,000 53,836,000

Allowance for Funds During Construction E =0 (for SCR - OAQPS) 0 0 0 Royalty Allowance F =0 (for SCR - OAQPS) 0 0 0 Preproduction Cost G 0.02 (D+E) 616,000 1,023,000 1,077,000 Inventory Capital H ICC 129,000 129,000 129,000 Initial Catalyst and Chemical I =0 (for SCR - OAQPS) 0 0 0 Total Capital Investment TCI D + E + F + G + H + I 31,556,000 52,298,000 55,042,000

Calculation of Capital Investment - OAQPS Method (Adjustment for Missing Scope)

Cost Parameter Variable Name Multiplier Equation Cost Amount Escallation to 2007 B&V Estimate Comments Equipment Costs EC 18,331,000 See original est Installation Costs IC 20,806,000 See original est Total Direct Capital Costs from OAQPS A DCC 22,327,000 37,062,820 39,137,000

Additions for Missing Scope on Direct Installation Costs Elevator J B&V Estimate Used 1,236,000 1,236,000 SCR Bypass K B&V Estimate Used 10,000,000 10,000,000 Nox Monitoring System L B&V Estimate Used 440,000 440,000 Electrical Upgrades M B&V Estimate Used 484,000 484,000 Instrumentation and Control System N B&V Estimate Used 291,000 291,000

Subtotal of Missing Direct Capital Cost CC J+K+L+M+N 12,451,000 12,451,000

Gross Receipt Tax GRT 0.062 0.062 * (EC + CC) 1,848,000 1,908,000 From CUECost Freight FR 0.05 0.05 * (EC + CC) 1,491,000 1,539,000 From CUECost

Installation Costs on Missing Scope IMS 1.135 1.135*(CC+GRT+FR) 17,922,000 18,044,000

Air Preheater Modifications Q B&V Estimate Used 8,685,000 8,685,000 Balanced Draft Conversion R B&V Estimate Used 17,122,000 17,122,000 Site Preparation S B&V Estimate Used 2,000,000 2,000,000 Buildings & Enclosures T B&V Estimate Used 500,000 500,000 Total Cost of Missing Scope MS CC+IMS+GRT+FR+Q+R+S+T 62,019,000 62,249,000

Total Direct Capital Costs with Adjustments DCCA DCC+MS 99,081,820 101,386,000

Indirect Installation Costs

General facilities 0.05 A 1,853,000 0 Engineering and home office fees 0.1 A 3,706,000 0 Engineering (B&V Calculation) 0.07 DCCA 0 7,097,000 CUECost method Process contingency 0.05 A 1,853,000 0 Total Indirect Installation Costs from OAQPS B 0.05A + 0.10A + 0.05A 7,412,000 7,097,000

Project Contingency C 0.15 (A+CC+B) 8,539,000 0 Project Contingency (B&V Calculation) CBV 0.2 DCCA 0 20,277,000 CUECost method

Total Plant Costs D A+B+C 53,014,000 66,511,000

Allowance for Funds During Construction E =0 (for SCR - OAQPS) 0 0 Royalty Allowance F =0 (for SCR - OAQPS) 0 0 Preproduction Cost G 0.02 (D+E) 1,060,000 0 Inventory Capital H ICC 0 0 Initial Catalyst and Chemical I =0 (for SCR - OAQPS) 0 0 Total Capital Investment TCI D + E + F + G + H + I 54,074,000 66,511,000

Additions for Missing Scope on Indirect Costs

Owner's Costs OC 0.05 DCCA 4,954,000 5,069,000 Construction Management CM 0.10 DCCA 9,908,000 10,139,000 Construction Indirects CI B&V Estimate 25,498,000 25,498,000 Start-up and spare parts SU 0.03 DCCA 2,972,000 3,042,000 Performance Test PT B&V Estimate 200,000 200,000 Total Cost of Missing Indirect Costs Scope MICS OC+CM+CI+SU+PT 43,532,000 43,948,000

Subtotal of Indirect Costs IC B+C+E+F+G+H+MICS 60,543,000 71,322,000

Interest During Construction IDC 0.0741 See Note Below $17,742,000 $19,196,000 CUECost Allows Lost Generation During Outage GEN 5 weeks @ 0.06095 $/kWh 23,674,000 23,674,000

Total Capital Investment with Adjustments TCIA DCCA + IC+IDC+GEN 201,040,820 215,578,000

OAQPS Estimate, RB.xls Page 3 of 3 Printed: 3/29/2008 9:59 PM

### Appendix C Reference Equipment Quotations