Final Report

ANALYSIS OF MOG AND LADCO’S FG D AND SCR CAPACITY AND COST

ASSUMPTIONS IN THE EVALUATION OF PROPOSED EGU 1 AND EGU 2

EMISSION CONTROLS

Prepared for

Midwest Ozone Group

Prepared by

James Marchetti

J. Edward Cichanowicz

January 19, 20072 Executive Summary

The focus of this analysis is two-fold: (i) to evaluate differences in the levels of FGD and SCR capacity estimated by the Midwest Ozone Group (MOG) and the Lake Michigan Air Directors Consortium (LADCO) in their evaluations of proposed “CAIRPlus” control measures for electric genera tion units in the Midwest (EGU1 and EGU2); and, (ii) to assess the differe nce in control cost assumptions used in both analyses.

LADCO Database Accuracy

The LADCO database does not contain emi ssion controls on several units known to be installed and operating. These include , among others, SCR installations at Merom Units 1 and 2, and Petersburg Units 2 and 3. Omission of these and other control technology installations likely causes LADCO’s estimates of SO2 and NOx emissions to exceed expected levels, and thus to impose a higher percent reduction than is actually

needed.

Similarity of LADCO and MOG Technology Estimates When SO2 Allowances Are Not

Banked

The use of allowance banking in the LADCO study – and how allowances are used – is a primary factor responsible for differences in estimates of technology deployment between LADCO and MOG. LA DCO’s analyses assume that banked

allowances would be used to defer the instal lation of emission contro ls, thus deferring the

eventual costs of control with EGU1 and EGU2. However, if SO2 and NOx allowance banking is not considered, then estimate s of technology deployment between the two

studies would be similar.

Significantly Higher Capital Costs

LADCO’s capital cost estimates for EGU1 and EGU2 compliance are based on cost assumptions for FGD and SCR that do not reflect actual cost s incurred by industry. Specifically, LADCO’s FGD capital costs ar e approximately $200/kW below industry estimates, while SCR equipment costs range from $25 to $45/kW below industry experience. The IPM model’s significant unde rstatement of equipment capital costs explains much of the difference between M OG and LADCO’s estimates of the costs of implementing EGU1 and EGU2.

Finally, as discussed below, a number of assumptions were made in our assessment of LADCO’s control proposals, ba sed on limited information contained in the initial LADCO EGU White Paper. LADCO’s subsequent IPM modeling reveals several critical additional dimensions to the EGU pr oposals, including the use of multiple phases and a “floating” emission rate-based cap. Ou r estimates of EGU control costs assumed a more traditional tonnage-based cap similar to that used in the acid rain program and the

EPA NOx SIP Call.3 INTRODUCTION

In January 2005, the Midwest Regional Pl anning Organization (MRPO) issued a White Paper outlining a possible set of contro l measures that electric generating units within the states of Illinois, Indiana, Michigan, Ohio and Wisconsin would have to meet beginning in 2008 and with final implementati on in 2013. These control measures would establish regional emission caps based upon sp ecified emission rates for both NOx and

SO2. Two sets of emission rates are described in the White Paper: referred to as Electric Generating Unit (EGU) 1 and 2. Since the re lease of this initial White Paper, two

economic studies have been conducted to evalua te the compliance implications to electric generators in meeting EGU1 and EGU2. The first study was conducted by the Midwest Ozone Group (MOG) in the spring of 2005. 1 The second study was conducted by the Lake Michigan Air Directors Cons ortium (LADCO) in the fall of 2006. 2

This analysis evaluates differences in the levels of FGD and SCR capacity estimated by MOG and LADCO needed to comply with EGU1 and EGU2, and discusses differences in the control cost assumptions us ed in both analyses. The discussion of cost assumptions is an update of a previous analysis for MOG. 3

EMISSIONS, CAPS AND CONTROL TECHNOLOGIES – HAS THE IPM

ANALYSIS MODELED ENOUGH SO2 AND NOx CONTROL TECHNOLOGY

TO ACHIEVE EGU2?

This section evaluates th e level of SO2 and NOx cont rol technology that has been modeled by LADCO to achieve the reduction targets outlined by EGU2, and whether the level of capacity approaches the level of capacity modeled by MOG in order to achieve EGU2 emission caps.

It should be noted that LADCO’s (IPM) modeled control capacity seems to represent “summer net” capacity, while MOG’s estimated control capacity is the “nameplate” capacity of the affected genera ting units Therefore, to enable a better comparison between MOG and LADCO’s mode led control capacities, we converted MOG’s “nameplate” to “summer net” capacity.

SO2 and NOx Control Capacity in 2012

Before evaluating the LADCO modele d control capacities for EGU2, wecompared the level of existing, planned and modeled FGD and SCR expected to be online beginning in 2012 under CAIR. It should be not ed that 2012 is also the first year of

1 Marchetti, Cichanowicz and Hein, (MCH), Evaluation of the Midwest RPO Interim Measures and EGU1

and EGU2 , August 1, 2005.

2 ICF Resources, Implementation of EGU1 and EGU2 Policies Using the Integrated Planning Model in the Midwest RPO Region , September, 2006.

3 Marchetti, Cichanowicz and Hein, Comparison of FGD and SCR Capital Cost Assumptions Used by

MCH and EPA , September 29, 2005.4 implementation of EGU1 and EGU2 in the 5- State MRPO. The MOG capacity levels are drawn from its 2005 study and updated information from the Emission-Economic Modeling System’s Data Base, while the LADCO capacity levels were obtained from its VISTASII_PC_1f run, which includes the 5-State MRPO Region.

Table 1 compares the level of existing and planned capacity in both studies, revealing significant differences between the two sources. Specifically, MOG has identified almost 37.9 GW of FGD capacity th at is or will be in stalled (existing and planned) by electric generators in the 5-State Region by 2012, while IPM only shows 14.7 GW. This same type of differential can also be seen with regard to SCR capacity in the 5-State Region. Specifically, MOG estimat es 36.8 GW of SCR capacity (existing and planned) will be in operation by 2012, while IPM only has 26.4 GW operating in 2012.

Table 1: Comparison of 2012 Controlled Ca pacity in the 5-State MRPO (GW)

FGD Capacity Existing (2005) Planned Modeled Total

MOG 12.0 25.9 2.2 40.1

LADCO 11.9 2.8 18.4 33.1

SCR Capacity

MOG 27.5 9.3 9.1 45.9

LADCO 23.0 3.4 10.3 36.7
Note: 1. Existing is installed capacity for year end 2005. 2. Planned capacity is base d upon announced FGD and SCR syst ems by electric generators in the 5-

State MRPO

.

Even taking into account the modeled capacity (additional technology required beyond already known deployments) to meet CAIR for both SO2 and NOx, the IPM results fall significantly below the MOG results . Consequently, there is a concern that base data used in the IPM analysis is not reflective of industry experience/compliance, specifically with regard to what is installe d and planned to be installed. For example,

MOG indicates there are 27.5 GW of existi ng SCR capacity, while LADCO (IPM) shows only 23.0 GW, a 4.5 GW difference. In reviewing the IPM file ( VISTASII_PC_1f ), we noticed several operating S CRs missing, including E.W. St out 7 (422 MW), Merom 1 & 2 (1,020 MW), Warrrick 4 (270 MW) and Petersbur g 2 & 3 (917 MW). Therefore, if the base data is not correct, the question then ar ises whether the modeled data is a realistic representation of industry comp liance and thereby may have over-estimated pre-EGU 1

and 2 SO2 and NOx emission levels.

SO2 and NOx Control Capacity to Meet EGU2

The LADCO report contains several ne w elements related to EGU compliance with EGU1 and EGU2, which were not made known to us when our original work was undertaken in the spring of 2005. Th ese new elements are as follows:5 • EGU1 and EGU2 compliance date is 2012, whereas, the MOG analysis assumed 2013;

• The EGU SO2 and NOx emission caps are moving or floating caps, which change from year-to-year ba sed upon changes in annual heat input, unlike the MOG caps which are fixe d and based upon a historical baseline;

• Compliance with EGU1 and EGU2 utili zes two phases: (i) Phase I is from 2009 to 2011, which has caps based upon the Interim Measures in the White Paper; and, (ii) Phase II is 2012 and beyond and has caps based upon EGU emission rates from the White Paper;

• MRPO electric generators that over-c ontrol in Phase I are able to carryforward their excess/banked allowances for compliance in Phase II. This

feature was not included in the MOG analysis because phases were not assumed or modeled and the White Paper did not mention that generators would be allowed to carry-forward allowances from a earlier phase; and,

• MRPO electric generators are allowe d to sell excess/banked allowances from EGU1 and EGU2 compliance to electric generato rs outside the 5- State MRPO Region.

Our review compares incremental control capacity, as modeled by MOG and LADCO, which generators in the 5-State MR PO Region would install under EGU2. The LADCO EGU2 policy run is identified as LADCO_PC_1d . However, both analyses were modeled under different regulator y regimes; therefore, our approach compares outcomes under a similar regulatory regimes and data. As mentioned above, the MOG analysis assumed a 2013 compliance date, with no carry over of allowances from any earlier phases. Under this type of regulatory regi me, electric generators within the 5-State MRPO Region would be required to meet EGU2 SO2 and NOx emission caps by that date. The LADCO analysis indicates EGU2 would be implemented in 2012; however, between 2012 and 2020, generators are allo wed to carry-forward both SO2 and NOx allowances for compliance, as illustrated in Table 6 of the LADCO report.

There is a particular concern with re gard to modeling in 2012. The LADCO report illustrates in 2012 affect ed units within the 5-State MRPO Region would have SO2 emissions of 432,000 tons under EGU2. Also shown in Table 6, the 2012 EGU2 SO2 emission budget computed by IPM is 473,000 tons, which seems to allow the banking of excess allowances. However, there may be an issue concerning the precision of the IPM model related to emissions and banking, which ultimately would affect the deployment of technology. Since the model does not evaluate compliance on an annual basis, the LADCO report indicates the 2012 cap is an average of 2010 – 2013 year caps, which encompasses the two phases of EGU2. Als o, the related LADCO Stratus report seems to imply on pages ES-2 and ES- 4 that the SO2 emissions may be an average of the same

years. 4 As mentioned earlier, Phase II of EGU2 compliance begins in 2012, when

affected EGUs would have to meet SO2 emission caps based upon an SO2 emission rate

4 Stratus Consulting Inc., Benefit Study of MRPO Candidate Control Options for Electricity Generation

, August 25, 2006.6 of 0.10 lbs/mmbtu, and not an average or hybrid cap. Consequently, the lack of precision in the LADCO IPM report could erroneous ly project a 2012 EGU2 SO2 cap and emissions that are too high. This error creates unrealistic SO2 reduction targets and allowance banks from 2010 to 2013, which re sults in the deferral of technology deployment beyond 2012.

Differences in Heat Input Assumptions

Regardless of these concerns about banked allowances, our review of the LADCO report suggests that by 2020 el ectric generators would ach ieve the 2020 SO2 EGU2 cap

without the use of banked allowances. Further, their NOx emissions would be slightly above the EGU2 cap, requiring the withdr awal of a small amount of banked NOx allowances. In addition, as best as we can determine, LADCO’s 2020 regional heat input of 6,011 TBtu is comparable to M OG’s 2013 regional heat input of 6,088 TBtu. 5
A discrepancy does arise when performi ng the same calculation using the 2020 NOx EGU2 cap (from Table 6) and the EGU2 NOx emission rate. This method provides an estimate of 2020 regional heat input of 6,482 TB tu, representing a sign ificant difference. Therefore, two questions arise: (i) is th ere a computational error in computing the regional heat input; or, (ii) has the LADCO report included more capacity in computing the EGU2 NOx budget than they used in computing the EGU2 SO2 budget. Since this question cannot be answered based upon the av ailable information in the LADCO report, we used the regional heat i nput derived from the SO2 budget of 6,011 TBtu. This value is very close to MOG’s 2013 regional heat input (for units >25 MW) of 6,088 TBtu, and allows a better comparison of technology deployment.

Therefore, comparing MOG’s 2013 t echnology deployment with LADCO’s 2020 technology deployment is appropriate, becau se LADCO’s compliance requires either very little or no use of allowances, and the regional heat input is comparable to both studies. However, we were unable to obtai n and review the IPM parsed files for 2018 and 2020 for the EGU2 policy run ( LADCO_PC_1d ); consequently, we had to make

some inferences on the level of FGD and SCR capacity that would have to be installed within the LADCO region to meet EGU2 in 2020. To do this, we evaluated two distinct data sets, based upon available data.

Because only aggregated information is available from the LADCO report, we can make only initial comparisons be tween MOG’s 2013 compliance and LADCO’s 2018 compliance estimates. As shown in Tabl e 2, MOG’s FGD capacity in 2013 is about 9.3 GW greater than LADCO, while MOG’ s SCR capacity is 13.1 GW greater than

LADCO.

5 The 2020 LADCO regional heat input is determined by dividing the 2020 SO2 EGU cap of 301,000 tons (from Table 6) by the EGU SO2 emission rate (0.10 lbs/mmbtu) yields a regional heat input of 6,011 TBtu.7 Table 2: Estimated Incremental FGD & SCR Capacity under EGU2 (GW)

Study FGD SCR MOG (2013) 60.7 41.0 LADCO (2018) 51.4 27.9

As mentioned earlier, the LADCO analysis allows fo r the banking and carrying forward of allowances, which allows for the deferral of both FGD and SCR deployment, while the MOG analysis did not allow for this type of banking. Even with the use of banked SO2 allowances for compliance and a less stringent emission cap in the LADCO analysis, the levels of FGD capacity in the tw o studies are very close. So the question arises, when the banks are drawn down to zero, would the LADCO FGD and SCR capacity mirror the MOG capacity?

Comparison of Emissions and Caps

Evaluating regional heat input and emissions in 2020 may provide additional insight. Using the regional heat inputs desc ribed earlier and com puted emission rates from Table 6 of the LADCO report yields the following emission/cap comparisons for

both studies:

Table 3: 5-State SO2 & NOx Emissi ons and Caps under EGU2 (tons)

MOG (2013) LADCO (2020) Emissions Cap Over/Under Emissions Cap Over/Under SO2 371,536 304,403 67,133 300,530 300,530 0 NOx 249,203 213,082 36,121 213,391 210,385 3,006 Regional

Heat Input 6,088 TBtu 6,011 Tbtu

Note: 1. The 2020 LADCO NOx emissions are based upon multiplying a computed NOx emission rate (from Table 6) of 0.071 and multiplying it by the LADCO regional heat input. 2. The SO2 and NOx caps for both MOG and LADCO were computed by multiplying the EGU2

SO2 and NOx emission rate by the regional heat input.

As shown in the above table, both th e SO2 and NOx emission caps for both MOG and LADCO are very close; however MOG’s em issions are higher. The primary factor affecting the emissions disparity between MOG and LADCO are assumptions defining the capabilities of control tec hnologies. LADCO assumes more aggressive control levels can be achieved by FGD and SCR technology. Specifically, LADCO estimates that electric generators would achieve a NOx emission rate of 0.071 lbs/mmbtu and a SO2 emission rate of 0.10 lbs/mmbtu by 2020. In comparison, MOG estimated control levels

of 0.082 lbs/mmbtu for NOx and 0.122 lbs/mmbtu for SO2.

It should be noted that MOG modeling to achieve these NOx and SO2 emission

rates showed 18.6 GW of exis ting coal-fired capacity woul d switch to PRB coal with FGD systems. The LADCO study still models a NOx bank; however to achieve a region-8 wide SO2 emission rate of 0.10 lbs/mmbtu it would seem the LADCO modeling would require either: (i) a larger sh ift to PRB coal with scrubbing within the 5-State Region than projected by MOG; or, (ii) the retirement of a signifi cant amount of existing coal capacity. Therefore, it seems the use of banked a llowances has allowed LADCO to defer the level FGD and SCR capacity to 2020 or beyond what MOG projected in 2013 under a no allowance carry-over regime. This sugge sts that the compli ance implications discussed by MOG eventually would occur in the LADCO modeling if it were extended further in time.

IPM COSTS AND INDUSTRY EXPERIENCE

This second section of the analysis provi des an update of control technology capital costs for flue gas desulfurization (FGD) and NOx control, focusing on wet FGD for the former and selective catalytic reducti on (SCR) NOx control for the latter. The wet FGD process cited in this documents refers to a wet limestone-based process, producing gypsum as a byproduct, and capable of 95-97% SO2 removal, depending on coal composition and averaging time.

Background

There is considerable information both in the public domain and reported anonymously describing the capital and operating cost of process equipment to control SO2 and NOx. Significant discrepancies exist among these various data sources provided by equipment suppliers, EPA, and industry.

Recent capital cost estimates for conventional wet FGD and SCR reported by owners significantly exceed those estimated using information published by the supplier community or the EPA. Several factors are likely responsible for this discrepancy; one significant factor is the strong demand for e nvironmental control equipment, coinciding with strong demand for general chemical pro cess facilities. The confluence of these

demands escalates the cost of la bor and materials essential for th is category of equipment. Compounding these differences in capital cost estimates is that some source data from EPA may not represent current market conditions, due to both the methodology and timing of the estimate.

It is instructive to consider the esca lation in the cost for chemical process equipment. One popular indicator of such co sts is the Chemical E ngineering Plant Index,

which reflects the escalation in cost for a wi de variety of process equipment. Figure 1 depicts the change in the Chemical Engi neering Plant Index (Chemical Engineering, 2006) reflecting the construction cost of general plant proce ss equipment, specifically from 1995 through mid-2006.9 Figure 1: Chemical Engineering Pl ant Index (CEPI): 1995 – July 2006) (Note: 1957-1959 = 100)

200 250 300 350 400 450 500 550

1994 1996 1998 2000 2002 2004 2006 2008

Year of Cost BasisChemical Engineering Plant Index

Figure 1 shows little change in the Chemical Engineering Plant Index from 1995 through the end of 2003, but 2004 marked the beginning of significant escalation that

continues unabated. This trend reflects several factors importa nt to environmental controls, such as escalation in material cost for upgrading electrical equipment. Due to intensive use of copper and a four-fold increase in copper pr ices, this index has risen rapidly since 2003. Competition for materials from China, driven by their rapid electrification program, is adding demand-push pressures to U.S. pollution control construction costs. Figure 1 shows that even with all other factors equal, cost escalation due to a robust demand will increase installed cost of process equipment.

Comparison of FGD Estimates: 2000-2006

Estimates of capital and operating cost for both wet and dry FGD equipment have been derived in the last five to seven year s from a variety of sources. These include estimates for CAIR compliance, specific costs announced for CAIR retrofits, and projections by EPA and regul atory agencies based upon knowledge of equipment cost and availability. Compounding the complexity of preparing realistic cost estimates is the uncertainty in labor pool availability and co st, and the project scope – what equipment changes are included or exclude d in the budget. This secti on summarizes the cost trends noted prior to the year 2006.

Figure 2 presents a summary of FGD cap ital cost, shown as a function of unit generating capacity, for both dry and wet FGD, derived from a number of sources. All reported equipment costs have been adjust ed to the end-of-y ear 2005, using the GDP escalating factor. It should be noted that FGD costs for all generating stations are reported per unit of generating capacity, even for system-wide designs for large10 generating systems. For example, FGD cap ital for Duke Energy’s Allen Units 1-4 is reported for a single Allen un it capacity of 270 MW; however the design is predicated on the generating capacity of the entire station of 1200 MW. Consequently, the available economies of scale – particularly importa nt in reagent receiving and solid byproduct management - serve to reduce the unit cost.

Figure 2 shows a wide disparity in proj ected costs between several sources and periods of time. These are discussed in the following sections.

2006 EPA IPM Data

The lowest capital cost projections for wet FGD are derived by EPA using their IPM cost correlations, which are applied for EPA modeling of system compliance costs. The IPM supporting documentation (EPA, 2006) and the key source papers (Staudt, 2006, and Khan, 2004) describe the basis of the estimates. The estimating methodology appears to reflect authentic utility cost accoun ting, and considers both direct and indirect costs. However, it is not clear if these es timates reflect a complete suite of balance-ofplant items, such as upgrade of flue gas fans and electrical distri bution components, or

reflect the most rece nt market conditions.11 Figure 2: Wet and Dry FGD Capital Cos t: Estimates Prior to 2006 (End-of-Year 2005 Dollar Basis)

0 100 200 300 400 500 600

0 200 400 600 800 1000 1200 Generating Capacity, MWUnit Dry or Wet FGD Cost, $/kW (EOY 2005) Wet FGD: System Study Dry FGD and FF: System Study Belews Creek 1, 2 EW Brown, Ghent
Amos
Southeast Installation
Dallman31-32 SystemStudyD CinergyReference DryFGDStationA
WetFGDStationA FortMartin 1, 2 2004 Hatfield Ferry 1-3, 2004 Monroe 3, 4 2006
Allen 1-5 2006
IPM 2006 Wet FGD
Wet FGD 20042005
1999 IPM Curve Power (IPM 2006 Wet FGD)

Cinergy 2003 System

Wet FGD Reference

1999 EPA IPM Wet

FGD Reference Wet FGD Curve:

2004-2005

Installations

2006 EPA IPM Wet

FGD Reference

The EPA IPM capital costs were based on soliciting budget estimates of uninstalled capital equipment costs – and as st ated in the reference paper (Staudt, 2006) only one response was received. It is possible that the exploratory and budgetary nature of the estimate as developed by the supplier re sulted in an atypically low estimate, which could not be detected by comparison to other sources. In addition, the supplier developed equipment costs for a new “greenfield” appl ication, with the inst alled retrofit cost provided by a semi-quantitative “r etrofit” factor. The retrof it factor selected for this analysis of 1.3 – an appropriate selection by historical sta ndards – may be too small to reflect the complexity of the most recent sites for which FGD is considered. It is widely believed that the first 100,000 MW of FGD capac ity retrofit were installed first on those units that provided the lowest removal cost ($ per ton basis), which implies the least capital cost. The units remaining may pres ent more challenging site conditions for

retrofits.

Also shown in Figure 2 for comparison is the wet FGD capital cost curve used by EPA in IPM modeling in 1999, which has served as the basis for all but the most recent IPM modeling runs. The projected capital co sts (also in end-of-y ear 2005 dollars) are slightly higher than the upda ted 2006 cost curve. It is not clear why the 2006-derived costs are lower, given significant increases in demand and material cost as shown by Figure 1.12 Cinergy 2003 System Wet FGD Study

A comprehensive evaluation of wet F GD cost for the Cinergy system was conducted in 2003 by Sargent & Lundy Engineers. Individual data points derived in this analysis are not shown but th e curve fit for the seven units in the study is reported and corrected to an end-of-year 2005 dollar basis. The shape of the curve is similar to that projected by EPA, but for the same generati ng capacity, Cinergy pr ojects approximately $75 to $100/kW higher capital cost.

2004-2006 Industry Estimates

Figure 2 reports a locus of points for both wet and dry FGD, derived from numerous cost references in 2004 and 2006, so me of which are public. For example, AEP published wet FGD capital cost for Amos, and Allegheny Energy for both Hatfield Ferry Units 1-3 and Fort Martin Units 1 and 2. Detroit Edison released capital cost for

Monroe Units 3 and 4. Duke Power released costs for Belews Creek and five units at Allen, the latter each 270 MW but totaling 1200 MW of generating capacity. LG&E energy similarly published results for E.W. Brown and Ghent.

Several anonymous sources contribute d cost estimates based on thorough engineering procurement studies: a southeast utility and two system studies for operators

in the Midwest.

The locus of data points from these estimates –all derived during the 2004-2006

timeframe – is shown. Also shown is a curv e reflecting the genera l relationship between these data points. Significantly , these costs exceed those projected by EPA for IPM by over $200/kW – more than double the projected level

.

Sources for Cost FGD Differences

There are several reasons why EPA and industry-generated wet FGD capital costs differ to the extent reported in Figure 2. E ach of these is addressed in the following

sections. The individual data points on Figure 2 may not a ll be directly comparable. Except for adjusting all cost estimates to an end-of-year 2005 dollar basis, no effort has been made to assure a uniform basis. The following factors, also included in the EPA methodology (Staudt, 2006), are all usually deri ved as a fraction of the total process capital, which describes the total cost for pr ocess equipment prior to installation. The

cost factors are described as follows:

Engineering and Construc tion Management Charges . The cost for engineering services to define the design of process equipment, a nd management of these services, is generally 10%, similar to that assumed by Staudt (2006). It is possible that challenging retrofit requires greater engine ering expenditure.

Process & Project Contingency . The usual assumptions for these standard contingency values for the relatively mature wet and/or dry FGD is 10% and 5%, respectively. For13 reported costs that reflect firm prices from s uppliers, it is unlikely any such charges are

included as line-item cost elements. For these fixed price bids, each equipment and process supplier will utilize an internal propr ietary margin to account for uncertainties. Projects that are conducted on an “open book” basis with a strategic partner will not include such cost elements, but allow cost re covery if actual incurred costs exceed those predicted.

General Facilities . This cost element covers road s, providing for special access, and buildings; any differences ar e expected to be small.

Contractor Profit/Fees . These charges can be 5-10% of the total

Project Scope . The specific equipment included in the FGD budget can vary. For example, Staudt (2006) discusses the possi bility of fan modifi cations and ductwork changes in an FGD retrofit, but these items are not addressed in the cost estimate. The additional resistance to flue gas flow for a conventional wet and dr y FGD system – from 4 to 8 in w.g. – will in most cases require some type of fan upgrade. Further, depending on how the flue gas handling system was or iginally designed, a significant run of ductwork may have to be strengthened, to avoid damage from significant negative pressure. Again, there is no indication these or the costs – albeit very site specific – are

included in the EPA-derived estimates.

Timing of Costs . The significant demand in flue gas processing equipment – for both FGD and SCR – has evolved into a premium for equipment and services since 2000, and especially so in the last year.

The role of the project schedule and the s ubsequent timing of the cost estimate are shown by Figure 3. This figure repeats the curv e-fit description of capital cost presented in Figure 2, along with 2006 revised costs as reported for two Allegheny Power stations – Fort Martin and Hatfield Ferry. Fort Martin ’s capital costs escalated significantly from estimates prepared in 2004.

Discussions with representatives of arch itectural engineeri ng companies involved in wet FGD procurement indicate that a strong demand for essential equipment and services is responsible for the cost escalation. Specific examples are:

Limited access to flue gas fans and slurry pumps . A limited number of equipment suppliers are qualified to provide the large, high reliability fans fo r flue gas and pumps for process slurry that are cri tical to reliable performance. At present, the manufacturing capabilities of key suppliers are booked – and establish the limiting step in FGD

installation of 30-36 months. Both the s hortage of equipment and willingness of purchasers to pay to expedite procurem ent contribute to these higher costs.14 Figure 3: FGD Capital Cost: 2004 vs. 2006 Es timates (End-of-Year 2005 Dollar Basis)

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) CinergyReference

FortMartin 1, 2 2004

Hatfield Ferry 1-3, 2004

2006 EPA IPM

RecentPowerLaw

Fort Martin 1-2 2006

Hatfield Ferry 1-3 2006

Power (2006 EPA IPM)

Cinergy 2003 System

Wet FGD Reference

2006 EPA IPM wet

FGD Reference 2006 vs. 2004:
Fort Martin 1, 2 2006 vs. 2004 Hatfield Ferry 1-

Wet FGD Curve:

2004-2005

Installations

Some observers have noted that the U. S. utility industry qualifies a limited number of suppliers of this equipment, and th at relaxing qualification requirements is one way to increase the number of suppliers (Hartenstein, 2006). Given the large and complex nature of recent system FGD installa tions, it is not known if this action would introduce the use of equipment with less proven reliability.

Limited Stack Erectors . Similarly, there are reportedly a limited number of suppliers

world-wide that can fabricate the wet stack de signs required to withstand the wet flue gas from FGD. Similar to the case for flue gas and slurry equipment, this can be a limiting step in FGD process installation. At presen t, it is reported that the four major stack erectors are booked through 2010; any new inst allation reportedly will not be able to install new wet stacks before the beginning of 2011.

Electrical Equipment. The requirement for additional power for pumps, fans, and associated equipment can significantly in crease the on-site demand for power, and

distribution such as motor control centers for power management and distribution. The cost of these upgrades – dependent on c opper-containing products – has increased reflecting the four-fold increase in copper prices in recent ye ars. Upgrade of electrical subsystems – historically 6-8% of an FGD project - can now exceed 15%.

Installation Difficulty. The units reflected in Figure 2 and 3 represent approximately the

second 100 GW of wet FGD installed. As di scussed previously, th e first 100 GW were initially selected for a large number of reasons – of which ease of retrofit and low capital15 cost was likely the most significant factor. It is these early applicati ons that provided the

bases for the historical retrofit factor of 1.3. It is likely th at units within the second 100

GW of retrofit candidates re present more difficult retrofit applications, which the

historical 1.3 retrofit fact or does not capture. Compounding the retrofit difficulty is the higher cost of labor, due to shortages reported by many operators of FGD process equipment.

In summary, the capital cost for wet FGD process equipment between estimates derived for use in IPM modeling and indus try-reported costs differ significantly, by approximately a factor of two. The key reasons for this difference are likely the timing of the estimates (e.g. reflecting 2005 and 2006 market conditions), the complexity of the retrofit sites, and the scope of equipment included.

The consequence of the difference in capit al cost, combined with differences in operating cost assumptions (the latter not addressed in this document) is a similarly wide difference in calculated cost pe r ton ($/ton) of SO2 removal. Specifically, the reported marginal cost values in Table 3 of the IC F report for the EGU2 category notes a range from $1,847 to $2,951/ton for SO2. In contrast, the recent analysis of the authors evaluating the IL Mercury Rule reports dry FGD removal costs between $2,600 and $4,200/ton. 6 These costs are based upon inputs from system generators in Illinois and reflect industry FGD capital cost s discussed in this section.

SCR NOx Control

Similar to the case of wet FGD, capital cost estimates derived for SCR NOx control from industry-reported sources and EP A differ significantly. Several reports of SCR capital cost have been published in re cent years (Hoskins, 2003; Cichanowicz, 2004; Marano, 2006). The most detailed and comprehensive analysis is provided by Marano, reporting global trends based on a pproximately 70 SCR installations erected between 1999 through 2005. As shown in Tabl e 4, Marano reports most SCR costs range from $100 to $200/kW. There is a noted increase in capital cost for un its installed after

2003.

It is instructive to compare the tre nd in reported and estimated SCR capital between industry sources and projections by EP A. Figure 4 depicts this trend, utilizing the individual data points reported by Cicha nowicz. (Marano did not report individual data so developing such a trend is not possi ble). Figure 4 shows th e wide disparity in capital cost for industry-reported units, whic h vary by a factor of two or more. The industry-reported data show that increasing generating capacity does not always lower unit (e.g. per $/kW) process cost, as the co mplexities imposed by the larger generating sites can complicate installation and elevate co st. Also shown on Figure 4 is the trend in projected SCR capital using the relations hip employed in EPA IPM modeling (Khan, 2004). This trend is well be low that reported by industry.

6 Testimony of James Marchetti before the Illinois Pollution Control Board in rulemaking R06-25 dated July 28, 2006.16 Table 4: SCR Capital Cost Survey Results

Reference Average Capital,

MW ($/kW) Low-High

Cost

Observed ($/kW) Observation

Hoskins, 2003 120 (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 81 (600-899 MW) to 123 (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.”

As explained by Khan (2004), the EPA IP M methodology uses reports of industry SCR costs but adopts these into a fixed scaling relationship. In contra st, we relied on the trend curve depicted in Figure 4 to estimate SCR capital costs.17 Figure 4. SCR Capital Cost: Industry Reports versus EPA IPM Modeling (2005 End-of-Year Dollar Basis)

0 50 100 150 200 250

0 200 400 600 800 1000 1200 1400

Unit Generating Capacity, MWSCR Capital Cost ($/kW, 2005)

EPA IPM SCR

Cost Curve Curve Fit of Data From Industry Survey

The reason for the disparity in SCR capital costs is likely the same as cited for wet FGD: the recent escalation in material prices has elevated the cost of materials and labor, and the plant sites for indus try-reported costs may be more complex than earlier estimates. Consequently, the difference between EPA and estimates derived from industry experience for SCR equipmen t can range from $25 to $45/kW.

Similar to the case for wet FGD, the EPA IPM cost assumptions for SCR are significantly below those repor ted by industry. The consequence of the difference in capital cost, combined with differences in operating cost assumptions (the latter not addressed in this document) is a similarly wide variance in calculated cost per ton ($/ton) for SCR NOx removal. Specifically, the reported marginal cost values in Table 3 of the ICF report cites for the EGU2 category a range from $$639 to $1,020/ton for NOx. In contrast, the MCH recent analysis evaluati ng the IL Mercury Rule reports SCR NOx removal costs between $1,500 to $9,800/ton. 7 These costs are based upon inputs from system generators in Illinois and reflect i ndustry SCR capital costs discussed in this

section.

7 Ibid.18 References

Author, Date Reference

Chemical Engineering,

2006 Economic Indicators , Chemical Engineering, October, 2006

Cichanowicz, 2004 Cichanowicz, J.E., Why are SCR Costs Still Rising , Power Magazine, April, 2004. EPA, 2006 Documentation for EPA Base Case 2006 (V.3.0) Using the Integrated Planning Model, Environmental Protection Agency, 2006, November, 2006. Hartenstein, 2006 Hartenstein, H., personal communication, August 30, 2006. Hoskins, 2003 Hoskins, B., et al., Uniqueness of SCR Retrofits Translates Into

Broad Cost Variations , Power Engineering, May, 2003. Khan, 2004 Khan, S., Updating Performance and Cost of NOx Control Technologies in the Integrated Planning Model , Proceedings of the 2006 Mega-Symposium, August, 2006, Baltimore, MD. Marano, 2006 Marano, M., et al., Estimating SCR Installation Costs , Power, January/February 2006 Staudt, 2006 Staudt, J. et. al., Updating Capital Cost of SO2 Control Technologies in the Integrated Planning Model and the Coal Utility Environmental Cost Model , Proceedings of the 2006 Mega-Symposium, August, 2006, Baltimore, MD.