Certificate of Authority Application

Edgewater Generating Station Unit 5

SO2 Reduction Project

Project Description and Justification

Wisconsin Power and Light Company

Madison, Wisconsin

July 27, 2012

Public VersionPSC REF#:169156

Public Service Commission of Wisconsin

RECEIVED: 07/27/12, 1:49:10 PM

Table of Contents

APPLICATION 1

INTRODUCTION 2

1.1 Edgewater Generating Station Unit 5 ....................................................................................... 4

1.2 Project Purpose ......................................................................................................................... 4

1.3 Selected Technology ................................................................................................................. 6

1.3.1 Technology Description 6

1.3.2 Technology Application at Edgewater Unit 5 6

1.4 Construction Approach ............................................................................................................. 9

1.5 Constructability Summary ...................................................................................................... 11

1.6 Milestone Schedule ................................................................................................................. 11

2.0 COST AND FINANCING ESTIMATES 13

2.1 Estimated Capital Cost and Cash Flow ................................................................................... 14

2.2 Financing Mechanism ............................................................................................................. 16

3.0 NEED AND ALTERNATIVE ANALYSIS 17

3.1 Planning For Emissions Regulatory Requirements ................................................................ 17

3.1.1 Cross State Air Pollution Rule (CSAPR) 17

3.1.2 Mercury and Air Toxics Standard (MATS) 18

3.1.3 Wisconsin State Mercury Rule (NR 446) 19

3.1.4 Potential EPA NSR/PSD Settlement 20

3.2 Emission Compliance Planning Process ................................................................................. 20

3.2.1 Evaluate Engineering Aspects of Emission Control Systems 20

3.2.2 Select Air Emission Compliance Plan 21

3.2.3 Implement Near-Term Tactical Responses for Regulatory Compliance 21

3.3 Project Need and Alternative Analysis ................................................................................... 21

3.3.1 Project Need 22

3.3.2 Analysis of Alternative Compliance Strategy 25

3.4 Need and Alternatives Analysis Summary ............................................................................. 34

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4.0 OPERATING PARAMETERS 35

4.1 Cost of Operations .................................................................................................................. 35

4.2 Operating Characteristics ........................................................................................................ 36

5.0 DESCRIPTION AND COST OF PROPERTY BEING REPLACED 38

6.0 REDUCTION TECHNOLOGY SELECTION 39

6.1 Technology Selection Process ................................................................................................ 39

6.2 Summary of Technology Assessment ..................................................................................... 39

7.0 ENVIRONMENTAL IMPACTS/PERMITS 41

7.1 Emissions Reductions ............................................................................................................. 41

7.2 Proximity to Floodplains......................................................................................................... 41

7.3 Information on Applicable Environmental Factors ................................................................ 41

7.3.1 Archaeological and Historic Resources 41

7.3.2 Threatened and Endangered Species 41

7.3.3 Solid Waste 42

7.3.4 Water Resources 42

7.3.5 Wastewater Discharge 42

7.3.6 Air Quality Resources 43

7.4 List of Permits and Approvals Needed ................................................................................... 43

8.0 DESIGNATION OF PUBLIC UTILITIES AND OTHERS AFFECTED 45

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FIGURES AND TABLES

Figure 1. Edgewater Unit 5 Project Location Map ...............................................................................5

Figure 2. Site Layout – Proposed Edgewater Unit 5 DFGD and FF System........................................8

Table 1. Edgewater Unit 5 DFGD Project Estimated Capital Cost ..................................................15

Table 2 Edgewater Unit 5 DFGD Project Annual Cash Flow .........................................................15

Table 3. Allocations ..........................................................................................................................18

Table 4. MATS Rule Limits .............................................................................................................19

Table 5 WPL Unit SO2 Emission Control and Operations Assumptions .........................................22

Table 6 WPL CSAPR Annual SO2 Emissions Comparison with Edgewater Unit 5 SO2 Controls .23

Table 7 WPL CSAPR Annual SO2 Emissions Comparison without Edgewater Unit 5 SO2 Controls.......... 24

Table 8 WPL‘s 2012 IRP Base Case and Sensitivities .....................................................................26

Table 9. Comparison of PVRR by Sensitivity between Installing DFGD and FF on Edgewater 5 and Early

Retirement of Edgewater .........................................................................................................................30

Table 10 EGEAS Analysis Results for Base Case.............................................................................31

Table 11. Calculations for the Payback Period of Installing a DFGD and FF on Edgewater Unit 5 .............33

Table 12. Edgewater Unit 5 DFGD Design Operating Parameters ....................................................35

Table 13 List of Required Permits and Approvals.............................................................................43

LIST OF APPENDICES

Appendix A General Site Layout

Appendix B Emission Reduction Technology Selection

Appendix C Integrated Resource Plan

Appendix D Project Conceptual Design Scope Assumptions

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ACRONYMS AND ABBREVIATIONS

ACI Activated Carbon Injection MATS Mercury and Air Toxics

Standards

AFUDC Allowance for Funds Used

During Construction

MM Million

B&W Babcock & Wilcox MMBtu Million British Thermal Units

BACT Best Available Control

Technology

MW Megawatts

BMP Best Management Practices NOx Nitrogen Oxides

BOP Balance of Plant NOV Notice of Violation

CA Certificate of Authority PVRR Net Present Value Revenue

Requirement

CAA Clean Air Act NSR New Source Review

CAIR Clean Air Interstate Rule O&M Operating and Maintenance

CaO Calcium Oxide (lime) PM Particulate Matter

CDS Circulating Dry Scrubber PM2.5 Particulate Matter less than 2.5

microns (μm) in diameter –

fine PM

CSAPR Cross State Air Pollution Rule PSCW Public Service Commission of

Wisconsin

CWIP Construction Work in Progress PSD Prevention of Significant

Deterioration

DCS Distributed Control System PRB Powder River Basin

DFGD Dry Flue Gas Desulfurization RACT Reasonably Available Control

Technology

DSI Dry Sorbent Injection SDA Spray Dryer Absorber

EGEAS Electric Generation Expansion

Analysis System

scfm standard cubic feet per minute

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EPA Environmental Protection

Agency

SCR Selective Catalytic Reduction

EPRI Electric Power Research

Institute

SIP State Implementation Plan

ESP Electrostatic Precipitator RPS Renewable Portfolio Standard

FD Forced Draft SOFA Separated Overfire Air

FF Fabric Filter SO2 Sulfur Dioxide

FGD Flue Gas Desulfurization SO3 Sulfur Trioxide

gpm Gallons per Minute SWWTF Sheboygan Waste Water

Treatment Facility

GWh Gigawatt hour TBtu Trillion British Thermal Units

H2O water Trona Sodium Sesquicarbonate

HAP Hazardous Air Pollutants WDNR Wisconsin Department of

Natural Resources

HCl Hydrogen Chloride WDT Wisconsin Department of

Transportation

ID Induced Draft WPL Wisconsin Power and Light

Company

IRP Integrated Resource Plan ZLD Zero Liquid Discharge

LSFO Limestone Forced Oxidation

LNB Low NOx Burners

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INTRODUCTION

Wisconsin Power and Light Company (WPL or the Company) respectfully requests

authorization from the Public Service Commission of Wisconsin (PSCW) to install a Dry Flue

Gas Desulfurization (DFGD) system, which includes a Fabric Filter (FF), (collectively the

Project or Control System) for control and removal of Sulfur Dioxide (SO2) on Edgewater

Generating Station Unit 5 (Edgewater Unit 5).

This project is part of WPL‘s plan to invest in needed controls at its newer, larger, and most

efficient generating units – the workhorses of our generation fleet – allowing customers to

continue to benefit from these existing assets. Our strategy is to equip these workhorse units

with emission control technologies to ensure they comply with applicable environmental rules,

now and in the future, so that we can continue meeting our customers‘ needs for reliable and

affordable energy.

Edgewater Unit 5 is one of WPL‘s larger and efficient units. Edgewater Unit 5 consists of a

wall-fired boiler with a gross maximum operating load of 430 MW. It is equipped with low NOx

burners (LNB) and separated overfire air (SOFA) to reduce Nitrogen Oxide (NOx) emissions.

Edgewater Unit 5 is also equipped with a cold-side electrostatic precipitator (ESP) for particulate

emissions control and activated carbon injection (ACI) to reduce mercury emissions. A selective

catalytic reduction (SCR) system is currently being installed on Edgewater Unit 51, with a

planned in service date of December 2012, to further reduce NOx emissions to meet Phase II

Reasonably Available Control Technology (RACT) requirements in accordance with Wis.

Admin. Code Chapter NR 428.

WPL seeks authority under Wis. Stat. §196.49 and Wis. Admin. Code PSC 112. Wis. Stat.

§196.49(2) requires a public utility to seek approval from the Commission that construction of its

Project does not violate any applicable rule or Commission Order. This Project meets the public

convenience and necessity, and the Project will not:

1. Substantially impair the efficiency of the service of the public utility.

2. Provide facilities unreasonably in excess of the probable future requirements.

3. When placed in operation, add to the cost of service without proportionately increasing

the value or available quantity of service unless the public utility waives consideration by

the commission, in the fixation of rates, of such consequent increase of cost of service.

The installation of the Control System on Edgewater Unit 5 meets the public convenience and

necessity because it allows WPL to continue to provide low cost, efficient energy in compliance

with environmental rules. Thus, Edgewater Unit 5 maintains its importance in WPL‘s generation

fleet for the foreseeable future. As will be demonstrated, the Control System on Edgewater

Unit 5 does not impair the efficiency of service, provide facilities unreasonably in excess of the

1 The Edgewater Unit 5 SCR project was applied for and approved under Docket No. 05-CE-137.

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probable future requirements, or add to the cost of service without proportionately increasing the

value of service.

WPL is committed to working cooperatively with PSCW and affected stakeholders on this

Project, which we hope to have in commercial operation in 2016. Importantly, the Project will

provide economic benefits not only to WPL‘s energy customers, but also to the Sheboygan area

as well as the State. The Project will allow Edgewater Unit 5 – a proven, reliable and efficient

facility – to maintain its importance in WPL‘s generation fleet for the foreseeable future.

Moreover, the Project will provide hundreds of jobs during peak construction, and keeping the

Unit on-line preserves an important source of jobs for Sheboygan and the surrounding

communities. As is the case with our other emission control projects, Wisconsin-made materials

will be used when possible, further boosting the local and State economies.

The proposed Control System enables WPL to comply with SO2 emission reduction

requirements, specifically those arising from the Environmental Protection Agency‘s (EPA)

Cross State Air Pollution Rule (CSAPR) or its replacement and would likely be required in any

potential settlement that WPL, the EPA, and Sierra Club reach regarding alleged New Source

Review (NSR) and Prevention of Significant Deterioration (PSD) air permitting violations.

WPL has developed a plan for reducing SO2 emissions from its fleet to meet CSAPR SO2

emissions reduction requirements through a combination of controlling emissions and unit

retirements. Reducing SO2 emissions at Edgewater Unit 5 is a critical component of this plan

and potential settlement with the EPA.2

Edgewater Unit 5 will benefit from the installation of the Control System through SO2 emissions

reductions of at least 90%, which also reduces the formation of fine particulate matter (PM2.5) in

the atmosphere, as SO2 is a precursor to PM2.5 formation. Reductions in SO2 emissions of at

least 90% translate into the removal of over 220,000 tons of SO2 from Edgewater Unit 5‘s

current emissions over a 30 year period.

Installation of a FF is a necessary component of a DFGD system to control particulate matter

(PM) emissions. The installation of the FF will provide additional benefit by reducing hazardous

air pollutants emitted from Edgewater Unit 5.

The Project is estimated to cost $413.7 MM. WPL‘s modeling of the Project and retirement of

Edgewater Unit 5 demonstrates that the Project is the most cost-effective alternative for meeting

future capacity and energy needs of WPL‘s customers. Installing the Control System will help to

ensure that WPL has sufficient capacity and energy to economically meet its long-term demands

while maintaining comparable reliability as compared to its current operations.

2 Although WPL has not reached a settlement with EPA regarding alleged NSR/PSD air permitting violations, and

settlement is not guaranteed, WPL has assumed a potential settlement would require SO2 emission reductions from

Edgewater Unit 5. Based upon its exploration of settlement options to date, WPL anticipates that the proposed

DFGD system at Edgewater Unit 5 would provide the SO2 emission reductions agreed to in the settlement.

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1.0 PROJECT DESCRIPTION

1.1 Edgewater Generating Station Unit 5

The Edgewater Generating Station (Edgewater) is located in the city of Sheboygan, Wisconsin,

along Lake Michigan (Figure 1). Edgewater Unit 5 began operating in 1985 with a design gross

capacity of 380 MW. The unit currently runs at a gross maximum operating load of 430 MW

and burns low sulfur Powder River Basin (PRB) coal. Edgewater Unit 5 has a Babcock &

Wilcox (B&W) wall-fired boiler retrofitted with LNB and SOFA technology to reduce NOx

emissions, an ACI system for mercury removal, followed by a cold-side ESP for particulate

emissions control. A SCR system is currently being installed on Edgewater Unit 5 to further

reduce NOx emissions to meet RACT Phase II requirements.

1.2 Project Purpose

The proposed emissions reduction project encompasses the installation of a DFGD system and

FF to reduce SO2 emissions from Edgewater Unit 5. The Control System was selected because it

meets the following WPL strategic objectives for Edgewater Unit 5:

Reduce SO2 emissions in a cost-effective manner to comply with current, pending and

future environmental regulations that require SO2 emissions reductions including the

federal CSAPR or similar replacement regulation.

Reduce SO2 emissions in a cost-effective manner that complies with emission reduction

requirements that could be required under a consent decree with the EPA and the Sierra

Club regarding alleged violations of NSR and PSD regulations at Unit 5.3

Constitute an economic benefit when compared to replacement of Edgewater Unit 5.

Minimize increased emission of other regulated pollutants.

Minimize generation of mercury contaminated wastewater from SO2 emission reduction

equipment.

Minimize the adverse impact on Edgewater Unit 5 balance of plant operations during and

after construction.

Maintain access to existing equipment for maintenance.

Provide long-term reliable operation of Edgewater Unit 5.

3 As discussed in Section 3.1.4, WPL has not reached agreement with the EPA and Sierra Club on resolution of the

Notice of Violation (NOV) and the related complaints, and the negotiations are the subject of a confidentiality

agreement. The discussion contained in this application reflects what WPL believes, based in part on existing

consent decrees would ultimately be included in a consent decree among WPL, EPA, and Sierra Club.

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Figure 1. Edgewater Unit 5 Project Location Map

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1.3 Selected Technology

Various flue gas desulfurization (FGD) technologies were assessed.4 DFGD with FF was

selected as the technology most suitable to be implemented for reduction of SO2 emissions from

Edgewater Unit 5 based on the strategic objectives previously noted. DFGD with FF is

characterized by the use of lime reagent, partial saturation of the flue gas stream, and production

of a dry byproduct.

1.3.1 Technology Description

The technology proposed for SO2 emissions reduction at Edgewater Unit 5 is a combination of a

DFGD and FF. With the DFGD technology, the flue gas exiting the Edgewater Unit 5 ESP

enters the absorber vessel; in the vessel, lime, water, and—depending on the design—recycled

solids contact the flue gas stream, which allows for sulfur oxides (SO2 and SO3) in the flue gas to

react with the lime reagent to form calcium compounds (CaSO3, CaSO4) that can then be

removed by the FF, in effect, scrubbing the flue gas. The major reactions in the absorber vessel

are as follows:

Lime Hydration: CaO + H2O Ca(OH)2

SOx Reactions: Ca(OH)2 + SO2 CaSO3 • ½ H2O + ½ H2O

Ca(OH)2 + SO3 + H2O CaSO4 • 2H2O

Sulfite Oxidation: Ca(OH)2 + SO2 + H2O + ½ O2 CaSO4 • 2H2O

Water introduced into the absorber vessel vaporizes, lowering the temperature and raising the

moisture content of the flue gas, which promotes removal of SO2. A FF, installed downstream of

the absorber vessel, removes the dry solids from the scrubbed gas. The dry solids consist of the

calcium compound reaction products, unreacted hydrated lime, and remaining flyash. A portion

of the dry solids from the FF may be recycled to the inlet of the absorber vessel depending on the

vendor-specific design. The remaining byproduct solids from the FF are sent to a landfill for

disposal.

1.3.2 Technology Application at Edgewater Unit 5

The preliminary design and sizing of the DFGD system is based on a Design Coal5 that

represents the range of current operating coals burned at Edgewater Unit 5 from various PRB

mines. The DFGD vessels and FF will be located north of Edgewater Unit 5, in an open area of

the plant site adjacent to the Sheboygan Waste Water Treatment Facility (SWWTF). New

ductwork will tie-in to the existing Unit 5 ductwork downstream of the existing ESP and induced

draft (ID) fans and will run to the inlet of the DFGD vessel. Lime receiving equipment will be

4 The full results of this assessment is presented in Appendices B and summarized in Section 6 of this Application.

5 Design Coal is defined in this application as coal that will be used for design and sizing of the DFGD system as

well as determining costs for equipment. The Design Coal is a fuel with characteristics that could reasonably be

burned at Edgewater Unit 5 in the future and allows for future fuel flexibility.

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located west of the DFGD vessels to allow for easy access from the main gate and limit truck

traffic to the interior of the plant site. New ID booster fans and ductwork located downstream of

the FF will transfer flue gas to the tie-in point at the existing chimney.

The site arrangement in Figure 2 shows a plot plan of the proposed Edgewater Unit 5 DFGD

project relative to the existing units. This layout is based on preliminary system design and

subject to revision with further detailed design and selection of equipment vendors.

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Edgewater Unit 5‘s existing ACI location6 is upstream of the air heater, and the carbon is

collected with the flyash in the existing ESP. The amount of activated carbon injected does not

substantially impact the flyash properties, and therefore Edgewater Unit 5 has been able to

maintain its flyash sales. Since the ACI location upstream of the air heater does not interfere

with flyash sales, the ACI will not be moved as part of the installation of the DFGD and FF. The

inclusion of a FF with the installation of the DFGD system does allow for the option in the future

to move the injection location downstream of the existing ESP and to collect the flyash separate

from the activated carbon should flyash sales be impacted by future changes to regulations.

The emissions reduction project will also include the following auxiliary equipment to support

the operation of the Control System:

Reagent storage and preparation equipment

Solids recycle equipment (if applicable to specific vendor design)

ID booster fans

Associated ductwork

Waste material handling equipment

A new controls building and new electrical equipment

Distributed control system for the new process equipment

Modifications to existing landfill site to accept the new DFGD waste

Balance of plant piping (fire protection, service water, compressed air, etc.)

Material Warehouse

Truck loading for byproducts

Truck unloading for lime

1.4 Construction Approach

The area north of the Edgewater Unit 5 chimney has been selected for the installation of the

Control System. This area is relatively open with a few existing structures that will need to be

removed or worked around to accommodate the construction of the Control System. The

selected site has limited or no access on three sides: a plant access road and the Edgewater Unit

5 chimney limit access to the south; Lake Michigan limits access to the east; and the SWWTF

limits access to the north. Construction activity sequencing and coordination with normal plant

activities will be vital to working within the constraints of the designated area with minimal

impacts on the existing plant operations. Outages will be required to tie-in the Control System.

6 The current ACI injection location is upstream of the air heaters, at the economizer outlet. When the SCR is

installed, the ACI injection location will be moved to downstream of the SCR, but still upstream of the air heater. In

both configurations, the ACI is upstream of the air heaters and ESP.

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WPL plans to minimize plant down-time by taking advantage of planned maintenance outages to

tie-in the new equipment.

The following is a high-level overview of the construction approach for the Project, which

focuses on minimizing the required outage duration of Edgewater Unit 5 and the impact of

construction on facility operations. Details included here may vary from the actual construction

approach after completion of detail engineering, specific equipment procurements, and

constructor(s) selection.

Laydown

Laydown space is available on WPL property west of Lakeshore Drive. This area is currently

being used as a laydown and staging area for the installation of the SCR on Edgewater Unit 5.

As such, it already has the necessary utilities in a fenced-in secure area, which WPL intends to

use to support the Project. Additional laydown, fabrication and staging areas will be required for

the Project at both Edgewater and off-site.

Civil

Structures, components, and foundations will be designed so that their strength equals or exceeds

the effects of factored load combinations. A geotechnical report will be used to define

foundation requirements. Buildings will enclose and protect the major equipment and provide

noise attenuation. Foundations for the primary equipment will be the first structures constructed

upon start of construction.

Demolition

A majority of the new equipment, including the absorber vessels, FF, ID booster fans, and lime

handling equipment, will be located in an area away from the main plant. Accordingly, the

Project will not require significant demolition or relocation of equipment or facilities. Area

preparation will require removal of the northeast storage building and rail spurs located north of

the Edgewater Unit 5 chimney. The contents of the storage building will be relocated. A new

rail spur will be located west of the rail yard to replace the track being demolished. (See Section

5 and Appendix A for further detail on demolition plans.)

DFGD Absorber and FF

The absorber vessels and FF equipment likely will be fabricated off-site and shipped in large

pieces to the project site. Fabrication approach will be finalized upon selection of the equipment

vendors and constructor(s), and will emphasize minimizing on-site fabrication.

Ductwork

Rectangular steel plate ductwork, including duct plate, stiffeners, and ductwork support structure

will be shipped to the site for installation. Some ductwork may be shop fabricated prior to

shipment to minimize on-site fabrication.

Mechanical Equipment

New mechanical equipment includes new ID booster fans and motors, lime unloading and

storage equipment, lime preparation equipment, solids handling equipment, blowers and air

compressors. The equipment details will be finalized in the detailed engineering phase, after

equipment vendors have been selected.

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Electrical

A fully redundant power supply will be installed to provide electrical power for the new

equipment. Major components of the electrical system include feeder cables from existing

switchgear, auxiliary transformers, motor control centers, substations and substation

modifications, and system grounding.

Instrumentation and Controls

New instrumentation and controls are required for the Control System operation. The additional

instrumentation and controls will be integrated into the plant‘s existing distributed control system

(DCS). The primary control functions will be automated process control, system monitoring,

and operational alarms. New controllers and operator and engineering workstations will be

provided with the new instrumentation and controls equipment. To the extent possible, the

existing continuous emissions monitoring systems (CEMS) will be utilized and recalibrated for

the lower emissions rates.

1.5 Constructability Summary

Based on site reviews and assessments conducted by engineering consultants, DFGD and FF

systems are feasible for installation and operation on Edgewater Unit 5. While there are site

specific constraints, the retrofit work is expected to be completed with minimal impact to

existing operations due to detailed planning and construction sequencing of the installation of

new equipment.

The site layout and construction approach is based on preliminary system design and subject to

revision with further detailed design and selection of equipment vendors and constructor(s). The

following tasks will be completed during detailed engineering to finalize the engineering plan,

layout and construction approach:

Selection of a specific DFGD technology

Selection of DFGD equipment vendor

Layout of vendor-specific equipment

Boiler implosion and transient analysis

Selection of constructor(s)

1.6 Milestone Schedule

Detailed engineering for the project is scheduled to begin in the third quarter of 2013. The

Project is anticipated to be in service in the fourth quarter of 2016. Timely approval of the

Project by the Commission will provide WPL schedule flexibility to minimize impacts of market

fluctuations in the cost of labor, materials, and capital. These market fluctuations may intensify

due to increased demand for DFGD and FF equipment needed to comply with pending or future

environmental regulations.

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The Table below presents WPL‘s anticipated regulatory timeline.

Milestone Date

Submit CA Application to PSCW July 2012

Receive CA (expected) 1st or 2

nd Quarter 2013

Award detailed engineering and procurement contract

(limited notice to proceed) 3rd

Quarter 2013

Receive environmental permits (expected) 2nd

Quarter 2014

The table below presents a preliminary milestone schedule for construction of the Edgewater

Unit 5 DFGD system to be in service in the fourth quarter of 2016. This schedule serves as the

basis for the Electric Generation Expansion Analysis System (EGEAS), which is discussed

further in Section 3.3.2 and Appendix C. The project schedule will be refined after the

engineering, procurement, and construction contracts have been signed, detailed engineering

begins, and after receipt of regulatory approval.

Milestone Date

Begin Construction 2nd

Quarter 2014

Equipment Commissioning 1st Quarter 2016

Tie-in outage 3rd

Quarter 2016

In Service 4th

Quarter 2016

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2.0 COST AND FINANCING ESTIMATES

An independent engineering consultant developed capital and operating and maintenance (O&M)

cost estimates for the Edgewater Unit 5 Project. The total Project estimate presented in this

section includes the following major items:

Civil, Structural, and Architectural Items – foundations, support and structural steel, and

flue gas ductwork

Mechanical and Process Equipment – DFGD and FF equipment, ID booster fans, lime

reagent and solids handling equipment, process piping, fire protection, blowers and air

compressors, spare parts, and balance of plant mechanical systems

Electrical Systems – auxiliary power distribution, transformers, motor control centers,

lighting, grounding, heat tracing, and the construction power system

Instrumentation and Controls – distributed control system (DCS) integration into existing

system and local instrumentation and controls of process equipment

Balance of Plant – steel, concrete, demolition and relocation and site preparation work

Landfill Modifications – installation of solids handling and storage equipment at the I-43

landfill, including site preparation, foundations, support steel, piping, electrical, and

instrumentation and control items

Fees – engineering, construction management, and start-up services, including

commissioning and performance testing

Owners‘ Costs – WPL personnel for management of the project and liaison with plant

operations, training of operating staff, project integration with existing plant equipment,

insurance, taxes, first fills reagent, emergency spares and contingency.

Costs presented in this CA application represent the engineering consultant‘s estimate, prepared

in May 2012, for the design, supply, and installation of the Control System. The estimate is

based on budgetary quotations received from vendors for the design and supply of the DFGD

and FF system7 and on the engineering consultant database of equipment, material and project

costs. In particular, costs for the design and supply of Balance of Plant (BOP) equipment and

installation of the DFGD and FF system and BOP equipment was developed by the engineering

consultant using such a database. WPL‘s project specific owner‘s costs mentioned above are

also included in the estimate.

7 Noted as a recommended next set item in Appendix B Section 7.2, these more site specific detail estimates were

requested to confirm the cost to install semi-dry FGD systems onto Edgewater Unit 5 for the purpose of this

application. These site specific estimates account for the cost difference between the model estimate in Appendix B

and the more detail cost estimate provided in the application.

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The estimate was adjusted in accordance to the construction milestone schedule included in

Section 1.6 to provide project costs consistent with the Project being in service in the fourth

quarter of 2016. An escalation rate of 3% per year was used to address anticipated inflation.

The costs have an expected accuracy of -10/+20%. The expected accuracy band and the project

escalation is not intended to account for significant increases in costs for the supply of material

or services due to unexpected market changes.

2.1 Estimated Capital Cost and Cash Flow

Estimated capital costs for the Edgewater Unit 5 Control System are provided in Table 1 and are

based upon the schedule presented in Section 1.6. The costs presented are inclusive of WPL‘s

internal costs. These costs do not include Allowance for Funds Used During Construction

(AFUDC).8

8 AFUDC is the process of including as a part of the total project costs, the applicable carrying costs on Construction

Work In Progress (CWIP) expenditures. If such CWIP balances are included in net investment rate base in a rate

proceeding, then AFUDC would not be included or computed on such amounts. WPL will request 50% CWIP to be

included in rate base for this project at the next available base rate case for consideration by this Commission.

Pursuant to the PSCW‘s Final Decision in Docket No. 6680-UR-118, WPL will accrue AFUDC on 100% of CWIP

balances between the time of Construction Authority (CA) approval and WPL‘s next available base rate case.

Because of the uncertainty of the timing and amount of AFUDC that may be applicable to this project, WPL has not

included AFUDC in this estimate. EGEAS runs assume 50% CWIP to be included in the rate base.

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Table 1. Edgewater Unit 5 DFGD Project Estimated Capital Cost

Description Cost ($)

Engineering / Home Office $31,850,000

DFGD/FF Equipment $57,350,000

Material Storage Equipment $5,360,000

ID Booster Fan Equipment $4,610,000

Other Engineered Equipment $7,860,000

Ductwork & Support Steel Material $8,740,000

Bulk Materials $10,590,000

Construction Labor $76,000,000

Construction Subcontracts $30,140,000

Construction Indirects $26,800,000

Construction Management / Start-Up Services $51,390,000

Sub-Total $310,690,000

Landfill Modificationsa $14,270,000

Sub-Total $324,960,000

Owners‘ Costs $88,750,000

Total Project Costb $413,710,000

a. Landfill modification costs include engineering, equipment, bulk materials, construction costs (labor,

subcontracts, indirects, management and start-up).

b. Accumulated project cost in year-of-occurrence dollars as presented in Table 2.

Cash flow estimates for the project schedule in Section 1.6 are shown in Table 2. These costs

include escalation and contingency but, as stated above, do not include AFUDC.

Table 2. Edgewater Unit 5 DFGD Project Annual Cash Flow

Year Annual % of Total Cost Annual Cash Flow ($)a

2013 2.4% $9,740,000

2014 14.7% $60,870,000

2015 46.3% $191,510,000

2016 35.5% $146,990,000

2017 1.1% $4,600,000

Total Project

Cost 100.0% $413,710,000

a. Costs are presented in year-of-occurrence dollars.

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Actual project costs and cash flow will vary depending upon project approval timing, actual

project schedule, and market conditions. It is expected that the pending and future federal

emissions control regulation will increase demand for DFGD and FF equipment. Timely

approval of this project may allow WPL to procure equipment and services at more favorable

pricing. It will also allow WPL to better manage risks associated with competing for a limited

supply of skilled labor (design engineers, craft labor, etc.) with others for this same type of

projects.

2.2 Financing Mechanism

The Edgewater Unit 5 Project is proposed as a rate-based project, financed using the traditional

utility capital structure. AFUDC, as applicable, will be included as part of the construction costs,

where all of the capital costs, including AFUDC, will be placed in-service and transferred to the

appropriate electric utility plant accounts and recovered through traditional ratemaking

treatment. The accrual and rate treatment of AFUDC will be in accordance with applicable

FERC regulations and PSCW rate orders covering the construction period.

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3.0 NEED AND ALTERNATIVE ANALYSIS

The proposed Control System at Edgewater Unit 5 enables WPL to comply with SO2 emission

reduction requirements, specifically those arising from the CSAPR or its replacement, and would

likely be required under any settlement between WPL, the EPA, and Sierra Club regarding

alleged NSR and PSD air permitting violations. The analysis presented in this section assesses

the installation of a DFGD and FF to reduce SO2 emissions at Edgewater Unit 5 as well as the

retirement and replacement of Edgewater Unit 5 as the compliance alternative. Both options

result in significant SO2 emission reductions from Edgewater Unit 5 although only the proposed

Control System ensures the long-term viability of the unit.

This section provides an overview of the analysis used to determine the need for the proposed

Control System at Edgewater Unit 5. The following sub-sections describe the emissions

regulatory requirements and compliance planning process as well as the need and rationale for

the proposed Control System at Edgewater Unit 5 and alternative of retirement and replacement.

3.1 Planning For Emissions Regulatory Requirements

Current federal and state air emission requirements that are applicable to Edgewater Unit 5 and

relevant to the proposed Control System include CSAPR, Mercury and Air Toxics Standard

(MATS), the Wisconsin Mercury Rule (NR 446) and any potential settlement that WPL may

enter into with the EPA and Sierra Club regarding alleged NSR and PSD air permitting

violations. The implications of these requirements on Edgewater Unit 5 and the impact of the

proposed Control System at Edgewater Unit 5 on WPL‘s ability to comply with them are

presented in Section 3.3 as part of the project need analysis. Additional information on

environmental regulations that apply more broadly to WPL‘s operations is provided in Section 8

of the 2012 Integrated Resource Plan (IRP) included in Appendix C.

3.1.1 Cross State Air Pollution Rule (CSAPR)

In July 2011, the EPA issued CSAPR, which includes requirements to reduce SO2 and NOx

emissions from fossil-fueled Electric Generating Units (EGUs) located in 27 states in the eastern

half of the United States. WPL‘s fossil-fueled EGUs with greater than 25 MW capacity

(including Edgewater Unit 5) would be impacted by CSAPR requirements. CSAPR was

expected to replace the Clean Air Interstate Rule (CAIR) and establish state emission caps for

SO2 and NOx beginning in 2012, to be known as Phase I. These SO2 and NOx emission caps

were expected to be lowered further by CSAPR in 2014 for EGUs located in Wisconsin, to be

known as Phase II. CSAPR also includes assurance provisions that would enforce state emission

caps. Beginning in 2012, these provisions require regulated EGUs with emissions in excess of

their allocated share of state emission caps to surrender additional penalty emission allowances

to the extent the emissions of the state as a whole are in excess of the state caps. These

provisions are expected to limit the amount of emissions trading that would be used to meet

compliance requirements.

In December 2011, the EPA also issued a final supplemental rule that added Wisconsin to

CSAPR for the ozone season NOx emissions trading program. In February 2012, the EPA issued

final revisions to CSAPR to correct the calculation of emission budgets in certain states,

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including an increase of the allowed Phase II annual SO2 budget and Phase I and II annual NOx

budgets for Wisconsin. These revisions would also delay the effective date of the assurance

provisions of CSAPR to Phase II, rather than in Phase I. The EPA is proceeding with final

issuance of these revisions to implement the changes as part of CSAPR, if the stay discussed

below is removed.

In December 2011, the United States Court of Appeals for the District of Columbia Circuit (D.C.

Circuit) stayed the implementation of CSAPR, and, as a result, CAIR obligations remain

effective pending further review by the D.C. Circuit and the EPA. WPL is currently unable to

predict the final outcome of the CSAPR stay. WPL currently believes that CAIR will be

replaced in the future, either by CSAPR, as currently written or as modified based upon a ruling

from the D.C. Circuit, or another rule that addresses the interstate transport of air pollutants.

Utility companies would comply with CSAPR emission requirements by surrendering one

CSAPR allowance for each ton of pollutant emitted. Utilities are allowed to purchase additional

CSAPR allowances to surrender if their emissions exceed their allowance allocations. In

addition, beginning in Phase II (2014), CSAPR would penalize utilities whose:

Emissions exceed their allowance allocation by 18% or more for annual SO2 and NOx

emissions, or by 21% or more for ozone season NOx emissions; and

Jurisdictional state‘s emissions exceed its allowance allocation in the same manner.

CSAPR contains a condition that would require that emission allowances allocated to a unit

which does not operate for two consecutive years must be retired after the fourth year of no

operation. The CSAPR emission allocations for WPL are presented in Table 3. This

information includes the allocations for WPL‘s share of units it operates. WPL CSAPR SO2

Emission allowances would no longer be available for compliance in the fifth year after the unit

retires and would be removed from the company‘s allowance allocation pool.

Table 3. Allocations

CSAPR Implementation Year CSAPR Emission Allocationsa

(tons)

2012 – Phase I 15,932

2014 – Phase II 9,498

a. CSAPR emission allocations listed for 2014 include Riverside Units 1 and 2. On May 18, 2012, WPL

announced that it exercised its option to purchase Riverside Energy Center, LLC, which currently

owns the Riverside Energy Center, from Calpine Corporation. Values represent WPL‘s ownership

share for jointly-owned units, which includes 46.2% of Columbia 1 and 2, and 68.2% of Edgewater 4.

3.1.2 Mercury and Air Toxics Standard (MATS)

In December 2011, the EPA issued the final Utility Maximum Achievable Control Technology

(MACT) Rule, also referred to as MATS. The MATS rule applies to all WPL coal-fueled EGUs

with greater than 25 MW of capacity located in Wisconsin, including Edgewater Unit 5. The

final rule requires compliance with emission limits for mercury, filterable PM as a substitute for

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non-mercury metal HAP, and hydrogen chloride (HCl) as a substitute for acid gas HAP. The

EPA also proposed alternative standards for total or individual non-mercury metals emissions

(instead of filterable PM) and SO2 emissions (instead of HCl for acid gases if a FGD system is

installed). In addition, work practice standards were proposed for organic HAPs emissions to

ensure proper combustion. Compliance is currently anticipated to be required by April 2015.

However, an entity can request an additional year for compliance, which may be granted on a

case-by-case basis by state permitting authorities for units that are needed to assure power

reliability, units repowering to gas, or units that need additional time to install air emission

control technology. The final MATS rule is subject to legal challenge in the D.C. Circuit.

Table 4 presents the MATS rule limits contained in the final rule.

Table 4. MATS Rule Limits

Pollutant Units Limit

Mercurya

lb/TBtu 1.2

Filterable Particulate Matter lb/MMBtu 0.03

Hydrogen Chlorideb lb/MMBtu 0.002

a. The MATS rule also has a generation-based mercury limit similar to NR 446 of 0.008 lb/GWh

b. There is an alternative acid gas limitation for EGUs that have a flue gas desulfurization (FGD) system

and SO2 CEMs installed. This alternative SO2 limitation is 0.20 lb/MMBtu.

3.1.3 Wisconsin State Mercury Rule (NR 446)

The Wisconsin State Mercury Rule requires electric utility companies in Wisconsin to meet

compliance requirements to reduce annual mercury emissions by 40% from a historic baseline

beginning in 2010 (Phase I). In addition, the Wisconsin State Mercury Rule requires large coal-

fueled EGUs with greater than 150 MW of capacity to either achieve a 90% annual mercury

emissions reduction standard or limit the annual concentration of mercury emissions to 0.008

pounds of mercury per gigawatt-hour beginning in 2015 (Phase II).

Small coal-fueled EGUs between 25 MW and 150 MW of capacity must install Best Available

Control Technology (BACT) by January 2015 to reduce mercury emissions. The Wisconsin

state mercury rule may change as a result of EPA issuing a final MATS rule because of a

requirement that the state rule be similar but not more restrictive than federal mercury

regulations. Within six months of the EPA issuing the final MATS rule, the Wisconsin state

mercury rule must be compared to the federal rule and interpreted as to whether the state rule

could be considered more restrictive than the federal rule. If the state rule is determined to be

more restrictive than the federal rule, it will need to be changed. In 2010, WPL filed its

compliance plan with the WDNR. WPL‘s will utilize large and small EGU averaging to comply

with the additional mercury rule emissions reduction requirements that commence in 2015.

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3.1.4 Potential EPA NSR/PSD Settlement

In December 2009, the EPA sent a NOV to WPL as an owner and the operator of Edgewater,

Nelson Dewey and Columbia Generating Stations. The NOV alleges that the owners failed to

comply with appropriate pre-construction review and permitting requirements and as a result

violated the PSD program requirements, Title V Operating Permit requirements of the Clean Air

Act (CAA), and the Wisconsin State Implementation Plan (SIP). In September 2010, the Sierra

Club filed a complaint against WPL in the U.S. District Court for the Eastern District of

Wisconsin, as owner and operator of the Edgewater Generating Station, which contained similar

allegations that modifications were made at Edgewater without complying with the CAA

requirements. In the Edgewater complaint from the Sierra Club, additional allegations were

made regarding violations of emission limits for visible emissions.

WPL believes the projects at Edgewater, Nelson Dewey and Columbia were routine or not

projected to increase emissions and therefore did not violate the permitting requirements of the

CAA. WPL is currently engaged in settlement negotiations with the EPA and Sierra Club.

Although WPL has not reached a settlement, and settlement is not guaranteed, for the purpose of

this CA application, WPL has assumed, based in part on existing EPA settlements, that any

settlement with EPA and Sierra Club will require SO2 emission reductions at Edgewater Unit 5.

To maintain schedule requirements, WPL is filing this CA application now using these assumed

emission reductions. If, as expected, a resolution of the EPA NOV is achieved, WPL will update

this application to take into account any terms or conditions of the settlement to the extent they

contradict the assumptions used in this application.

3.2 Emission Compliance Planning Process

Air emissions are managed by WPL on a system basis through a strategic planning process and

multi-emission strategy that considers both increasingly stringent environmental requirements

and changing demand on EGUs. This planning process is highly dynamic and continually

evolving to address current and anticipated conditions. Work associated with the planning

process encompasses strategy development, long-term strategic planning, and shorter-term

tactical implementation, more precisely detailed below.

3.2.1 Evaluate Engineering Aspects of Emission Control Systems

Air pollution control systems are evaluated for incorporation into the emission compliance plan,

factoring in current information on technology performance, cost, and operational constraints.

Commercially Available Control Technologies

The current status of emission control technology performance is monitored and evaluated

through trade organizations, emission control equipment suppliers, and engineering design firms

that support the installation of emission control equipment. This information assists in

determining appropriate emission control options to consider for long-term emissions planning.

Once long-term strategic emissions plans are approved, technical staff proceeds with preliminary

engineering necessary to make the final selection of plant and unit-specific emission controls.

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Physical and Operational Constraints

Each power plant site and EGU is unique in its configuration. This presents specific engineering

and design aspects that must be considered in the emission planning process, including fuel use

and fuel use capability, current emission control equipment performance, physical space

available for new emission controls, necessary equipment upgrades to support emission controls,

required maintenance, and the potential need to shut down units for prolonged periods to install

the new equipment. Each stakeholder must coordinate its power plant outages with those of

other regional power plants and the electric transmission system operator to confirm adequate

power is available during outage periods. The engineering services group defines possible

timing of control installation, including planned outages and other power plant maintenance

activities, to ensure the continuation of reliable and cost-effective utility operations during

emission control equipment installation.

3.2.2 Select Air Emission Compliance Plan

The air emission planning process creates cost-effective and feasible emission control strategies

that consider available emission control technologies and their associated costs and performance.

Emission reduction projects are chosen by matching projected future emissions against various

environmental compliance scenarios and forecasted electricity demand. As discussed earlier in

this section, the environmental compliance scenarios considered in emissions planning include

current federal and state air quality standards, as well as more stringent outcomes associated with

future federal and state regulations. The potential EPA settlement is an additional potential

compliance requirement and, as such, assumptions regarding a potential settlement are

incorporated into the WPL compliance plan.

The selection of an air emission plan is completed on the basis of regulatory compliance, cost,

and feasibility of implementation and technology performance. The air emission planning

process combines needed emission reductions, available emission controls, and other operational

considerations. The outcome is development of a long-term plan to install multi-emission

controls on specific generating units at specific points in time.

3.2.3 Implement Near-Term Tactical Responses for Regulatory Compliance

While long-term plans assist in understanding the sensitivity of proposed emission controls to

differing environmental compliance scenarios and help prioritize investments in emission control

equipment, shorter-term tactical plans aid in the selection of specific emission controls for

detailed technical reviews, determine feasibility at a plant and unit-specific level, refine cost

estimates, and update financial budgets. Shorter-term tactical plans span the immediate two to

five-year period. Due to the significant construction lead time necessary to install major air

pollution controls, implementation of the short-term tactical plan must occur as part of the

longer-term strategy.

3.3 Project Need and Alternative Analysis

WPL uses the EGEAS model to analyze its current and future generation needs. WPL‘s EGEAS

analysis of project need and alternative compliance strategies applies common generation unit

emission control and operations assumptions to WPL‘s two plans. Plan 1 represents installation

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of the DFGD and FF, and Plan 2 represents early retirement. Each plan was analyzed under a

Base Case (or Reference Case9). Each plan was also analyzed under nineteen sensitivities that

adjusted assumptions such as fuel prices, renewable generation requirements, constraints on

carbon emissions, etc.

WPL then compares the EGEAS Present Value Revenue Requirement (PVRR) of each Plan

under the Base Case and each sensitivity to determine the relative economic merit of each plan.

3.3.1 Project Need

CSAPR

The Control System is needed at Edgewater Unit 5 to comply with the SO2 emission reduction

requirements of Phase II of the CSAPR.

Table 5 summarizes plant controls and planned retirements with regard to SO2 emission

reductions. Retirement dates are not definitive.

Table 5. WPL Unit SO2 Emission Control and Operations Assumptions

Generation Unit Planned

Control/Operation

Timing

Columbia 1 DFGD and FF Mid-2014

Columbia 2 DFGD and FF Mid-2014

Edgewater 3 Unit Retirement End of 2015

Edgewater 4 Unit Retirement End of 2018

Edgewater 5 DFGD and FF End of 2016

Nelson Dewey 1 Unit Retirement End of 2015

Nelson Dewey 2 Unit Retirement End of 2015

In its project need planning and analysis, WPL assumes that annual SO2 emissions under

the CSAPR cannot exceed the WPL fleet allowance allocation by more than 18%. This

assumption avoids the possibility of any potential assurance provision-related penalties.

WPL‘s project need analysis also considers that CSAPR requires retirement of emission

allowance allocations for units that cease operation in the fifth year after operations have

ceased.

9 Base Case and Reference Case are used interchangeably in the application and in Appendix C.

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Table 6 presents projected SO2 emissions data for the WPL coal-fired generation fleet after the

Edgewater Unit 5 SO2 controls are operational (90 percent removal efficiency) compared to the

CSAPR Phase II SO2 allowance allocation. As demonstrated by the data presented in Table 6,

WPL will achieve compliance with CSAPR Phase II SO2 emission reduction requirements under

its emission control and operational plan. As shown in Table 7, without the planned Edgewater

Unit 5 Control System, WPL would have a CSAPR Phase II SO2 allowance deficit of

approximately 3,500 tons, nearly 60% of its allocation, after unit retirements. This would subject

WPL to potential CSAPR assurance provision related penalties.

Table 6. WPL CSAPR Annual SO2 Emissions Comparison with Edgewater Unit 5 SO2

Controls

Generation

Unita

2011 Actual

SO2

Emissionsb

(tons)

Projected

SO2

Emissionsc

(tons)

CSAPR Phase II

SO2 Allowance

Allocationd

(tons)

CSAPR Phase II

SO2 Allowance

Allocation Post-Unit

Retiremente (tons)

Columbia 1 5,750 624 1,789 1,789

Columbia 2 5,788 611 1,786 1,786

Edgewater 3 641 0 426 0

Edgewater 4 3,555 0 1,438 0

Edgewater 5 8,340 858 2,421 2,421

Nelson Dewey 1 5,684 0 746 0

Nelson Dewey 2 5,821 0 869 0

WPL TOTAL 35,579 2,093 9,475 5,995

a. Data represents WPL‘s share of jointly-owned units

b. Actual 2011 emissions data as measured by continuous emissions monitor

c. Projected emissions based on anticipated emission rate after controls are operational and 2011 actual heat

input

d. Allowance allocation does not include allowances assigned to WPL gas-fired units

e. Allowance allocation post-unit retirement assumes allocated allowances are no longer available in the fifth

year after the unit ceases operation, does not include allowances allocated to WPL gas-fired units

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Table 7. WPL CSAPR Annual SO2 Emissions Comparison without Edgewater Unit 5 SO2

Controls

Generation

Unita

2011

Actual

SO2

Emissionsb

(tons)

Projected

SO2

Emissionsc

(tons)

CSAPR Phase

II SO2

Allowance

Allocationd

(tons)

CSAPR Phase II

SO2 Allowance

Allocation Post-Unit

Retiremente (tons)

Columbia 1 5,750 624 1,789 1,789

Columbia 2 5,788 611 1,786 1,786

Edgewater 3 641 0 426 0

Edgewater 4 3,555 0 1,438 0

Edgewater 5 8,340 8,238 2,421 2,421

Nelson Dewey 1 5,684 0 746 0

Nelson Dewey 2 5,821 0 869 0

WPL TOTAL 35,579 9,473 9,475 5,995

a. Data represents WPL‘s share of jointly-owned units

b. Actual 2011 emissions data as measured by continuous emissions monitor

c. Projected emissions based on anticipated emission rate after controls are operational and 2011 actual heat

input

d. Allowance allocation does not include allowances assigned to WPL gas-fired units

e. Allowance allocation post-unit retirement assumes allocated allowances are no longer available in the

fifth year after the unit ceases operation, does not include allowances allocated to WPL gas-fired units

MATS Rule and Wisconsin State Mercury Rule

Edgewater Unit 5 currently meets the mercury reduction requirements under MATS and the

Wisconsin State Mercury Rule. This is accomplished using the current calcium bromide

injection and ACI systems. These systems currently operate in a manner that produces flyash

which is beneficially used by the concrete industry.

Utilizing the existing ACI system in combination with the planned FF may allow mercury

emissions to be controlled in a lower-cost manner. The FF provides increased retention time.

This may provide Edgewater Unit 5 with the flexibility to utilize less activated carbon and

reduce injection of calcium bromide. In addition, the planned FF may provide greater mercury

reductions and reductions of other hazardous air pollutants regulated under MATS.

Potential EPA NSR and PSD Settlement

Although WPL has not reached a settlement with EPA on alleged NSR and PSD violations, and

settlement is not a definitive outcome, for the purpose of this CA application, WPL assumed that

a potential settlement with the EPA regarding the alleged violations would require SO2 emission

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reductions at Edgewater Unit 5. The planned Control System would be needed to meet the SO2

emission reductions required by the potential settlement.

3.3.2 Analysis of Alternative Compliance Strategy

A. WPL‘s Integrated Resource Plan

On an ongoing basis, WPL analyzes its generation needs for the next decade and beyond in order

to assure that it will have sufficient capacity and energy to reliably supply its future retail and

wholesale loads in an economically efficient fashion consistent with applicable state and federal

policies. The results of this analysis, which are summarized in WPL‘s Integrated Resource Plan

(IRP), are used to guide WPL‘s generation plans and to identify the specific plans that would

meet WPL‘s capacity needs while balancing economic, environmental, and reliability impacts.

WPL strives to maintain a balanced resource portfolio, which incorporates base load,

intermediate, and peaking resources; energy from renewable sources; and demand-side

management programs which offset generation needs.

WPL utilizes the EGEAS model to develop its IRP analyses. EGEAS is an accepted computer

model designed, in part, to determine an optimal, least-cost, electric generation fleet expansion

plan that integrates alternative demand- and supply-side resources. The model will also calculate

the annual detailed production costs associated with the optimal plan. Inputs to the EGEAS

model generally include:

forecasts of load and energy requirements;

characteristics of:

o existing generation resources;

o energy efficiency and demand-side management projections; and

o potential new resources (planning alternatives) including generating plants and

off-system purchases;

on-going and expected wholesale energy sales and purchases;

fuel, operating, and emission allowance cost projections; and

system reliability criteria.

Based on the inputs and modeling specifications, EGEAS produces a generation expansion plan,

which satisfies system load and operating requirements while minimizing the present value

revenue requirement (PVRR). The PVRR is calculated over a study period, which in WPL‘s IRP

analyses is usually a 30-year study period with a 35-year extension period. Generally,

differences in PVRR values between modeled plans are used to determine impacts (benefits or

detriments) on customer costs for generation resources and measure the relative economic value

of the modeled plans. The greater the PVRR difference between the modeled plan and the

alternative plan, the greater the impact on customer generation costs relative to the alternative

plan.

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WPL updated its IRP over the course of late 2011 and early 2012 (2012 IRP), with the EGEAS

runs supporting the 2012 IRP completed in June 2012. The IRP is presented in Appendix C.

1. Reference Case and Sensitivity Cases.

WPL created and generated a reference case, or base case, in EGEAS for the 2012 IRP, which

modeled various assumptions, including peak and energy load forecasts, coal and natural gas

price forecasts, emission rates and allowance costs, capital costs, and other factors. The

assumptions for the reference case are described in detail in Section 10 of WPL‘s 2012 IRP.

Following the development of the reference case, WPL created and generated nineteen

sensitivities to evaluate the effects of changes to various key assumptions in the EGEAS model.

Table 8. WPL’s 2012 IRP Base Case and Sensitivities

Case Sensitivity

CASE B1 Reference/Base Case

CASE B2 Higher DFGD&FF Capital cost for Edgewater 5

CASE B3 Economy energy purchases not available

CASE B4 Higher RPS with more wind resource added

CASE B5 Higher natural gas prices by 10%

CASE B6 Higher natural gas prices by 20%

CASE B7 Lower natural gas prices by 10%

CASE B8 Lower natural gas prices by 20%

CASE B9 Higher coal fuel prices by 10%

CASE B10 Lower coal fuel prices by 10%

CASE B11 Higher supply-side capital costs by 10%

CASE B12 Lower supply-side capital costs by 10%

CASE B13 Higher cost for new wind resources

CASE B14 Monetizing emission costs for CO2

CASE B15 Higher emission costs for SO2 by 10%

CASE B16 Lower emission costs for SO2 by 10%

CASE B17 Higher emission costs for NOx by 10%

CASE B18 Lower emission costs for NOx by 10%

CASE H1 High Load Forecast

CASE L1 Low Load Forecast

Section 13 of Appendix C of the 2012 IRP, describes the nineteen sensitivities in greater

detail.

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2. Supply-Side Planning Alternatives.

WPL‘s 2012 IRP included various supply-side planning alternatives, which the EGEAS model

could choose to install in the expansion plans. The EGEAS model is able to select among these

various planning alternatives and to ―install‖ one or more of these units, depending upon the

specific unit constraints, to create an optimal (least-cost) expansion plan. The planning

alternatives include non-combustible and combustible renewable resources (wind and biomass),

natural gas-fired combined cycle and combustion turbines, and other generating units. The

expansion alternatives included in the 2012 IRP were designed to provide a spectrum of

supply-side expansion alternatives, including noncombustible renewable resources, combustible

renewable resources, and nonrenewable combustible resources. Among the specific supply-side

planning alternatives that WPL modeled are:

Solar Photovoltaic at 10 MW

Wind Turbines at 100 MW blocks

Biomass at 35 MW

Biogas at 10 MW

Simple cycle GE 7FA.05 at approx. 189 MW

Combined cycle 2X1 GE 7FA.05 at 300 MW (jointly owned)10

Ultra-Supercritical Pulverized Coal at 300 MW (jointly owned)

Subcritical Circulating Fluidized Bed at 300 MW (jointly owned)

Integrated Gasification Comb. Cycle at 300 MW (jointly owned)

Advanced Passive 1000 (Nuclear) at 300 MW (jointly owned)

Peak Purchases at 50 MW.

This spectrum of resources (in addition to the demand side alternatives discussed below) enables

WPL to study its resource portfolio under the Wisconsin Energy Priorities Law, Wis. Stat.

§ 1.12. Section 9 of WPL‘s 2012 IRP contains additional discussion of WPL‘s supply-side

planning alternatives.

3. Energy Efficiency and Conservation Alternatives.

Energy conservation and efficiency programs will remain an integral part of WPL‘s resource

strategy. Future Demand Side Management (DSM) spending combining Focus on Energy and

WPL‘s programs will remain near historic levels, thus yielding historic DSM results. The

existing levels of energy efficiency are incorporated in the 2012 IRP through the energy load

forecasts. WPL included existing and expected levels of interruptible load and direct load

10

The units parenthetically marked as ―jointly owned‖ are units WPL assumed, for modeling purposes, WPL would

own 50% of the entire unit. This enables WPL to calculate the economic and operating benefits of the larger units.

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control impacts through the peak load forecasts. WPL also modeled a committed supply side

resource at the 1.5% level to act as a proxy for demand side management.

In addition to the supply-side planning alternatives, WPL also modeled a demand-side planning

alternative in the 2012 IRP: Aggressive DSM. The Aggressive DSM alternative was based upon

the proposed increase in statewide conservation and efficiency programs included in the

November 2010 Quadrennial Planning Docket, Docket No. 05-GF-191. In the 2012 IRP, WPL

modeled aggressive DSM for 2014 through 2016.

In 2009, the annual incremental savings associated with the Statewide Focus and the Shared

Savings programs in WPL was 1.01% of retail load, which was the same goal for 2011 in the

Quadrennial Planning Docket. Conservation levels in 2012, 2013, and 2014 were projected to

increase above the WPL‘s historical conservation levels. Using this data, WPL modeled

additional annual incremental savings of 63,010 MWh; 96,554 MWh; and 99,237 MWh for

2014, 2015, and 2016, respectively, as an alternative aggressive DSM option. The Aggressive

DSM alternative modeled in WPL‘s 2012 IRP is initially available in 2014 with 63,010 MWh

and 13.1 MW. By 2016, the levelized savings tops out at 258,801 MWh and 53.7 MW from the

higher level in conservation. The Aggressive DSM alternative assumes the conservation

spending level reverts back to 2009 levels in 2017; however, the model assumes a 14-year

conservation equipment life with savings remaining through 2029.

4. Planning Reserve Margin.

For 2012, WPL projects to own or have under contract approximately 3,130 MISO planning

reserve credits (PRCs) of generating capacity based on summer capacity ratings. WPL‘s

capacity needs are presently met through a combination of owned capacity and purchased

capacity, some of which is in the state of Wisconsin and some of which is out-of-state. In

assessing capacity needs, WPL currently maintains a MISO planning reserve margin (PRM) of

3.81% in each year of the 30-year study period modeled in EGEAS. The 3.81% PRM reflects

the requirement for Planning Year 2011/2012 under the Resource Adequacy portion of the MISO

tariff (this portion of the tariff is also referred to as Module E). The PRM is determined annually

through a Loss of Load Expectation analysis process, and reflects adjustments for the impacts of

demand diversity and forced outages.

B. Modeling the Proposed Project and Alternative.

In the WPL 2012 IRP, Edgewater Unit 5 is modeled as having the proposed DFGD and FF

installed and operating in 2017 as part of WPL‘s current base system plan (Plan 1). To aid in the

determination of the economic impact (benefit or detriment) of this plan, WPL has specified an

alternative plan (Plan 2) to reduce SO2 emissions to comply with pending and future

environmental regulations and requirements by retiring Edgewater Unit 5 at the end of 2016.

Plan 2 was run under the same base or reference set of assumptions and the same nineteen

Sensitivities as discussed above for the plan to address the same SO2 reduction and regulatory

goals achieved by installing a DFGD and FF on Edgewater Unit 5. The results of Plans 1 and 2

are documented in Appendix C § 13D.

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C. Economic Benefits of the Proposed DFGD and FF Installed on Edgewater Unit 5

WPL‘s modeling of Plans 1 and 2 demonstrates that the Edgewater Unit 5 installation of a

DFGD and FF is the most cost effective plan for meeting future capacity and energy needs of

WPL. WPL‘s ability to continue to rely on Edgewater Unit 5 will help to ensure that WPL has

sufficient capacity and energy to economically meet its long-term demands at a lower cost than

the alternative plan of early retirement of Edgewater Unit 5.

1. Installing the DFGD and FF on Edgewater Unit 5 is Cost Effective Compared

to Early Retirement of Edgewater Unit 5 at the end of 2016

WPL modeled the installation of the DFGD and FF on Edgewater Unit 5 at a cost of $413

million under each of the reference/base case and nineteen sensitivities modeled in the 2012 IRP.

WPL also conducted EGEAS runs under each of those twenty sensitivities in which WPL

assumed that Edgewater Unit 5 was retired early, enabling EGEAS to select planning alternatives

to replace Edgewater Unit 5. Under the base case and eighteen of the nineteen sensitivities, the

runs that assume the installation of the DFGD and FF on Edgewater Unit 5 (Plan 1) result in

lower PVRR when compared to the runs that assume Edgewater Unit 5 is retired at the end of

2016 (Plan 2)11

. The benefits of Plan 1 range from a PVRR with extension of approximately $

57.7 million to $288.7 million depending on the sensitivity, as can be seen in Table 9, and in

more detail in Appendix C, § 13D.

11 Sensitivity B8 was the only sensitivity that resulted in a negative PVRR. This run demonstrated that significantly

lower gas prices throughout the study period would result in a negligible negative-PVRR to install the Control

System in place of early retirement.

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Table 9: Comparison of PVRR by Sensitivity between Installing DFGD and FF on Edgewater 5 and Early Retirement of Edgewater 5

Sensitivity / Case Plan 1

Install DFGD&FF on Edgewater 5

Plan 2

Retire Edgewater 5 Early, 12/31/2016

PVRR

Difference

Sensitivity PVRR M$ Sensitivity PVRR M$ M$

Reference/Base Case CASE B1 10493.7 CASE B1_E5P2 10632.6 138.9

Higher DFGD&FF Capital cost for

Edgewater 5 CASE B2 10574.9

CASE B2_E5P2 10632.6

57.7

Economy energy purchases not

available CASE B3 10661.5

CASE B3_E5P2 10797.7

136.2

Higher RPS with more wind resource

added CASE B4 10501.0

CASE B4_E5P2 10637.2

136.2

Higher natural gas prices by 10% CASE B5 10807.3 CASE B5_E5P2 11019.6 212.3

Higher natural gas prices by 20% CASE B6 11086.8 CASE B6_E5P2 11375.5 288.7

Lower natural gas prices by 10% CASE B7 10154.9 CASE B7_E5P2 10218.5 63.6

Lower natural gas prices by 20% CASE B8 9773.1 CASE B8_E5P2 9764.4 -8.7

Higher coal fuel prices by 10% CASE B9 10695.4 CASE B9_E5P2 10771.2 75.8

Lower coal fuel prices by 10% CASE B10 10288.6 CASE B10_E5P2 10493.2 204.6

Higher supply-side capital costs by 10% CASE B11 10631.8 CASE B11_E5P2 10822.1 190.3

Lower supply-side capital costs by 10% CASE B12 10342.8 CASE B12_E5P2 10431.9 89.1

Higher cost for new wind resources CASE B13 10716.4 CASE B13_E5P2 10860.3 143.9

Monetizing emission costs for CO2 CASE B14 11874.4 CASE B14_E5P2 11950.5 76.1

Higher emission costs for SO2 by 10% CASE B15 10494.2 CASE B15_E5P2 10633.1 138.9

Lower emission costs for SO2 by 10% CASE B16 10493.2 CASE B16_E5P2 10632.1 138.9

Higher emission costs for NOx by 10% CASE B17 10493.0 CASE B17_E5P2 10631.9 138.9

Lower emission costs for NOx by 10% CASE B18 10494.3 CASE B18_E5P2 10633.3 139.0

High Load Forecast CASE H1 10894.1 CASE H1_E5P2 11035.9 141.8

Low Load Forecast CASE L1 10115.6 CASE L1_E5P2 10257.4 141.8

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For example, the Reference Case examines resource needs if the DFGD and FF are assumed to

be installed on Edgewater Unit 5 and it operates until the end of 2045. The PVRR of this case

including the extension period is $10,493.7 million. In comparison, where the reference case is

modified to assume Edgewater Unit 5 is retired at the end of 2016, the PVRR including

extension is $10,632.6 million, which is $138.9 million higher than if the DFGD and FF are

installed on Edgewater Unit 5.

Table 10. EGEAS Analysis Results for the Base Case

Compliance Plan

PVRR

($ MM)

Differential from Base

Case

($ MM)

1. Install SO2 Emission Controls (Base Case) $ 10,493.7

2. Replace Edgewater Unit 5 $ 10,632.6 $ 138.9

Under the Base Case assumptions where Edgewater Unit 5 is retired early (Plan 2), the full

capacity of Edgewater 5 is replaced almost immediately, primarily with the combination of a 300

MW jointly owned combined cycle unit in 2017 and a 189 MW simple cycle combustion turbine

in 2018. This response occurs in 13 of the 19 sensitivities. In 5 of the remaining 6 sensitivities

this immediacy is advanced by adding the simple cycle combustion turbine in 2017. The

expansion plans for Plan 2 are provided in Appendix C § 13C.

Also of specific note is that, as shown in Table 9 above, all but one case where the Control

System is installed on Edgewater Unit 5 have a lower PVRR than the comparable cases where

Edgewater Unit 5 is retired early. This suggests that the modeled cost of the DFGD and FF for

Edgewater Unit 5, approximately $1,073/kW, in combination with its operational costs, are

lower in total than what otherwise would be purchased or generated if Edgewater Unit 5 were

retired early.

2. Aggressive Demand Side Management Does Not Obviate the Need for

Edgewater Unit 5 with the FGD

The Aggressive DSM planning alternative was selected in every sensitivity modeled in both

Plans 1 and 2. The selection of the Aggressive DSM planning alternative did not replace the

need to operate Edgewater Unit 5 with the DFGD and FF. Additionally, the installation of the

Edgewater Unit 5 DFGD and FF still remained the most cost effective means of meeting

capacity and energy needs for all but one sensitivity.

3. Payback Year Analysis

The calculations of the payback period of eight years is shown on Table 11, and is calculated as

follows: First, the year-to-year cumulative system PVRRs for each of Plans 1 and 2 are made

more comparable by removing the year-to-year cumulative PVRR for the DFGD and FF from

the Plan 1 cumulative PVRR (called ―Net Plan 1 cumulative PVRR‖). Next, the difference in

year-to-year Net Plan 1 cumulative PVRR and Plan 2 cumulative PVRR is calculated. Third, the

total cumulative PVRR for the DFGD and FF is compared to the annual differences in Net Plan 1

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cumulative PVRR and Plan 2 cumulative PVRR. The year in which the total cumulative PVRR

for the DFGD and FF exceeds the annual difference in Net Plan 1 cumulative PVRR and Plan 2

cumulative PVRR is the year prior to the year of payback. The number of payback years equals

the year of pay back less the first full year of operations plus one.

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Table 11. Calculations for the Payback Period of Installing a DFGD and FF On Edgewater Unit 5, $MM

Year Plan 1

Cumulative

PVRR

DFGD & FF

Capital Costs

Cumulative

PVRR

Net Plan 1

Cumulative PVRR:

Plan 1 Cumulative

PVRR Excluding

DFGD & FF

Capital Costs

Cumulative PVRR

Plan 2

Cumulative

PVRR

Net Plan 1

Cumulative

PVRR Less

Plan 2

Cumulative

PVRR

Total

DFGD &

FF Capital

Costs

Cumulative

PVRR

Payback

Period: The

Year of

Payback Less

The First Full

Year of

Operations

Plus One

a b c d = b - c e f = d - e g h

2011 $ 391.9 $ - $ 391.9 $ 391.9 $ -

2012 $ 768.7 $ - $ 768.7 $ 768.2 $ 0.5

2013 $ 1,135.2 $ 0.2 $ 1,135.0 $ 1,133.5 $ 1.5

2014 $ 1,534.5 $ 1.8 $ 1,532.7 $ 1,507.6 $ 25.1

2015 $ 1,983.8 $ 8.6 $ 1,975.2 $ 1,928.8 $ 46.4

2016 $ 2,425.0 $ 21.7 $ 2,403.3 $ 2,334.4 $ 68.9

2017 $ 2,875.0 $ 67.5 $ 2,807.5 $ 2,819.1 $ (11.6)

2018 $ 3,297.6 $ 108.1 $ 3,189.5 $ 3,281.3 $ (91.8)

2019 $ 3,745.1 $ 143.7 $ 3,601.4 $ 3,761.3 $ (159.9)

2020 $ 4,157.1 $ 174.9 $ 3,982.2 $ 4,200.0 $ (217.8)

2021 $ 4,535.5 $ 202.4 $ 4,333.1 $ 4,607.2 $ (274.1)

2022 $ 4,892.5 $ 226.5 $ 4,666.0 $ 4,990.3 $ (324.3)

2023 $ 5,233.6 $ 247.6 $ 4,986.0 $ 5,355.0 $ (369.0)

2024 $ 5,550.5 $ 266.1 $ 5,284.4 $ 5,689.5 $ (405.1) $ 375.1 8

2025 $ 5,847.5 $ 282.3 $ 5,565.2 $ 6,011.8 $ (446.6)

2026 $ 6,128.8 $ 296.5 $ 5,832.3 $ 6,310.3 $ (478.0)

2027 $ 6,393.2 $ 308.9 $ 6,084.3 $ 6,586.6 $ (502.3)

2028 $ 6,642.7 $ 319.6 $ 6,323.1 $ 6,844.2 $ (521.1)

2029 $ 6,883.5 $ 328.9 $ 6,554.6 $ 7,092.2 $ (537.6)

2030 $ 7,122.1 $ 337.0 $ 6,785.1 $ 7,324.9 $ (539.8)

2031 $ 7,339.5 $ 343.9 $ 6,995.6 $ 7,538.4 $ (542.8)

2032 $ 7,544.7 $ 349.8 $ 7,194.9 $ 7,746.2 $ (551.3)

2033 $ 7,735.3 $ 354.9 $ 7,380.4 $ 7,937.9 $ (557.5)

2034 $ 7,912.5 $ 359.1 $ 7,553.4 $ 8,116.0 $ (562.6)

2035 $ 8,097.8 $ 362.7 $ 7,735.1 $ 8,301.9 $ (566.8)

2036 $ 8,263.0 $ 365.7 $ 7,897.3 $ 8,466.3 $ (569.0)

2037 $ 8,417.0 $ 368.3 $ 8,048.7 $ 8,619.7 $ (571.0)

2038 $ 8,568.3 $ 370.4 $ 8,197.9 $ 8,770.1 $ (572.2)

2039 $ 8,711.9 $ 372.2 $ 8,339.7 $ 8,913.1 $ (573.4)

2040 $ 8,850.1 $ 373.7 $ 8,476.4 $ 9,042.9 $ (566.5)

Ext

Period $ 10,493.7 $ 375.1 $ 10,118.6 $ 10,632.6 $ (514.0)

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4. Summary of Economic Analyses

The EGEAS analysis provides a broad review of the installation of the DFGD and FF on

Edgewater Unit 5. The results of this analysis support the installation of the DFGD and FF on

Edgewater Unit 5 by demonstrating that the installation is the most economical alternative, under

many different sensitivities, to meet WPL‘s demand and energy needs for the modeled future.

Moreover, the analysis shows that the installation of the DFGD and FF on Edgewater Unit 5

represents the overall least cost alternative to WPL's ratepayers compared to early retirement of

Edgewater Unit 5 in order to reduce SO2 emissions to comply with pending and future

environmental regulations and requirements, and further compliance with current regulations.

The EGEAS analysis also demonstrates that the installation of the DFGD and FF on Edgewater

Unit 5 satisfies the Energy Priorities Law, Wis. Stat. § 1.12(4). While the EGEAS runs selected

Aggressive DSM, that selection did not obviate the need for the installation of the DFGD and FF

on Edgewater Unit 5. Additionally, WPL modeled various supply side alternatives including

wind and solar installations. The EGEAS runs demonstrate that the continued operation of

Edgewater Unit 5, with the installation of the DFGD and FF, as well as the other aspects of

WPL‘s base plan and fleet expansion is a more cost effective means of meeting the capacity and

energy needs than retiring Edgewater 5 early.

3.4 Need and Alternatives Analysis Summary

The Edgewater Unit 5 proposed DFGD and FF system will reduce SO2 emissions at the

Edgewater Generating Station. Installation will allow WPL to comply with CSAPR SO2

emission reduction requirements without subjecting WPL to potential CSAPR assurance

provision related penalties. Moreover, installation of the controls will satisfy potential unit-

specific emission reduction requirements which WPL believes could be required under a

settlement with EPA and Sierra Club over alleged NSR and PSD violations. The Control System

is a critical component of WPL‘s emission compliance strategy for the following reasons:

Investment in SO2 emission controls at Edgewater Unit 5 will significantly reduce

emissions of SO2;

Investment in SO2 emission controls at Edgewater Unit 5 and continued operation of the

unit, compared to retirement and replacement of Edgewater Unit 5, reduces ratepayer

revenue requirements for nearly all of the sensitivities modeled;

Investment in SO2 emission controls at Edgewater Unit 5 is responsive to the increasing

stringency and uncertainty associated with achieving and maintaining compliance.

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4.0 OPERATING PARAMETERS

The Control System for Edgewater Unit 5 will be designed to meet key operating parameters, including SO2 removal. The following sections describe operations of this system on Edgewater Unit 5 and associated operating costs based on burning the Design Coal—actual operating costs and emission reductions are subject to the coal type used at Edgewater Unit 5.

4.1 Cost of Operations

Table 12 provides a preliminary breakdown of key performance, fixed and variable operating parameters for the Control System to be installed on Edgewater Unit 5. For the purpose of estimating operating costs, the variable operating parameters and associated cost estimates are based on Edgewater Unit 5 burning the Design Coal and operating information from the vendors. Fixed operating parameters are based on operating and maintenance typical of a DFGD and FF system of this size and operating capability.

Table 12. Edgewater Unit 5 DFGD Design Operating Parameters

Operating Parameter Edgewater Unit 5 Units Performance Parameters

Plant Gross Maximum Rating 430 MW

Annual Capacity Factor %

SO2 Removal Efficiency (minimum) 92 %

SO2 Removed 0.79 lb/MMBtu

10,200 tons/year

Variable Operating Parameters

Flue Gas Flow Rate 1,190,000 scfm

FGD Solids to Disposal 4.3 tons/hr

Potable Water to Lime Preparation 35 Gpm

Dilution Water to DFGD 355 Gpm

Lime Consumption 4,000 lb/hr

Power Requirement (DFGD, FF and ID fan) 6.9 MW

Fixed Operating Parameter

Additional Operating Personnel 12 FTEs

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Fixed and variable operating costs are based on the consumption rates presented in Table 9 and

the following assumptions:

Pebble Lime Reagent: $124/ton

Edgewater Off-site Landfill: $18/ton

Potable Water: $1.12/1000 gallons

Dilution Water: $0.40/1000 gallons

Operating Personnel: $58/hr

The total annual operating cost (fixed and variable) for the Edgewater Unit 5 Control System is

estimated to be approximately $12,470,000 (in 2011 dollars12

).

4.2 Operating Characteristics

Installation of the Control System on Edgewater Unit 5 will have impacts on the operation of the

unit. The most significant items are as follows.

Boiler Furnace Pressure Transients and ID Fans

The addition of the Control System on Edgewater Unit 5 is not expected to trigger the need for

furnace reinforcement. This will be confirmed during the detailed design phase of the project.

Edgewater Unit 5 currently operates with forced draft (FD) and ID fans. The DFGD system and

FF will be located downstream of the existing ID fans, which will remain in service for this

project. Booster ID fans, installed at the outlet of the new FF, will be needed to overcome the

additional pressure drop required to carry the flue gas through the proposed emission control

equipment and interconnecting ductwork.

Process Control

The Control System will require new controls to be added and integrated into the operator

interface in the existing control room. Plant personnel will require training on all new equipment

and controls.

Materials Handling System

The lime will be delivered as pebble or hydrated lime. The pebble lime will be processed to

hydrated lime for use in the DFGD vessel. The DFGD byproduct solids will be collected in a

storage silo prior to being transported to an off-site landfill for disposal. The storage silo will be

equipped with vent filters to control the release of dust.

12

Annual operating costs were estimated in 2011 dollars and do not include costs associated with the auxiliary

power. In the EGEAS analysis accompanying this Application, the operating costs were escalated from 2011 dollars

to year-of-occurrence dollars.

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Truck and Rail Traffic

Based on the economic analysis performed as part of the creation of the application for a

certificate of authority, in conjunction with consulting engineers, WPL has determined that the

least capital intensive method for ongoing delivery of lime reagent and removal of the DFGD

byproduct solids is a truck delivery and removal system. While the truck solution results in the

lowest capital cost, it will result in an increase in the truck traffic around the site. It is

anticipated that about three trucks daily will be delivering lime and about 6 trucks daily will be

removing waste product to the landfill site. Rail traffic to the site is not expected to be affected

by the operation of the Control System.

Plant Operating Personnel

Based on historical data and operational studies, it is estimated that 12 new operating staff will

be needed to operate the proposed emission control and landfill systems. Actual staffing levels

will be determined by plant personnel at a later date.

Chemical Handling

Lime is the primary chemical required for operation of the Control System. The lime will be

delivered in crushed, pebble, or hydrated form via enclosed truck trailers and pneumatically

conveyed to the storage silo. The storage silo and lime preparation area will be equipped with

vent filters to control release of dust.

Auxiliary Power Consumption

Approximately 7 MW of auxiliary power will be consumed by the Control System. The

auxiliary power is for operation of the lime preparation equipment, DFGD vessel, FF, solids

handling equipment, balance of plant equipment, and booster ID fan.

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5.0 DESCRIPTION AND COST OF PROPERTY BEING REPLACED

The current project layout and general arrangement of the Control System was developed to

improve constructability, reduce length of equipment tie-in outages and reduce relocation and

demolition work. Based on preliminary engineering completed, the following major facilities are

planned for demolition:

Northeast storage building

Two rail spurs

Undergrounds (culverts, piping, electrical, foundations, etc.)

The cost estimate for the Edgewater Unit 5 project includes $1,300,000 (2011 dollars) for

demolition and removal. The net book value of the facilities is approximately $12,997 as of

12/31/2011. No other existing equipment or structures are anticipated to be demolished or

replaced as part of this project. Two 12 kV electrical lines supplying the SWWTF plant will need

to be relocated. See Appendix A for further detail on the demolition plans.

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6.0 REDUCTION TECHNOLOGY SELECTION

The following section is a synopsis of the emission control technology selection analysis. The

complete analysis of technologies considered, including the pros and cons of their application for

Edgewater Unit 5 that form the basis of the decision for the technology selected, can be found in

Appendix B.

6.1 Technology Selection Process

The following technologies were evaluated for SO2 reduction:

Semi-dry FGD, Spray Dry Absorber (SDA)

Semi-dry FGD, Circulating Dry Scrubber (CDS)

Semi-dry FGD, Alstom NIDTM

technology

Dry FGD, Dry Sorbent Injection (DSI)

Integrated Emission Control (IEC), Regenerative Activated Coke technology (ReACT)

Wet FGD, Limestone Forced Oxidation (LSFO)

Specific technologies selected for evaluation were determined based upon the following criteria:

Technology must be capable of achieving a minimum of 90% SO2 removal to promote

compliance with current, pending and future rules and any potential settlement.

Technology must be commercially available and proven for emission reductions at units

of comparable or larger size.

Capability of technology to meet strict surface water mercury discharge standards or

achieve zero liquid discharge.

Technology and fuel compatibility.

Reliable and long-term removal efficiencies achievable by each technology.

Co-benefits for maximum multi-pollutant emission controls, including sulfur trioxide

(SO3), mercury, and other HAPS cited in the EPA‗s MATS rule.

Implementation timeframes, especially lead times and availability of critical components.

Plant specific considerations (e.g. space or current plant equipment constraints).

The final selection of the technology to accomplish the goal of SO2 emission reductions at

Edgewater Unit 5 was determined as the least-cost system from an analysis of the relative costs

of the candidate technologies meeting the above selection criteria.

6.2 Summary of Technology Assessment

Although the LSFO system is capable of the required removal, it was eliminated for technical

reasons related to wastewater production and treatment and the requirement of new wet chimney

to handle the cooled and saturated flue gas. The LSFO system produces a wastewater stream,

which will require further treatment prior to discharge. Additionally, new wastewater effluent

guidelines for power plants, scheduled to be proposed in November 2012, could require the

installation of a zero liquid discharge (ZLD) system to treat the LSFO wastewater stream.

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Although ZLD systems are currently marketed for this service, the ability of such a system to

consistently and reliably treat the wastewater produced by the LSFO system has not been proven.

It is uncertain whether WPL could permit a new emission source, which would be required with

the installation of a new chimney. Additionally, when the flue gas exits the chimney it will form

a dense water vapor plume under all ambient conditions that can be perceived as a major impact

on area visibility.

The DSI system was eliminated from consideration because it has limited operational history for

SO2 control, is unable to achieve the required emission reduction level of 90%, imposes the

greatest limitations on Edgewater Unit 5 by limiting future SO2 reductions, fuel flexibility, and

eliminating flyash sales. The DSI system also required the greatest amount of in-plant rail and/or

truck traffic to handle the byproduct.

The ReACT system was eliminated from consideration for this application because there are no

commercial installations of similar or greater size units operating in the U.S.; the only source of

supply for the key reagent of activated coke is China; and the required creation and requisite

handling of a concentrated sulfuric acid byproduct and mercury contaminated waste.

The remaining semi-dry FGD technologies (SDA, CDS and NID), referred to in this Application,

as dry FGD (DFGD) because they produce a dry byproduct, are the best options to meet the

requirements for Edgewater Unit 5 in that they:

All are commercially available. Although SDA has the most established operational

history, both CDS and NID have been installed and operated long enough to be

considered viable alternates. They are best suited to units that fire coal with a coal sulfur

content 1.5 wt% or less. Because Edgewater Unit 5 currently fires a PRB coal with lower

sulfur content, these technologies allow for future fuel flexibility.

Provide cost effective control. The above DFGD systems can reliably and

economically achieve a minimum of 90% reduction in SO2 emissions.

Utilize the existing chimney. The flue gas exiting the DFGD system is not saturated

with water vapor. Therefore, chimney exit velocity requirements can be maintained and

the potential for corrosion of the existing chimney liner is limited. This allows the

existing chimney to remain in operation, saving considerable project cost associated with

constructing a new chimney.

Produce no mercury contaminated wastewater. A DFGD and FF system produces a

dry byproduct. There is no continuous wastewater stream containing mercury or other

pollutants that would require treatment to meet discharge standards.

Provide increased flexibility to maintain Edgewater Unit 5 ash sales. The installation

of a baghouse allows for the future injection of activated carbon for mercury control

downstream of the existing ESPs and collected separately from the flyash.

Provide additional co-benefits. The DFGD and FF system is very effective at capturing

fine particulate matter such as PM2.5 and acid mist.

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7.0 ENVIRONMENTAL IMPACTS/PERMITS

The proposed project location and preliminary site layout for the project are shown in Section 1,

on Figure 1 and Figure 2. The general site layout is also shown in Appendix A.

7.1 Emissions Reductions

The proposed Project at Edgewater Unit 5 is designed to reduce SO2. There will be co-benefit

reductions of mercury, acid gases, and other HAPs. Controlling SO2 emissions will reduce acid

rain and the formation of fine particulate matter in the atmosphere.

7.2 Proximity to Floodplains

The area for the location of the Edgewater Unit 5 Control System is not within a floodway, 100-

year floodplain, or flood-prone areas.

7.3 Information on Applicable Environmental Factors

Several environmental factors have been considered for the proposed project. The studies

performed include the following:

Archaeological and historic resources

Threatened or endangered species

Solid waste

Water resources

Wastewater discharge

Additional information is found in the following sections.

7.3.1 Archaeological and Historic Resources

A study was performed in January 2008 by an independent consultant regarding the potential

presence of cultural, archeological, and burial sites at the Edgewater facility. According to the

study, there are no known archaeological or historic resources in the construction footprint of the

project.

7.3.2 Threatened and Endangered Species

A study was performed in December 2007 by an independent consultant identifying potential

threatened and endangered species at the Edgewater facility. According to the study, the

potential exists to impact threatened, endangered, or special concern species on the Edgewater

property, especially on the sand dunes along the lakeshore. These species include: red-

shouldered hawk (buteo lineatus); piping plover (charadrius melodus); one-flowered broomrape

(orobanche uniflora); thickspike (elymus lanceolatus ssp. psammophilus); American sea-rocket

(cakile edenntula); Northern Mosaic Forest; and Southern Sedge Meadow.

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However, construction of the Control System on Edgewater Unit 5 will occur on already

developed WPL property with no adverse impacts to critical habitats for endangered, threatened,

or special concern species. Appropriate Best Management Practices (BMPs) and erosion control

techniques will be used to prevent impacts to habitats. Accordingly, no detrimental impact to

threatened, endangered, or special impact species is expected.

7.3.3 Solid Waste

Currently, bottom ash and flyash is sold or transported off-site to a company-owned landfill.

The existing ESPs are expected to remain in operation after the addition of the Control System,

allowing for continued beneficial reuse of the flyash. No impact on the bottom ash composition

or disposition is expected. The proposed FF will collect dry FGD process particulates, including

calcium compounds, unused lime reagent, and any flyash and activated carbon from the ACI

system remaining in the flue gas. No market currently exists for this material, although WPL is

participating in research to evaluate the beneficial use of DFGD byproducts. For the purpose of

determining the environmental impacts of the project, WPL assumes that the volume of solid

waste collected in the FF will be sent off-site for disposal.

7.3.4 Water Resources

A study was performed in January 2008 by an independent consultant regarding the potential

presence of wetlands and open waters at the Edgewater facility. Based on information in this

study, the area where Edgewater Unit 5 construction activities will take place will not impact

wetlands or open waters.

To operate the proposed emission control systems, plant water consumption will increase. The

lime preparation process will require approximately 35 gallons per minute (gpm) of high quality

water such as potable or lake water. Based on 2011 water use data, this will potentially increase

Edgewater Generating Station‘s water usage by approximately 0.02%. Edgewater Unit 5

currently uses 216,952 gpm, which will increase to 216,987 gpm. The increased amount is still

well within the plant‘s permitted water usage rate of 321,250 gpm. An additional 355 gpm of

dilution water is required to cool the flue gas in the DFGD vessel. This dilution water can be of

a lower quality such as cooling pond water, ash pond water or other wastewater stream. The

water quality of each source will need to be verified for its suitability for the process. WPL will

attempt to minimize the impact to water resources by first utilizing existing water sources, such

as waters that are part of the facility‘s wastewater discharge system, before committing to

consuming any additional or new water supply. A plant water balance study will be performed as

part of this project to understand which existing water sources can be used to supply the project‘s

water needs.

7.3.5 Wastewater Discharge

Edgewater Generating Station‘s wastewater discharge will not be affected by the addition of the

proposed emission reduction systems because the DFGD system operates without wastewater

discharge. Water used in the DFGD system is absorbed in the process and the spent reagent and

particulate matter is collected in a FF and sent for disposal or recycled back to the absorber.

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7.3.6 Air Quality Resources

Operation of the Control System is expected to result in a direct decrease in air pollutants.

Ancillary operations, including material deliveries, lime unloading and storage, and byproduct

handling may result in minor increases in fugitive dust PM. WPL will develop dust mitigation

strategies to minimize fugitive dust as part of the detailed engineering design.

7.4 List of Permits and Approvals Needed

Table 13 provides a list of permits and approvals that may be required for the project.

Table 13. List of Required Permits and Approvals

Agency Reference Permit/Plan/Approval/

Report Regulated Activity Needed

Water Quality

WDNR Wis. Stat. Ch. 30 Waterway Permit Work within a drainage way or waterway

Prior to construction

WDNR WAC NR 216

Erosion Control Plan and Storm Water Management Plan for Construction Activities

Land disturbances greater than 1 acre

Prior to construction

WDNR WAC NR 216 SWPPP Storm water management for industrial facilities. This may need to be updated for the new operation

Prior to operation

WDNR WAC NR 200 WPDES Discharge Permit Tank containment and tank loading pad system discharge

Prior to construction

WDNR WAC NR 200 WPDES General Discharge Permit Dewatering during construction

Prior to construction

WDNR WAC NR 200 WPDES General Discharge Permit Hydrostatic testing of tanks Prior to hydrostatic testing

WDNR WAC NR 142.06 Water Use Registration and Consumptive Use Permit

Increased water use Prior to construction

Hazardous Materials

USEPA 40 CFR Part 112 SPCC Plan Temporary oil storage on-site for construction activities

Prior to arrival of oil on-site

USEPA 40 CFR Part 112 SPCC Plan Additional chemical or fuel storage on-site supporting the newly constructed equipment

Prior to commencing operation

USEPA 40 CFR Part 302 CERCLA Emergency Response Planning Spill response of hazardous materials. We typically cover this in our SPCC plan.

Prior to chemicals being on-site

USEPA 40 CFR Part 355 EPCRA Emergency Response Planning Spill response of hazardous materials. We typically cover this in our SPCC plan.

Prior to chemicals being on-site

USEPA 40 CFR Part 370 Initial Notification Notification of lime stored onsite

Prior to chemicals being on-site

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Agency Reference Permit/Plan/Approval/

Report Regulated Activity Needed

Air Quality

USEPA 40 CFR Part 72 Acid Rain Permit Emission controls, rates, and averaging plans need to be updated if NOx or SO2 emissions change.

Prior to operation

WDNR WAC NR 405 and 406

Construction Permit (NSR, PSD, etc.) New or increased emissions due to the modification

Prior to construction

WDNR WAC NR 407 Title V Operation Permit Activities covered in construction permit need to be rolled into the Title V operating permit

Within time period specified in construction permit

Tall Structures

FAA 14 CFR Part 77 Notice of Proposed Construction or Alteration

Use of crane during construction 200 feet tall or within 20,000 feet of an airport.

Prior to construction

Solid Waste/Byproducts

WDNR Waste Disposal Authorization Approval to dispose of new material in a landfill

Prior to disposal

WDNR Byproduct Use Authorization Approval for beneficial reuse Prior to use

Transportation

WDOT WAC Trans 254 Delivery of large/heavy components Single trip permit for the transportation of loads of excessive size and or weight

Prior to shipment

Municipality City, county, village, etc.

Delivery of large/heavy components Single trip permit for the transportation of loads of excessive size and/or weight

Prior to shipment

Municipality City, county, village, etc.

Transport to Landfill Multi trip permit for the transportation of DFGD byproduct solids by truck to land fill.

Prior to disposal

Local Approvals

Municipality City of Sheboygan Construction Permit Building permit Prior to construction

Municipality and County

City, county, village, etc.

Zoning Variance Evaluate local ordinances for zoning requirements and approvals based on detailed engineering and construction (e.g. for structure height requirements).

Prior to construction

Municipality and County

City, county, village, etc.

Local approvals for air quality, water quality, storm water, hazardous materials, etc.

Evaluate local ordinances for environmental or construction requirements based on detailed engineering and construction.

Prior to construction

Public Version

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8.0 DESIGNATION OF PUBLIC UTILITIES AND OTHERS AFFECTED

Edgewater Unit 5 is wholly owned by WPL. The project will require coordination with the

American Transmission Company (ATC) for any required modifications or enhancements to

ATC assets to power the equipment. The SWWTF is immediately north of the plant. The

SWWTF‘s electrical power currently runs underground in the proposed construction area. This

electrical service may need to be relocated to accommodate the DFGD design and construction.

No other public utilities will be affected by this project.

Public Version