### 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.