Certificate of Authority Application 

Edgewater Generating Station Unit 5 

NOx Reduction Project 

Project Description and Justification 

Wisconsin Power and Light Company 

Madison, Wisconsin 

November 2008 

PSC REF#:105618 Public Service Commission of Wisconsin

RECEIVED: 12/15/08, 10:57:26 AM
i 

TABLE OF CONTENTS 

APPLICATION................................................................................................................. 1

Introduction....................................................................................................................... 2

1.0 Project Description ............................................................................................... 3

1.1 Technology Objectives ....................................................................................... 6 

1.2 Selected Technology........................................................................................... 7 

1.3 Construction Approach ....................................................................................... 7 

1.4 Constructability Summary .................................................................................. 9 

1.5 Milestone Schedule............................................................................................. 9 

2.0 Cost and Financing Estimates............................................................................ 10

2.1 Estimated Capital Cost and Cash Flow............................................................. 11 

2.2 Financing Mechanism....................................................................................... 12 

3.0 Need and Alternative Analysis........................................................................... 13

3.1 Background....................................................................................................... 13 

3.2 Emissions Compliance Planning Process ......................................................... 14 

3.2.1 Compliance Strategy................................................................................. 14

3.2.2 Update Integrated Resources Plan (IRP) ................................................. 14

3.2.3 Evaluate Engineering Aspects of Emissions Controls.............................. 15

3.2.4 Planning for Air Emissions Regulatory Requirements ............................. 16

3.2.5 Select Air Emissions Compliance Plan..................................................... 20

3.2.6 Implement Near-Term Tactical Responses for Regulatory Compliance .. 21

3.2.7 Review and Update Air Emissions Compliance Plan............................... 21

3.3 Project Need and Alternatives Analysis ........................................................... 21 

3.3.1 Project Need.............................................................................................. 21

3.3.2 Alternative Analysis .................................................................................. 26

3.4 EGEAS Modeling Summary............................................................................. 27 

3.5 Need and Alternatives Analysis Summary ....................................................... 27 

4.0 Operating Parameters ........................................................................................ 29

4.1 Cost of Operations ............................................................................................ 29 

4.2 Operating Characteristics.................................................................................. 29 

5.0 Description and Cost of Property Being Replaced .......................................... 31

6.0 NOx Reduction Technology Selection............................................................... 32

6.1 Technology Selection Process .......................................................................... 32 

6.1.1 Technology Selection Analysis.................................................................. 32

6.2 Technology Selection Summary....................................................................... 33 

7.0 Environmental Impacts/Permits........................................................................ 34

7.1 Maps and Drawings of Proposed Project and Site............................................ 34 

7.2 Proximity to Floodplains................................................................................... 34 

7.3 Information on Applicable Environmental Factors .......................................... 34 

7.3.1 Archaeological and Historic Resources ................................................... 34

7.3.2 Threatened and Endangered Species........................................................ 34

7.3.3 Solid Waste................................................................................................ 35

7.3.4 Water Resources ....................................................................................... 35

7.3.5 Wastewater Discharge.............................................................................. 35

7.4 List of Permits and Approvals Needed ............................................................. 35 
ii 

8.0 Designation of Public Utilities and Others Affected ........................................ 37

Appendix A General Site Layout ............................................................................ 38

Appendix B NOx Technology Descriptions ........................................................... 39

Appendix C Project Conceptual Design Scope Assumptions............................... 43

Appendix D Additional Requested EGEAS Runs ................................................. 46

FIGURES AND TABLES 

Figure 1. Edgewater Unit 5 SCR Project Location Map ................................................... 4 

Figure 2. Typical SCR Reactor Design.............................................................................. 5 

Figure 3. Site Layout – Proposed Edgewater Unit 5 SCR System .................................... 6 

Table 1. Edgewater Unit 5 SCR Estimated Capital Cost................................................. 11 

Table 2. Edgewater Unit 5 SCR Project Annual Cash Flow ........................................... 11 

Table 3. Edgewater Unit 5 SCR Levelized Cost.............................................................. 12 

Table 4. NOx Emissions and RACT Compliance Summary at the Edgewater Generating 

Stationa

.................................................................................................................. 25 

Table 5. EGEAS Analysis Results................................................................................... 27 

Table 6. Edgewater Unit 5 SCR Operating Parameters................................................... 29 

Table 7. NOx Reduction Technologies Maximum Removal Efficiencies from Baseline 

Emissions at Edgewater Unit 5............................................................................. 33 

Table 8. List of Required Permits and Approvals............................................................ 35 

Table 9. Additional EGEAS Runs ................................................................................... 51 

Table 10. Summary of Expansion Plan Associated with Additional EGEAS Runs..........52 
iii 

ACRONYMS AND ABBREVIATIONS 

acfm – actual cubic feet per minute 

B&W – Babcock & Wilcox 

BART – Best Available Retrofit 

Technology 

CA – Certificate of Authority 

CAA – Clean Air Act 

CACP – Clean Air Compliance Group 

(part of WPL) 

CAIR – Clean Air Interstate Rule 

CAMR – Clean Air Mercury Rule 

CAVR – Clean Air Visibility Rule 

CO – Carbon Monoxide 

CO2 – Carbon Dioxide 

DCS – Distributed Control System 

EGEAS – Electric Generation Expansion 

Analysis System 

EPA – Environmental Protection 

Agency 

EPRI – Electric Power Research 

Institute 

ESP – Electrostatic Precipitator 

FIP – Federal Implementation Plan 

GHG – Greenhouse Gas 

H2O – water 

ID – Induced Draft 

IRP – Integrated Resource Plan 

LNB – Low NOx Burners 

MM – Million 

MMBtu – Million British Thermal Units 

MW – Megawatts 

N2 – Nitrogen 

NAAQS – National Ambient Air Quality 

Standards 

NH3 – Ammonia 

NOx – Nitrogen Oxides 

NPVRR – Net Present Value Revenue 

Requirement 

PM – Particulate Matter 

PM2.5 – Particulate Matter less than 2.5 

microns (μm) in diameter 

PPA – Purchase Power Agreements 

PSCW – Public Service Commission of 

Wisconsin 

PSD – Prevention of Significant 

Deterioration 

PRB – Powder River Basin 

RACT – Reasonably Available Control 

Technology 

RRI – Rich Reagent Injection 

SAM – Sulfuric Acid Mist 

scfm – standard cubic feet per minute 

SCR – Selective Catalytic Reduction 

SIP – State Implementation Plan 

SNCR – Selective Non-Catalytic 

Reduction 

RPS – Renewable Portfolio Standard 

SOFA – Separated Overfire Air 

SO2 – Sulfur Dioxide 

SO3 – Sulfur Trioxide 

SPC – Strategic Planning Committee 

WDC – Wisconsin Department of 

Commerce 

WDNR – Wisconsin Department of 

Natural Resources 

WDT – Wisconsin Department of 

Transportation 

WEPCO – Wisconsin Electric Power 

Company 

w.g. – water gauge 

WPL – Wisconsin Power and Light 

Company

2 

Introduction 

In this Certificate of Authority application, Wisconsin Power and Light Company (WPL) 

and Wisconsin Electric Power Company (WEPCO) are requesting authorization to install 

a Selective Catalytic Reduction (SCR) system for control of Nitrogen Oxides (NOx) on 

Unit 5 at the Edgewater Generating Station in Sheboygan County, Wisconsin. WPL 

owns 75% of Edgewater Unit 5, and WEPCO holds 25% ownership. The unit consists of 

a wall-fired boiler currently operated at 430 MW gross generation and a cold-side 

Electrostatic Precipitator (ESP) for particulate emissions control. Because Sheboygan 

County has been designated an ozone non-attainment area, the Edgewater Generating 

Station must contribute to improving air quality in the area by complying with 

Reasonably Available Control Technology (RACT) requirements as set forth in the 

Wisconsin Administrative Code, Chapter NR 428. Specifically, RACT requirements 

under NR 428 necessitate that emission sources reduce their NOx emissions to comply 

with Phase I and Phase II emissions reduction requirements beginning in 2009 and 2013 

respectively. 

WPL has developed a plan for reducing NOx emissions from the Edgewater Generating 

Station to comply with RACT requirements as set forth in NR 428. WPL has optimized 

combustion and upgraded burner technology on existing Edgewater units, including the 

completed installation of SmartBurn technology on Edgewater Unit 5. WPL is in the 

process of installing SNCR/RRI technology on Edgewater Units 3 and 4, with in-service 

dates planned for December 2008. WPL views the installation of this SCR system on 

Edgewater Unit 5 as another key component in the NOx reduction plan. 

Phase I RACT compliance is expected to be met through a facility-wide NOx emissions 

averaging plan for the Edgewater Generating Station. The SCR on Edgewater Unit 5 is 

scheduled for commercial operation in the Spring of 2011 to ensure that the unit is 

compliant with RACT Phase II. WPL determined, through an independent engineering 

assessment, that this SCR project is the only feasible option for Edgewater Unit 5 to 

comply with Phase II RACT requirements. 

This SCR project is estimated to cost $153 MM and, based on WPL’s ownership share of 

the project, has a Net Present Value Revenue Requirement (NPVRR) benefit in excess of 

$500 MM when compared to retiring the unit, based on WPL’s EGEAS analysis. WPL’s 

EGEAS project payback period has been calculated to be approximately six years. 

WEPCO plans to separately file a cost and need analysis for this project which will 

include their modeling results. The results demonstrate that the continued operation of 

Edgewater Unit 5 with the proposed NOx controls is the least cost option for their 

customers. 
3 

1.0 Project Description 

The Edgewater Generating Station is located south 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 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 Separated Overfire Air 

(SOFA) technology and Low NOx Burners (LNB) (SmartBurn technology) to reduce 

NOx emissions, followed by a cold-side ESP for particulate emissions control. The 

proposed project addressed in this CA application is an SCR installation on Edgewater 

Unit 5 for NOx emissions reduction necessary to meet RACT requirements at the 

Edgewater Generating Station. 
4 

Figure 1. Edgewater Unit 5 SCR Project Location Map 

The proposed project includes installation of Selective Catalytic Reduction (SCR) 

technology for NOx reduction on Edgewater Unit 5, which would also include 

installation of 19% aqueous ammonia reagent tanks, an ammonia feed building, 

associated tie-in ductwork, and support structures. The following sections describe the 
5 

selected technology as it applies to Edgewater Unit 5, the proposed site layout, and 

construction approach. This information is based on preliminary system design and 

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

schedule for the project is to begin detailed engineering in the first quarter of 2009 with 

commercial operation expected by Spring of 2011. 

Figure 2 shows the typical integration of an SCR system into a utility boiler application. 

The Edgewater Unit 5 SCR installation will be similar to this layout, with the SCR 

located in front of the ESP and mounted over the fan room, in series with existing 

operations. Note that this figure shows an SCR reactor bypass, which will not be 

included in the Edgewater Unit 5 SCR system. 

Figure 2. Typical SCR Reactor Design1

The site arrangement in Figure 3 (enlarged in Appendix A) shows a plot plan of the 

Edgewater Unit 5 SCR project relative to existing units. The Edgewater Unit 5 SCR will 

be located in front of the existing precipitator and will be mounted directly over the fan 

room at the north side of the Edgewater Unit 5 boiler building. Ammonia storage tanks, 

transfer pumps, and control building will be located west of the turbine building as 

indicated in Figure 3. Major transportation modes, rail and road access exist up to the 

construction area. Temporary roads to the construction site will be required during 

 

1

 Stultz, S.C., J.B. Kitto, and G.L. Tomei, eds. Steam: Its Generation and Use. Boston: Babcock & 

Wilcox Company, 2005. 
6 

construction. Note that the information displayed in Figure 3 is conceptual, based on 

preliminary design, and may be modified during detailed engineering. 

Figure 3. Site Layout – Proposed Edgewater Unit 5 SCR System 

1.1 Technology Objectives 

The SCR NOx control system for Edgewater Unit 5 will be designed to meet the 

following objectives: 

 Reduce NOx emissions to meet Phase II RACT requirements and improve air 

quality in Wisconsin 

 Reduce NOx emissions to required levels with the most cost effective 

technology 

 Minimize adverse impacts to other regulated pollutants 

 Maintain existing fuel flexibility 

 Maintain the reliability, operability, and performance of the units and new 

equipment 

 Minimize disruption to operations during the construction period 

 Minimize outage time during construction tie-ins. 
7 

1.2 Selected Technology 

The technology proposed for NOx reduction at Edgewater Unit 5 is a selective catalytic 

reduction (SCR) system. In an SCR system, NOx, is removed via reaction with an 

ammonia-based reagent (NH3), resulting in molecular nitrogen (N2) and water vapor 

(H2O). The major reactions are the following: 

4NO + 4NH3 + O2  4N2 + 6H2O 

2NO2 + 4NH3 + O2  3N2 + 6H2O 

The NOx reduction reactions occur as the flue gas passes through the catalyst chamber. 

The Edgewater Unit 5 SCR is designed to use 19% aqueous ammonia solution as the 

reducing agent. Anhydrous ammonia was also considered, but discounted due to 

associated safety concerns with storing and handling a toxic compressed gas. The 

aqueous ammonia reagent is vaporized and injected into the flue gas downstream of the 

economizer through an injection grid mounted in the ductwork. Compressed air is used 

to atomize the aqueous ammonia reagent. The hot flue gas and atomized reagent then 

flow into the catalyst chamber where NOx is reduced to nitrogen and water. The nitrogen 

gas and water vapor leave the SCR system and flow out the stack with the flue gas. 

The preliminary design of the SCR at Edgewater Unit 5 consists of the following 

components: one reactor with not fewer than three layers of catalyst, an ammonia storage 

and delivery system, an ammonia injection system, an in-duct mixing apparatus, steam 

soot blowers, sonic horns, instrumentation, inlet ductwork from economizer to SCR 

including expansion joints, outlet ductwork from SCR to air heaters including expansion 

joints, an economizer bypass, SCR inlet and outlet NOx monitors, as well as an NH3

monitor at the SCR outlet. 

Based on Edgewater Unit 5 current operation, the SCR system will be designed to meet 

75% removal efficiency, or 0.06 lb/MMBtu average outlet NOx over the life of the 

catalyst, and will allow no more than 5 ppm NH3 slip. There are a number of vendors that 

manufacture SCR reactors based on specific catalyst designs. WPL solicited proposals 

for engineering and procurement during the third quarter of 2008 and expects to request 

proposals from constructors in the fourth quarter of 2008. No preference will be given to 

any particular vendor. 

1.3 Construction Approach 

The following is a high-level overview of the construction approach for the project. Two 

primary objectives in the design, construction, and start-up of this equipment are to 

minimize impact on the operation of the unit during construction and to minimize the tiein outage time. 

Civil

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

exceeds the effects of factored load combinations. Deep foundations will be used for 
8 

heavy loaded SCR support columns; all other foundations, such as for the ammonia 

storage area, will be shallow foundations. These will be installed early in the 

construction phase of the project. 

Selective Catalytic Reduction (SCR) System

The SCR reactor will be mounted over the fan room at the north side of Edgewater Unit 5 

boiler building. This location minimizes the length of inlet/outlet duct necessary to direct 

flue gas from the economizer outlet to the SCR and return the treated flue gas from the 

SCR to the existing air heaters. Currently, no reactor bypass is included, and the plant 

expects to run the SCR year round. Catalyst cleaning will be accomplished by sonic 

horns with provisions for future steam soot blowers. 

Ammonia Handling/Injection System

Ammonia storage for the Edgewater Unit 5 SCR will be located on the west side of the 

Unit 5 turbine building in a diked area. Ammonia storage will be based on aqueous 

ammonia (19% by weight) delivered to the site by truck and likely stored in bullet type 

tanks. The injection system will consist of pre-wired ammonia supply skids, including 

necessary pumps, gauges, isolation valves, electrical panel, and input/output junctions for 

connection to the plant distributed control system (DCS). An ammonia injection system 

will be provided with the SCR. The ammonia injection system is comprised of an 

ammonia flow control system and an atomization air system. 

Ductwork

Ductwork will be added from the economizer to the SCR inlet and from the SCR outlet to 

the air heater inlet. Sufficient duct length before the reactor will be provided to ensure 

that ammonia will uniformly mix with the flue gas. Additionally, an economizer bypass 

will be included to maintain required operating temperatures to the SCR and avoid 

ammonium bisulfate plugging problems at low load operation. Quality non-metallic 

ductwork expansion joints will be used. 

Mechanical Equipment

Existing Induced Draft fans (ID fans) with no modification would operate at higher 

capacity after addition of SCR (operating at 95% from previous 80% capacity). It is 

anticipated that in order to maintain reasonable operating margin on the fans, either fan 

modifications or upgrades will be necessary. Additional engineering studies will 

determine the final decision on the need for ID fan modifications. 

Electrical

Electrical equipment will be installed on elevated concrete pads to prevent water 

intrusion. The AC auxiliary distribution system will be supplied from the existing plant 

power, requiring a new transformer and motor control center in the SCR area. The 

existing electrical system is expected to provide DC and vital AC requirements for the 

SCR system. Cables will be installed in cable trays, conduit and underground ducts. 

Additional ground protection, lighting systems, heat trace system, voice communication 

systems, and fire detection systems will be installed as necessary for safe and efficient 

operation of the SCR. 
9 

Instrumentation and Controls

New instrumentation and controls are required for the SCR and ammonia tank farm 

systems. 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 workstations will be integrated into existing operator interfaces. 

1.4 Constructability Summary 

Based on site reviews and other assessments by engineering consultants, an SCR system 

is feasible for Edgewater Unit 5. As mentioned previously, the SCR will be located in 

front of the existing electrostatic precipitator mounted directly over the fan room. 

Laydown space is available west of Lakeshore Drive. Road and rail access exists up to 

the construction area, and additional temporary roads will be required for construction. 

Activities requiring more investigation prior to finalizing the construction approach 

include the following: 

 Layout of selected vendor’s specific equipment 

 Evaluation of necessity of ID fan upgrades 

 Confirm foundation design with geotechnical report 

 Structural analysis of ductwork upstream of air heater and ESP to 

determine if additional pressure on these sections will require 

strengthening 

 Review of fire protection system requirements by local fire officials. 

It is expected that these issues will be finalized after the vendor is selected and detailed 

engineering is complete. 

1.5 Milestone Schedule 

The following is a preliminary milestone schedule for the Edgewater Unit 5 SCR project. 

This schedule will be refined after the engineering, procurement, and construction 

contracts have been signed and detailed engineering begins. Equipment lead times have 

been getting longer as equipment demand increases. Equipment lead time will be a 

considerable factor in meeting the project completion schedule. 

Milestone Date

Issue Request For Proposal (RFP) for engineering and procurement Aug 2008 

Issue RFP for constructor Oct 2008 

Submit CA application to PSCW Nov 2008 

Award engineering and procurement contract (limited notice to proceed) Mar 2009 

Award constructor contract (limited notice to proceed) May 2009 

Receive CA (expected) Nov 2009 

Begin Construction Post CA Approval 

Edgewater Unit 5 SCR project completion Spring 2011 
10 

2.0 Cost and Financing Estimates 

An independent engineering consultant developed capital and operating and maintenance 

cost estimates for the Edgewater Unit 5 SCR project. The total project estimate presented 

in this section includes the following major items: 

 Civil, Structural and Architectural items (including foundations, support and 

structural steel, and flue gas ductwork) 

 Mechanical and process related items (SCR systems, ammonia storage and 

transfer systems, process piping, fire protection, and balance of plant 

mechanical systems) 

 Electrical systems (including auxiliary power distribution, lighting, grounding, 

heat tracing, and the construction power system) 

 Instrumentation and Controls (including DCS integration into existing system 

and local instrumentation and controls) 

 Engineering fees, construction management, and start-up services (including 

commissioning and performance testing). 

 Owner’s costs including WPL project personnel, training, licensing and 

permitting support, and initial reagent inventory 

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

prepared in January 2008, with WPL’s project specific owner’s costs, cost of spare 

equipment, contingency, and insurance expenditures. The costs have an expected 

accuracy of -5/+15%. As detailed design and engineering work progresses, project cost 

estimates will be refined. 
11 

2.1 Estimated Capital Cost and Cash Flow 

Estimated capital costs for the Edgewater Unit 5 SCR are provided in Table 1 based upon 

the schedule presented in Section 1.5. These costs do not include Allowance for Funds 

Used During Construction (AFUDC).2

 

Table 1. Edgewater Unit 5 SCR Estimated Capital Cost 

Description Cost ($) 

SCR Reactor Housing and Installation $21,209,000 

Ammonia Handling and Injection $873,000 

Miscellaneous Equipment/ Spares/ Balance of Plant $15,184,000 

Ductwork Modifications $6,110,000 

General Facilities $4,585,000 

Indirects $8,449,000 

Craft Labor/Installation $20,695,000 

Engineering / Construction Management / Start-Up Services $14,756,000 

 Sub-Total $91,861,000 

Contingency $20,104,000 

Escalation $14,695,000 

 Sub-Total $34,799,000 

Prime Contractor's Markup $10,898,000 

Owner's Costs $16,386,000 

 Total Project Cost $153,944,000 

Cash flow estimates for the project are shown in Table 2. These costs include escalation 

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

Table 2. Edgewater Unit 5 SCR Project Annual Cash Flow 

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

2008 1.2% $1,866,000 

2009 16.4% $25,225,000 

2010 63.2% $97,326,000 

2011 19.2% $29,527,000 

Total Project Cost 100.0% $153,944,000 

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

 

2

 AFUDC is the process of including as a part of the total project 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. 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. 
12 

Table 3 shows the cost of this project on the basis of dollars per ton of NOx emissions 

removed and includes the key assumptions associated with this calculation. Capital costs 

for this project ($153,944,000) have been calculated to be $15,400/ton NOx removed, 

based on NOx emissions reduction down to 0.06 lb/MMBtu, which is the expected 

annual average outlet NOx emissions rate over the life of the catalyst. Inlet NOx is 

assumed to be the current NOx emissions from Edgewater Unit 5 with SmartBurn 

technology (0.16 lb/MMBtu). The calculation assumes energy produced from this unit 

remains essentially unchanged in the future. 

Table 3. Edgewater Unit 5 SCR Levelized Cost 

Cost Basis Assumption Parameter 

Value 

Parameter 

Units 

Inlet NOx emissions 0.16 lb/MMBtu 

Outlet NOx emissions 0.06 lb/MMBtu 

Annual NOx removed 1,421 Tons/year 

Capital Cost $153,944 1000 $ 

Annual O&M Cost (2007 $) $1,736 1000 $/year 

Levelized Capital Cost $19,400 1000 $/year 

Levelized O&M Cost $2,500 1000 $/year 

Total Levelized Cost $21,900 1000 $ 

Total Levelized Cost $15,400 $/ton 

All costs presented in this section are contingent upon adherence to the schedule 

presented in Section 1.5. Timely approval of the project will protect against increased 

costs arising from current equipment and materials shortages that are the result of the 

numerous emission reduction and new generation projects proposed and under 

construction. It will also allow WPL to better manage risks associated with competing 

for a limited supply of skilled labor (design engineers, craft labor, etc.) for these same 

projects. 

2.2 Financing Mechanism 

The project to install an SCR system on Edgewater Unit 5 is proposed as a traditional 

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

costs. Upon completion, all of the capital cost including AFUDC will be placed inservice and transferred to electric utility plant subject to traditional ratemaking treatment 

for recovery of such costs. 
13 

3.0 Need and Alternative Analysis 

3.1 Background 

This section provides an overview of the planning analysis used in developing the need 

for the Edgewater Unit 5 SCR system in light of current and future environmental 

regulations, technical feasibility, and strategic long-term financial planning. Emissions 

control projects are planned through WPL’s overall long-term strategic planning process 

using a multi-emissions and fleet-wide approach in conjunction with an awareness of 

anticipated future regulations and evolving electricity demands. WPL’s strategy focuses 

on long-term solutions with an emphasis on high value-added emissions control projects 

that capitalize on fleet-wide synergies and opportunities. The multi-emissions strategy is 

dynamic and considers both increasingly stringent environmental regulations and 

growing electricity demand on the generating units. 

The decision to install SCR at Edgewater Unit 5 resulted from the promulgation of 

increasingly stringent air quality regulations. In 2004, the EPA designated ten counties in 

Southeastern Wisconsin, including Sheboygan County where the Edgewater Generating 

Station resides, as non-attainment areas for the ozone National Ambient Air Quality 

Standard (NAAQS). As a result, the Wisconsin Department of Natural Resources 

(WDNR) promulgated NR 428, creating new NOx emissions standards through the 

adoption of RACT requirements for ozone non-attainment areas in Wisconsin. RACT 

specifies that sources comply in two phases, Phase I limits enforced beginning in 2009 

and the more stringent Phase II limits enforced beginning in 2013. 

In anticipation of lower NOx emissions requirements, WPL began reducing NOx 

emissions at the Edgewater Generating Station in 1999 through the implementation of the 

Combustion Initiative. NOx emissions have already been reduced at Edgewater Units 3, 

4, and 5 by 58%, 84%, and 31%, respectively, using combustion controls. The 

SNCR/RRI projects currently under construction on Edgewater Units 3 and 4 are 

expected to reduce NOx emissions on each unit by approximately 30 – 40%, and this 

Edgewater Unit 5 SCR is planned to reduce NOx by approximately 60 – 70% in order to 

meet Phase II RACT requirements, which go into effect in 2013. 

WPL has deemed the installation of SCR at Edgewater Unit 5 necessary to both its 

operational strategy and long-term emissions compliance program. The following 

sections will explain WPL’s compliance planning process, and the need and rationale for 

installation of the SCR system on Edgewater Unit 5 as part of the broader multi-pollutant 

compliance plan for WPL. 
14 

3.2 Emissions Compliance Planning Process 

3.2.1 Compliance Strategy 

WPL manages air emissions in the context of its overall strategic planning process in 

order to implement a multi-emissions strategy that considers both increasingly stringent 

environmental requirements and growing demand on its electric generating units. This 

planning process is highly dynamic and continually evolving. Work associated with the 

planning process takes place over a continuum that encompasses strategy development, 

long-term strategic planning, and shorter-term tactical planning. Tactical planning 

focuses on near-term implementation of the long-term strategic plan. Major components 

of WPL’s planning process are discussed in this section. The basic components include: 

 Update the Integrated Resource Plan (IRP)3

 Evaluate engineering aspects of emissions controls technical and cost data 

including plant operational constraints 

 Develop scenarios of future air emissions reduction requirements by 

identifying known and proposed or pending new regulations 

 Select an air emissions plan on the basis of regulatory compliance, net present 

value of total cost, feasibility of implementation, and technology performance 

 Implement near-term tactical responses for air emissions plan as components 

of the longer-term strategy 

 Review and update air emissions plan as part of strategic planning process. 

These components of WPL’s planning process are further described in Sections 3.2.2 – 

3.2.7 that follow. 

3.2.2 Update Integrated Resource Plan (IRP) 

WPL’s emissions planning process includes projections of electricity demand on its 

electric generating units based on the IRP. The IRP shows how WPL intends to continue 

to balance the anticipated system energy needs with energy supply. WPL estimates the 

system energy needs using a year-by-year forecast that includes customer demand, the 

energy required at the time of maximum consumption, and the total amount of energy 

consumed. The forecast of energy needs includes energy use by residential, commercial, 

and industrial customers. The forecast for WPL’s system incorporates new customers 

based upon historical trends, and analyzing changes associated with using energy more 

efficiently. Through the IRP, WPL determines the most feasible and economic approach 

to satisfy varying electricity demand and regulatory requirements. 

 

3

 Although WPL’s 2006 IRP has not been completely updated, the EGEAS model used in the instant 

application reflects the May 2007 revisions to the 2006 IRP as included in PSCW Docket No. 6680-CA170. Further updates to that version of the model include projected load, capital costs for Nelson Dewey 

Unit 3 and competing alternatives considered in PSCW Docket No. 6680-CA-170, emission rates, and 

variables germane to the instant application. 
15 

The forecast of energy needs developed through the IRP is matched against existing 

energy supply. If energy supply is not sufficient or economically optimal to meet energy 

needs, additional energy capacity is warranted. WPL uses a computer model to match 

existing and all feasible combinations of future energy supply alternatives together with 

the forecast of energy needs to assist in selecting any needed additional energy supply. 

Specifically, the Electric Generation Expansion Analysis System (EGEAS) computer 

model is used to accomplish these tasks. EGEAS is a modular production costing and 

energy supply expansion software package initially developed under the sponsorship of 

the Electric Power Research Institute (EPRI). 

The EGEAS model focuses on choosing economically optimal energy supply for various 

scenarios, which may manifest themselves during the planning period, typically twenty or 

more years into the future. Various combinations of attributes that are uncertain during 

the planning period comprise the various scenarios. These attributes include energy 

needs, fuel prices, energy supply capital costs, purchase power costs, and the value of 

emissions reductions. EGEAS uses mathematical calculations to test feasible 

combinations of future energy supply alternatives and determine economically optimal 

combinations for each scenario analyzed. Each energy supply alternative is modeled 

using expected energy production characteristics, as well as operating and capital costs. 

EGEAS simulates matching the energy supply to the energy needs on a monthly basis. 

The EGEAS model defines a combination of energy supply alternatives to be 

economically optimal if it minimizes the cumulative present worth of the revenue 

requirements during the planning and extension period and maintains a defined level of 

energy supply reliability. 

The results of the EGEAS modeling are one facet of the IRP process. The process must 

also consider financial, operational and regulatory risks which the EGEAS model cannot 

explicitly incorporate. WPL considers these risks in its broader IRP process that extends 

beyond the use of the EGEAS model. After carefully considering the scenarios analyzed 

using the EGEAS model and their associated financial, operational and regulatory risks, 

WPL constructs an IRP reference base case. WPL uses the projected future generating 

unit output from the IRP reference base case for projecting future air emissions. 

Section 3.4 describes EGEAS runs specific to this project. 

3.2.3 Evaluate Engineering Aspects of Emissions Controls 

WPL’s Clean Air Compliance Program (CACP) engineering team evaluates air pollution 

controls for incorporation into the emissions planning process including current 

information on technology performance, cost, and operational constraints. 

Commercially Available Control Technologies

WPL monitors and evaluates the current status of emissions control technology 

performance through trade organizations, emissions control equipment suppliers, and 
16 

engineering design firms that support the installation of emissions control equipment. 

The information WPL receives from these parties assists in determining appropriate 

emissions control options to include and use in emissions planning. This information is 

useful for long-term strategic 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 emissions controls. 

Physical and Operational Constraints

Each power plant site and electric generating unit is unique in its configuration. This can 

present specific engineering and design challenges that must be considered in the 

emissions planning process such as current emissions control equipment performance, 

physical space available for new emissions controls, necessary equipment upgrades to 

support emissions controls such as the need for increased fan power, and required 

maintenance to reliably operate new controls. In addition, other operational 

considerations during emissions controls construction include the potential need to shut 

down units for prolonged periods. WPL must coordinate its power plant outages with 

those of other regional power plant operators and the electric transmission system 

operator to ensure adequate power is available during these outage periods. The 

engineering services group defines possible timing of control installation, including 

planned outages, given other power plant maintenance activities, to assure the 

continuation of reliable and cost-effective utility operations during emissions control 

installation. The construction schedule for installation of SCR on Edgewater Unit 5 is 

designed to minimize unnecessary tie-in outage time. 

3.2.4 Planning for Air Emissions Regulatory Requirements 

Multi-emissions planning requires evaluating future air emissions regulations and 

understanding associated impacts to WPL utility operations. Understanding the 

regulatory framework governing current, forthcoming, and future air emissions 

requirements is necessary to understand how to develop a flexible multi-emissions 

strategy that can change in response to changes in air emissions requirements. Due to the 

changing nature of air emissions requirements, WPL needs to continually monitor and 

remain informed about their current status. This section discusses current regulations and 

future policy development for air emissions requirements and WPL's consideration of 

these regulations for emissions planning to develop reduction scenarios. 

The Clean Air Act (CAA) directs the EPA to establish regulatory requirements to address 

various pollutants throughout the United States. This ensures that all citizens have the 

same basic health and environmental protections. The CAA recognizes that states are 

often better positioned to carry out certain, specific requirements due to their knowledge 

of local industry and air quality conditions. Wisconsin implements many requirements of 

the CAA within state borders. Wisconsin assumes this responsibility by developing and 

complying with state implementation plans (SIPs) that document the collection of 

regulations the state will use to ensure air quality is maintained and CAA requirements 

are met. 
17 

The states must involve the public, through hearings and opportunities to comment, in the 

development of each SIP. The EPA must approve each SIP; if a SIP is deemed not 

acceptable, the EPA can assume enforcement of the applicable CAA provisions in that 

state by issuing a federal implementation plan (FIP). If an FIP is imposed, the FIP 

governs applicable regulatory requirements in a state until the SIP is approved. Once a 

SIP is approved, the SIP outlines the state’s requirements that will serve to implement the 

relevant CAA provisions. The Wisconsin Department of Natural Resources (WDNR) is 

the primary regulatory agency that implements the CAA requirements in Wisconsin. 

As part of the basic framework under the CAA, the EPA is required to establish NAAQS, 

which serve to protect public health and welfare. These standards address six criteria 

pollutants: nitrogen oxides (NOx), sulfur dioxide (SO2), particulate matter (PM), ozone, 

carbon monoxide (CO), and lead. Combustion of fossil fuels from power plant boilers 

results in direct air emissions of NOx, SO2, CO, and PM. In addition, emissions of 

nitrates and sulfates react as fine aerosols in the atmosphere to create fine particulate 

matter also known as PM less than 2.5 microns in diameter (PM2.5). Ozone is not directly 

emitted from power plants, but results from the photochemical reaction of certain 

pollutant emissions, including NOx in the atmosphere. 

The SIP specifies the regulations that each state will utilize to maintain NAAQS and 

related CAA requirements. Areas that comply with NAAQS are considered to be in 

attainment whereas routinely monitored locations that do not comply with these standards 

may be classified by the EPA as non-attainment and require further regulatory 

requirements. The CAA regulatory framework imposes emission requirements beyond 

those developed to meet the NAAQS. The operating service area of WPL is currently in 

attainment with all NAAQS with the exception of Sheboygan County4

, where Edgewater 

Unit 5 resides, which is currently classified as moderate non-attainment for the 1997 8-

hour ozone standard. 

The following sections summarize the status of current state and federal air regulations 

and how they apply to the Edgewater Generating Station. 

RACT

The RACT rule stems from the 2004 EPA designation of non-attainment of the 8-hour 

ozone standard in counties located in southern and eastern Wisconsin. In accordance 

with the CAA, Wisconsin developed a SIP that takes corrective measures for these 

counties to achieve attainment status. Accordingly, the WDNR promulgated NR 428, in 

which the RACT rule limits NOx emissions from stationary combustion sources in 

Kenosha, Manitowoc, Milwaukee, Ozaukee, Racine, Sheboygan, Washington, and 

Waukesha counties. 

 

4

 The US EPA has proposed to designate six Wisconsin counties as non-attainment for the PM2.5 NAAQS, 

including Columbia County where WPL’s Columbia Generating Station resides. EPA is expected to make 

its final designation by December 18, 2008. 
18 

Compliance with RACT applies to individual combustion units; however, a facilityaveraging plan can be utilized amongst units located in the non-attainment area. Phase I 

RACT compliance begins on May 1, 2009 and establishes unit-specific emissions limits 

of 0.20 lb/MMBtu and 0.15 lb/MMBtu for small (Edgewater 3) and large (Edgewater 4 

and 5) boilers, respectively. Phase II RACT compliance takes effect on May 1, 2013 and 

establishes unit-specific emissions limits of 0.15 lb/MMBtu and 0.10 lb/MMBtu for small 

and large boilers, respectively. Under a facility-wide averaging plan, an emission limit is 

established based on each unit’s specific NOx emissions limit and heat input contribution 

to the facility as a whole. The result is a weighted average NOx emissions limit. Under 

RACT, emissions allowances can not be purchased or traded via a “cap-and-trade” 

model. 

Clean Air Interstate Rule (CAIR)

In 2005, the EPA issued the Clean Air Interstate Rule (CAIR), requiring reductions of 

SO2 and NOx emissions from existing and new electric generating units with greater than 

25 MW of capacity. The CAIR rule was based on a cap-and-trade market-based program 

to reduce the regional transport of electric utility emissions to non-attainment areas in the 

eastern U.S. On July 11, 2008, the U.S. Court of Appeals for the District of Columbia 

Circuit vacated CAIR in its entirety. As of the filing of this application, the court has not 

issued the mandate in the case effectuating its order and is currently considering several 

petitions for rehearing. The court’s decision and the continuing developments in the case 

create some uncertainty regarding CAIR’s NOx and SO2 emissions requirements. 

However, the recent CAIR vacatur neither affects the RACT rule nor the necessity to 

install emissions controls on Edgewater Unit 5. Moreover, WPL believes that any 

regulations succeeding CAIR will be at least as stringent as CAIR. 

Clean Air Visibility Rule (CAVR)

The EPA issued the Clean Air Visibility Rule (CAVR) in 2005 to address regional haze. 

CAVR requires states to develop and implement SIPs to address visibility impairment in 

designated national parks and wilderness areas across the country with a national goal of 

no impairment by 2064. Affected states, including Wisconsin, were required to submit a 

SIP to the EPA to include Best Available Retrofit Technology (BART) air pollution 

controls and other additional measures needed for reducing state contributions to regional 

haze. The implementation of the CAVR SIP reductions is scheduled to begin to take 

effect in 2014 with full implementation before 2018. Generating facility emissions of 

primary concern for BART and regional haze regulation include SO2, NOx and PM. 

Under CAVR, states slated to participate in CAIR's cap-and-trade program could 

determine that CAIR has precedence over BART. Wisconsin was scheduled to comply 

via this method; however, the recent vacatur of the CAIR regulation leaves Wisconsin’s 

compliance strategy to CAVR currently undefined. WPL must provide BART-analyses 

to the Wisconsin DNR by January 9, 2009 for BART-eligible units. Edgewater Unit 5 is 

not a BART-eligible unit. 
19 

Mercury Emissions Regulations

In 2005, the EPA issued the Clean Air Mercury Rule (CAMR), which would require 

reductions of mercury emissions from existing and new U.S. coal-fired electric 

generating units with greater than 25 MW of capacity in a two-phased approach. CAMR 

would use a national cap-and-trade system, where compliance may be achieved by 

adding mercury controls and/or purchasing allowances. In February 2008, a court 

decision vacated and remanded CAMR to the EPA for reconsideration. The EPA's 

response to this court decision and associated implications to WPL are uncertain at this 

time. 

In 2004, the WDNR independently issued NR 446, a state-only mercury emission control 

rule that affects electric utility companies in Wisconsin. The 2004 Wisconsin mercury 

rule included a requirement to cap mercury emissions from major utilities beginning on 

January 1, 2008, with 40% and 75% reductions required by 2010 and 2015, respectively. 

The rule does not require a specific method or technology for mercury emissions 

reduction, thus allowing utilities to choose one that is both cost effective and best suited 

for its particular needs. 

In June of 2008, the Wisconsin Natural Resources Board approved revisions to NR 446. 

These revisions, approved by the legislature in October of 2008, eliminate the 2008-2009 

cap, maintain the requirement to reduce emissions by 40% by 2010 and increase the 

reduction required by 2015 to 90%. Present in this rule is an option to phase in the 

mercury reductions if companies reduce emissions of NOx and SO2 as well. This phase 

in of retrofits would allow for mercury reductions of 70% reduction by 2015, 80% by 

2018 and 90% by 2021. 

WPL has already installed activated carbon injection at its Edgewater Unit 5 to assist it in 

complying with the currently existing state-only mercury control rule. In addition, 

WPL’s Clean Air Compliance Program calls for the installation of a baghouse on 

Edgewater Unit 5 for greater than 90% mercury emissions reduction, should the current 

system not attain such levels of capture. The proposed installation is slated for 2014 in 

advance of the 2015 mercury rule deadline. 

Future CO2 Regulations

There is considerable debate regarding the public policy response that the U.S. should 

adopt regarding greenhouse gas (GHG) emissions. Initiatives to address CO2 emissions 

are underway at state, regional, and national levels. During its multi-emission planning, 

WPL reviews proposed GHG legislation and regulation to attempt to understand its 

impact on decisions regarding emission control projects. 

WPL’s parent company, Alliant Energy, acknowledges the potential of climate change 

and the forthcoming public policy that will encompass it. Accordingly, Alliant Energy 

maintains the following position on climate change: 
20 

 It is in the best interest of share-owners and customers that future efforts 

to reduce greenhouse gas emissions be guided by an effective, mandatory 

policy that is national in scope, integrates multiple sectors, provides 

planning certainty, and allows flexible compliance actions consistent with 

national energy policy requirements 

 Alliant will continue to invest in energy efficiency and renewable energy 

 Alliant will continue to participate in collaborative efforts to further the 

development of technological advancements in emissions controls and 

generation performance. 

Alliant Energy’s climate change position is guided by the following principles: 

 Sufficient scientific evidence exists to support greenhouse gas emissions 

reduction efforts 

 Technology solutions based on sound science are critical and should be 

developed 

 Greenhouse gas reduction efforts should not be targeted at any single 

industry but rather at all sectors 

 Alliant is part of the solution 

 Economic growth and sustainable development is possible while also 

reducing greenhouse gas emissions. 

Alliant Energy has strategically focused on the following areas to reduce greenhouse 

gases: 

 Installation of commercially proven controls for air emissions and 

continued operational excellence to achieve further generating facility 

efficiency improvements 

 Demand-side management including energy conservation programs 

 Expansion of company-owned renewable energy sources 

 Continued use of Purchased Power Agreements (PPAs) and investments 

that focus on lower or non-emitting generation resources 

 Development of technology solutions through funding of collaborative 

research programs for advanced clean coal generation as well as potential 

options for carbon sequestration. 

3.2.5 Select Air Emissions Compliance Plan 

WPL's air emissions planning process creates cost-effective and feasible emissions 

control strategies considering available emissions controls including the cost and 

performance of the controls and needed emissions reductions. The selection process 

links available emissions controls provided by WPL’s CACP engineering team with 

projected future air emissions of interest. Projected future emissions are based upon 

projected future generating unit output from the IRP reference base case and estimated 

emissions rates. Emission reduction projects are chosen by matching projected future 
21 

emissions against various environmental compliance scenarios. 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 selection of an air emissions plan is completed on the basis of 

regulatory compliance, net present value of total cost, and feasibility of implementation 

and technology performance. 

3.2.6 Implement Near-Term Tactical Responses for Regulatory Compliance 

The air emissions planning process combines needed emissions reductions, available 

emissions controls, and other operational considerations to develop a long-term plan of 

multi-emissions controls to install on specific generating units at specific points in time. 

Long-term plans span 30 years or more. Shorter-term tactical plans span the immediate 

two to five-year period. Long-term plans assist in understanding the sensitivity of 

proposed emissions controls to differing environmental compliance scenarios and help 

prioritize investments in emissions controls. Shorter-term tactical plans help in the 

selection of specific emissions controls for detailed technical reviews, determine 

feasibility at a plant and unit-specific level, refine cost estimates, and update financial 

budgets. The air emissions planning process provides WPL with the flexibility to address 

regulatory uncertainty, technology improvements, and other changing business conditions 

when planning emissions controls investments. Due to the significant construction 

necessary to install air pollution controls, implementation of near-term tactical responses 

must occur as part of the longer-term strategy. 

3.2.7 Review and Update Air Emissions Compliance Plan 

The end result of WPL’s air emissions planning process is a comprehensive multiemissions air compliance plan. Plan recommendations are presented to the company’s 

Strategic Planning Committee (SPC) for review and approval. WPL updates its multiemissions air compliance plans annually as part of the overall strategic planning process. 

WPL may also update these plans in the interim due to significant changes in 

environmental regulations, emissions control technology performance or cost, regulatory 

requirements, or utility operating conditions. 

3.3 Project Need and Alternatives Analysis 

3.3.1 Project Need 

The installation of SCR on Edgewater Unit 5 for NOx control is necessary to attain 

compliance with RACT requirements. SCR installation is the only method through 

which full RACT compliance can be achieved without decommissioning the unit, as 

allowances can not be purchased or traded under the RACT rule. Other available NOx 

control technologies implemented on Edgewater Unit 5 would not yield the necessary 

NOx removal efficiency for Phase II RACT compliance (see Section 6). 
22 

The installation of the SCR system on Edgewater Unit 5 plays a significant role in WPL’s 

fleet-wide Clean Air Compliance Program and is in alignment with the company’s proactive, value-added driven compliance philosophy. Although the CAIR rule was vacated 

by the DC Circuit Court in July 2008, WPL fully anticipates the future will yield a 

similar, if not more stringent, federal or state rule in place for NOx emissions reductions, 

either through EPA promulgation or as a legislative modification or addendum to the 

Clean Air Act. It is anticipated that installation of SCR at Edgewater Unit 5 will assist in 

complying with future rules. 

To date, WPL has been successful with NOx emission reduction projects at Edgewater as 

part of a voluntary emission reduction program. In 1999, the facility began reducing 

emission of NOx through the implementation of the Combustion Initiative and 

SmartBurn technologies. In addition, the facility has been participating in an ozone 

season NOx averaging plan under NR 428 since year 2003 and has consistently 

performed under the limits required by the rule. These NOx reduction projects and how 

they contribute to WPL’s strategy for meeting RACT requirements through a facilityaverage plan are described below. 
23 

NOx Control Technologies at the Edgewater Generating Station 

Given that WPL is able to comply with RACT by averaging Edgewater Generating 

Station’s emissions on a facility-wide basis, it is important to understand the current NOx 

control technologies that are being installed and planned for at the Edgewater Generating 

Station and the impact of those technologies on achieving RACT compliance. The 

following summarizes NOx reduction technologies implemented to date as well as 

planned projects. 

Edgewater Unit 3

WPL is currently installing selective non-catalytic reduction (SNCR) and rich reagent 

injection (RRI) technologies on Edgewater Unit 3, to be operational by December 31, 

2008. The Edgewater Unit 3 SNCR/RRI project is an extension of the SmartBurn project 

approved by the PSCW in 2001 with the issuance of a CA (Docket 6680-CE-162). A 

revision to the CA reflecting the SNCR/RRI initiative was submitted to the PSCW in 

October of 2007 and was approved on December 10, 2007. WPL anticipates a 30-40% 

reduction in NOx emissions with a target achievable NOx emission rate of approximately 

0.20 lb/MMbtu, as compared to the RACT required rates for a small cyclone boiler of 

0.20 lb/MMBtu (Phase I) and 0.15 lb/MMbtu (Phase II). Edgewater Unit 3 NOx 

emissions reductions will assist the Edgewater facility in meeting its RACT Phase I and 

II facility-wide average NOx emissions targets. WPL considered SCR installation for 

Edgewater Unit 3 to be impractical based on cost and thus rejected an SCR on Edgewater 

Unit 3 from further consideration as a technology for RACT compliance. 

Edgewater Unit 4

WPL is currently installing SNCR/RRI technologies on Edgewater Unit 4 to be 

operational by December 31, 2008. The Edgewater Unit 4 SNCR/RRI effort is an 

extension of the SmartBurn project approved by the PSCW in 2000 with the issuance of a 

CA (Docket 5-CE-114). A revision to the CA reflecting the SNCR/RRI initiative was 

submitted in October of 2007 was approved on November 28, 2007. These technologies 

have been pilot scale tested on the unit in early 2008 as a precursor to the full scale 

installation. The SNCR/RRI modifications are anticipated to yield a 30-40% reduction in 

NOx emissions with a target achievable NOx emission rate of approximately 0.11 

lb/MMBtu, as compared to the RACT-required rates for a large cyclone boiler of 0.15 

lb/MMBtu (Phase I) and 0.10 lb/MMBtu (Phase II). Edgewater Unit 4 NOx emissions 

reductions will assist the Edgewater facility in meeting its Phase I and II facility-wide 

average requirements. 

Edgewater Unit 5

WPL has installed SmartBurn technology, consisting of Low NOx Burners (LNB) and 

Separated Overfire Air (SOFA) technology, on Edgewater Unit 5 as a part of the 

Combustion Initiative projects to reduce NOx emissions at the site. These technologies 

have resulted in a 31% reduction of NOx emissions from Edgewater Unit 5, from 0.229 

lb/MMBtu down to 0.16 lb/MMBtu. 
24 

As outlined in this application, WPL is planning the installation of SCR technology for 

the Edgewater Unit 5 facility and anticipates a 75% reduction from baseline NOx 

emissions (0.229 lb/MMBtu) combined with SmartBurn technology, with a target 

emission rate of 0.06 lb/MMbtu. The RACT rates required for a large wall-fired boiler 

are 0.15 lb/MMBtu (Phase I) and 0.10 lb/MMBTU (Phase II). Prior to SCR installation, 

Phase I RACT requirements will be met through a facility-wide NOx emission averaging 

plan. With the SCR installation, Edgewater Unit 5 will be able to meet unit -specific 

Phase II RACT NOx emission rate requirements, and will contribute to facility-wide 

NOx emission averaging for the purposes of complying with RACT Phase II 

requirements. 

RACT Compliance Scenarios 

WPL has conducted an analysis of possible NOx control technologies for Edgewater 

Units 3, 4, and 5 for compliance with Phase I and Phase II RACT requirements under a 

facility-wide averaging plan.5

 Five scenarios of possible NOx controls installed at each 

unit were analyzed. Table 4 shows possible NOx emissions scenarios with SNCR/RRI 

NOx controls installed on Edgewater Unit 3 and various combinations of controls 

installed on Edgewater Units 4 and 5. This table shows that the SCR on Edgewater Unit 

5 is necessary to meet Phase II RACT requirements, as scenarios without it (Scenarios 1 

and 3) do not result in facility Phase II compliance, indicated by a negative compliance 

margin. 

 

5

 The facility-wide emissions average was calculated using the heat input from the past five years (2003-

2007) for each unit in conjunction with projected emission performance rates based on various controls 

installed at each unit. 
25 

Table 4. NOx Emissions and RACT Compliance Summary at the Edgewater Generating 

Stationa 

Scenario 1: Current and Approved Operation 

Controls Installed SNCR/RRI SNCR/RRI SOFA 

Year 

Estimated 

Facility Limit 

(lb/MMBtu) 

Edgewater Unit 3 

(lb/MMBtu) 

Edgewater Unit 4 

(lb/MMBtu) 

Edgewater Unit 5 

(lb/MMBtu) 

Compliance 

Margin 

2009 0.155 0.20 0.11 0.16 7.5% 

2010 0.155 0.20 0.11 0.16 7.5% 

2011 0.155 0.20 0.11 0.16 7.5% 

2012 0.155 0.20 0.11 0.16 7.5% 

2013 0.105 0.20 0.11 0.16 -36.6% 

2014+ 0.105 0.20 0.11 0.16 -36.6% 

Scenario 2: SCR Installed on Edgewater Unit 5 (As Proposed in this CA Application) 

Controls Installed SNCR/RRI SNCR/RRI SOFA and SCR 

(2012) 

Year 

Estimated 

Facility Limit 

(lb/MMBtu) 

Edgewater Unit 3 

(lb/MMBtu) 

Edgewater Unit 4 

(lb/MMBtu) 

Edgewater Unit 5 

(lb/MMBtu) 

Compliance 

Margin 

2009 0.155 0.20 0.11 0.16 7.5% 

2010 0.155 0.20 0.11 0.16 7.5% 

2011 0.155 0.20 0.11 0.16 7.5% 

2012 0.155 0.20 0.11 0.06 39.2% 

2013 0.105 0.20 0.11 0.06 10.5% 

2014+ 0.105 0.20 0.11 0.06 10.5% 

Scenario 3: SCR Installed on Edgewater Unit 4 

Controls Installed SNCR/RRI SNCR/RRI and 

SCR (2013) SOFA 

Year 

Estimated 

Facility Limit 

(lb/MMBtu) 

Edgewater Unit 3 

(lb/MMBtu) 

Edgewater Unit 4 

(lb/MMBtu) 

Edgewater Unit 5 

(lb/MMBtu) 

Compliance 

Margin 

2009 0.155 0.20 0.11 0.16 7.5% 

2010 0.155 0.20 0.11 0.16 7.5% 

2011 0.155 0.20 0.11 0.16 7.5% 

2012 0.155 0.20 0.11 0.16 7.5% 

2013 0.105 0.20 0.06 0.16 -16.8% 

2014+ 0.105 0.20 0.06 0.16 -16.8% 

a. Edgewater Unit 5 NOx emissions presented are from the entire unit, both WEPCO’s and WPL’s 

shares. Although WEPCO plans to separate its share of Edgewater Unit 5 NOx emissions from 

WPL’s share of emissions for their RACT averaging plan for 2009, this is an annual decision and 

may change in future years such that WPL may have to account for all NOx emissions for 

Edgewater 5. For example, Scenario 2 would have a compliance margin in Phase II of 5.9% should 

WEPCO’s share of Edgewater Unit 5 not be included. 
26 

3.3.2 Alternative Analysis 

1) Install Other NOx Control Technologies

WPL has considered a range of commercially available technologies for NOx removal at 

Edgewater Unit 5, including Rich Reagent Injection (RRI), Selective Non-Catalytic 

Reduction (SNCR), Hybrid SCR, and Full-size SCR. The SNCR and RRI do not yield 

NOx emissions reductions necessary to meet the RACT requirements for Edgewater Unit 

5. The Hybrid SCR has not been commercially proven on a boiler as large as Edgewater 

Unit 5 and would likely require costly modifications to meet NOx emissions limits (an 

ammonia distribution system). Additionally, published removal rate from the Hybrid 

SCR system would only marginally meet RACT Phase II requirements. The SCR is the 

only technology capable of producing emissions low enough to comply with RACT 

Phase II requirements (see discussion in Section 6). Because other NOx control 

technologies can not reliably provide sufficient removal of NOx to meet RACT, those 

technologies were not included in the EGEAS analysis. 

2) Retire Edgewater Unit 5

Retiring Edgewater Unit 5 was not deemed a practical decision as it is a relatively new 

baseload generating facility that ranks in the top 25 percent most efficient plants in 

Wisconsin in terms of plant heat rate. Retirement would require replacement of the 

generating capacity provided by Edgewater Unit 5, which, as shown by the EGEAS runs, 

would require a NPVRR premium of over $500 MM dollars for WPL’s share of 

Edgewater Unit 5, versus installing an SCR on the unit. Continuing operation of 

Edgewater Unit 5 was deemed prudent compared to retiring the unit for the following 

reasons: 

 An analysis comparing the Net Present Value Revenue Requirements (NPVRR) 

showed a benefit to control the unit in excess of $500 MM dollars versus retiring 

the unit (discussed in Section 3.4 below). 

 The payback period of the SCR project, compared to retiring the unit, is 

approximately 6 years after operation of the SCR (Section 3.4). 

 Edgewater Unit 5 is the newest baseload generating facility in the WPL fleet, with 

operations beginning in 1985. The unit has an expected remaining life of 45 

years. 

 Edgewater Unit 5 is an efficient power plant in terms of heat rate. It ranks in the 

top 25 percent in terms of heat rate and efficiency, when compared to similar 

power plants in Wisconsin. 

 Edgewater Unit 5 is a robust and flexible power plant in terms of fuel flexibility, 

turn-up, and turn-down. This allows the unit to follow load requirements, 

reducing the amount of emissions during periods of low electrical usage. The 

operation of Edgewater Unit 5 is unique and integral to the overall strategic 

operations of WPL. 

 Edgewater Unit 5 is on schedule to meet current mercury control rules. It 

operates an activated carbon injection system and, if needed, may install a 
27 

baghouse to meet the 90% mercury emissions reduction required under the 

revised state mercury rule. 

3.4 EGEAS Modeling Summary 

As discussed in the above sections, in order to work toward achieving RACT Phase II 

compliance, decommissioning Edgewater Unit 5 is the only alternative to controlling 

NOx by SCR on Edgewater Unit 5. Therefore, WPL conducted a cost/benefit analysis on 

the SCR installation with the comparison of two EGEAS cases:6

 Installation of SCR NOx emissions control at Edgewater Unit 5 pursuant to the 

RACT requirements (base case) 

 The retirement of the Edgewater Unit 5 facility (alternative case) 

The two EGEAS cases are summarized in Table 5. The EGEAS runs showed an 

economic benefit of controlling the unit versus retiring the unit in excess of $500 MM for 

WPL’s share of the project. Table 5 also includes NPVRR for an additional scenario that 

includes the installation of a baghouse and scrubber on Edgewater Unit 5. 

Table 5. EGEAS Analysis Results* 

EGEAS Run NPVRR 

($ MM) 

Savings Versus 

Retirement 

($ MM) 

Base Case: Install SCR 13,852.0 +554.6 

Alternative Case: Retire Edgewater 5 in 2012 14,406.6 

Installation of FGD and baghouse in 2014a 14,069.3 +337.3 

* This table summarizes the modeling results for WPL’s share of the project. 

a. Modeled for informational purposes to demonstrate NPVRR for unit with 

installed controls for NOx, Hg, PM, and SO2

In recognition of the various requests of the Commissioners in Wisconsin Electric Power 

Company Docket No. 6630-CE-299, WPL is providing in Appendix D several additional 

EGEAS scenarios modeling its share of the project. 

3.5 Need and Alternatives Analysis Summary 

The installation of an SCR on Edgewater Unit 5 serves to reduce NOx emissions on the 

unit to comply with RACT requirements. This SCR will also contribute to a facility-wide 

averaging of NOx emissions for the purposes of complying with RACT at the Edgewater 

Generating Station. Based, in part, on the EGEAS runs that WPL conducted, WPL has 

concluded that the installation of an SCR on Edgewater Unit 5 is a prudent alternative to 

retiring the unit. Buying NOx allowances is not an alternative under NR 428 RACT 

requirements, and in order to meet the limits set forth in the RACT rule, the SCR 

technology is the sole technology available to do so for Edgewater Unit 5. The EGEAS 

 

6

 The EGEAS runs were conducted prior to the oral decision in PSCW Docket No. 6680-CE-170, and were 

based upon the updated IRP used in that case. 
28 

runs for WPL’s share show that installing the SCR on Edgewater Unit 5 has a benefit of 

over $500 MM in NPVRR when compared to retiring the unit. For the reasons 

previously stated, WPL has determined that this project is both prudent and necessary for 

meeting current regulatory requirements and continuing to provide cost effective 

electricity generation to WPL’s customers. 

The additional EGEAS scenarios, which were modeled in response to the requests in 

Docket No. 6630-CE-299, show a benefit in NPVRR to the installation of an SCR on 

Edgewater Unit 5, in comparison to retiring the unit, under each modeled future, 

including when CO2 is monetized and under a carbon-constrained future. 
29 

4.0 Operating Parameters 

4.1 Cost of Operations 

Table 6 provides a preliminary breakdown of fixed and variable operating parameters for 

the SCR system to be installed on Edgewater Unit 5. The operating and maintenance 

estimates are based on information from vendors of SCR systems and on Edgewater Unit 

5 burning the current fuel, PRB coal. Fixed operating parameters are based on operating 

and maintenance typical of an SCR of this size and operating capability. 

Table 6. Edgewater Unit 5 SCR Operating Parameters 

Operating Parameter Edgewater Unit 5 

SCR Value Units 

Plant Gross Rating 430 MW 

Annual Capacity Factor 71 % 

Flue Gas Flow at Economizer 

Outlet 2,085,000 acfm @ 700°F 

Existing NOx Controls LNB and SmartBurn 

SCR NOx Removal Efficiency 75 % 

SCR outlet NOx Emissions 0.06 lb/MMBtu 

Reagent Required 19% Aqueous NH3 

Reagent Consumption 1,600 lbs/hr 

Catalyst Life 24,000 Hours of SCR Operation 

Catalyst Volume 10,700 ft3

Atomizing Air Requirement 210 scfm 

Steam 5,700 lbs/hr 

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

6 and the following assumptions: 19% aqueous ammonia reagent cost of $180/ton, 

catalyst cost of $145/ft3, steam cost $3.86/1,000 lb steam. The total annual operating cost 

is expected to be approximately $1,736,000 (in 2007 dollars). 

4.2 Operating Characteristics 

Installation of the SCR 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 existing furnace pressure at Edgewater Unit 5 does not require reinforcement of the 

furnace with addition of the SCR on Edgewater Unit 5. The existing ID fans operate at 

~80% capacity at maximum operating load (430 MW). It is anticipated that the addition 

of the SCR will increase draft losses approximately 8” w.g. and the existing ID fans 

would operate at 95% capacity. In order to ensure adequate fan margin, modifications or 

replacement fans may be necessary. A detailed evaluation of possible fan modifications 

will be finalized after selection of the SCR technology supplier. 
30 

Process Control

The SCR system requires 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 Handing System

Ammonia delivery and preparation will require a moderate amount of operator 

involvement. The 19% aqueous ammonia will be delivered by truck, stored, and injected 

into the SCR system by atomization injection. 

Truck and/or Rail Traffic

Truck traffic will increase slightly because of the delivery of ammonia reagent for the 

SCR system. It is not expected that rail traffic will be impacted by operation of the SCR. 

Plant Operating Personnel

Existing personnel are expected to operate and maintain the new equipment. 

Instrument Air

The SCR air system will tie into the existing instrument air system on site, and will 

include new air compressors and dryers to service the SCR atomizing air requirement, 

sonic horns, and ammonia tank farm. 

Chemical Hazards

Ammonia is the primary chemical required for operation of the SCR system. In order to 

reduce hazardous chemical handling on-site, the project is using 19% aqueous ammonia 

(compared to the alternative anhydrous ammonia). The aqueous reagent will be delivered 

to the site by truck and transferred to storage tanks from an unloading station with a 

breakaway stand. Additionally, the ammonia injection system will be provided with an 

Emergency Stop (E-Stop) system which terminates ammonia feed to the SCR reactor 

either from automatic leak detection or upon operator command. Ammonia tanks will be 

equipped with emergency relief valves and manual shut-off valves for tank fill and 

supply openings. 

Auxiliary Power Consumption

The new SCR system will add approximately 1,600 kW of auxiliary power required for 

running Edgewater Unit 5. The auxiliary power is for additional ID fan power required 

to overcome the pressure drop, and a smaller amount for balance of plant motors. 
31 

5.0 Description and Cost of Property Being Replaced 

The current project layout and general arrangement of the SCR system was developed to 

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

and demolition work. As it is currently planned, the only existing equipment anticipated 

to be removed as part of the Edgewater Unit 5 SCR project are the decommissioned acid 

tanks on the west side of the turbine building. This is to be the location of the ammonia 

storage and supply system. The net book value of the decommissioned acid tanks is 

approximately $5,000. No other existing equipment or structures are anticipated to be 

demolished or replaced as part of the Edgewater Unit 5 SCR project. 
32 

6.0 NOx Reduction Technology Selection

WPL’s compliance plan includes installation of NOx control at Edgewater Unit 5 to meet 

RACT requirements. Various commercial NOx reduction technologies were reviewed for 

application at Edgewater Unit 5, including feasibility of implementation on Edgewater 

Unit 5, ability to meet RACT requirements, and capital and operating cost considerations. 

WPL has successfully lowered their NOx emissions at Edgewater Unit 5 by ~30%, down 

to 0.16 lb/MMBtu, by installing SOFA and low NOx burners (SmartBurn technology) in 

2006. To meet RACT Phase II requirements, NOx emissions must be below 0.10 

lb/MMBtu for the individual unit. To meet RACT Phase II requirements, an SCR was 

chosen for NOx reduction as it is the single proven technology commercially available 

that can achieve the level of NOx removal required. 

6.1 Technology Selection Process 

The specific technology chosen to accomplish the goal of reduction emissions at 

Edgewater Unit 5 was determined by an analysis of the following: 

 Available technologies 

 Reliable, long-term NOx removal efficiencies achievable by each technology 

 Specific costs for each technology at Edgewater Unit 5 

 Implementation timeframes 

 Lead times and availability of critical components 

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

constraints). 

Based on site requirements and already installed NOx control systems, the following 

technologies were evaluated for NOx reduction to meet RACT at Edgewater Unit 5: 

SNCR, Hybrid SNCR/SCR, and SCR. 

6.1.1 Technology Selection Analysis 

Edgewater Unit 5 currently employs the SmartBurn LNB including SOFA, reducing NOx 

emissions by 30%, from 0.229 lb/MMBtu down to 0.16 lb/MMBtu. Table 7 summarizes 

the expected removal efficiencies on Edgewater Unit 5 with additional NOx removal 

technologies combined with existing SmartBurn technology controls. 
33 

Table 7. NOx Reduction Technologies Maximum Removal Efficiencies from Baseline 

Emissions at Edgewater Unit 5 

NOx Reduction Technology Stand Alone NOx 

Removal Efficiencya

Removal Efficiency 

Combined with 

SmartBurnb

SmartBurn – Low NOx Burners (LNB) 

including Separated Overfire Air (SOFA) 30% - 

Rich Reagent Injection (RRI) 30% 50% 

SNCR 25% 50% 

Hybrid SCRc 55% 65% 

Full-size SCR 90% 90% 

a. Stand alone removal efficiency indicates removal from baseline emissions from Edgewater Unit 5, 0.229 

lb/MMBtu (assumes no SmartBurn technology installed). 

b Technology removal rates achieved when combined with SmartBurn technology, consistent with 

removal from 0.229 lb/MMBtu (assuming SmartBurn technology installed on Edgewater Unit 5). 

c. Hybrid SCR removal efficiencies stated in this table assume even distribution of ammonia reagent to the 

SCR catalyst. 

To achieve the individual Edgewater Unit 5 Phase II RACT limit of 0.10 lb/MMBtu from 

the baseline 0.229 lb/MMBtu, a combined (with SmartBurn technology) removal 

efficiency of approximately 60% must be achieved. The removal efficiencies in Table 7 

indicate that SCR and Hybrid SCR are the only technologies capable of achieving the 

required level of NOx removal on Edgewater Unit 5. However, Hybrid SCR is not a 

commercially proven technology. 

Hybrid SCR combines ammonia injection in the boiler (SNCR) with installation of a 

catalyst downstream that makes use of the ammonia slip from the upstream SNCR. 

Although this system has shown 50-60% removal in demonstration tests, the system lacks 

sufficient operating experience to be considered commercially proven on a unit as large 

as Edgewater Unit 5. The major concern with this system is the ammonia distribution at 

the catalyst, which, if insufficient, would not only provide unacceptable NOx removal, 

but also allow for high ammonia slip. If a supplemental ammonia distribution system 

was included as part of the Hybrid SCR, then the system costs would be comparable to a 

full SCR system. 

For the reasons stated above, the SCR technology was chosen as the desired technology 

for lowering NOx emissions at Edgewater Unit 5. 

6.2 Technology Selection Summary 

An SCR is the only commercially available control technology that can reduce Edgewater 

Unit 5 NOx emissions below the 0.10 lb/MMBtu limit required by RACT Phase II. 
34 

7.0 Environmental Impacts/Permits 

7.1 Maps and Drawings of Proposed Project and Site 

The proposed project location and preliminary site layout for the project are shown in 

section 1, on Figures 1 and 2. The general site layout is also shown in Attachment A. 

7.2 Proximity to Floodplains 

The area for the location of the Edgewater Unit 5 SCR project is not within a floodway or 

100-year floodplain. 

7.3 Information on Applicable Environmental Factors 

Several environmental factors have been considered for the proposed SCR 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); oneflowered broomrape (orobanche uniflora); thickspike (elymus lanceolatus ssp. 

psammophilus); American sea-rocket (cakile edenntula); Northern Mosaic Forest; and 

Southern Sedge Meadow. 

However, construction of the SCR on Edgewater Unit 5 will occur on already developed 

WPL property with no adverse impacts to critical habitats for endangered, threatened, or 
35 

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 

The Edgewater Unit 5 SCR project will have minimal impact to the solid waste (i.e. fly 

ash) operations at the facility. Currently, bottom and fly ash is sold or trucked off-site to 

a company-owned landfill. The injection of ammonia into the flue gas, as part of the 

SCR process, may result in the entrainment of ammonia residuals in the fly ash. 

However, this is expected to be minimal and will not affect the end use of the fly ash. 

7.3.4 Water Resources 

Plant water consumption will not increase with the addition of the SCR system. 

7.3.5 Wastewater Discharge 

Plant wastewater discharge will not be affected by the addition of the SCR system. 

7.3.6 Air Quality Resources 

Operation of the SCR can result in oxidation of sulfur dioxide (SO2) to sulfur trioxide 

(SO3) which combines with water vapor to form sulfuric acid mist (SAM). The 

Edgewater Unit 5 SCR preliminary design specification calls for low SO2 to SO3 catalyst 

to mitigate the potential for increased SAM emissions. Further review will determine 

whether or not SAM emissions will exceed the SAM Prevention of Significant 

Deterioration (PSD) threshold. If the threshold is expected to be exceeded, WPL will 

conduct a formal PSD review. 

7.4 List of Permits and Approvals Needed 

Table 8 provides a list of permits and approvals that may be required for the project. 

Table 8. List of Required Permits and Approvals 

Item Agency Planned Activity Type of Approval 

1 PSCW Replacement, modification, or 

addition at a generating plant with 

cost greater than $7.9 million 

Certificate of Authority 

2 Wisconsin 

Department of Natural 

Resources (WDNR) 

Construction, installation, or 

alteration of an air pollutant source 

Air construction permit; air 

quality operation permit; PSD 

evaluation (contingent upon 

SAM emissions) 
36 

3 WDNR Discharge of storm water from 

construction sites impact one acre 

or more 

WPDES General Storm Water 

Construction Permit 

4 WDNR Discharge of storm water from 

plant operations 

Modify existing storm water 

pollution prevention plan 

5 WDNR Integrity testing of equipment Hydrostatic Test Water Permit 

6 Wisconsin 

Department of 

Commerce (WDC) 

Construction - storm water 

management 

Approval of Plan Summary 

Review Application and 

Submittal of Notice of Intent 

(per requirements of Comm 

60) 

7 WDC Construction – revision of existing 

building 

Approval of Plans and 

Specifications 

8 WDC Construction of plumbing facilities Approval of Plans and 

Specifications 

9 Wisconsin 

Department of 

Transportation (WDT) 

Delivery of large/heavy 

components 

Permit for the transportation of 

loads of excessive size and/or 

weight (Section 348.26(2) WI 

Stats.) 

10 Sheboygan County Delivery of large/heavy 

components 

Permit for the transportation of 

loads of excessive size and/or 

weight (Section 348.26(2) WI 

Stats.) 

11 City of Sheboygan Construction Building Permit (upon 

Commerce approval of Plans 

and Specifications) 

12 City of Sheboygan Delivery of large/heavy 

components 

Permit for the transportation of 

loads of excessive size and/or 

weight (local ord.) 
37 

8.0 Designation of Public Utilities and Others Affected 

WPL has joint-ownership of Edgewater Unit 5. WPL owns 75% and WEPCO owns 25% 

of the Edgewater Unit 5 plant. The SCR project supports RACT compliance at the 

Edgewater Generating Station and will improve air quality in the ozone non-attainment 

area of Sheboygan County. By doing so, the project has potential to open the County to 

new industry and help promote economic development in the County. 
38 

Appendix A General Site Layout 
39 

Appendix B NOx Technology Descriptions 

Secondary or post combustion control systems are located downstream of primary 

combustion systems. They can be used independently or in combination with primary 

control systems. These processes typically use ammonia or urea to react with the NOx in 

the flue gas to reduce NOx to molecular nitrogen. The secondary control systems 

included in this section are Selective Catalytic Reduction (SCR), Selective Non-catalytic 

Reduction (SNCR), a hybrid combination of SCR and SNCR, and Rich Reagent Injection 

(RRI). Other secondary control technologies on the market at varying stages of 

development are not included in this evaluation due to their developmental status. 

Selective Catalytic Reduction (SCR)

SCRs are generally designed for a maximum inlet gas temperature of 750°F. The SCR 

uses air taken from the air heater air outlet for ammonia dilution. Design temperature 

range is from 350°F to 600°F. In typical installations, the minimum acceptable flue gas 

temperature to maintain catalyst performance and eliminate problems with ammonia 

injection is approximately 550-600°F. The actual minimum load and gas temperature for 

the unit is determined on site-specific basis. 

Furnace Impacts - The addition of the SCR increases the boiler gas side operating 

pressure drop. For balanced draft units, the static pressure in the duct at the air heater 

(gas side) and ID fan inlet will be more negative than under previous operating 

conditions. Gas-path pressure changes, including upset or excursion events due to 

addition of the SCR and the increase in ID fan head capability, are determined by 

evaluation of the current operating pressure, the design pressure, and a suitable margin 

below design pressure. Any new ductwork would be designed to current guidelines of 

NFPA 8502. More detailed analysis will need to be made during the design phase to 

determine whether structural reinforcement is necessary. 

SCR Reactor - SCR reactor housing supports the catalyst modules on guide frames. The 

reactor assembly generally includes a catalyst removal system. A monorail system is used 

to move the catalyst into the reactor housing. The joints between modules are sealed to 

prevent flue gas bypassing the catalyst. 

The following subsystems would be common for all units operating at a single site: 

ammonia delivery and storage, and ammonia transfer (pumps and piping that transport 

ammonia to the ductwork on inlet side of SCR reactor). 

Aqueous or Anhydrous Ammonia Reagent– Anhydrous ammonia (NH3) is designated to 

be a hazardous material that requires significant permitting and spill reporting paperwork. 

A tank rupture or major leak could result in a potentially life threatening environment for 

a large area of the plant site, and possibly extending beyond the boundaries of the plant. 

Many facilities have opted for the use of aqueous ammonia to avoid these issues. In the 

event of a spill, aqueous ammonia tends to keep ammonia in the solution, resulting in 
40 

easier cleanup and a much smaller area that would be impacted within the plant. The 

major drawback of the use of aqueous ammonia is the added cost to ship all of the water 

along with the ammonia that is needed. 

Ammonia Injection System - Each ammonia injection grid must be designed for even 

ammonia distribution across the face of the SCR catalyst. Some systems incorporate the 

capability to manually bias the ammonia injection to account for non-uniformity of NOx 

and flue gas flow at the SCR inlet. Others rely on upstream mixing devices to produce a 

uniform NOx and NH3 distribution and computerized control systems to maintain the 

proper ammonia injection rates. 

Ammonia Atomizing Air Compressors - Compressed air is used to atomize the ammonia. 

Dedicated skid mounted compressors are typically used for ammonia atomization. 

Dilution Air Fans - Two 100% capacity dilution air fans will be provided for each SCR 

vaporization skid. The fans will be centrifugal type skid mounted assemblies. For each 

unit, dilution air fans will be designed for operation with 350°F to 600°F air, and the 

capability to withstand 750°F. The fan controls will have the capability to automatically 

start the standby fan on low air pressure. The source of dilution air is a takeoff on the air 

heater air outlet duct. The fans will be located with each vaporization skid. 

Flow Distribution - Flow distribution devices, if necessary, will be provided to assure 

adequate flue gas and ammonia distribution and effective utilization of catalyst. The flow at 

the economizer exit is expected to be stratified and is likely to vary with load. Static and 

dynamic means of flow compensation may be required. 

Electrical Supply - A common electrical supply system provides power to the ammonia 

pumps and controls. New electrical components will typically be necessary, including an 

MCC and new switchgear. Alarm/monitoring signals are wired to the nearest existing, 

continuously manned control room. The increased pressure drop may require that the 

existing ID fans be upgraded on some units, requiring new electrical connections for 

larger motors in some cases. The existing starters may be reused, and a new cable will be 

installed to the motor. 

Selective Non-Catalytic Reduction (SNCR)

SNCR was originally developed in Japan in the 1970s for use on oil and gas-fired units. 

SNCR requires injection of ammonia or urea into the proper temperature window within 

the back pass of the furnace. The ammonia or urea reacts with NOx species to form 

nitrogen and water. Emission reduction capabilities range from15-20% at 5-ppm 

ammonia slip to 30% at 10-ppm ammonia slip in most commercial installations. 

An SNCR system requires the installation of reagent storage and transfer equipment, a 

multilevel injection grid and the necessary control instrumentation. Due to the 

elimination of the catalyst used in the SCR process, the SNCR consumption rates for 

ammonia or urea are 3-4 times the rates required for an SCR system. 
41 

The gas temperature at the point of injection is critical to the NOx reduction performance 

of an SNCR system. This window falls in a range of 1600-2000F with an optimum 

temperature of approximately 1800F. Above this temperature, ammonia begins to 

thermally decompose and below this temperature, the reaction rate for NOx reduction 

decreases, resulting in increased ammonia slip. The temperature profile in any given 

boiler changes with fluctuations in boiler load. Therefore, the optimum injection point 

will move during cycling operation and multiple injection points will be required. It 

should also be noted that the longer the ammonia or urea stays within the optimum 

temperature window, the higher the NOx reduction that is achieved. Residence times in 

excess of one second are desirable to achieve the maximum reduction efficiency. The 

minimum residence time is approximately 0.3 seconds for moderate performance. 

However, most large utility boilers have heat transfer surfaces (pendants and platens) 

positioned in this flue gas temperature zone. This will reduce the effective use of the 

SNCR system, even if multiple injection levels are installed. In some cases, these 

internal obstructions will make the application of SNCR impractical. 

Controlling the injection of the ammonia or urea is critical to performance of the SNCR 

system. Continuous ammonia slip measurements would allow direct control of the 

injection rates, but reliable equipment for ammonia measurement is not currently 

available commercially. The location of the injection ports must also consider the 

distribution of ammonia across the furnace cross section. Multiple injection zones and 

levels are typically required in a utility application to account for the large volume within 

a furnace. 

One of the major problems associated with ammonia slip is the formation of ammonium 

bisulfate due to reaction with sulfur trioxide (SO3) in the flue gas. This compound will 

precipitate at air heater operating temperatures and can lead to fouling and plugging. 

Also a concern is the formation of nitrous oxide (N2O) during the SNCR reactions. Urea 

injection typically leads to higher N2O production rates. N2O formation rates increase as 

the rate of NOx reduction increases. 

Additives and enhancers have been tested to improve SNCR performance; however, none 

are commercially available. Some are designed to maintain the temperature window 

(methane) while others are designed to lower the temperature at which the reaction will 

occur. The use of additives is not considered in the SNCR evaluation. 

For SNCR installations, the actual NOx removal rate is strongly influenced by the carbon 

monoxide (CO) level in the injection zone. Variations in the CO concentration can move 

the temperature window where the urea reaction chemistry performs adequately. 

Therefore, unit load, burner firing pattern, and localized CO concentration are additional 

variables that increase the complexity of SNCR system control. 

Hybrid SNCR/SCR

This system combines the NOx reduction capability of SNCR in the boiler with the 

installation of an SCR catalyst downstream that uses the ammonia slip from the SNCR 
42 

process. The major problem with this process is adequate distribution of ammonia to the 

SCR catalyst. Control is difficult due to varying NOx distributions in the flue gas. 

Therefore, inlet NOx concentrations at the catalyst face may be much lower than design 

levels, resulting in ammonia passing through the catalyst without reaction. High local 

concentrations of NOx would have insufficient ammonia for reaction, resulting in 

reduced NOx reduction efficiency. Some hybrid systems will use a supplemental 

ammonia injection system to ensure sufficient ammonia feed to the SCR catalyst. If the 

injection system is required, then the cost for the total system will approach that of a fullscale SCR system. 

NOx reductions typically fall in a range of 50-60% for this hybrid system, although some 

test programs indicate that up to 90% NOx removal is technically feasible with this 

combined system. The primary reason for including the hybrid design in any evaluation 

is the potential for cost savings versus a full-scale system. As the ammonia 

maldistribution increases downstream of the SNCR subsystem, the volume of catalyst 

required increases. At some point, the cost savings from reduced catalyst volume will be 

more than offset by the higher chemical feed costs associated with an SNCR system. The 

purpose of the hybrid design is to increase the SNCR removal efficiency from 30% to 50-

60% while at the same time reducing the ammonia slip rates to 5 ppm or less and also 

reducing the ammonia or urea feed rate by 30% or more. Demonstration tests have 

shown the potential for this design, but it should not be considered a standard commercial 

offering. 

Rich Reagent Injection

Rich Reagent Injection (RRI) is the process of injecting amine-based compounds into the 

fuel-rich regions of the furnace to reduce the formation of NOx. The RRI process was 

originally developed for coal-fired cyclone boilers, and performs well in the fuel-rich 

lower furnace created by operating cyclone boilers with Overfire Air. RRI is similar to 

selective non-catalytic reduction (SNCR), which injects urea into the furnace where the 

gas temperatures are between 1600o

F and 2000oF. The RRI process, on the other hand, 

injects the urea at higher gas temperatures (2400oF – 3100oF) within the combustion zone 

of the lower furnace where the conditions are ideal for NOx reduction. RRI can reduce 

NOx by 40% and generally has low ammonia slip. 

The RRI process, which can be licensed from Reaction Engineering International and the 

Electric Power Research Institute, is a complementary technology that can be coupled 

with other NOx reduction technologies such as low NOx burners, Overfire Air, and 

SNCR. The RRI process is particularly compatible with SNCR as it uses similar 

chemicals and hardware. Combined RRI and SNCR systems have demonstrated NOx 

reductions of 50%. The RRI process has been demonstrated at two full-scale utilities: 

Conectiv’s 160 MW B. L. England Unit 1 and Ameren UE’s 480 MW Sioux Unit 1. 
43 

Appendix C Project Conceptual Design Scope Assumptions 

General Project Estimate 

Project Description Retrofit NOx control SCR project. 

Type of Plant Utility grade reliability 

Design Fuel 

Current coal: Jacobs Ranch, 8,614 Btu/lb, 28% moisture, 5.6% ash, 

0.45% sulfur. Design coal: Rosebud PRB, 9,154 Btu/lb, 25% 

moisture, 8.8% ash, 0.8% sulfur. 

Boiler Design Steam 

Pressure 2,400 psig 

Boiler Design Steam 

Temperature 1,000°F 

Operation Load Following with swings 430 MW 

Capacity Factor 71% 

Minimum Load Capacity 16% 

Project Location Edgewater Generating Station in Sheboygan County, along Lake 

Michigan 

Site Description 

Brownfield- with existing Unit 5, began commercial operation in 

1985. Also at this site are Edgewater Units 3 and 4 (60 MW and 325 

MW). 

Boiler Manufacturer Babcock & Wilcox 

Project Commissioning and 

Start-up Date Fall 2011 

Cost Basis/Assumptions 

General 

Ammonia Supply 

 Source 19% aqueous ammonia from remote source TBD 

 Delivery Tank truck to site 

 Storage 

Two 45,000 gallon horizontal, carbon steel, 30 psig design pressure 

bullet type tanks and one pre-assembled and pre-wired aqueous 

ammonia supply skid. 

Catalyst disposal Catalyst manufacturer to provide replacement catalyst will also be 

responsible for spent catalyst disposal. 

Site Conditions 

Adequate space to support additional equipment, with constraints 

existing due to access of existing roads and placement of existing 

plant equipment. 

Soil Conditions/Stability Soils are stable and require no further preparation in and around area 

suitable for use as laydown. 

Subsurface Rock Rock exists in the area. 

Dewatering Not anticipated to be required. 

Construction Storm water 

Control BMP will be employed during construction. 

Wetland Mitigation No wetlands exist in the area of proposed construction. 

Landscaping Minimal landscaping is required. Disturbed areas will be seeded for 

erosion control. 

Rail Access Existing spur on site may be used for receipt of equipment shipped by 

rail. 
44 

Truck Access Existing roads will be used for construction access. Temporary roads 

may also need to be used for transportation of equipment. 

Laydown Areas Sufficient space is available west of Lakeshore Drive in close 

proximity to the work area. 

Structural 

Soil Bearing Capacity 

Additional geotechnical information will be used to determine soil 

stability in specific areas of the SCR project. It is expected that the 

heavily loaded SCR support columns will require deep foundations. 

Other foundations needed for the ammonia storage area will likely be 

shallow foundations. 

SCR SCR and related stair towers and equipment will be enclosed with 

materials to match those used in the existing plant. 

Ammonia Storage Ladder and platform will be provided for access to the tanks and pump 

skids. 

Mechanical 

Pumps Sparing philosophy includes 2x100% for most applications. 

Compressed Air Supply From existing Edgewater Unit 5 air supply system. 

Fire Protection SCR structure will be provided with dry stand pipe for fire automatic 

fire suppression. 

Fire Detection 

A Main Fire Control Panel (MFCP) will be located in the Main 

Control room and will be provided input from new Local Fire Control 

Panels (LFCP) at the SCR electric shelter. 

Ammonia Handling Ammonia delivered as 19% aqueous ammonia solution by truck to 

storage tanks on site. 

Emissions Control 

Emissions Control 

 NOx 

Existing combustion controls are installed – SOFA and LNB. 

Combined, these technologies reduce NOx to 0.16 lb/MMBtu. 

Current project is SCR installation on Edgewater Unit 5 to reduce 

outlet annual average NOx to 0.06 lb/MMBtu. 

 SO2 Current limit is 1.2 lb/MMBtu 3-hr average 

 Opacity 20% 

 Hg 40% reduction required by 2010; 

90% reduction is by required by 2015 

Electrical 

Auxiliary Power 

Additional auxiliary power to SCR system will be supplied from 

existing available plant power. A new motor control center in the 

SCR is required, but new distribution transformers will not be 

required. 

Control System DCS tie-in with existing plant system. 

Plant Communications 

Dial telephone systems will be provided. Page-party systems will also 

be provided at operating and maintenance locations, equipment rooms, 

and major control locations. 

Construction 

Performance Testing Included for all components regardless of contracting approach. 

Stack Testing Included to meet RACT 428 NOx emissions requirements. 

Commissioning and Start-up Included 

Operator Training Included 
45 

Construction Utilities 

 Water Supply Water supply for construction will be from existing water supply. 

 Construction Sanitary 

Facilities 

Construction personnel sanitary facilities will be portable facilities 

with wastes being removed and disposed of off-site via a portable 

vacuum truck. 

 Construction Power Existing plant will provide construction power requirements. 

Equipment Delivery Major equipment may be received via existing rail. Minor equipment 

may be received via rail or tuck, whichever is more efficient. 

Construction Schedule 

It is assumed that the construction schedule will be adequate to allow 

the project to be completed with minimal overtime. Construction 

schedule will be estimated as a 5x10 schedule to incentivize labor. 

Construction Facilities Facilities (buildings) built to support construction will be mobile and 

removed after construction. 

Existing Facilities No relocation of existing facilities is anticipated at this time. 

Miscellaneous 

Permanent Plant Operating 

Spare Parts Allowance included assuming some amount of spares. 
46 

Appendix D Additional Requested EGEAS Runs 

The following requests for further analyses were identified in the Concurrence to the 

Certificate and Order for pollution control equipment on the Oak Creek Power Plant, 

Docket No. 6630-CE-299: 

A. A base case consisting of CO2 monetization and the Renewables Portfolio 

Standard (RPS). 

B. Potential future scenarios in which certain variables are modeled as variations, or 

bookends from the base case, namely: 

1) CO2 costs based on: 

i) “Reputable current estimates from such sources as the Environmental 

Protection Agency (EPA) or the Pew Center on Global Climate Change to 

provide a reasonable range” 

ii) Start date of carbon controls 

iii) Emissions cap amount 

2) Natural gas prices at low, medium (base), and high levels and one scenario of 

high gas prices and low coal prices 

3) Coal prices at low, medium, and high levels 

4) Reserve margins at regional reliability entity recommendation and state level 

5) Construction costs at low, medium, and high levels 

6) MISO impacts, both selling into and buying out of the market with and 

without the proposed plants 

7) Demand and energy forecasts, updated for the next thirty years with low, 

medium, and high sensitivities 

8) Generation options as follows: 

i) The feasibility and availability of nuclear energy by 2020 

ii) No new coal generation 

iii) No new coal generation, but availability of nuclear energy by 2020. 

C. An updated IRP “if it has been two years or more since the last IRP was filed with 

a Certificate of Public Convenience and Necessity Case.” 

The last request, item C in the above list, has been addressed since WPL is working from 

an updated IRP (May 2007) as filed and accepted as complete in Docket No. 6680-CE170. 

Tables 9 and 10, below, summarize additional EGEAS runs designed to address items A 

and B in the above list including the bookends described under item B. Table 9 describes 

the focus of each of the additional EGEAS runs while Table 10 summarizes the 

expansion plans associated with each of the additional EGEAS runs. 

Table 9 presents a combination of three Plans and five Future Scenarios. Each one of the 

15 cells in the table represents a single EGEAS run. Each EGEAS run’s description may 

be determined by combining the information about its corresponding Plan and Future 
47 

Scenario. For instance, Plan 1, Future Scenario 2 (EDG5 P1F2) represents the net 

present value of the revenue requirement (NPVRR) analysis corresponding to the plan to 

install the SCR in 2011 under the base conditions plus monetized CO2 emissions using 

one of the PSCW staff price forecasts used in Docket No. 6680-CA-170, as well as 

nuclear generation available after 2020. 

The specific details and purposes behind each of the Plans and Future Scenarios are 

described below. Please note that the prima facie case presented by WPL in the instant 

filing is based, in part, on an EGEAS base (EDG5 P1F1) and alternative (EDG5 P2F1) 

case excluding CO2 monetization, yet includes the current RPS standard. EGEAS run 

EDG5_P3F1 was modeled for informational purposes to demonstrate NPVRR for the 

unit with installed controls for NOx, Hg, PM, and SO2. The Concurrence in Docket No. 

6630-CE-299 requested that the EGEAS base case consist of CO2 monetization and the 

RPS standard. The EGEAS run EDG5 P1F2, adds CO2 monitization to the WPL base 

case.. Furthermore, the remaining runs attempt to capture the information requested in 

the Concurrence in Docket No. 6630-CE-299, and are not intended to represent WPL’s 

proposals in this case. 

Plans

Plans 1, 2, and 3 describe a range of actions that could transpire at Edgewater Unit 5: 

 Plan 1 represents the installation of the SCR in 2011. 

 Plan 2 represents retiring Edgewater Unit 5 at the end of 2012 instead of installing 

the SCR in 2011. As noted in the application, installing the SCR is the only 

alternative to comply with RACT. 

 Plan 3 represents the installation of a bag house and scrubber in 2014 in addition 

to the installation of the SCR in 2011, as discussed in section 3.2.4 of the 

application. 

Future Scenarios

The five Future Scenarios represent planning scenarios in which key variables are added 

or altered to test the robustness of the outcomes derived from analysis of the plans using 

the base case, Future Scenario 1. 

Future Scenario 1, the base case, makes no revisions, additions, or alterations. Plans 1 

through 3 combined with Future Scenario 1 are identical to those reported in Table 5 of 

the application. 

Future Scenario 2 alters the base case by monetizing CO2 emissions using one of the 

PSCW staff price forecasts used in Docket No. 6680-CE-170. Nuclear generation will be 

available in this and Future Scenarios 3, 4, and 5 after year 2020 in the planning horizon. 

Future Scenarios 3 and 4 represent conditions that would favor and disfavor the retention 

of Edgewater Unit 5, respectively. In these Future Scenarios, natural gas and coal fuel 
48 

prices, purchased power prices, SO2 and NOx allowance prices, the costs to install the 

SCR, and demand and energy forecasts are varied to create these favorable and 

disfavorable conditions. 

Future Scenario 5 represents a carbon-constrained, CO2 emissions monetized 

environment. Future Scenario 5 alters the base case by monetizing CO2 emissions using 

one of the PSCW staff price forecasts used in Docket No. 6680-CE-170 identical to the 

price forecast used in Future Scenario 2. When CO2 monetization begins, in 2015, 

natural gas prices increase and coal prices decrease with corresponding changes in 

purchase power market prices, as a result of changes in generation economic dispatch to 

reduce CO2 emissions. This future scenario also includes policy changes consistent with 

a carbon constrained environment including an enhanced RPS of 25 % renewables by 

2025 and removal of the current production tax credit for wind generation. 

MISO Impact Resulting from Changes to Availability of In-State Generation 

This is a qualitative assessment of the MISO-related impacts related to changes in 

generation resources inside the Wisconsin Energy Market resulting from changes in the 

available set of in-state generation resources. The purpose of this assessment is to 

address bookend 6 in the above list regarding the impact of installing the SCR at 

Edgewater Unit 5 versus retiring the unit. As part of this assessment, it is important to 

understand the structure of the MISO market, drivers for cost impacts and the likely 

result of discrete, specific decisions that change system topology. 

The MISO energy market, as provided for and operated pursuant to the MISO 

Transmission and Energy Market Tariff (TEMT), is generally designed to levelize the 

cost of energy (Marginal Energy component of Locational Marginal Price - LMP) across 

the MISO footprint through a centralized economic dispatch mechanism. At the same 

time, MISO recognizes and mitigates transmission overloading by redispatching 

generation resources, on an out-of-economic basis, which are economically suboptimal 

combinations of generation used to reallocate power flows, thereby reducing line loading 

to acceptable levels. The cost of this suboptimal redispatch is identified and charged to 

those generators and loads which are most directly responsible for the potential overloads 

through the congestion component of LMP. In essence, the LMP congestion component 

provides a cost signal to generators and loads which is intended to encourage a reduction 

of generation output at those locations where excess generation injections are creating 

transmission overloads while stimulating increased generation production at locations 

that additional generation would be beneficial to the transmission grid. Similar behavior 

is intended for load, although load is significantly less operationally flexible than 

dispatchable generation resources and in many cases unable to respond to the congestionrelated cost signals. 

From a historic perspective, generation, along with purchases and sales, was dispatched 

by a utility in order to serve its load directly. The objective function was to precisely 

meet a volumetric energy requirement while minimizing the cost to do so. Within the 

MISO market, MISO is responsible for the volumetric balancing of generation and load, 
49 

while minimizing cost subject to reliability constraints. The utility buys its load 

requirements from MISO at the prevailing MISO market price, and sells its generation 

and transactional energy resources (purchases) to MISO in response to MISO’s price 

signals, receiving payments from MISO based on the MISO LMP price (for purposes of 

this assessment, discussion of the MISO Day-Ahead vs Real-time markets is not 

considered.) In this market structure the revenue a utility receives from the sale of its 

generation into the market offsets the cost it must pay the market for the energy needed to 

serve its load. Ideally, the generation resource mix serves as a financial hedge against the 

cost of serving load.

MISO computes actual LMP price signals, both energy and congestion components 

(additionally a loss component) every five minutes in real-time, and also produces a 

binding Day-Ahead set of hourly LMPs used for financial settlement and unit 

commitment purposes. However, MISO does not produce either a binding longer-term 

set of LMP prices or a non-binding public forecast of LMP prices that could be used to 

accurately site new generation or loads. Neither does MISO publicly produce an LMP 

analysis that could be used by generation producers to reasonably predict the cost impact 

that might result from discrete additions of transmission equipment. In fact, there are no 

publicly available, long-term plans for new transmission that are definitive largely due to 

the uncertainty of siting authorization and the associated resulting design, timing and cost 

of any potential transmission additions. 

In essence, the MISO LMP prices only provide an extremely short-term price signal. 

Every change in system topology (load levels, transmission availability and additions and 

generation additions, retirements and availability) impacts LMP prices, and information 

relating to most of these possible changes are not available to most market participants 

more than a short time in advance, if at all. As a consequence, it is extremely difficult to 

reasonably predict market prices or conditions more than a short time into the future with 

any degree of accuracy. However, it is possible to qualitatively describe the likely impact 

on prices that would result from a singular change to the topology of the system, 

recognizing that subsequent unforeseen and unrelated changes to the system may result in 

additional cost impacts that reverse the effect of such change. 

With respect to the question of whether the public is better served by deploying 

additional capital to enhance environmental controls at Wisconsin-based generators, in 

this case Edgewater Unit #5, or to retire that generator and consider alternate capacity 

and energy supplies, it is reasonable to consider the impact on the price of energy in the 

Wisconsin portion of the MISO footprint. Wisconsin generally, and the WUMS portion 

of the state in particular is relatively isolated from the rest of MISO due to transmission 

limitations. In fact, WUMS is presently identified as a Narrowly Constrained Area 

(NCA) within MISO, a designation that recognizes these limitations and imposes pricing 

restrictions to prevent market abuses. Because of limitations to Wisconsin’s import 

capability, most of Wisconsin’s power requirements need to be served by generation that 

originates from within the state in order to avoid extreme congestion risk or jeopardize 

system stability. The reduction of available generation, particularly that produced by 

relatively low cost resources such as coal-fired facilities, would have the effect of either 
50 

increasing the amount of out-of-state energy that would be produced and imported to 

serve the electric load in Wisconsin, or increasing in-state production by more expensive 

resources. 

Increased out-of-state supply would result in greater transmission loading, which would 

create a need for further economically sub-optimal redispatch to mitigate this 

transmission loading, and therefore result in increased congestion costs within Wisconsin. 

This is the logical result of MISO sending a cost signal seeking to increase the amount of 

generation produced inside the state. However, if there is no additional generation 

available inside the state, the LMP costs will rise until MISO is no longer able to mitigate 

transmission overloads, at which point MISO will simply require load curtailments. It is 

important to note that as LMP congestion charges rise, remaining in-state generation will 

receive a higher level of revenue for the generation it does produce. But the entire load in 

the same area will also experience this cost increase, and since the available generation 

will be less than before the targeted generator is retired, there will be a reduction in the 

overall hedge value of the generation, and the cost paid by electric customers will likely 

increase. At the same time that the LMP price inside the state increases due to 

congestion impacts, LMP prices outside of the state will drop as power from those areas 

is priced by MISO at lower levels in order to encourage reduced generation so as to 

reduce the power flows that are creating the overloading. Therefore, power purchased 

from out of state resources becomes a progressively less valuable offset to the higher cost 

being paid by Wisconsin loads. 

In the short-term, higher cost peaking generators inside the state will be able to respond 

to the MISO cost signals and produce higher levels of energy output, raising costs but 

avoiding outages. Over time, however, as this peaking generation becomes more fully 

deployed for baseload needs, the state will exhaust its available supplies, the LMP prices 

will rise as driven by transmission-related congestion, and load curtailments will become 

commonplace. 

To present a balanced view of the future, it needs to be recognized that the above 

scenario will inevitably occur regardless of near-term environmentally driven retirements 

simply as a result of normal load growth without associated expansion of dispatchable 

baseload resources, much of which needs to be located within the state. However, the 

situation will present itself much more quickly if existing efficient baseload generation is 

retired prematurely, particularly large facilities such as Edgewater #5. The effect of the 

reduction of a single generator is very difficult to quantify, but there is no question, 

qualitatively, on the directional impact of prices within MISO or the WUMS portion of 

the state. The possibility that multiple baseload generators, representing a significant 

percentage of Wisconsin’s baseload fleet, could be retired in the near future raises serious 

questions about the cost of electric service and service reliability in Wisconsin.
51 

Table 9. Additional EGEAS Runs 

Future 1 Base AssumptionsNo Monetized CO2 Allowances

Future 2 Base Assumptions and MonetizedCO2 Allowances-Based upon Staff's NED 3 CO2 ramp approach($10/ton beginning in 2015, ramping to $25/ton in 2025 (2008 dollars))-Nuclear Available after 2020.

Future 3 High Retention Value-Gas prices high-Coal prices Low- Purchase power market prices consistent with gas prices- SO2 allowance prices at current market rates- Project costs are 10% below the estimate- Nuclear Available after 2020

Future 4 Low Retention Value-Gas prices low-Coal prices high- Purchase power market prices consistent with gas prices- SO2 allowance prices at high rates (SO2 and NOX cost levels prior to vacation of CAIR)- Project costs are 20% above the estimate-

FuCaBe-C-G-C- P

Plan 1: Install SCR in 2011

$13,852.0 M

P1F1

(EDG5_45_P1F1)

$16,804.3 M

P1F2

(EDG5_45_P1F2G)

$13,936.5 M

P1F3

(EDG5_45_P1F3C)

$14,991.6 M

P1F4

(EDG5_45_P1F4C)

Plan 2: Do not install SCR and retire Edgewater Unit 5 at the end of 2012

$14,406.6 M

P2F1

(EDG5_12_P2F1)

$17,209.5 M

P2F2

(EDG5_12_P2F2G)

$14,533.1 M

P2F3

(EDG5_12_P2F3C)

$15,419.7 M

P2F4

(EDG5_12_P2F4C)

Plan 3: Install SCR in 2011 and Bag House and Scrubber in 2014

$14,069.3 M

P3F1

(EDG5_BH_P3F1)

$17,029.1 M

P3F2

(EDG5_BH_P3F2E)

$14,139.2 M

P3F3

(EDG5_BH_P3F3C)

$15,207.2 M

P3F4

(EDG5_BH_P3F4C)

* NPVRR values stated in table cells are in millions of 2005 dollars (discounted present value).

Plans

Future Scenarios*
52 

Table 10. Summary of Expansion Plan Associated with Additional EGEAS Runs 

Case Case Description

NPV

30

years

NPV

with

Extension

Difference

Compared

to Base

P1F1 (EDG5_45_P1F1) Install SCR in 2011, WPL base 

assumptions

$10,626.5 $13,852.0 WPL BASE

P2F1 (EDG5_12_P2F1) Do not install SCR and retire 

Edgewater Unit 5 at the end of 2012, 

WPL base assumptions

$11,082.1 $14,406.6 $555

P3F1 (EDG5_BH_P3F1) Install SCR in 2011 and Bag House and 

Scrubber in 2014, WPL base 

assumptions

$10,830.4 $14,069.3 $217

P1F2 (EDG5_45_P1F2G) Install SCR in 2011, WPL Base 

Assumptions and Monetized

CO2 Allowances

$12,429.6 $16,804.3 Future 2

BASE

P2F2 (EDG5_12_P2F2G) Do not install SCR and retire 

Edgewater Unit 5 at the end of 2012, 

WPL Base Assumptions and Monetized

CO2 Allowances

$12,731.2 $17,209.5 $405

P3F2 (EDG5_BH_P3F2E) Install SCR in 2011 and Bag House and 

Scrubber in 2014, WPL Base 

Assumptions and Monetized

CO2 Allowances

$12,628.8 $17,029.1 $225

P1F3 (EDG5_45_P1F3C) Install SCR in 2011, High Retention 

Value

$10,773.3 $13,936.5 Future 3

BASE

P1F2 (EDG5_12_P2F3C) Do not install SCR and retire 

Edgewater Unit 5 at the end of 2012, 

High Retention Value

$11,277.8 $14,533.1 $597

P3F3 (EDG5_BH_P3F3C) Install SCR in 2011 and Bag House and 

Scrubber in 2014, High Retention Value

$10,954.8 $14,139.2 $203

P1F4 (EDG5_45_P1F4C) Install SCR in 2011, Low Retention 

Value

$11,459.5 $14,991.6 Future 4

BASE

P2F4 (EDG5_12_P2F4C) Do not install SCR and retire 

Edgewater Unit 5 at the end of 2012, 

Low Retention Value

$11,783.0 $15,419.7 $428

P3F4 (EDG5_BH_P3F4C) Install SCR in 2011 and Bag House and 

Scrubber in 2014, Low Retention Value

$11,657.3 $15,207.2 $216

P1F5 (EDG5_45_P1F5C) Install SCR in 2011, Carbon 

Constrained Future

$12,623.4 $17,175.5 Future 5

BASE

P2F5 (EDG5_12_P2F5C) Do not install SCR and retire 

Edgewater Unit 5 at the end of 2012, 

Carbon Constrained Future

$13,038.0 $17,680.3 $505

P3F5 (EDG5_BH_P3F5C) Install SCR in 2011 and Bag House and 

Scrubber in 2014, Carbon Constrained 

Future

$12,832.8 $17,387.6 $212

Future 4 Future 5 Future 1 Future 2 Future 3