### CURRENT CAPITAL COST AND COST

- EFFECTIVENESS

OF POWER PLANT EMISSIONS CONTROL TECHNOLOGIES

Prepared by J. Edward Cichanowicz

Prepared for Utility Air Regulatory Group

July 2013

### TABLE OF CONTENTS

SECTION 1 OVERVIEW AND SUMMARY 1

- 1

SECTION 2 BACKGROUND 2

- 1

2.1 Introduction 2

- 1

2.2 Environmental Mandates 2

- 1

2.3 FGD and SCR Inventory 2

- 2

2.3 New Genera ting Stations 2

- 6

SECTION 3 FACTORS AFFECTING REPORTED CAPITAL COST 3

- 1

3.1 Capital Cost Reporting Methodology 3

- 1

3.2 Capital Cost Escalation 3

- 2

3.3 Site and Design Factors 3

- 2

SECTION 4 MAT ERIAL AND LABOR ESCALATION 4

- 1

4.1 Basic Materials 4

- 1

4.2 Construction Labor 4

- 4

SECTION 5 FLUE GAS DESULFURIZATION COSTS 5

- 1

5.1 FGD Capital Costs 5

- 1

5.1.1 Wet FGD 5

- 1

5.1.2 Dry FGD 5

- 3

5.2 FGD Operating Cost 5

- 4

5.2.1 Wet FGD 5

- 5

5.2.2 Dry FGD 5

- 5

5.3 Levelized Removal Cost Per Ton 5

- 6

SECTION 6 SELECTIVE CATALYTIC REDUCTION COST 6

- 1

6.1 SCR Capital Cost 6

- 1

6.2 Operating Cost 6

- 4

6.2.1 SCR Catalyst 6

- 5

6.2.2 Reagent 6

- 6

6.2.3 Example Operating Cost 6

- 7

6.2.4 Levelized Remova l Cost P er Ton 6

- 8SECTION 7 FABRIC FILTER CONTROL TECHNOLOGY COSTS 7

- 1

7.1 Fabric Filter Capital Cost 7

- 2

7.1.1 Good Site Access 7

- 3

7.1.2 Limited Site Access 7

- 4

7.2 Example Operating Cost 7

- 6

7.2.1 Fixed O&M 7

- 6

7.2.2. Variable O&M. 7

- 6

7.3 Levelized Cost 7

- 7

SECTION 8 COST COMPETITIVENESS 8

- 1

8.1 Power Market Reference 8

- 1

8.2 SCR, FGD Reference Unit Cost 8

- 3

8.3 Role of Fabric Filter 8

- 4

APPENDIX A EX AMPLE WET FGD CAPITAL COST DATA A

- 1

APPENDIX B EXAMPLE SCR CAPITAL COST DATA B

- 1LIST OF FIGURES

Figure 2

- 1. Historical and Projected Wet, Dry FGD Capacity: Installed MW

per Year

................................ ................................ ................................ ....... 2

- 3 Figure 2

- 2. Historical and Projected Wet, Dry FGD Capacity: Cumulative MW

per Year

................................ ................................ ................................ ....... 2

- 3 Figure 2

- 3. Historical and Projected SCR Capacity: Annual Installed Capacity

(MW)

................................ ................................ ................................ ........... 2

- 4 Figure 2

- 4. Historical and Projected SCR Capacity : Cumulative Installed SCR

Capacity (MW)

................................ ................................ ........................... 2

- 5 Figure 2

- 5. Historical, Projected FGD and SCR Annual Capacity (MW)

...................... 2

- 5 Figure 2

- 6. Historical, Projected FGD and SCR Cumulative Capacity (MW)

............... 2

- 6 Figure 3

- 1. Bureau of Economic Analysis (BEA) Implicit GDP Deflator

..................... 3

- 3 Figure 3

- 2. First Energy Sammis Station: Constrained Site

................................ .......... 3

- 6 Figure 3

- 3. Confined Site at PNM San Juan Station: Retrofit Fabric Filters, Upgraded

FGD, Candidate SCR Locations

................................ ................................ . 3

- 8 Figure 4

- 1. Steel Mill Products Cost History

................................ ................................ . 4

- 2 Figure 4

- 2. Iron Ore Cost Escalation

................................ ................................ .............. 4

- 2 Figure 4

- 3. Price History Escalation: Nickel, Molybdenum, and Copper

..................... 4

- 3 Figure 4

- 4. U.S. Bureau of Economic Analysis Finished Goods Capital Price Index

... 4

- 4 Figure 4

- 5. U.S. Bureau of Economic Analysis Private Industry Construction Worker

Labor Rate Index

................................ ................................ ......................... 4

- 5 Figure 5

- 1. Wet FGD Pro cess Equipment Cost: Four Periods of Deployment

............. 5

- 2 Figure 5

- 2. Dry FGD Process Equipment Cost: Various Sources

................................ . 5

- 4 Figure 5

- 3. Calculated SO 2 Removal Cost per Ton: Wet FGD Retrofit to 500 MW

Reference Unit

................................ ................................ ............................ 5

- 7 Figure 6

- 1. Capital Cost of SCR Process Equipment vs. Generating Capacity:

............ 6

- 2 Figure 6

- 2. Increase in SCR Capital Cost Based on Four Time Periods (Three

Increments)

................................ ................................ ................................ . 6

- 3 Figure 7

- 1. Fabric Filter Particulate Control Device and D etail of Filter Material

........ 7

- 1 Figure 7

- 2. Fabric Filter Capital Cost (2011 $ Basis) vs. Generating Capacity

............. 7

- 2 Figure 7

- 3. Dai ryland Power Madgett Unit 1: Fabric Filter Installation

....................... 7

- 3 Figure 7

- 4. Dynegy Vermilion Units 1 and 2: Fabric Filter Installation

....................... 7

- 4 Figure 7

- 5. Arizona Public Service’s Cholla Units 3 and 4: Fabric Filter Retrofit

(Moderate Difficulty)

................................ ................................ .................. 7

- 5 Figure 7

- 6. Alliant Lansing Unit 4: Fabric Filter Retrofit (Moderate D ifficulty

........... 7

- 5 Figure 8

- 1. Competitive Power Landscape: Wholesale (Peak) Power Prices, and Fuel

Cost for Generating Options

................................ ................................ ....... 8

- 2 Figure 8

- 2. FGD and SCR Incremental and Total Carrying Costs Compared to Fuel

Costs for NG/CC and Steam Boilers

................................ .......................... 8

- 3 Figure 8

- 3. Fabric Filter Total Cost vs. NG/CC Fuel Charge: 300 and 500 MW

Units

................................ ................................ ................................ ............ 8

- 5 Figure A

- 1. Individual Cost Data for Wet FGD: Phase 1 CAAA Applications (Curve A

of Figure 5

- 1)

................................ ................................ ............................. A

- 1Figure A

- 2. Individual Cost Data for Wet FGD: 2003

- 2007 Applications (Curve B of Figure 5

- 1)

................................ ................................ ................................ . A

- 2 Figure B

- 1. Individual Cost Data for SCR: Curve B of Figure 6

- 1

............................... B

- 1LIST OF TABLES

Table 3

- 1. Comparison Proximate Analysis, Select Ash Constituents, and Trace

Constituents of Three Commonly Used U.S. Coa ls

................................ ..... 3

- 4 Table 5

- 1. Example Fixed, Variable O&M for Wet FGD

................................ .............. 5

- 5 Table 5

- 2. Example Fixed, Variable Operation and Maintenance for Dry FGD

............ 5

- 6 Table 6

- 1. Key SCR Operating Cost Components: 500 MW Reference Plant

............. 6

- 8 Table 7

- 1. Key Fabric Filter Operating Cost Components: 500 MW Reference Plant

($250/kW Capital, 2011 Dollar Basis)

................................ ......................... 7

- 7Overview and Summary

1

- 1 SECTION 1

OVERVIEW AND SUMMARY

The utility industry is well into a third consecutive decade of aggressively retrofitting flue gas emission contr ols to existing power plants. These actions are in response to several federal and state mandates, including the Clean Air Interstate Rule (CAIR) and the Cross State Air Transport Rule (CSAPR) which require retrofit of flue gas desulfurization (FGD) and se lective catalytic reduction (SCR) at many units by 2015. In a parallel effort, environmental controls are being retrofit to satisfy the Mercury and Air Toxics Standards (MATS). Further, FGD and SCR can be required to address regional haze through the Clean Air Visibility Rule (CAVR), as well as the increasingly stringent National Ambient Air Quality Standards (NAAQS). Finally, individual utility company Settlement Agreements with EPA and the Department of Justice (DOJ) over alleged New Source Review (NSR) v iolations will influence equipment installation for some owners. Many of these mandates require controls to be installed and operating by 2015.

The robust demand for control equipment experienced from 2006 through 2009 which strained international and dom estic supply chains has relaxed. As a result, the availability and price of key components and corrosion

- resistant metals (such as C276 Hastolloy) have changed

– to the benefit of the purchaser. However, despite an increase in the supply of construction la bor, hourly labor rates continue to increase, although less aggressively than in 2006

- 2009.

The capital cost to retrofit FGD and SCR equipment continues to escalate. This report also addresses the cost for fabric filters

– heretofore not tracked over time

– and shows such equipment is less costly than FGD or SCR, but still requires substantial investment. A key reason for continued escalation of FGD and SCR cost is the ever

- increasing complexity of the host sites. The remaining units to be retrofit are typ ically located at older and more crowded sites, which provide less space to locate equipment and for construction. Such retrofits typically require convoluted and complex ductwork, increasing installation difficulty.

Capital cost for present

- day FGD insta llations in 2012 and planned for 2014 has slightly escalated from the 2008

- 2011 timeframe. Specifically, retrofit of wet FGD to a 500 MW unit in the 2012

- 2014 timeframe requires $500/kW (2011 dollars).

The levelized cost of SO 2 removal is determined from capital and operating cost, and reported as the cost to remove one ton of SO 2 . At $500/kW, a wet FGD process retrofit to a 500 MW unit firing coal with sulfur content of 5 lbs/SO 2 /MBtu, and incurring typical operating costs will expend near $600 to remove each ton of SO 2. For a coal with this sulfur content, each increase in wet FGD capital cost by $100/kW elevates the cost of SO 2 removal by almost $100 per ton. For PRB coal with a sulfur content of 0.9 lb SO 2 /MBtu, a $500/kW wet FGD process retrofit to a 5 00 MW plant will expend $2,300/ton for SO 2 removal. For this PRB coal each $100/kW increase in FGD capital cost will increase SO 2 removal cost by $400/ton.Overview and Summary

1

- 2 Capital cost for SCR NO x control has escalated at a materially higher rate over the same time perio d. Recent data show a 500 MW unit retrofitting SCR between 2012 and 2014 would incur on average a capital cost of $425/kW, which could vary between $300 and $550/kW (in 2011 dollars).

The prices for consumables driving SCR operating cost

– catalyst and r eagent

– continue to evolve. Catalyst unit price has remained low in the last 4

- 5 years, with new catalyst requiring a cost of approximately $5,000/cubic meter. The cost of ammonia

- based reagent appears to have “decoupled” from the historical relationship with natural gas, due to strong fertilizer demand. Typical delivered cost for anhydrous ammonia is $600

- 800/ton and these prices are expected to persist through about 2015. For most SCR applications, reagent has replaced catalyst supply as the largest SCR operating cost component.

Similar to SO 2 , the levelized cost for NO x control is determined from capital and operating cost, and reported as the cost to remove one ton of NO x . For a typical 500 MW unit firing an eastern bituminous coal, and equipped with a boiler generating 0.38 lb/MBtu of NO x , an SCR process requiring $450/kW provides NO x removal for about $5,200/ton. For this same unit, each $100/kW increase in SCR capital cost elevates NO x removal cost by about $1,200/ton. For a 500 MW unit firing PRB an d producing NO x at a rate of 0.20 lb/MBtu, an SCR process requiring $450/kW provides NO x removal for about $11,000/ton. Each $100/kW increase in SCR capital cost incurred for this unit increases NO x removal cost effectiveness by $2,400/ton.

More important than calculated cost per ton of pollutant removal is the impact of retrofit environmental controls on the cost

- competitiveness of a unit in wholesale power markets. It is well known that recent low natural gas prices have reduced wholesale power prices in the U.S., by an average of 12% in 2012 compared to 2011. Excluding the hydropower

- dominated CAISO region in the Pacific Northwest, wholesale power prices throughout the U.S. ranged from about $30/MWh at Palo Verde to $46/MWh for NYISO. The retrofit of FGD alone for a 500 MW unit can add $16/MWh to the production cost that must be bid into the market

– approximating the fuel cost for a coal

- fired boiler. Such an additional cost can render a unit uncompetitive.

In summary, although material and labor shorta ges witnessed during the 2006

- 2009 timeframe have abated, the cost to retrofit FGD and SCR equipment continues to increase. The extent of escalation is small for wet FGD, but notable for SCR. The cost increases are driven by the increasing complexity of sm aller sites, hosting generally older units. Typically, large units with accessible, open sites have already been retrofit, as the most cost effective projects were first sought. The additional cost of deploying FGD and SCR has reduced the competitiveness o f these units compared to natural gas

- fired generation.Background

2

- 1 SECTION 2

BACKGROUND

2.1 INTRODUCTION The cost to retrofit air pollution controls to coal

- fired power stations escalated rapidly over the
ten

- year period starting from the year 2000. Despite the slowi ng world

- wide economy, the cost to retrofit air pollution controls since 2010 remains at elevated levels.

Several factors drive the escalated costs. First, although prices for specialized materials of construction have subsided, specialized labor costs h ave not materially changed. Perhaps more important, the remaining generating sites to be retrofit are more challenging

– these complex sites’ limited access for construction personnel and equipment.

These costs are not anticipated to relax. Several compe ting mandates are evolving that will require additional equipment operating within the next few years. A review of these mandates and cost pressures follows.

2.2 ENVIRONMENTAL MANDAT ES Several major environmental control regulations have been issued in re cent years, all requiring compliance within a short time period.

Most notably, the Clean Air Interstate Rule (CAIR) and the Cross State Air Transport Rule (CSAPR)

– require retrofit of FGD and SCR at many units by not later than 2015. At nearly the

same time, environmental controls are required to satisfy the Mercury and Air Toxics (MATS) rule. Further, initiatives to address regional haze such as the Clean Air Visibility Rule (CAVR) and increasingly stringent National Ambient Air Quality Standards (NAAQS ) can affect SO 2 and NO x emission rates and the need for FGD and SCR. Finally, individual utility company consent decrees with EPA, the Department of Justice (DOJ) and some states over alleged New Source Review (NSR) violations will influence equipment ins tallation for some owners.

Each of these mandates is described as follows.

Clean Air Interstate Rule (CAIR) and the Cross

- State Air Pollutant Rule (CSAPR). The details and history of how these two inseparable rules evolved is beyond the scope of this p aper. In brief, both rules employed Phase 1 and Phase 2 compliance dates for SO 2 and NO x emissions which were vacated by the courts. CSAPR was proposed in August of 2011 to replace CAIR

– the latter vacated in 2008. However, CSAPR itself was vacated in Aug ust of 2012

– altering the 2015 plans for many operators. With CSAPR vacated, CAIR has been reinstated

– thus CAIR’s Phase 2 mandate is in force requiring additional FGD and SCR by 2015.Background

2

- 2 Mercury and Air Toxic Standards (MATS). The MATS rule, by requiring control of mercury (Hg), fine particulate matter, and hydrogen chloride (HCl), requires additional control equipment to be installed by 2016. This rule requires the retrofit of baghouses to enable controlling fine particles and providing a favorable envir onment to remove Hg and HCl with reagents. The MATS rule also prompts owners to consider upgrades or refinements to SCR and FGD, which through “co

- benefits” remove Hg.

National Ambient Air Quality Standards (NAAQS). NAAQS are reviewed every 5 years as

s tipulated under the Clean Air Act and often result in lower ambient standards. EPA’s revisions to NAAQS require States with air basins exceeding the ambient standards to develop State Implementation Plans (SIPs) to improve air quality. States predominantly look to power plants to further reduce emissions.

Clean Air Visibility Rule (CAVR). This federal regulation requires all states to revise their SIPs to improve visibility in Mandatory Class I Federal Areas, which are national parks and wilderness areas. Consequently, states may require retrofit of emissions controls, above and beyond other environmental requirements, to achieve “reasonable progress” toward improving visibility in Mandatory Class I Federal Areas. These plans designate a Best Available Retr ofit Technology (BART) that must be installed.

For example, the states of Illinois, Indiana, Michigan, and Wisconsin, through the Lake Michigan Air Directors Consortium, periodically consider controls for SO 2 and NO x beyond other federal programs (e.g., C AIR or CSAPR). Regulatory agencies in other regions in the country such as the southeast (VISTAS) and far west (WRAP) routinely consider revising local mandates. The extent and timing of these mandates is uncertain, but some initiatives could be proposed t o require control equipment during the 2014 to 2018 period.

Settlements Regarding Alleged NSR Violations . Allegations by the U.S. EPA that provisions of the CAA regarding NSR were violated prompted several owners to agree to install FGD and SCR on sched ules that differ from those required to meet CAIR.

2.3 FGD AND SCR INVENTOR Y Figures 2

- 1 to 2

- 6 report the inventory of FGD (both wet and dry) and SCR process equipment that has been installed, or is planned to be installed, to meet regulatory mandates. F igure 2

- 1 shows the generating capacity (MW) equipped with either wet or dry FGD each year through 2012, and projections for 2013 through 2015. The peak of at least 20,000 MW each year occurred in 2008, 2009, and 2010. Figure 2

- 2 presents the cumulative ca pacity equipped with FGD since 2001

– approaching 120,000 MW by the end of 2012. Added to the inventory of almost 96,000 MW prior to the year 2002, at about 225,000 MW of the U.S. coal

- fired fleet will be equipped with FGD by 2015.Background

2

- 3 Figure 2

- 1 . Historical and Projected Wet, Dry FGD Capacity: Installed MW per Year

Figure 2

- 2 . Historical and Projected Wet, Dry FGD Capacity: Cumulative MW per YearBackground

2

- 4 The trends in SCR are equally important. Figure 2

- 3 shows the annual generating capacity retrofit with SCR over the same time period. Since the peaks in 2002 to 2004, the generating capacity retrofit with SCR in e ach year ranges between about 4,000 and 10,000 MW. Figure 2

- 4 presents the cumulative generating capacity equipped with SCR, which approaches 130,000 MW in 2012.

One additional factor prompting SCR and FGD retrofit is their removal of Hg and other hazardo us air pollutants (HAPs) by “co

- benefits”. Specifically, SCR is known to prompt Hg oxidation to a soluble state (mercuric chloride, Hg(Cl) 2 ) increasing removal by wet FGD. A select inventory of units is equipped with both SCR and FGD. Figures 2

- 5 and 2

- 6 r eport this inventory in terms of annual and cumulative generating capacity, respectively. Both figures identify the installation year as the first year of operation with both control systems. Unlike Figures 2

- 1 and 2

- 2, the data in Figures 2

- 3 and 2

- 4 refl ect FGD installed prior to 2002. (Thus, almost all of the FGD equipment reported for the years 2003 through 2005 reflect FGD installed prior to 2002). Figure 2

- 6 shows almost 70,000 MW of capacity is equipped with both SCR and FGD through 2012. Many of the se units are operated to provide some degree of Hg removal.

Figure 2

- 3 . Historical and Projected SCR Capacity: Annual Installed Capacity (MW)Background

2

- 5 Figure 2

- 4 . Historical and Projected SCR Capacity: Cumulative Installed SCR Capacity (MW)

Figure 2

- 5 . Historical, Projected FG D and SCR Annual Capacity (MW)Background

2

- 6 Figure 2

- 6 . Historical, Projected FGD and SCR Cumulative Capacity (MW)

2.3 NEW GENERATING STATI ONS The projected number of new coal

- fired units planned to begin operations between 2013 and 2020 has decreased notably. As of early 2013, approximately 2,500 MW of coal

- fired capacity is either in final engineering or under construction. The efforts to acquire the necessary permits have been initiated

– and in some case completed

– for an additional 4,300 MW but it is not clear how many of proposed units will actually be built. Both the present economic climate, and the regulatory uncertainty with regard to CO 2 regulation have all dampened interest

. Th e most notable source of regulatory uncertainty is EPA’s April 13, 2012 proposed New Source Performance Standards (NSPS) for CO 2 emissions from coal

- fired power stations.Factors Affecting Reported Capital Cost

3

- 1 SECTION 3

FACTORS AFFECTING RE PORTED CAPITAL COST

This section reviews the factors tha t affect the capital cost for air pollution control equipment. These factors include (a) the methodology by which costs are developed, (b) how cost is escalated over time, (c) features of the host power stations.

3.1 CAPITAL COST REPORTI NG METHODOLOGY

A ccurately reporting the cost for air pollution control equipment requires a consistent accounting method. Both direct and indirect costs to acquire the process, and fixed and variable operating costs must be accounted for. EPRI’s Technical Assessment Guide 1 provides one such methodology which has served as a model used by DOE, EPA, and other organizations assess
costs.

The focus of this report is installed capital cost for environmental control equipment. The capital cost consists of several key components , defined as follows:

Process Equipment . The reaction vessels, absorbers, reagent receiving and supply systems, process controls, and initial inventory of catalysts, reagent, and filter (for baghouses) comprise this category of cost.

General Facilitie s . The land occupied by the process, access roads, support buildings and laboratories make up general facilities.

Installation Charges . These costs include construction and installation labor, materials, and special equipment (rental of cranes, etc.).

E ngineering Charges . Engineering charges include selecting the process, defining the specific conditions are the site, optimizing the process design for the site, integrating the process design with balance

- of

- plant equipment, and procurement.

Owner’s Cos ts . Owner’s costs include staff for management, engineering, and developing proper operating practices.

Finance, Other Charges . Finance charges are mostly Allowance for Funds Used During Construction, an accounting charge to accommodate the financing during construction when the equipment is not in use. In addition, some states (e.g., New Mexico) impose a “gross receipts” tax, essentially a sales tax on industrial equipment.

1 TAG TM Technical Assessmen t Guide: Electricity Supply

– 1993 , EPRI TR

- 102275

- V1R7, Volume 1: Rev 7, June 1993.Factors Affecting Reported Capital Cost

3

- 2 Preproduction, Inventory Capital . Spare parts and the initial (typically 30 day) supply of reagent and chemicals comprise this charge.

Not all cited environmental control costs reflect a complete scope. For example, Tampa Electric in 1998 reported installing FGD for less than $100/kW 2 , but this cost did not include reagent
prepa ration equipment or other support facilities that were previously installed for two earlier FGD towers. Similarly, the cost for PacifiCorp to convert an existing hot

- side ESP at the Wyodak station to a fabric filter was not used to reflect the cost of retr ofitting a stand

- alone installation. Public Service of New Mexico recently expended significant funds to provide state

of

- art wet FGD at the San Juan Generating Station; however this work utilized components of the legacy Wellman

- Lord process preventing th e true cost of a stand

- alone process to be determined.

Capital costs are reported as received from the owner. Where costs are adjusted, the purpose, methods, and significance of the adjustment are explained in an accompanying footnote.

3.2 CAPITAL COST E SCALATION Capital cost was adjusted to account for the escalation over the time periods in this analysis. The earliest periods for which costs are 1995 are for the “Phase 1” retrofit of flue gas desulfurization processes, per the 1990 Clean Air Act Amendm ents. The costs incurred in these years are escalated to 2011 using the Bureau of Economic Analysis (BEA) Implicit GDP Price Deflator. This index is one of several metrics that could be used to measure price changes due to dilution of purchasing power of t he dollar, exclusive of price changes due to demand. A definition of the BEA GDP Implicit Deflator is found on the BEA website. 3

Figure 3

- 1 depicts the GDP Implicit Deflator that is used to adjust environmental control costs from the year incurred to the end

- of

- year 2011 dollar basis.

3.3 SITE AND DESIGN FACT ORS This report cites single

- point costs for environmental controls based on what an owner has incurred, or estimates to be incurred in the next 12

- 24 months. Using a single point to represent
cost for an environmental control system suggests a definitive understanding of costs that does not exist. In reality, the cost for such complex equipment varies over a wide range, even for a narrowly defined specification or set of process conditions. This var iability will be evident in graphical depictions of process cost presented in Sections 5

- 7.

2 “ Tampa Electric announces plans to reduce emissions from Big Bend Units One and Two”, New Release, July 20, 1998, TECO/Tampa electric, available at: http://www.tampaelec tric.com/company/mediacenter/article/index.cfm?article=110
3 http://www.bea.gov/faq/index.cfm?faq_id=513&start=0&cat_id=0Factors Affecting Reported Capital Cost

3

- 3 Figure 3

- 1 . Bureau of Economic Analysis (BEA) Implicit GDP Deflator

A brief summary of site

- specific factors , and how they impact capital cost, is as follows:

Fuel Composition . The fuel defines the volume of combustion products, the content of particulate matter, SO 2 , and NO x , and the composition of fly ash. These flue gas characteristics define process equipm ent size and cost. For example, Powder River Basin (PRB) or other sub

bituminous coals can generate up to 30% greater volume flue gas, compared to an eastern bituminous coal, to be processed for the same generating capacity. The quantity of sulfur to be
pr ocessed and the fate of the byproduct

– extent of dewatering, and preparation for resale or disposal

– also affect cost. For SCR reactors, the fly ash composition and presence of trace elements such as arsenic and phosphorous can determine reactor volume a nd catalyst arrangement.

Table 3

- 1 compares the composition of three coals widely used in the U.S. These coals represent the categories of (a) eastern bituminous, (b) Powder River Basin, representing the most popular subbituminous coal, and (c) lignite c oal from Texas. It is not possible to designate any one coal as more problematic than another

– each has features that challenge the design and operation of air pollution control equipment.Factors Affecting Reported Capital Cost

3

- 4 Table 3

- 1 . Comp arison Proximate Analysis, Select Ash Constituents, and Trace Constituents of Three Commonly Used U.S. Coals

Units Texas Lignite Powder River Basin Eastern

Bituminous

Proximate (%, as

- received)

Moisture %, as received 26.41

- 36.00 26.8 6.2

Ash “ 8.45

- 2 2.01 4.8 9.9

Fixed Carbon “ 15.42

- 31.05 35.6 49.7

Volatiles “ 21.1

- 38.05 32.9 34.0

Sulfur “ 0.76

- 1.98 0.20 1.60

Heating Value Btu/lb (Btu/kg) 5,768

- 7,848 (2765) 8861 (4019) 12,386 (5618)

Selected Ash Analysis

PO 5 % 0.10

- 0.20 1.9 0.1

SiO 2 “ 24.63

- 55 .85 21 49

Fe 2 O 3 “ 0.09

- 16.47 10 3.7

Al 2 O 3 “ 12.36

- 25.86 16 26.5

TiO 2 “ 1.03

- 2.08 2.4 1.5

MN 3 O 4 “
- 0.10

-
CaO “ 6.19

- 31.41 33 0.9
Mgo “ 1.44

- 3.59 5.0 0.5

K 2 O “ 0.18

- 1.03 0.44 1.7

Na 2 O “ 0.15

- 1.0 2.1 0.4

SO 3 “ 5.76

- 20.93 4.4 0.6

SrO “
- 0.3 0.2

B aO “
- 1.6 0.78

Selected Trace Elements

As (mg/kg) 2

- 7 1 5

Cl “ <100 <100 1,300

Hg “ 0.18

- 0.32 .09 0.10

Specifically, eastern bituminous coals generate relatively low flue gas volume per unit of output, but can contain large amounts of sulfur that el evate FGD cost. Further, arsenic content can be high, which if not mitigated by alkalinity from calcium, will accelerate catalyst deactivation. In contrast, PRB coals generate a substantial volume of flue gas per unit output, increasing the sizeFactors Affecting Reported Capital Cost

3

- 5 of reactio n vessels, but contain less sulfur compared to bituminous coals, lowering the mass of sulfur byproduct that must be removed. The NO x generated by PRB is relatively low minimizing the catalyst volume for SCR process equipment.

Texas lignite composition is highly variable, and can contain substantial amounts of high silica

containing ash, which erodes ductwork and catalyst. The lower gas velocities generally required for this application increase equipment size and cost.

Further discussion of how coal prop erties affect environmental control cost is presented in the subsequent sections reporting FGD, SCR, and fabric filter cost.

Site Congestion and Retrofit Difficulty . Limited space on

- site complicates construction

– there is less access to “lay

- down” equ ipment prior to erection, locate cranes, and productively use labor. As a result installation time is extended increasing capital cost. A site with three or more older units of small generating capacity will almost invariably incur high retrofit costs due to limited access. This cost penalty can be partially offset if gas flow from multiple small units is treated in a single device

– only applicable to wet FGD. In contrast, a site that hosts a sole large unit provides for economies of scale, and can offer u nconstrained space for construction.

Figure 3

- 2 shows perhaps one of the most constrained sites in the U.S.

– First Energy’s Sammis Station. The site, comprised of seven generating units ranging from 190 to 680 MW, is bordered by steep terrain, a four

- lan e highway, and the Ohio River. First Energy required more than four years to retrofit two SCR reactors (to Units 6 and 7), and three FGD absorbers each sized for 800 MW.

The work at Sammis was complicated by a previous project that placed four fabric fi lter collectors across the four lane highway from the station. Due to the constrained site and presence of the retrofit equipment, the capital cost for the Sammis SCR and FGD process are among the highest over the 2006

- 2010 timeframe.

Existing Site Auxili ary and Support Facilities . FGD and SCR process equipment demand auxiliary power, steam, and compressed air. As the availability of these consumables at a site varies, additional infrastructure to supply and distribute these consumables may be necessary. The most costly can be new power distribution infrastructure including transformers, switchgear and/or “motor control centers.” The escalation in price until 2008 of copper

- containing electrical subsystems has contributed to cost increases; during periods of peak copper pricing electrical infrastructure escalated from 5

- 6% of an FGD budget to more than 10%.

Flue Gas 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 and strengthening of ductwork and boiler walls is necessary to prevent collapse or implosion.Factors Affecting Reported Capital Cost

3

- 6 Figure 3

- 2 . First Energy Sammis Station: Constrained Site

Waste Water Treatment Requirements . For wet FGD, the need to treat process discharge water varies depending on permitted limits. Zero

- water discharge re quirements can impose large costs on the entire FGD slurry treatment and dewatering systems, and may possibly interfere with FGD chemistry. For wet FGD process equipment installed at a site in North Carolina, wastewater treatment facilities comprised betwe en 9 and 14% of the total capital cost. The design of a waste water treatment system has been a key point of contention in the retrofit of wet FGD to the PSNH Merrimack Station, contributing in part to this FGD process incurring perhaps the highest capital cost on record. Waste water treatment equipment alone for this station has been estimated to cost $23M. 4

Stack: Rebuild or Replace . Retrofit of wet FGD process equipment can require replacement of or a major rebuild of the stack. Flue gas treated by wet FGD poses corrosion and deposition potential, due to relatively low saturation temperature and content of SO 3 . The least cost solution can involve a new stack rather than retrofitting corrosion

- resistant liners to an existing stack. Figure 3

- 2 shows the l ocation of the new stack to accommodate the three retrofit FGD processes.

4 Expert Report of John H. Koon in the Matter of Comments on the NPDES Permit for PSNH’s Merrimack Station (2012), February 24, 2012, available at www.epa.gov/region1/npdes/ merrimack

station/pdfs/.../PC

- 6.pdfFactors Affecting Reported Capital Cost

3

- 7 Equipment Sparing and Redundancy Philosophy . The operating strategy of the owner, and the cost incurred for an FGD outage determines the equipment sparing and redundancy. Sparing
p hilosophy can affect capital cost by 10

- 20%. Operators with sufficient margin in meeting the SO 2 or NO x “cap,” or for whom SO 2 or NO x “allowances” are available, may choose to lower capital cost by minimizing redundant equipment. Conversely, operators for whom access to SO 2 or NO x allowances is limited or costly may elect to invest in more spare equipment.

Materials of Construction . Special

- purpose materials can resist corrosion and erosion, and support high reliability, but elevate capital cost. Specifi cally, using high alloy containing steels or rubber

- lined absorber vessels or pumps will increase reliability. The ability of a fluid to corrode, erode, or otherwise compromise piping must be considered when selecting construction materials. For wet FGD us ing higher alloy and lined equipment adds 10

- 20% to project capital
cost.

Capital versus Operating Cost . Many decisions revert to a tradeoff between capital and operating cost; some capital savings are derived only at the expense of higher operating cost . For SCR, a key example is the catalyst layout

– the number of initial and final layers of catalyst utilized. For example, a reactor layout of 2 initial layers and 1 spare layer (i.e., 2+1) will result in a lower capital but higher operating cost, compare d to utilizing 3 initial layers and 1 spare layer (i.e., 3+1). The key difference is higher catalyst consumption over a long

- term period.

Site complexity is perhaps the most important of these preceding factors. Capital costs continue to escalate because sites where FGD and SCR are to be retrofit are more complex than many prior applications for several reasons. The largest generating capacity units with the best site access have already been equipped with FGD and SCR, leaving smaller and older units for retrofit today.

The case of SCR retrofit to Public Service New Mexico’s (PNM) San Juan Station illustrates this point. 5 Figure 3

- 3 presents a satellite image of the San Juan Station, which similar to the First Energy Sammis Station required retrofit of st ate

- of

- art air pollution controls for SO 2 , particulate matter, and NO x . The San Juan station when constructed was equipped with what at the time was
state

- of

- art FGD technology. PNM was one of several utility operators in the 1970s that promoted the applic ation of “regenerable” SO 2 controls

– in this case the Wellman

- Lord process for converting captured SO 2 into marketable sulfuric acid. The Wellman

- Lord FGD process, although state

- of

- art at the time of installation, was not able to provide the SO 2 removal capability and reliability required by PNM in the present operating environment. The original FGD process was removed and conventional limestone

- based FGD process installed, along with fabric filters to improve particulate matter control. The additional eq uipment limited access for cranes and construction equipment to install SCR.

5 Evaluation of Engineering and Analytical Studies to Assess the Cost of Selective Catalytic Reduction (SCR) NOx Control Technology, for the Public Service Company of New Mexico San Juan Generating Station , prepared for PNM Resouces, January 31, 2012.Factors Affecting Reported Capital Cost

3

- 8 Figure 3

- 3 . Confined Site at PNM San Juan Station: Retrofit Fabric Filters, Upgraded FGD, Candid ate SCR Locations

The need to accommodate SCR escalated the estimate of total gas pressure drop across the entire air pollution control system. This additional gas pressure drop, along with other operating factors, prompted the need to include plans to a dopt “balanced draft” gas handling. The cost impact of conversion to balanced draft

– not only gas handling equipment but structural reinforcement of the boiler

– added considerably to the estimated cost to retrofit SCR on all four units at this station.

Cost estimates for SCR for these and other facilities are described in Section 6.Material and Labor Escalation

4

- 1 SECTION 4

MATERIAL AND LABOR E SCALATION

The cost of basic material and labor has significantly escalated in the last decade, specifically from the year 2000 through 2012. The escalation of material prices in 2008 and 2009 has abated, with most prices “relaxed” from peak values observed at that time. Labor costs have not decisively changed from peak values. This section discusses how material prices and labor costs impact equipm ent cost.

4.1 BASIC MATERIALS Basic materials required to fabricate air pollution control equipment are iron ore for products such as structural steel and ductwork, copper for wire and cable, and elements such as nickel and molybdenum for processed metal s. These materials, along with the cost and productivity of labor, determine the price of finished equipment such as pumps, valves, piping, instrumentation and control systems. Demand for these materials from approximately 2006 through most of 2008
was str ong due to robust world

- wide construction in process industries. Since 2008 the demand for such materials and has declined. This recent trend has mitigated but not eliminated cost

concerns.

Figures 4

- 1 to 4

- 4 present price escalation data for basic materi als over the last 10 years (with the exception of iron ore, for which data are only available over a three year period). These data, accessed either from the U.S. Bureau of Economic Analysis 6 (BEA) or a commercial source 7

, reflect pricing from 2002 to the present. The data in Figures 4

- 1 to 4

- 4 show prices for key materials have relaxed from the 2008

- era, reverting to 2007 levels. Consequently, all material prices are lower than their 2008 peaks but remain above mid

- decade values.

Specifically, Figure 4

- 1 presents the change in the BEA cost index for steel products (1982 prices as a base case). Figure 4

- 1 shows 2009 steel mill prices to be 60

- 70% of peak prices reported in the mid

- 2008, returning in 2012 to 80% of peak levels. Similarly, Figure 4

- 2 shows
t he price for iron ore pellets, after escalating from 2009 through 2011 by almost a factor of two, reverting to early 2009 levels by the end of 2012.

6 See U.S. Bureau of Economic Analysis, “Price Indices for Gross Domestic Product by Major Type of Product”, revised December, 2009, http://www.bea.gov/national/nipaweb/SelectTable.asp?Selected=Y
7 See www.Infomine.comMaterial and Labor Escalation

4

- 2 Figure 4

- 1 . Steel Mill Products Cost History

Figu re 4

- 2 . Iron Ore Cost EscalationMaterial and Labor Escalation

4

- 3 The cost for special alloys used for wet FGD absorbers and reaction vessels, and for high pressure, high temperature boiler components, has also relaxed from peak 2008 value s. Both nickel and molybdenum, key ingredients to corrosion

- resistant and high

- strength materials, experienced increased demand and higher prices up to 2007. Copper is an important component of electrical distribution and wiring systems. Figure 4

- 3 present s price trends for molybdenum, nickel, and copper over the time period of 2003 through most of 2012. Figure 4

- 3 shows prices for molybdenum and nickel escalated from 2003 by almost a factor of 10, but in late 2012 reverted to about twice the 2003 price. In contrast, the price of copper, which escalated by up to a factor of 8 in the 2008 peak, in 2011 revisited the peak. In late 2012 copper prices remain elevated.

Figure 4

- 3 . Price History Escalation: Nic kel, Molybdenum, and Copper

The price of delivered, finished equipment

– as reflected by Federal Reserve Economic Data (FRED)

– has continued to escalate as finished goods require manufacturing labor in addition to materials. Depending on the specific pro duct, the manufacturing labor can represent a cost that exceeds the contribution of materials, specifically for certain pumps, gas fans, valves, and alloy steel plates, the latter with specific surface features. Figure 4

- 4 shows how the prices of finished goods continued to escalate through the recession period in the 2008 and 2009 timeframe.Material and Labor Escalation

4

- 4 Figure 4

- 4 . U.S. Bureau of Economic Analysis Finished Goods Capital Price Index

FGD projects implemented from 2006 through 2008 incurred schedule delays due to limited availability of equipment for reagent preparation, slurry recirculating pumps, agitator pumps, certain forced and induced draft fans, and stack construction. Equipment availability rarely imposes si milar limits in the present market.

4.2 CONSTRUCTION LABOR The availability of qualified field labor has been a historical concern to support the timely and effective installation of process equipment. Typically labor rates can be a premium and escalate

r apidly for crafts with the most lengthy apprenticeship programs (e.g., boilermakers), as well as crafts with less restrictive training (pipefitters, electricians). Escalation in specialty construction labor was documented by the industry through 2007 8 , but such escalation has abated in the last 5 years.
Figure 4

- 5 presents wage escalation for private construction workers observed since 2000. This category of construction laborer reflects broad construction trades, not necessarily the specialized trades for heavy equipment construction, but is believed indicative of utility construction costs. This escalation in labor wage rate in Figure 4

- 5 is equal to an annual rate of 3

- 4% from 2008 through 2012. 9

The labor rate escalation shown in Figure 4

- 5 will incre ase installed equipment cost, but is not a dominant factor as experienced prior to 2008.

8 Building New Baseload Generation in the Midwest, MMEA Presentation, Black & Veatch, May 11, 2006.
9 See Table 5, “Natural Resources, Constructi on, and Maintenance”, change registered in September 2009 versus September 2008, U.S. Bureau of Labor Statistics, www.bls.gov/news.release/eci.t05.htmMaterial and Labor Escalation

4

- 5 Figure 4

- 5 . U.S. Bureau of Economic Analysis Private Industry Construction Worker Labor Rate IndexFlue Gas Desulfurization Costs

5

- 1 SECTION 5

FLUE GA S DESULFURIZATION CO STS

This section discusses capital and operating costs for wet and dry FGD process equipment, reflecting units installed from 1995 and through 2011. The estimated cost for FGD installations being installed or planned from 2012 to 2014 is also presented.

5.1 FGD CAPITAL COSTS The capital cost reported in this section describes a complete scope of work, including all indirect charges and Allowance for Funds Used During Construction, escalated into end

- of

- year 2011 basis using the BEA I mplicit GDP Deflator.

It should be cautioned not all data presented in this section reflect comparable cases

– each unit will differ with respect to inlet SO 2 , SO 2 removal, fuel type, absorber design, dewatering and byproduct management, and balance

- of

- pl ant equipment. The general cost trend shown in the figures is believed to reflect the industry average.

5.1.1 Wet FGD Figure 5

- 1 presents capital cost data for four deployment periods, from 1995 through 2014. Capital cost (unit basis, or $/kW) is displayed versus generating capacity. Three curves represent capital cost versus generating capacity for the earliest deployment periods. The most recent installations

– in 2012 or planned through 2014

– are represented by five discreet data points. Most FGD units employ limestone reagent, and with few exceptions, are designed for 95% SO 2 removal, forced oxidation treatment of byproduct, and are equipped with mist eliminators.

Curve A represents the capital cost for units that started commercial service prior to Ja nuary 1995 to comply with Phase 1 of acid rain rules. Curve A is based on the capital cost of 16 units, for which 11 provide 95% or greater SO 2 removal. All units but two employ limestone as reagent, with the remainder using magnesium

- enhanced lime. Curve A shows for these early installations that unit capital cost ($/kW) decreases only slightly with increasing generating capacity. Further, capital cost widely varies around the average values shown. Appendix A presents the 16 data points for Curve A, and sh ows that the average value of $370/kW represents costs that vary mostly between $300 and $495/kW.

Curve B represents the capital cost for units that started commercial service over the ten

- year period from 1997 through 2007. Due to the predominant use of low sulfur Power River Basin coal for compliance, a relatively small number of units started commercial service during this period. Twelve units provide the basis for Curve B, which exhibits a more conventional relationship between generating capacity and unit capital cost. Appendix A presents the individual data points for Curve B, showing the extent the cost data vary around the mean values. For example, at 600 MW Curve B reveals a capital cost of $310/kW, when the actual data ranged from a low of about $220/kW to $480/kW

.Flue Gas Desulfurization Costs

5

- 2 Figure

Figure 5

- 1 . Wet FGD Process Equipment Cost: Four Periods of Deployment

Curve C presents capital cost for units that started commercial service between 2008 and 2011. Most of these units were deployed to meet Phase 1 of the CAIR mandates; other units were constructed to comply with NSR consent decrees agreed to with the Department of Justice. A large number of units began service in this time period

– Curve C is based on 28 separate FGD facilities. Significant variability in the 28 data points is exhibited around the mean values.

The large number of cost data in the 2008

- 2011 timeframe enables comparing the cost to retrofit FGD to two or more units at one s ite. The results (not shown) indicate there is no distinguishable difference in cost ($/kW basis) when retrofitting FGD to more than one unit at a site, compared to a single stand

- alone unit of approximately the same capacity.

Capital cost for the most recent inventory of FGD processes

– those installed in 2012, or planned for startup not later than 2014

– are represented by five discreet points in Figure 5

- 1.Flue Gas Desulfurization Costs

5

- 3 These data in Figure 5

- 1 suggest the following observations:

Capital Cost has Escalated wit h Time . With the exception of the early Phase 1 acid rain FGD retrofits, Figure 5

- 1 shows the cost to retrofit FGD has increased for each of the four time periods. For a 400 MW unit, the average capital cost incurred for FGD installed by 1995 compared to units installed by 2008 is very similar. However, the unit cost for FGD increases by almost $150/kW for units installed in the 2008

- 2011 timeframe. Cost data for units retrofit in 2012 and through 2014 are limited but suggest no change or perhaps a slight escalation from the most recent (2008

- 2011) timeframe.

Most Capital Cost Data Exhibit Significant Economies of Scale . With the exception of the Phase 1 acid rain rule FGD retrofits, the minimum unit capital cost ($/kW) is incurred at higher generating capacities. This observation is consistent with historical trends for process equipment.

FGD processes retrofit by 1995 to meet the Phase 1 acid rain rules are an exception. The 1990 CAA Amendments was the first federal mandate to create SO 2 emission allo wances

– enabling averaging or production of SO 2 emission credits. Many Phase 1 FGD processes were designed for 93% SO 2 removal and greater, and employed single FGD absorber towers to treat up to 700 MW of flue gas. The use of a single absorber tower for s uch la rge units was not unprecedented

– but there was limited experience from which to derive a commercial design. It is possible the Phase 1 acid rain units were designed conservatively, thus economies

- of

- scale were negligible.

5.1.2 Dry FGD Figure 5

- 2 de picts capital cost for lime

- based dry FGD presented as a function of generating capacity. The costs represented include the reagent supply equipment, the spray dryer absorber vessel, and the fabric filter to capture both fly ash and particulate from sulfat ion. Similar to the case for wet FGD, these costs are expressed in 2011 dollars, and reflect all direct and indirect charges. Most dry FGD equipment represented in Figure 5

- 2 is designed for 93

- 95% SO 2 removal. Depending on the specific application, the or iginal particulate collector removes fly ash (an ESP in most cases) so ash handling and disposition is the same as prior to retrofit.

Two sources of data are used for Figure 5

- 2. A curve describing dry FGD unit capital cost ($/kW) based on a system study for eleven units at a Midwestern utility is included, reflecting cost for application to units from 200 to 800 MW. These estimates were developed in 2006 and are escalated to 2011.

Actual dry FGD costs incurred are reported for the time periods of 2008

- 20 11 and 2012

- 2014. Costs reported for the time period 2008

- 2011 decrease with increasing generating capacity, and are consistent with the 2006 system design study.

Costs reported for units installed between 2012 and 2014 also decrease with increasing
gene rating capacity. The unit dry FGD costs appear to have notably increased from 2008

- 2011; however

, the relatively few data points limit drawing a conclusion.Flue Gas Desulfurization Costs

5

- 4 Figure 5

- 2 . Dry FGD Proc ess Equipment Cost: Various Sources

The observations from the dry FGD installations are parallel to those of wet FGD, and are as follows:

Unit Capital Cost Has Escalated with Time . Dry FGD capital cost appears to have escalated from the 2008

- 2011 timef rame, to present installations for 2013 and 2014. Limited cost data implies caution regarding this conclusion.

Capital Cost Exhibits Significant Economies of Scale . Within the limitations of the data, unit capital cost decreases considerably with increas ing generating capacities. Data from all three sources exhibit this trend: the power

- law fit from the study for a Midwestern utility; the data from 2008

- 2011; and the two data reported for installations planned for 2013 and 2014. The limited number of dat a risks drawing conclusive evidence, but the trend parallels that of wet FGD and other process equipment.

5.2 FGD OPERATING COST Operating costs are comprised of fixed components, whose content does not appreciably change with generator output, and varia ble components, whose content changes in proportion of generator output. Fixed and variable components of FGD operation are summarized as follows:

Fixed O&M . The fixed operating and maintenance (O&M) cost is comprised of materials and operating staff tha t are required, independent of how much the process is operated. The fixed O&M is estimated based on a fixed percent of the capital cost

– and the size

– of equipment.Flue Gas Desulfurization Costs

5

- 5 Variable O&M . The variable O&M cost is mostly comprised of reagent consumption, soli d waste byproduct and disposal, auxiliary power consumption, and make

- up water.

Examples of operating cost incurred for wet and dry FGD systems are described subsequently.

5.2.1 Wet FGD Table 5

- 1 presents an example of the fixed and variable operating co st components for a wet FGD system for a 500 MW unit, as recommended by Sargent & Lundy. 10 For example, fixed O&M labor is based on an additional 12

- 16 plant operators must be added to support wet FGD, depending on the size of the generating unit.

Table 5

- 1 reports for a typical 500 MW plant, firing eastern bituminous coal with an SO 2 content of 3 lbs/MBtu (i.e., about 1.5% sulfur by weight), wet FGD requires fixed O&M of $8.15 /kW

- y and variable O&M of $3.60/MWh. This wet FGD process is assumed to require 1.6% of the total plant generating capacity to operate. The auxiliary power consumption is assigned a cost penalty based on the wholesale energy price.

Table 5

- 1 . Example Fixed, Variable O&M for Wet FGD

Op erating Cost Units Value Comment or Input Fixed Additional Labor $/kW

- y 3.00 8 additional operators Maintenance Labor, Material $/kW

- y 5.00 Administrative Labor $/kW

- y 0.15 Variable Limestone Reagent $/MWh 0.66 Limestone at $15/ton Waste Disposal $/MWh 2.47 Disposal at $30/ton Make

- up Water $/MWh 0.08 Make

- up water Auxiliary Power $/MWh 0.40 Based on 1.6% power consumption, energy price of $25/MWh

5.2.2 Dry FGD
Table 5

- 2 presents an example of the fixed and variable operating cost components for a 500 MW dry FGD system, as recommended by Sargent & Lundy. 11

Table 5

- 2 reports that for a typical 500 MW plant, firing low sulfur eastern bituminous coal (0.5% sulfur content), dry FGD requires fixed O&M of $8.61/kW

- yr and variable O&M of

10 IPM Model

– Revisions to Cost and Performance for APC Technologies: Wet FGD Cost Development Methodolog

y Final, prepared by Sargent & Lundy, August 2010, Project 12301

- 007, for Perrin Quarles Associates, Inc.
11 IPM Model

– Revisions to Cost and Performance for APC Technologies: SDA FGD Cost Development Methodology Final, prepared by Sargent & Lundy, August 2010, Project 12301

- 007, for Perrin Quarles Associates, Inc.Flue Gas Desulfurization Costs

5

- 6 $1.40/MWh. T he dry FGD process is assumed to require 1.35% of the plant generating capacity. The auxiliary power consumption is assigned a cost penalty based on the wholesale energy price.

Table 5

- 2 . Example Fixed, Vari able Operation and Maintenance for Dry FGD

Operating Cost Units Value Comment or Input Fixed Additional Labor $/kW

- y 3.33 8 additional operators Maintenance Labor, Material $/kW

- y 5.12 Administrative Labor $/kW

- y 0.16 Variable Lime Reagent $/MWh 0.60 Lime at $95/ton Waste Disposal $/MWh 0.43 Disposal at $30/ton Make

- up Water $/MWh 0.03 Make

- up water Auxiliary Power % MW production lost 1.35% or

$0.34/MWh $0.34/MWh based on

wholesale energy price of $25/MWh

5.3 LEVELIZED REMOVAL CO ST PER TON

T he total cost of deploying wet or dry FGD will include the capital charge and the sum of fixed and variable operating charges.

For a 500 MW power plant, Figure 5

- 1 suggests wet FGD capital cost for units installed in 2012 or thereafter is about $500/kW, e qual to $250 M capital investment. The annual charge for this capital

– based on a 20

- year recovery period and applying the capital cost recovery factor from EPRI’s Technical Assessment Guide (0.13), is $32.5 M. In addition to this annual charge for capita l, wet FGD operating costs will be incurred as exemplified by Table 5

- 1 for eastern bituminous coal with 3 lbs SO 2 /MBtu sulfur content. Operating cost for lower sulfur coals are analogous to Table 5

- 2 but are lower in approximate proportion to sulfur conte nt.

Figure 5

- 3 summarizes these charges, cast in terms of cost per ton of SO 2 removed. Figure 5

- 3 shows the divergence in cost for controlling SO 2 from a higher sulfur eastern bituminous coal, and relatively low sulfur coal such as PRB.

In the present u tility operating environment, it is likely more important to view FGD cost in terms of compromising the economic position of a unit in a competitive power market. A comparison of how FGD variable and total carrying costs affect the c ompetitiveness of a 500 MW unit in the wholesale power market is presented in Section 8.Flue Gas Desulfurization Costs

5

- 7 Figure 5

- 3 . Calculated SO 2 Removal Cost per Ton: Wet FGD Retrofit to 500 MW Reference UnitSelective Catalytic Reduction Cost

6

- 1 SECTION 6

SELECTIVE CATALYTIC REDUCTIO N COST

This section presents capital and operating costs for SCR NO x control, reflecting units installed from 1994 through planned for 2014.

6.1 SCR CAPITAL COST Figure 6

- 1 summarizes capital cost data for four deployment periods, starting as early as 1994 and projected through 2014. Three curves represent unit capital cost ($/kW) vs. generating capacity for three periods of historical data. Eight discrete cost data are presented for units retrofit in 2012 and projected through 2014.

Figure 6

- 1 repre sents cost data from over sixty SCR installations. The costs are reported as 2011 dollars, and include both staff engineering and owners’ engineering charges, and financing charges (AFUDC). As with FGD process equipment, it should be cautioned that not all cost data represent comparable cases

– most differ in inlet NO x , NO x removal, fuel type, reactor design and arrangement, number of catalyst layers, and balance

- of

- plant equipment. However, the trend in cost shown in Figure 6

- 1 is believed an accurate refl ection of the industry average.

Figure 6

- 1 presents four curves reflecting cost incurred over discrete time periods. These include the years (a) pre

- 2000, reflecting the earliest projects, (b) 2000

- 2007, reflecting the class of units installed prior to b road Phase 1 CAIR compliance, (c) 2008

- 2011, reflecting units installed during the height of Phase 1 CAIR compliance, and (d) 2012 and beyond, reflecting units recently installed or presently under construction. The individual data points are omitted for

c larity. The complete set of data and cost curves can be viewed in Appendix D.

Curve A represents capital cost for five units retrofit with SCR for operation prior to 2000 to comply with either a state regulation or the 1997 SIP

- Call. Also, Phase 2 of the acid rain program required approximately 50% NO x reduction for the “Group 2” boilers, achievable for many units only with SCR. Curve A shows the earliest units retrofit with SCR incurred capital cost ($/kW basis) did not change with generating capacity

– the average cost was about $100/kW.

Curve B represents the capital cost for units starting commercial operation from about 2000 through 2007. Curve B was derived from 32 units, most of which were deployed to meet Phase 1 CAIR mandates for NO x ; although so me units were constructed to satisfy consent decrees in regard to alleged New Source Review (NSR) violations. Curve B data exhibit a modest relationship between generating capacity and capital cost

- higher generating capacity enables slightly lower unit c ost ($/kW basis). Appendix B presents the actual cost data showing the variation around the mean, with values as low as $100/kW and as high as $275/kW.Selective Catalytic Reduction Cost

6

- 2 Figure 6

- 1 . Capital Cost of SCR Process Equipment vs. Generating Capacity: Four Time Periods

Curve C represents the capital cost for sixteen units starting commercial service between 2008 and 2011, with most intended for Phase 1 CAIR mandates. Individual data for the 16 separate SCR facilities (not shown) exhibit great variability.

Curve D reflects cost for units either retrofit with SCR in 2012, or projected cost for units to be operating in 2014.

Comparing the cost described by the three curves and the cost data for 2012

- 2014 ins tallations suggests the following:

Capital Cost has Escalated with Time . Capital investment required for SCR has escalated since the earliest installations prior to 2000. For a 500 MW unit, the average capital cost incurred for units installed between 20 03 and 2008 increased by $75/kW compared to those installed prior to 2000. The capital required for a 500 MW unit increased by another $100/kW for units installed in 2008

- 2011; and by $200/kW for units installed in 2012

- 2014. Meaningful escalation in cost is clear despite the variability in the data.

Capital Cost Exhibits Significant Economies of Scale . Lower capital cost per unit ($/kW) output is observed at higher generating capacities

– materially so in many cases. An exception in this trend is noted for the units installed prior to 2000 to meet Phase 1 of the 1997 SIP

- Call. Similar to the case of wet FGD, this early data cohort does not exhibit this trend

– perhaps also aSelective Catalytic Reduction Cost

6

- 3 consequence of higher design margins to account for uncertainty in the largest u nits, and limited experience.

Figure 6

- 2 presents the increase in SCR capital cost over the four time periods. Figure 6

- 2 reports a total escalation of $166/kW over 12 years

– about $14/kW per year. This trend is anticipated to continue to 2015, as SCR i s installed on smaller generating units located at complex sites continues.

Figure 6

- 2 . Increase in SCR Capital Cost Based on Four Time Periods (Three Increments)

An example of how market forces and site characteristics affect SCR cost is demonstrated by the two SCR installations at the Consumers Energy Campbell station, separated by 4

- 5 years.

Consumers Energy installed SCR at Campbell Unit 3 (915 MW) for start

- up in 2007, and incurred a capital cos t used as one of the data points to derive Curve B. Figure 6

- 3 presents a satellite image showing the layout of the Campbell station and the location of Units 1

- 3. The SCR for Unit 3 was designed and constructed by a leading engineering firm and has proved a capable design. Consumers Energy was able to exploit market forces at the time

– arranging for contracting in approximately 2004 and constructing the process to be operable by 2007

– ahead of the surge in orders for Phase 1 CAIR compliance. Figure 6

- 3 s hows ample access to Unit 3 on both sides for construction activities. Unit 2 does not offer the same equipment access.Selective Catalytic Reduction Cost

6

- 4 Figure 6

- 3. Site Layout for Consumers Energy Campbell Station: Units 1

- 3 (SCR Retrofit to Units 2, 3)

In 2010, Consumers Energy engaged the same supplier to retrofit SCR to the 424 MW Unit 2. The timing of the project prevented Consumers Energy from replicating the favorable market conditions encountered for Unit 2

– demand for this type of process equipment was m uch greater than in 2004. Economies

- of

- scale also played a role, with Unit 2 less than half of the generating capacity of Unit 3. The demand for components, materials, and construction labor during the 2008

- 2010 timeframe substantially exceeded that for Un it 3. As a consequence, the capital cost to retrofit SCR to Unit 2 for 2013 startup per unit capacity ($/kW) exceeds that for Unit 3 by more than 50%. The experience of Consumers Energy

– that an SCR

- savvy owner incurred very different costs at adjacent un its at the same station

– demonstrates the role of market forces and site conditions in controlling technology cost.

6.2 OPERATING COST Operating costs for SCR processes consist mostly of replacement catalyst and ammonia

- based reagent. The cost for each of these consumables has changed in the last 10 years. In the early phases of SCR operation, replacing catalyst was the largest component of operating cost, followed by reagent. In the last ten years, a decrease in catalyst cost and escalating ammonia pric es have inverted this relationship

– for most units reagent supply now dominates operating cost. Fixed operating and maintenance costs are generally small compared to these two components.

Factors affecting catalyst and reagent supply and reagent cost ar e discussed subsequently.Selective Catalytic Reduction Cost

6

- 5 6.2.1 SCR Catalyst The unit cost of catalyst has decreased significantly since the early 1980s. Further, the ability to regenerate or rejuvenate catalyst for a cost equivalent to approximately 50% of the cost for new product rest rains price.

Figure 6

- 4 presents the unit price of catalyst since the early 1980s, corrected to a 2011

- dollar basis. Figure 6

- 4 shows a decrease in unit price by a factor of five since the earliest commercial bids. Minimum prices of near $4,000/m 3 were o bserved in 2005. At this time the demand for catalyst was low

– generating units in the U.S. equipped with SCR had not yet required substantial replacement catalyst

– most installations were relatively new and operated “seasonally” from May 1 through Septe mber 30. Also, in 2005 the demand for SCR equipment to meet Phase 1 of CAIR

– with the requirement that equipment be installed and operational by 2009

– had not yet materialized. Since 2005 catalyst prices have escalated slightly due to demand

– despite th e cost pressures of catalyst regeneration which can provide replacement catalyst for approximately 50% of new material price.

Catalyst prices at present remain in the approximate range of $5,000

- 6,000/m 3 , although there have been reports of cost below $5 ,000/m 3 in the last 12 months.

Figure 6

- 4. History of SCR Catalyst Prices: 1980

- 2012 (2011 Dollar Basis)Selective Catalytic Reduction Cost

6

- 6 6.2.2 Reagent Any savings in SCR operating cost due to decreases in catalyst price have been offset by higher cost for ammonia

- b ased reagent. SCR operators can choose from four types of ammonia

- based 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,

r ecognizing that alternative reagent forms are equally viable.

Historically, the cost of anhydrous ammonia is largely determined by the cost of natural gas feedstock. In late 2008, the cost for anhydrous ammonia for both agricultural and industrial appli cation exceeded $1,000/ton for many suppliers. Figure 6

- 5 depicts the cost of anhydrous ammonia in the Midwest, showing the relationship with time. Over the same period natural gas prices have decreased to the range of $2

- 3/MBtu.

Anhydrous ammonia prices at present are more driven by the demand for fertilizer due to strong prices for corn and other agricultural products. Figure 6

- 6 depicts the ratio of wholesale anhydrous ammonia process to natural gas. The escalation in the ratio of ammonia to natural ga s in 2008 exhibits the decoupling of the price of these two products, reflecting the strong agricultural demand.

Figure 6

- 5. Midwestern Anhydrous Ammonia Prices: August 2008

- June 2012Selective Catalytic Reduction Cost

6

- 7 Figure 6

- 6. Ratio of An hydrous Ammonia to Natural Gas Price: 2001

- 2011

6.2.3 Example Operating Cost The operating and maintenance cost for an SCR process can be developed (for a 500 MW unit) based on assumptions in Table 6

- 1. These are:

Fixed O&M . Spare parts and support fo r miscellaneous duties that must be executed regardless of unit operation. Experience suggests this cost can be $200,000 annually.

Catalyst Supply . Catalyst supply cost is determined by periodic purchases from which an annual charge can be calculated. Th e periodic purchases add catalyst to the spare layer or replace existing catalyst. For an SCR reactor with a 2+1 catalyst arrangement, designed with an initial space velocity of 3,200 l /h and a 16,000 operating hour guarantee, the purchase of one layer

eve ry 16,000

- 20,000 operating hours may be required. Operating experience suggests this replacement frequency can be a best

- case scenario, and greater catalyst changeout needed.

Reagent Cost . The purchase of anhydrous ammonia for 87% NO x removal from 0.35 l b/MBtu, at 80% capacity factor, defines the reagent cost. A delivered price of $750/ton is assumed.

Auxiliary Power . Auxiliary power for an additional 5 inch water gauge (w.g.) flue gas pressure drop is assumed

– 4 inch w.g. for the process flange

- to

- fla nge, and an additional 1 inch w.g. across the air heater.Selective Catalytic Reduction Cost

6

- 8 Catalyst Cleaning . Sootblower consumption of 0.2% of the plant steam output is adopted; this steam is assigned a cost of $1/MBtu. Many new SCR installations employ acoustic horns for cleaning, w hich require auxiliary power that constitutes approximately the same cost.

Operating Staff . One additional operator dedicated to 50% duty is assumed to be required to maintain the above components. Also, a part time (50%) engineer to assess operation an d evaluate data is assumed. The need to account for additional staff due for SCR operation is highly variable; some owners report additional operating or engineering staff is not added for these purposes.

Table 6

- 1 provides a summary of SCR operating cost . The analysis cites fixed O&M, additional labor for operating staff, steam for sootblowers, reagent for NO x reduction, auxiliary power and an annualized charge for catalyst supply. Of note is that for the reference case presented, the annual equivalent ch arge for replacement catalyst is about 1/3 of the annual charge for anhydrous ammonia

– a prospect unthinkable in the last decade. Clearly, the high cost of reagent

– prompted by agriculture demand for fertilizer and fertilizer feedstock

– elevates the con trol cost per ton.

Table 6

- 1 . Key SCR Operating Cost Components: 500 MW Reference Plant

Operating Cost Units Value Comment or Input Fixed Consumable materials, Maintenance staff $/kW

- y 0.40 Percent of process capital ($200,000 for 500 MW) Operators/engineering $/kW

- y 0.80 50% of one operator, one engineer Variable Ammonia reagent $/MWh 0.42 Anhydrous ammonia at $750/ton Catalyst replacement (annual equivalent) $/MWh 0.13 Acquire one layer at 16,00 0 hr operating intervals Fuel cost (auxiliary steam) $/MWh 0.03 Make

- up water Auxiliary power $/MWh 0.08 Based on 5” w.g. @ energy price of $25/MWh

6.2.4 Levelized Removal Cost P er Ton The levelized cost of NO x control per ton of NO x removed is determ ined from both operating costs and capital recovery charges, normalized by the amount of NO x removed.

The 500 MW reference plant described in Section 5 is used as the basis for this analysis. This boiler emission rate for this reference unit, firing bitum inous coal, is assumed to be 0.35 lb NO x /MBtu, and require control to a stack outlet value of 0.05 lb/MBtu (86% reduction).

The total charges can be developed for a 500 MW unit retrofit with SCR in 2012 or thereafter. Figure 6

- 1 suggests a 500 MW plant a dopting SCR will incur a capital charge of approximately $450/kW, thus requiring $225 M. Based on a 20

- year life and using the capital cost recoverySelective Catalytic Reduction Cost

6

- 9 factor from EPRI’s TAG of 0.13, an annual charge for capital is estimated to be $28.5 M. Consequently, the sum of total operating costs and the annual charge for capital recovery will be $2.972 and $28.5 M, totaling $31.5 M.

Figure 6

- 7 presents the levelized cost of NO x removal, in terms of cost incurred per ton of NO x removed, as a function of SCR capital c ost. The results are shown for both an eastern bituminous coal and PRB, the latter characterized by a boiler emission rate of 0.20 lb/MBtu. The lower boiler NO x emission rate elevates the cost per ton, despite lower reagent consumption.

In the present ut ility operating environment, it is likely more important to view SCR retrofit cost in terms of compromising the economic position of a unit in a competitive power market. A comparison of how the retrofit of SCT affects the wholesale power price in competit ive markets is presented in Section 8.

Figure 6

- 7: NO x Control Cost per Ton of NO x RemovedFabric Filter Contro l Technology Costs

7

- 1 SECTION 7

FABRIC FILTER CONTRO L TECHNOLOGY COSTS

Section 7 presents capital and operating costs for fabric filter particulate controls, co mmonly referred to as “baghouses,” retrofit to existing units. The reasons to retrofit fabric filter equipment are numerous. These reasons include (a) satisfying consent decrees over alleged New Source Review violations, (b) as part of a dry FGD process eq uipment, and (c) to comply with the Mercury and Air Toxics (MATS) rule.

Similar to SCR and FGD, fabric filter control technology has ev olved in recent decades. Figure 7

- 1 presents a perspective view of a fabric filter with the inset showing how the filter bags are arranged and the gas flow pattern.

Figure 7

- 1 . Fabric Filter Particulate Control Device and Detail of Filter Material 12

Fabric filter controls can employ thousands of individual filters

– 14,000 for a 500 MW plant, arranged in perhaps 8 to 15 individual compartments. These filters are configured as “bags” and are oriented so particulate

- laden flue gas enters from the periphery (outside) of the filter, with flue gas flo wing radially inward. Particulate matter is removed on the fabric. The bags are periodically cleaned of the collected ash by any of several methods; the present state

- of

- art

12 Source: Adopted from B&W Brochure, Pulse

- Jet Fabric Filters, available at http://babcock.com/products/environmental_equipment/particulate_and_dust_control.htmlFabric Filter Contro l Technology Costs

7

- 2 approach is a cleaning “pulse” of high

- pressure air that dislodges the ash. Fabric filter particulate collectors that employ this method of cleaning are referred to as the “pulse

- jet” design. The cleaning cycle is typically intervals of several hours.

7.1 FABRIC FILTER CAPITA L COST Fabric filter capital cost is reported in Figure 7

- 2 for a complete scope of work, including all indirect charges and Allowance for Funds Used During Construction, escalated into end

- of

- year 2011 dollar basis.

Figure 7

- 2 displays fabric filter capital cost as a function of generating capacity for seventeen units, representing a wide range of generating capacity and application. The costs reported include both the fabric filter and ancillary equipment, such as flue gas fans and additional ductwork.

Figure 7

- 2 . Fabric Filter Capital Cost (2011 $ Basis) vs. Generating Capacity

The costs in Figure 7

- 2 are highly variable. Most notably, there is no clear relationship between capital cost and generating capacity.

The capital cost to retrofit fabric filters, si milar to FGD and SCR, depends on numerous site

specific factors. These include (a) available space for ductwork near the air heater, (b) clearFabric Filter Contro l Technology Costs

7

- 3 access by cranes and construction equipment, and (c) the cost for process equipment and construction labor.

Se veral example sites are discussed, categorized in terms of site access as either “good” or “limited”.

7.1.1 Good Site Access Two generating sites with “good” access

– Dairyland Power Madgett Unit 1 and Dynegy Vermillion Units 1 and 2

– are described. Sites designated with “good” access typically incurred a fabric filter capital cost of less than $200/kW.

Figure 7

- 3 depicts the site layout for Dairyland Madgett Unit 1. The fabric filter, denoted within the blue circle, processes flue gas from the boilerhous e after passing through the SCR reactor. The gas flow path is shown exiting the boilerhouse, passing through and exiting the SCR reactor (red arrows). The flue gas then passes through the air heater (red circle) and continues into the fabric filter (blue c ircle). The flue gas exits the fabric filter and enters the stack along the path indicated by the green arrows.

Figure 7

- 3 . Dairyland Power Madgett Unit 1: Fabric Filter Ins tallation

Figure 7

- 4 presents the site layout for Dynegy Vermilion Units 1 and 2. The flue gas from each unit exits the boilerhouse and passes through the air heater (red circle), then enters a common duct leading to the fabric filter (blue circle). The f lue gas from the fabric filter returns to the stack (ductwork indicated by the green arrows).Fabric Filter Contro l Technology Costs

7

- 4 Figure 7

- 4 . Dynegy Vermilion Units 1 and 2: Fabric Filter Installation

7.1.2 L imited Site Access The highest cost fabric filters (from $200

- 400/kW) are located at sites where construction access is severely inhibited. Two stations are discussed for this category

– Arizona Public Service’s Cholla Units 3 and 4, and Alliant Lansing Un it 4.

Figure 7

- 5 depicts Arizona Public Service’s Cholla site. Units 3 and 4 are “interior” and “exterior” units, respectively. Figure 7

- 5 shows gas flows for both units from each boilerhouse into an SCR reactor, which after passing through the air heater s (red circle) enters the fabric filter (blue circle). The flue gas from the fabric filter returns to the stack as indicated by the green

arrows.

Cholla Unit 3 presents limited access compared to Unit 4

– the abandoned Unit 4 ESP further complicates crane location. As a result of the difference in construction access, Unit 3 fabric filter capital and installation cost exceeded that for Unit 4 by 30%.

Alliant’s Lansing Station offers a second example of a site with limited access. Figure 7

- 6 depicts the U nit 4 layout, showing the fabric filter (blue circle) as retrofit in 2008. The adjacent water body restricts crane location to one of the four sides, which complicated installation. Figure 7

- 6 shows gas flows from the boilerhouse into an SCR reactor, and t ransits through extended ductwork to the fabric filter. The return gas ductwork (green arrows) is partially blocked by the stack.Fabric Filter Contro l Technology Costs

7

- 5 Figure 7

- 5 . Arizona Public Service’s Cholla Units 3 and 4: Fabric Filt er Retrofit (Moderate Difficulty)

Figure 7

- 6 . Alliant Lansing Unit 4: Fabric Filter Retrofit (Moderate DifficultyFabric Filter Contro l Technology Costs

7

- 6 7.2 EXAMPLE OPERATING CO ST The operating and maintenance c ost for a fabric filter can be developed (for a hypothetical 500 MW unit), based on assumptions in Table 7

- 1 that define the conditions of operation. These are:

7.2.1 Fixed O&M Fixed operating and maintenance (O&M) expenditures consist of spare parts and services for miscellaneous duties

– independent of how much the fabric filter is operating. This cost is assumed to be equivalent to 0.25% of process capital.

In addition, one operator at 50% duty is required for general maintenance. A part time (50%)

en gineer is also assumed to be required to assess operation and evaluate data. The specific staff needs are highly variable; some owners report adding operating staff while others require these duties to be absorbed by existing staff.

7.2.2. Variable O&M.
R eplacement filter bags and cages, and auxiliary power are key components to variable O&M.

Replacement Bags and Cages Supply . The 500 MW reference unit is assumed to contain 14,000 individual filter bags, which (with support cages) are assumed replaced at 3

- year intervals. Consistent with assumptions developed by Sargent & Lundy for EPA, the replacement bags and support cages are assumed to cost $80 and $60 each, respectively. 13 The annual cost to replace bags and cages is developed assuming 1/3 of the total filter bag and cage inventory is replaced annually.

Auxiliary Power . The auxiliary power demand depends on the design of the fabric filter, most notably the air/cloth ratio. Typically, the fabric filter pulse

- jet design that uses high air/cloth ratios ( ~6 ft/s) will incur a greater gas pressure drop than designs based on conventional reverse

gas or shake

- deflate cleaning. A typical pulse

- jet unit with an air/cloth ratio of 6 ft/s will incur an additional 6 inch water gauge (w.g.) gas pressure drop. For t he present analysis, an additional auxiliary power of 8

- inch w.g. gas pressure drop is assumed

– comprised of 6 inch w.g. for the fabric filter and an additional 2 inch w.g. for ductwork.

Table 7

- 1 summarizes the operating cost components for a fabric fil ter retrofit to the 500 MW reference unit. The cost analysis includes fixed O&M, labor required for operating staff, and the variable O&M for replacement filters and auxiliary power.

13 IPM Model

– Revisions to Cost a nd Performance for APC Technologies: Particulate Control Cost Development Methodology Final, prepared by Sargent & Lundy, March 2011, Project 12301

- 009, for Systems Research and Applications Corporation.Fabric Filter Contro l Technology Costs

7

- 7 Table 7

- 1 . Key Fabric Filter Operating Cost Components: 500 MW Reference Plant ($250/kW Capital, 2011 Dollar Basis)

Cost Component Basis Annual Cost for 500 MW ($/yr) Annual Cost for

500 MW (mills/kWh) Operations Fixed O&M Process Capital 312,500 0.084 Labor Operators/Par t

- time Engineer 396,360 0.106 Total Fixed O&M 708,860 0.190 Variable O&M Replacement Filter Materials Based on individual filter cost

of $80 each, and support cage cost of $60/each 650,000 0.173

Auxiliary Power 8 inch w.g. total @ $20/MWh 430,000 0. 115

Total Variable O&M 1,074,000 0.289 Total Operations 1,783,846 0.48 Capital Capital Requirement Based on unit cost of

$250/kW, and capital recovery factor of 0.13 16,250,000 4.37

Total: Levelized Operations and Capital 18,038,500 4.85

7.3 LEVELI ZED COST

Table 7

- 1 summarizes levelized cost of deploying fabric filter control technology is developed, based on capital recovery and operating cost.

Levelized costs are developed for the 500 MW reference plant described in Section 5, retrofit with a fab ric filter in 2011. Table 7

- 1 reflects a fabric filter capital charge of approximately $250/kW, thus requiring $125 M. Based on a 20 year life and using the capital cost recovery factor from EPRI’s TAG of 0.13, the annual charge for capital is estimated to be $16.25 M.

The sum of all operating costs and the annual charge for capital recovery will be $1.78 and $16.25 M, totaling $18.03 M. Levelized cost per production basis to deploy a fabric filter for the 500 MW reference unit is 4.85 mills/kWh.Cost Competitiveness

8

- 1 SECTION 8

COS T COMPETITIVENESS

This report has summarized the cost of FGD, SCR, and fabric filter air pollution controls. The cost metrics considered are capital requirement, and fixed and var iable operating costs for a 500 MW reference plant.

Historically, the cost for environmental controls has been measured in terms of the cost per ton ($/ton) for removing SO 2 , NO x , or particulate matter. The significance of this cost index is perhaps diminished in the present economic climate, where total emission “caps” and ambi ent air standards are driven by mandates within CAIR, CSAPR, and MATS. Further, most control equipment contributes to removing more than one pollutant

– SCR and FGD remove not only NO x and SO 2 , but assist in mercury and acid gas (e.g., hydrochloric acid) r emoval. Fabric filters remove particulate matter but also help remove mercury and acid gases. As a result, measuring the value of environmental controls in terms of removing one pollutant does not always reflect the complete benefit.

Perhaps more importan t in the present economic climate is how retrofit of air pollution controls affects the wholesale power price of units in power markets. Analyses released by The Brattle Group 14 , Bloomberg Government 15 , and SNL Financial 16 predict unit retirements based on th e added cost for environmental controls and the wholesale energy price in a local market.

Several examples illustrate this point. First, the fuel cost for both coal

- fired and natural gas/combined cycle (NG/CC) generation is compared to U.S. wholesale ener gy prices. Two reference cases demonstrate how the cost to retrofit environmental controls affects competitiveness in power markets. The cost to retrofit FGD, SCR and fabric filter equipment to a 500 MW reference unit is compared to the 2012 U.S. wholesale energy price. In addition, the cost to retrofit and operate a fabric filter to a smaller (300 MW) unit, operating at lower capacity factor and using “allowances” to comply with NO x and SO 2 limits, is compared to the wholesale energy price.

8.1 POWER MAR KET REFERENCE The incremental cost to retrofit and operate environmental controls to a 500 MW unit is compared to both fuel and U.S. wholesale energy prices. The fuel cost for a combined cycle generating unit is also compared.

14 Potential Coal Plant Retirements in the U.S. and Impacts on Gas Demand , prepared by Metin Celebi, presentation at CERI Conference, Calgary, CN, February 27, 2012.
15 The Twilight of Coal

-

fired Power? The EPA’s New Standards for Greenhouse Gases , prepared by R. Barnett et. al., Bloomberg Government, May 1, 2012.
16 Upcoming, recent coal

- fired power plant retirements , M. Niven
, et al., SNL Financial, Wednesday, March 28, 2012.Cost Competitiveness

8

- 2 Figure 8

- 1 presents 2012 wh olesale energy prices for eight power markets in the U.S. 17 The fuel cost for conventional coal

- fired generation is also shown, along with fuel cost for natural gas combined cycle generators

– the most prominent alternative to coal

- fired power.

Two scenari os of fuel cost are represented for both coal

- fired and natural gas/combined cycle generation. For coal

- fired generation, fuel cost for a delivered fuel price of $1.50/MBtu and a 9,600 Btu/kWh heat rate (low cost) and $2.25/MBtu and heat rate of 11,500 Btu /kWh (higher cost) are reported. Fuel cost for natural gas/combined cycle generation is shown for low cost ($3/MBtu and 7,000 Btu/kWh heat rate) and higher cost ($4/MBtu and 8,000 Btu/kWh heat rate) scenarios.

Figure 8

- 1 . Competitive Power Landscape: Wholesale (Peak) Power Prices, and Fuel Cost for Generating Options

Figure 8

- 1 shows for coal

- fired or natural gas/combined cycle generation that the cost for fuel comprises a lar ge fraction of, or even exceeds, wholesale power prices in certain regions in the U.S. The cost for fuel under the least fuel cost scenarios for natural gas/combined cycle and steam boiler operation can comprise 50

- 65% of the median wholesale energy prices . The cost for fuel for higher cost scenarios exceeds the minimum wholesale power price and approaches the median wholesale power prices.

17 Today In Energy, U.S. Energy Information Agency, January 9, 2013, available at http://www.eia.gov/todayinenergy/detail.cfm?id=9510Cost Competitiveness

8

- 3 The cost of fuel relative to a whole energy market leaves little margin to absorb for air pollution control costs.

8.2 SCR, FGD REFERENCE U NIT COST

The total cost for SCR and FGD for coal

- fired generators

– fixed and variable operating cost, and capital recovery

– is compared to the wholesale energy price, and fuel charges for natural gas/combined cycle and coal

- fired generators. The analysis is conducted for a 500 MW reference unit firing eastern bituminous coal.

Figure 8

- 2 compares the cost for FGD and SCR to the fuel cost for coal

- fired boilers, the fuel cost for natural gas/combined cycle generation, and the range of wholesale energy prices.

Figure 8

- 2 . FGD and SCR Incremental and Total Carrying Costs Compared to Fuel Costs for NG / CC and Steam Boilers

Wet FGD . Three cost cases are presen ted for wet FGD deployed to a 500 MW unit firing eastern bituminous coal. These are the FGD variable O&M cost, and total cost for a 65% and 85% capacity factor. The variable cost of almost $4/MWh is small compared to the total cost of $13/MWh, as calculate d for an 85% capacity factor. The total FGD cost increases to $16/MWh if the capacity factor decreases to 65%.Cost Competitiveness

8

- 4 Figure 8

- 2 shows the cost for FGD can be up to half or more of the lowest 2011 wholesale energy price. The wet FGD total cost can approach or e qual the fuel charge for a coal

- fired generator experiencing a low cost fuel scenario (coal at $1.50/MBtu and a 9,600 Btu/kWh heat rate).

SCR. Two cost cases are presented for SCR. Figure 8

- 2 shows total incurred cost is about $8 and $11/MWh for the 85% and 65% capacity factor cases, respectively. Figure 8

- 2 shows the cost to deploy SCR about 2/3 the cost to deploy wet FGD, at the same capacity factor.

Wet FGD and SCR . The combined total cost for wet FGD and SCR

– about $23/MWh

– almost equals the low est wholesale energy price for 2011. Figure 8

- 2 shows the combined cost for FGD and SCR exceeds the fuel cost for either natural gas/combined cycle or coal

- fired boilers (the low cost scenario). The combined wet FGD and SCR cost is about 75% of the fuel co st for natural gas/combined cycle and coal

- fired boilers for the high cost scenario.

Figure 8

- 2 shows the total cost for wet FGD and SCR, by almost equaling the fuel price, can eliminate a unit from competitive power generation.

8.3 ROLE OF FABRIC FILTE R A fabric filter will be required by many units to improve control of particulate matter and provide a favorable environment to remove mercury and acid gases. This section will consider the cost to retrofit fabric filters to the 500 MW reference case. In addition, the cost to retrofit and operate a fabric filter to a small generating capacity, low capacity factor unit that complies with NO x and SO 2 emission limits using allowances will be considered.

Figure 8

- 3 presents the total fabric filter cost for bo th applications

– the 500 MW reference plant operating at 80% capacity factor, and a 300 MW unit operating at 50% capacity factor. The capital cost for this equipment is derived from Figure 7

- 1: an intermediate value of $250/kW is selected for the 500 MW cases, and $325/kW for the 300 MW case. The operating costs are defined by a 3

- year changeout period for fabric filter media and cages, and a gas pressure drop of 8 inch w.g.

Figure 8

- 3 shows for the 500 MW reference unit that a fabric filter requires abo ut half of the capital for either of wet FGD and SCR. As a result, total incurred cost for a fabric filter is about $5/MWh for the 80% capacity factor case. This cost

– alt hough notable for a 500 MW unit

– may not remove the unit from wholesale energy mark ets.

The cost impact can be very different for a 300 MW unit that employs allowance purchases to meet NO x and SO 2 mandates. A 300 MW unit, if incurring a fabric filter capital charge of $325/kW and operating at a 50% capacity factor, will incur a total ad ditional cost of $10/MWh.

Retrofitting a fabric filter to a 300 MW unit imposes a competitive disadvantage compared to natural gas/combined cycle generation. Figure 8

- 3 shows the incurred total cost for a fabric filter for this unit is about 1/2 the fuel cost for natural gas/combined cycle generation, for the $3/MBtu and 7,000 Btu/kWh heat rate, and about 1/3 the fuel cost for $4/MBtu and 8,000 Btu/kWh heat
rate.Cost Competitiveness

8

- 5 Figure 8

- 3 . Fabr ic Filter Total Cost vs. NG/CC Fuel Charge: 300 and 500 MW UnitsCurrent Capital Cost and Cost

- Effectiveness of Power Plant Emissions Control Technologies

A

- 1 APPENDIX A

EXAMPLE WET FGD CAPITAL COST DATA

Figure A

- 1. Individual Cost Data for Wet FGD: Phase 1 CAAA Applications (Curve A of Figure 5

- 1)Current Capital Cost and Cost

- Effectiveness of Power Plant Emissions Control Technologies

A

- 2 Figure A

- 2. Individual Cost Data for Wet FGD: 2003

- 2007 Applications (Curve B of Figure 5

- 1)Current Capital Cost and Cost

- Effectiveness of Power Plant Emissions Control Technologies

B

- 1 APPENDIX B

EXAMPLE SCR CAPITAL COST DATA

Figure B

- 1. Individual Cost Data for SCR: Curve B of Figure 6

- 1