Certificate of Authority Application
Edgewater Generating Station Unit 5
SO2 Reduction Project
Project Description and Justification
Wisconsin Power and Light Company
Madison, Wisconsin
July 27, 2012
Public VersionPSC REF#:169156
Public Service Commission of Wisconsin
RECEIVED: 07/27/12, 1:49:10 PM
Table of Contents
APPLICATION 1
INTRODUCTION 2
1.1 Edgewater Generating Station Unit 5 ....................................................................................... 4
1.2 Project Purpose ......................................................................................................................... 4
1.3 Selected Technology ................................................................................................................. 6
1.3.1 Technology Description 6
1.3.2 Technology Application at Edgewater Unit 5 6
1.4 Construction Approach ............................................................................................................. 9
1.5 Constructability Summary ...................................................................................................... 11
1.6 Milestone Schedule ................................................................................................................. 11
2.0 COST AND FINANCING ESTIMATES 13
2.1 Estimated Capital Cost and Cash Flow ................................................................................... 14
2.2 Financing Mechanism ............................................................................................................. 16
3.0 NEED AND ALTERNATIVE ANALYSIS 17
3.1 Planning For Emissions Regulatory Requirements ................................................................ 17
3.1.1 Cross State Air Pollution Rule (CSAPR) 17
3.1.2 Mercury and Air Toxics Standard (MATS) 18
3.1.3 Wisconsin State Mercury Rule (NR 446) 19
3.1.4 Potential EPA NSR/PSD Settlement 20
3.2 Emission Compliance Planning Process ................................................................................. 20
3.2.1 Evaluate Engineering Aspects of Emission Control Systems 20
3.2.2 Select Air Emission Compliance Plan 21
3.2.3 Implement Near-Term Tactical Responses for Regulatory Compliance 21
3.3 Project Need and Alternative Analysis ................................................................................... 21
3.3.1 Project Need 22
3.3.2 Analysis of Alternative Compliance Strategy 25
3.4 Need and Alternatives Analysis Summary ............................................................................. 34
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4.0 OPERATING PARAMETERS 35
4.1 Cost of Operations .................................................................................................................. 35
4.2 Operating Characteristics ........................................................................................................ 36
5.0 DESCRIPTION AND COST OF PROPERTY BEING REPLACED 38
6.0 REDUCTION TECHNOLOGY SELECTION 39
6.1 Technology Selection Process ................................................................................................ 39
6.2 Summary of Technology Assessment ..................................................................................... 39
7.0 ENVIRONMENTAL IMPACTS/PERMITS 41
7.1 Emissions Reductions ............................................................................................................. 41
7.2 Proximity to Floodplains......................................................................................................... 41
7.3 Information on Applicable Environmental Factors ................................................................ 41
7.3.1 Archaeological and Historic Resources 41
7.3.2 Threatened and Endangered Species 41
7.3.3 Solid Waste 42
7.3.4 Water Resources 42
7.3.5 Wastewater Discharge 42
7.3.6 Air Quality Resources 43
7.4 List of Permits and Approvals Needed ................................................................................... 43
8.0 DESIGNATION OF PUBLIC UTILITIES AND OTHERS AFFECTED 45
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FIGURES AND TABLES
Figure 1. Edgewater Unit 5 Project Location Map ...............................................................................5
Figure 2. Site Layout – Proposed Edgewater Unit 5 DFGD and FF System........................................8
Table 1. Edgewater Unit 5 DFGD Project Estimated Capital Cost ..................................................15
Table 2 Edgewater Unit 5 DFGD Project Annual Cash Flow .........................................................15
Table 3. Allocations ..........................................................................................................................18
Table 4. MATS Rule Limits .............................................................................................................19
Table 5 WPL Unit SO2 Emission Control and Operations Assumptions .........................................22
Table 6 WPL CSAPR Annual SO2 Emissions Comparison with Edgewater Unit 5 SO2 Controls .23
Table 7 WPL CSAPR Annual SO2 Emissions Comparison without Edgewater Unit 5 SO2 Controls.......... 24
Table 8 WPL‘s 2012 IRP Base Case and Sensitivities .....................................................................26
Table 9. Comparison of PVRR by Sensitivity between Installing DFGD and FF on Edgewater 5 and Early
Retirement of Edgewater .........................................................................................................................30
Table 10 EGEAS Analysis Results for Base Case.............................................................................31
Table 11. Calculations for the Payback Period of Installing a DFGD and FF on Edgewater Unit 5 .............33
Table 12. Edgewater Unit 5 DFGD Design Operating Parameters ....................................................35
Table 13 List of Required Permits and Approvals.............................................................................43
LIST OF APPENDICES
Appendix A General Site Layout
Appendix B Emission Reduction Technology Selection
Appendix C Integrated Resource Plan
Appendix D Project Conceptual Design Scope Assumptions
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ACRONYMS AND ABBREVIATIONS
ACI Activated Carbon Injection MATS Mercury and Air Toxics
Standards
AFUDC Allowance for Funds Used
During Construction
MM Million
B&W Babcock & Wilcox MMBtu Million British Thermal Units
BACT Best Available Control
Technology
MW Megawatts
BMP Best Management Practices NOx Nitrogen Oxides
BOP Balance of Plant NOV Notice of Violation
CA Certificate of Authority PVRR Net Present Value Revenue
Requirement
CAA Clean Air Act NSR New Source Review
CAIR Clean Air Interstate Rule O&M Operating and Maintenance
CaO Calcium Oxide (lime) PM Particulate Matter
CDS Circulating Dry Scrubber PM2.5 Particulate Matter less than 2.5
microns (μm) in diameter –
fine PM
CSAPR Cross State Air Pollution Rule PSCW Public Service Commission of
Wisconsin
CWIP Construction Work in Progress PSD Prevention of Significant
Deterioration
DCS Distributed Control System PRB Powder River Basin
DFGD Dry Flue Gas Desulfurization RACT Reasonably Available Control
Technology
DSI Dry Sorbent Injection SDA Spray Dryer Absorber
EGEAS Electric Generation Expansion
Analysis System
scfm standard cubic feet per minute
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EPA Environmental Protection
Agency
SCR Selective Catalytic Reduction
EPRI Electric Power Research
Institute
SIP State Implementation Plan
ESP Electrostatic Precipitator RPS Renewable Portfolio Standard
FD Forced Draft SOFA Separated Overfire Air
FF Fabric Filter SO2 Sulfur Dioxide
FGD Flue Gas Desulfurization SO3 Sulfur Trioxide
gpm Gallons per Minute SWWTF Sheboygan Waste Water
Treatment Facility
GWh Gigawatt hour TBtu Trillion British Thermal Units
H2O water Trona Sodium Sesquicarbonate
HAP Hazardous Air Pollutants WDNR Wisconsin Department of
Natural Resources
HCl Hydrogen Chloride WDT Wisconsin Department of
Transportation
ID Induced Draft WPL Wisconsin Power and Light
Company
IRP Integrated Resource Plan ZLD Zero Liquid Discharge
LSFO Limestone Forced Oxidation
LNB Low NOx Burners
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INTRODUCTION
Wisconsin Power and Light Company (WPL or the Company) respectfully requests
authorization from the Public Service Commission of Wisconsin (PSCW) to install a Dry Flue
Gas Desulfurization (DFGD) system, which includes a Fabric Filter (FF), (collectively the
Project or Control System) for control and removal of Sulfur Dioxide (SO2) on Edgewater
Generating Station Unit 5 (Edgewater Unit 5).
This project is part of WPL‘s plan to invest in needed controls at its newer, larger, and most
efficient generating units – the workhorses of our generation fleet – allowing customers to
continue to benefit from these existing assets. Our strategy is to equip these workhorse units
with emission control technologies to ensure they comply with applicable environmental rules,
now and in the future, so that we can continue meeting our customers‘ needs for reliable and
affordable energy.
Edgewater Unit 5 is one of WPL‘s larger and efficient units. Edgewater Unit 5 consists of a
wall-fired boiler with a gross maximum operating load of 430 MW. It is equipped with low NOx
burners (LNB) and separated overfire air (SOFA) to reduce Nitrogen Oxide (NOx) emissions.
Edgewater Unit 5 is also equipped with a cold-side electrostatic precipitator (ESP) for particulate
emissions control and activated carbon injection (ACI) to reduce mercury emissions. A selective
catalytic reduction (SCR) system is currently being installed on Edgewater Unit 51, with a
planned in service date of December 2012, to further reduce NOx emissions to meet Phase II
Reasonably Available Control Technology (RACT) requirements in accordance with Wis.
Admin. Code Chapter NR 428.
WPL seeks authority under Wis. Stat. §196.49 and Wis. Admin. Code PSC 112. Wis. Stat.
§196.49(2) requires a public utility to seek approval from the Commission that construction of its
Project does not violate any applicable rule or Commission Order. This Project meets the public
convenience and necessity, and the Project will not:
1. Substantially impair the efficiency of the service of the public utility.
2. Provide facilities unreasonably in excess of the probable future requirements.
3. When placed in operation, add to the cost of service without proportionately increasing
the value or available quantity of service unless the public utility waives consideration by
the commission, in the fixation of rates, of such consequent increase of cost of service.
The installation of the Control System on Edgewater Unit 5 meets the public convenience and
necessity because it allows WPL to continue to provide low cost, efficient energy in compliance
with environmental rules. Thus, Edgewater Unit 5 maintains its importance in WPL‘s generation
fleet for the foreseeable future. As will be demonstrated, the Control System on Edgewater
Unit 5 does not impair the efficiency of service, provide facilities unreasonably in excess of the
1 The Edgewater Unit 5 SCR project was applied for and approved under Docket No. 05-CE-137.
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probable future requirements, or add to the cost of service without proportionately increasing the
value of service.
WPL is committed to working cooperatively with PSCW and affected stakeholders on this
Project, which we hope to have in commercial operation in 2016. Importantly, the Project will
provide economic benefits not only to WPL‘s energy customers, but also to the Sheboygan area
as well as the State. The Project will allow Edgewater Unit 5 – a proven, reliable and efficient
facility – to maintain its importance in WPL‘s generation fleet for the foreseeable future.
Moreover, the Project will provide hundreds of jobs during peak construction, and keeping the
Unit on-line preserves an important source of jobs for Sheboygan and the surrounding
communities. As is the case with our other emission control projects, Wisconsin-made materials
will be used when possible, further boosting the local and State economies.
The proposed Control System enables WPL to comply with SO2 emission reduction
requirements, specifically those arising from the Environmental Protection Agency‘s (EPA)
Cross State Air Pollution Rule (CSAPR) or its replacement and would likely be required in any
potential settlement that WPL, the EPA, and Sierra Club reach regarding alleged New Source
Review (NSR) and Prevention of Significant Deterioration (PSD) air permitting violations.
WPL has developed a plan for reducing SO2 emissions from its fleet to meet CSAPR SO2
emissions reduction requirements through a combination of controlling emissions and unit
retirements. Reducing SO2 emissions at Edgewater Unit 5 is a critical component of this plan
and potential settlement with the EPA.2
Edgewater Unit 5 will benefit from the installation of the Control System through SO2 emissions
reductions of at least 90%, which also reduces the formation of fine particulate matter (PM2.5) in
the atmosphere, as SO2 is a precursor to PM2.5 formation. Reductions in SO2 emissions of at
least 90% translate into the removal of over 220,000 tons of SO2 from Edgewater Unit 5‘s
current emissions over a 30 year period.
Installation of a FF is a necessary component of a DFGD system to control particulate matter
(PM) emissions. The installation of the FF will provide additional benefit by reducing hazardous
air pollutants emitted from Edgewater Unit 5.
The Project is estimated to cost $413.7 MM. WPL‘s modeling of the Project and retirement of
Edgewater Unit 5 demonstrates that the Project is the most cost-effective alternative for meeting
future capacity and energy needs of WPL‘s customers. Installing the Control System will help to
ensure that WPL has sufficient capacity and energy to economically meet its long-term demands
while maintaining comparable reliability as compared to its current operations.
2 Although WPL has not reached a settlement with EPA regarding alleged NSR/PSD air permitting violations, and
settlement is not guaranteed, WPL has assumed a potential settlement would require SO2 emission reductions from
Edgewater Unit 5. Based upon its exploration of settlement options to date, WPL anticipates that the proposed
DFGD system at Edgewater Unit 5 would provide the SO2 emission reductions agreed to in the settlement.
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1.0 PROJECT DESCRIPTION
1.1 Edgewater Generating Station Unit 5
The Edgewater Generating Station (Edgewater) is located in the city of Sheboygan, Wisconsin,
along Lake Michigan (Figure 1). Edgewater Unit 5 began operating in 1985 with a design gross
capacity of 380 MW. The unit currently runs at a gross maximum operating load of 430 MW
and burns low sulfur Powder River Basin (PRB) coal. Edgewater Unit 5 has a Babcock &
Wilcox (B&W) wall-fired boiler retrofitted with LNB and SOFA technology to reduce NOx
emissions, an ACI system for mercury removal, followed by a cold-side ESP for particulate
emissions control. A SCR system is currently being installed on Edgewater Unit 5 to further
reduce NOx emissions to meet RACT Phase II requirements.
1.2 Project Purpose
The proposed emissions reduction project encompasses the installation of a DFGD system and
FF to reduce SO2 emissions from Edgewater Unit 5. The Control System was selected because it
meets the following WPL strategic objectives for Edgewater Unit 5:
Reduce SO2 emissions in a cost-effective manner to comply with current, pending and
future environmental regulations that require SO2 emissions reductions including the
federal CSAPR or similar replacement regulation.
Reduce SO2 emissions in a cost-effective manner that complies with emission reduction
requirements that could be required under a consent decree with the EPA and the Sierra
Club regarding alleged violations of NSR and PSD regulations at Unit 5.3
Constitute an economic benefit when compared to replacement of Edgewater Unit 5.
Minimize increased emission of other regulated pollutants.
Minimize generation of mercury contaminated wastewater from SO2 emission reduction
equipment.
Minimize the adverse impact on Edgewater Unit 5 balance of plant operations during and
after construction.
Maintain access to existing equipment for maintenance.
Provide long-term reliable operation of Edgewater Unit 5.
3 As discussed in Section 3.1.4, WPL has not reached agreement with the EPA and Sierra Club on resolution of the
Notice of Violation (NOV) and the related complaints, and the negotiations are the subject of a confidentiality
agreement. The discussion contained in this application reflects what WPL believes, based in part on existing
consent decrees would ultimately be included in a consent decree among WPL, EPA, and Sierra Club.
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Figure 1. Edgewater Unit 5 Project Location Map
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1.3 Selected Technology
Various flue gas desulfurization (FGD) technologies were assessed.4 DFGD with FF was
selected as the technology most suitable to be implemented for reduction of SO2 emissions from
Edgewater Unit 5 based on the strategic objectives previously noted. DFGD with FF is
characterized by the use of lime reagent, partial saturation of the flue gas stream, and production
of a dry byproduct.
1.3.1 Technology Description
The technology proposed for SO2 emissions reduction at Edgewater Unit 5 is a combination of a
DFGD and FF. With the DFGD technology, the flue gas exiting the Edgewater Unit 5 ESP
enters the absorber vessel; in the vessel, lime, water, and—depending on the design—recycled
solids contact the flue gas stream, which allows for sulfur oxides (SO2 and SO3) in the flue gas to
react with the lime reagent to form calcium compounds (CaSO3, CaSO4) that can then be
removed by the FF, in effect, scrubbing the flue gas. The major reactions in the absorber vessel
are as follows:
Lime Hydration: CaO + H2O Ca(OH)2
SOx Reactions: Ca(OH)2 + SO2 CaSO3 • ½ H2O + ½ H2O
Ca(OH)2 + SO3 + H2O CaSO4 • 2H2O
Sulfite Oxidation: Ca(OH)2 + SO2 + H2O + ½ O2 CaSO4 • 2H2O
Water introduced into the absorber vessel vaporizes, lowering the temperature and raising the
moisture content of the flue gas, which promotes removal of SO2. A FF, installed downstream of
the absorber vessel, removes the dry solids from the scrubbed gas. The dry solids consist of the
calcium compound reaction products, unreacted hydrated lime, and remaining flyash. A portion
of the dry solids from the FF may be recycled to the inlet of the absorber vessel depending on the
vendor-specific design. The remaining byproduct solids from the FF are sent to a landfill for
disposal.
1.3.2 Technology Application at Edgewater Unit 5
The preliminary design and sizing of the DFGD system is based on a Design Coal5 that
represents the range of current operating coals burned at Edgewater Unit 5 from various PRB
mines. The DFGD vessels and FF will be located north of Edgewater Unit 5, in an open area of
the plant site adjacent to the Sheboygan Waste Water Treatment Facility (SWWTF). New
ductwork will tie-in to the existing Unit 5 ductwork downstream of the existing ESP and induced
draft (ID) fans and will run to the inlet of the DFGD vessel. Lime receiving equipment will be
4 The full results of this assessment is presented in Appendices B and summarized in Section 6 of this Application.
5 Design Coal is defined in this application as coal that will be used for design and sizing of the DFGD system as
well as determining costs for equipment. The Design Coal is a fuel with characteristics that could reasonably be
burned at Edgewater Unit 5 in the future and allows for future fuel flexibility.
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located west of the DFGD vessels to allow for easy access from the main gate and limit truck
traffic to the interior of the plant site. New ID booster fans and ductwork located downstream of
the FF will transfer flue gas to the tie-in point at the existing chimney.
The site arrangement in Figure 2 shows a plot plan of the proposed Edgewater Unit 5 DFGD
project relative to the existing units. This layout is based on preliminary system design and
subject to revision with further detailed design and selection of equipment vendors.
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Edgewater Unit 5‘s existing ACI location6 is upstream of the air heater, and the carbon is
collected with the flyash in the existing ESP. The amount of activated carbon injected does not
substantially impact the flyash properties, and therefore Edgewater Unit 5 has been able to
maintain its flyash sales. Since the ACI location upstream of the air heater does not interfere
with flyash sales, the ACI will not be moved as part of the installation of the DFGD and FF. The
inclusion of a FF with the installation of the DFGD system does allow for the option in the future
to move the injection location downstream of the existing ESP and to collect the flyash separate
from the activated carbon should flyash sales be impacted by future changes to regulations.
The emissions reduction project will also include the following auxiliary equipment to support
the operation of the Control System:
Reagent storage and preparation equipment
Solids recycle equipment (if applicable to specific vendor design)
ID booster fans
Associated ductwork
Waste material handling equipment
A new controls building and new electrical equipment
Distributed control system for the new process equipment
Modifications to existing landfill site to accept the new DFGD waste
Balance of plant piping (fire protection, service water, compressed air, etc.)
Material Warehouse
Truck loading for byproducts
Truck unloading for lime
1.4 Construction Approach
The area north of the Edgewater Unit 5 chimney has been selected for the installation of the
Control System. This area is relatively open with a few existing structures that will need to be
removed or worked around to accommodate the construction of the Control System. The
selected site has limited or no access on three sides: a plant access road and the Edgewater Unit
5 chimney limit access to the south; Lake Michigan limits access to the east; and the SWWTF
limits access to the north. Construction activity sequencing and coordination with normal plant
activities will be vital to working within the constraints of the designated area with minimal
impacts on the existing plant operations. Outages will be required to tie-in the Control System.
6 The current ACI injection location is upstream of the air heaters, at the economizer outlet. When the SCR is
installed, the ACI injection location will be moved to downstream of the SCR, but still upstream of the air heater. In
both configurations, the ACI is upstream of the air heaters and ESP.
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WPL plans to minimize plant down-time by taking advantage of planned maintenance outages to
tie-in the new equipment.
The following is a high-level overview of the construction approach for the Project, which
focuses on minimizing the required outage duration of Edgewater Unit 5 and the impact of
construction on facility operations. Details included here may vary from the actual construction
approach after completion of detail engineering, specific equipment procurements, and
constructor(s) selection.
Laydown
Laydown space is available on WPL property west of Lakeshore Drive. This area is currently
being used as a laydown and staging area for the installation of the SCR on Edgewater Unit 5.
As such, it already has the necessary utilities in a fenced-in secure area, which WPL intends to
use to support the Project. Additional laydown, fabrication and staging areas will be required for
the Project at both Edgewater and off-site.
Civil
Structures, components, and foundations will be designed so that their strength equals or exceeds
the effects of factored load combinations. A geotechnical report will be used to define
foundation requirements. Buildings will enclose and protect the major equipment and provide
noise attenuation. Foundations for the primary equipment will be the first structures constructed
upon start of construction.
Demolition
A majority of the new equipment, including the absorber vessels, FF, ID booster fans, and lime
handling equipment, will be located in an area away from the main plant. Accordingly, the
Project will not require significant demolition or relocation of equipment or facilities. Area
preparation will require removal of the northeast storage building and rail spurs located north of
the Edgewater Unit 5 chimney. The contents of the storage building will be relocated. A new
rail spur will be located west of the rail yard to replace the track being demolished. (See Section
5 and Appendix A for further detail on demolition plans.)
DFGD Absorber and FF
The absorber vessels and FF equipment likely will be fabricated off-site and shipped in large
pieces to the project site. Fabrication approach will be finalized upon selection of the equipment
vendors and constructor(s), and will emphasize minimizing on-site fabrication.
Ductwork
Rectangular steel plate ductwork, including duct plate, stiffeners, and ductwork support structure
will be shipped to the site for installation. Some ductwork may be shop fabricated prior to
shipment to minimize on-site fabrication.
Mechanical Equipment
New mechanical equipment includes new ID booster fans and motors, lime unloading and
storage equipment, lime preparation equipment, solids handling equipment, blowers and air
compressors. The equipment details will be finalized in the detailed engineering phase, after
equipment vendors have been selected.
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Electrical
A fully redundant power supply will be installed to provide electrical power for the new
equipment. Major components of the electrical system include feeder cables from existing
switchgear, auxiliary transformers, motor control centers, substations and substation
modifications, and system grounding.
Instrumentation and Controls
New instrumentation and controls are required for the Control System operation. The additional
instrumentation and controls will be integrated into the plant‘s existing distributed control system
(DCS). The primary control functions will be automated process control, system monitoring,
and operational alarms. New controllers and operator and engineering workstations will be
provided with the new instrumentation and controls equipment. To the extent possible, the
existing continuous emissions monitoring systems (CEMS) will be utilized and recalibrated for
the lower emissions rates.
1.5 Constructability Summary
Based on site reviews and assessments conducted by engineering consultants, DFGD and FF
systems are feasible for installation and operation on Edgewater Unit 5. While there are site
specific constraints, the retrofit work is expected to be completed with minimal impact to
existing operations due to detailed planning and construction sequencing of the installation of
new equipment.
The site layout and construction approach is based on preliminary system design and subject to
revision with further detailed design and selection of equipment vendors and constructor(s). The
following tasks will be completed during detailed engineering to finalize the engineering plan,
layout and construction approach:
Selection of a specific DFGD technology
Selection of DFGD equipment vendor
Layout of vendor-specific equipment
Boiler implosion and transient analysis
Selection of constructor(s)
1.6 Milestone Schedule
Detailed engineering for the project is scheduled to begin in the third quarter of 2013. The
Project is anticipated to be in service in the fourth quarter of 2016. Timely approval of the
Project by the Commission will provide WPL schedule flexibility to minimize impacts of market
fluctuations in the cost of labor, materials, and capital. These market fluctuations may intensify
due to increased demand for DFGD and FF equipment needed to comply with pending or future
environmental regulations.
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The Table below presents WPL‘s anticipated regulatory timeline.
Milestone Date
Submit CA Application to PSCW July 2012
Receive CA (expected) 1st or 2
nd Quarter 2013
Award detailed engineering and procurement contract
(limited notice to proceed) 3rd
Quarter 2013
Receive environmental permits (expected) 2nd
Quarter 2014
The table below presents a preliminary milestone schedule for construction of the Edgewater
Unit 5 DFGD system to be in service in the fourth quarter of 2016. This schedule serves as the
basis for the Electric Generation Expansion Analysis System (EGEAS), which is discussed
further in Section 3.3.2 and Appendix C. The project schedule will be refined after the
engineering, procurement, and construction contracts have been signed, detailed engineering
begins, and after receipt of regulatory approval.
Milestone Date
Begin Construction 2nd
Quarter 2014
Equipment Commissioning 1st Quarter 2016
Tie-in outage 3rd
Quarter 2016
In Service 4th
Quarter 2016
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2.0 COST AND FINANCING ESTIMATES
An independent engineering consultant developed capital and operating and maintenance (O&M)
cost estimates for the Edgewater Unit 5 Project. The total Project estimate presented in this
section includes the following major items:
Civil, Structural, and Architectural Items – foundations, support and structural steel, and
flue gas ductwork
Mechanical and Process Equipment – DFGD and FF equipment, ID booster fans, lime
reagent and solids handling equipment, process piping, fire protection, blowers and air
compressors, spare parts, and balance of plant mechanical systems
Electrical Systems – auxiliary power distribution, transformers, motor control centers,
lighting, grounding, heat tracing, and the construction power system
Instrumentation and Controls – distributed control system (DCS) integration into existing
system and local instrumentation and controls of process equipment
Balance of Plant – steel, concrete, demolition and relocation and site preparation work
Landfill Modifications – installation of solids handling and storage equipment at the I-43
landfill, including site preparation, foundations, support steel, piping, electrical, and
instrumentation and control items
Fees – engineering, construction management, and start-up services, including
commissioning and performance testing
Owners‘ Costs – WPL personnel for management of the project and liaison with plant
operations, training of operating staff, project integration with existing plant equipment,
insurance, taxes, first fills reagent, emergency spares and contingency.
Costs presented in this CA application represent the engineering consultant‘s estimate, prepared
in May 2012, for the design, supply, and installation of the Control System. The estimate is
based on budgetary quotations received from vendors for the design and supply of the DFGD
and FF system7 and on the engineering consultant database of equipment, material and project
costs. In particular, costs for the design and supply of Balance of Plant (BOP) equipment and
installation of the DFGD and FF system and BOP equipment was developed by the engineering
consultant using such a database. WPL‘s project specific owner‘s costs mentioned above are
also included in the estimate.
7 Noted as a recommended next set item in Appendix B Section 7.2, these more site specific detail estimates were
requested to confirm the cost to install semi-dry FGD systems onto Edgewater Unit 5 for the purpose of this
application. These site specific estimates account for the cost difference between the model estimate in Appendix B
and the more detail cost estimate provided in the application.
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The estimate was adjusted in accordance to the construction milestone schedule included in
Section 1.6 to provide project costs consistent with the Project being in service in the fourth
quarter of 2016. An escalation rate of 3% per year was used to address anticipated inflation.
The costs have an expected accuracy of -10/+20%. The expected accuracy band and the project
escalation is not intended to account for significant increases in costs for the supply of material
or services due to unexpected market changes.
2.1 Estimated Capital Cost and Cash Flow
Estimated capital costs for the Edgewater Unit 5 Control System are provided in Table 1 and are
based upon the schedule presented in Section 1.6. The costs presented are inclusive of WPL‘s
internal costs. These costs do not include Allowance for Funds Used During Construction
(AFUDC).8
8 AFUDC is the process of including as a part of the total project costs, the applicable carrying costs on Construction
Work In Progress (CWIP) expenditures. If such CWIP balances are included in net investment rate base in a rate
proceeding, then AFUDC would not be included or computed on such amounts. WPL will request 50% CWIP to be
included in rate base for this project at the next available base rate case for consideration by this Commission.
Pursuant to the PSCW‘s Final Decision in Docket No. 6680-UR-118, WPL will accrue AFUDC on 100% of CWIP
balances between the time of Construction Authority (CA) approval and WPL‘s next available base rate case.
Because of the uncertainty of the timing and amount of AFUDC that may be applicable to this project, WPL has not
included AFUDC in this estimate. EGEAS runs assume 50% CWIP to be included in the rate base.
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Table 1. Edgewater Unit 5 DFGD Project Estimated Capital Cost
Description Cost ($)
Engineering / Home Office $31,850,000
DFGD/FF Equipment $57,350,000
Material Storage Equipment $5,360,000
ID Booster Fan Equipment $4,610,000
Other Engineered Equipment $7,860,000
Ductwork & Support Steel Material $8,740,000
Bulk Materials $10,590,000
Construction Labor $76,000,000
Construction Subcontracts $30,140,000
Construction Indirects $26,800,000
Construction Management / Start-Up Services $51,390,000
Sub-Total $310,690,000
Landfill Modificationsa $14,270,000
Sub-Total $324,960,000
Owners‘ Costs $88,750,000
Total Project Costb $413,710,000
a. Landfill modification costs include engineering, equipment, bulk materials, construction costs (labor,
subcontracts, indirects, management and start-up).
b. Accumulated project cost in year-of-occurrence dollars as presented in Table 2.
Cash flow estimates for the project schedule in Section 1.6 are shown in Table 2. These costs
include escalation and contingency but, as stated above, do not include AFUDC.
Table 2. Edgewater Unit 5 DFGD Project Annual Cash Flow
Year Annual % of Total Cost Annual Cash Flow ($)a
2013 2.4% $9,740,000
2014 14.7% $60,870,000
2015 46.3% $191,510,000
2016 35.5% $146,990,000
2017 1.1% $4,600,000
Total Project
Cost 100.0% $413,710,000
a. Costs are presented in year-of-occurrence dollars.
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Actual project costs and cash flow will vary depending upon project approval timing, actual
project schedule, and market conditions. It is expected that the pending and future federal
emissions control regulation will increase demand for DFGD and FF equipment. Timely
approval of this project may allow WPL to procure equipment and services at more favorable
pricing. It will also allow WPL to better manage risks associated with competing for a limited
supply of skilled labor (design engineers, craft labor, etc.) with others for this same type of
projects.
2.2 Financing Mechanism
The Edgewater Unit 5 Project is proposed as a rate-based project, financed using the traditional
utility capital structure. AFUDC, as applicable, will be included as part of the construction costs,
where all of the capital costs, including AFUDC, will be placed in-service and transferred to the
appropriate electric utility plant accounts and recovered through traditional ratemaking
treatment. The accrual and rate treatment of AFUDC will be in accordance with applicable
FERC regulations and PSCW rate orders covering the construction period.
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3.0 NEED AND ALTERNATIVE ANALYSIS
The proposed Control System at Edgewater Unit 5 enables WPL to comply with SO2 emission
reduction requirements, specifically those arising from the CSAPR or its replacement, and would
likely be required under any settlement between WPL, the EPA, and Sierra Club regarding
alleged NSR and PSD air permitting violations. The analysis presented in this section assesses
the installation of a DFGD and FF to reduce SO2 emissions at Edgewater Unit 5 as well as the
retirement and replacement of Edgewater Unit 5 as the compliance alternative. Both options
result in significant SO2 emission reductions from Edgewater Unit 5 although only the proposed
Control System ensures the long-term viability of the unit.
This section provides an overview of the analysis used to determine the need for the proposed
Control System at Edgewater Unit 5. The following sub-sections describe the emissions
regulatory requirements and compliance planning process as well as the need and rationale for
the proposed Control System at Edgewater Unit 5 and alternative of retirement and replacement.
3.1 Planning For Emissions Regulatory Requirements
Current federal and state air emission requirements that are applicable to Edgewater Unit 5 and
relevant to the proposed Control System include CSAPR, Mercury and Air Toxics Standard
(MATS), the Wisconsin Mercury Rule (NR 446) and any potential settlement that WPL may
enter into with the EPA and Sierra Club regarding alleged NSR and PSD air permitting
violations. The implications of these requirements on Edgewater Unit 5 and the impact of the
proposed Control System at Edgewater Unit 5 on WPL‘s ability to comply with them are
presented in Section 3.3 as part of the project need analysis. Additional information on
environmental regulations that apply more broadly to WPL‘s operations is provided in Section 8
of the 2012 Integrated Resource Plan (IRP) included in Appendix C.
3.1.1 Cross State Air Pollution Rule (CSAPR)
In July 2011, the EPA issued CSAPR, which includes requirements to reduce SO2 and NOx
emissions from fossil-fueled Electric Generating Units (EGUs) located in 27 states in the eastern
half of the United States. WPL‘s fossil-fueled EGUs with greater than 25 MW capacity
(including Edgewater Unit 5) would be impacted by CSAPR requirements. CSAPR was
expected to replace the Clean Air Interstate Rule (CAIR) and establish state emission caps for
SO2 and NOx beginning in 2012, to be known as Phase I. These SO2 and NOx emission caps
were expected to be lowered further by CSAPR in 2014 for EGUs located in Wisconsin, to be
known as Phase II. CSAPR also includes assurance provisions that would enforce state emission
caps. Beginning in 2012, these provisions require regulated EGUs with emissions in excess of
their allocated share of state emission caps to surrender additional penalty emission allowances
to the extent the emissions of the state as a whole are in excess of the state caps. These
provisions are expected to limit the amount of emissions trading that would be used to meet
compliance requirements.
In December 2011, the EPA also issued a final supplemental rule that added Wisconsin to
CSAPR for the ozone season NOx emissions trading program. In February 2012, the EPA issued
final revisions to CSAPR to correct the calculation of emission budgets in certain states,
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including an increase of the allowed Phase II annual SO2 budget and Phase I and II annual NOx
budgets for Wisconsin. These revisions would also delay the effective date of the assurance
provisions of CSAPR to Phase II, rather than in Phase I. The EPA is proceeding with final
issuance of these revisions to implement the changes as part of CSAPR, if the stay discussed
below is removed.
In December 2011, the United States Court of Appeals for the District of Columbia Circuit (D.C.
Circuit) stayed the implementation of CSAPR, and, as a result, CAIR obligations remain
effective pending further review by the D.C. Circuit and the EPA. WPL is currently unable to
predict the final outcome of the CSAPR stay. WPL currently believes that CAIR will be
replaced in the future, either by CSAPR, as currently written or as modified based upon a ruling
from the D.C. Circuit, or another rule that addresses the interstate transport of air pollutants.
Utility companies would comply with CSAPR emission requirements by surrendering one
CSAPR allowance for each ton of pollutant emitted. Utilities are allowed to purchase additional
CSAPR allowances to surrender if their emissions exceed their allowance allocations. In
addition, beginning in Phase II (2014), CSAPR would penalize utilities whose:
Emissions exceed their allowance allocation by 18% or more for annual SO2 and NOx
emissions, or by 21% or more for ozone season NOx emissions; and
Jurisdictional state‘s emissions exceed its allowance allocation in the same manner.
CSAPR contains a condition that would require that emission allowances allocated to a unit
which does not operate for two consecutive years must be retired after the fourth year of no
operation. The CSAPR emission allocations for WPL are presented in Table 3. This
information includes the allocations for WPL‘s share of units it operates. WPL CSAPR SO2
Emission allowances would no longer be available for compliance in the fifth year after the unit
retires and would be removed from the company‘s allowance allocation pool.
Table 3. Allocations
CSAPR Implementation Year CSAPR Emission Allocationsa
(tons)
2012 – Phase I 15,932
2014 – Phase II 9,498
a. CSAPR emission allocations listed for 2014 include Riverside Units 1 and 2. On May 18, 2012, WPL
announced that it exercised its option to purchase Riverside Energy Center, LLC, which currently
owns the Riverside Energy Center, from Calpine Corporation. Values represent WPL‘s ownership
share for jointly-owned units, which includes 46.2% of Columbia 1 and 2, and 68.2% of Edgewater 4.
3.1.2 Mercury and Air Toxics Standard (MATS)
In December 2011, the EPA issued the final Utility Maximum Achievable Control Technology
(MACT) Rule, also referred to as MATS. The MATS rule applies to all WPL coal-fueled EGUs
with greater than 25 MW of capacity located in Wisconsin, including Edgewater Unit 5. The
final rule requires compliance with emission limits for mercury, filterable PM as a substitute for
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non-mercury metal HAP, and hydrogen chloride (HCl) as a substitute for acid gas HAP. The
EPA also proposed alternative standards for total or individual non-mercury metals emissions
(instead of filterable PM) and SO2 emissions (instead of HCl for acid gases if a FGD system is
installed). In addition, work practice standards were proposed for organic HAPs emissions to
ensure proper combustion. Compliance is currently anticipated to be required by April 2015.
However, an entity can request an additional year for compliance, which may be granted on a
case-by-case basis by state permitting authorities for units that are needed to assure power
reliability, units repowering to gas, or units that need additional time to install air emission
control technology. The final MATS rule is subject to legal challenge in the D.C. Circuit.
Table 4 presents the MATS rule limits contained in the final rule.
Table 4. MATS Rule Limits
Pollutant Units Limit
Mercurya
lb/TBtu 1.2
Filterable Particulate Matter lb/MMBtu 0.03
Hydrogen Chlorideb lb/MMBtu 0.002
a. The MATS rule also has a generation-based mercury limit similar to NR 446 of 0.008 lb/GWh
b. There is an alternative acid gas limitation for EGUs that have a flue gas desulfurization (FGD) system
and SO2 CEMs installed. This alternative SO2 limitation is 0.20 lb/MMBtu.
3.1.3 Wisconsin State Mercury Rule (NR 446)
The Wisconsin State Mercury Rule requires electric utility companies in Wisconsin to meet
compliance requirements to reduce annual mercury emissions by 40% from a historic baseline
beginning in 2010 (Phase I). In addition, the Wisconsin State Mercury Rule requires large coal-
fueled EGUs with greater than 150 MW of capacity to either achieve a 90% annual mercury
emissions reduction standard or limit the annual concentration of mercury emissions to 0.008
pounds of mercury per gigawatt-hour beginning in 2015 (Phase II).
Small coal-fueled EGUs between 25 MW and 150 MW of capacity must install Best Available
Control Technology (BACT) by January 2015 to reduce mercury emissions. The Wisconsin
state mercury rule may change as a result of EPA issuing a final MATS rule because of a
requirement that the state rule be similar but not more restrictive than federal mercury
regulations. Within six months of the EPA issuing the final MATS rule, the Wisconsin state
mercury rule must be compared to the federal rule and interpreted as to whether the state rule
could be considered more restrictive than the federal rule. If the state rule is determined to be
more restrictive than the federal rule, it will need to be changed. In 2010, WPL filed its
compliance plan with the WDNR. WPL‘s will utilize large and small EGU averaging to comply
with the additional mercury rule emissions reduction requirements that commence in 2015.
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3.1.4 Potential EPA NSR/PSD Settlement
In December 2009, the EPA sent a NOV to WPL as an owner and the operator of Edgewater,
Nelson Dewey and Columbia Generating Stations. The NOV alleges that the owners failed to
comply with appropriate pre-construction review and permitting requirements and as a result
violated the PSD program requirements, Title V Operating Permit requirements of the Clean Air
Act (CAA), and the Wisconsin State Implementation Plan (SIP). In September 2010, the Sierra
Club filed a complaint against WPL in the U.S. District Court for the Eastern District of
Wisconsin, as owner and operator of the Edgewater Generating Station, which contained similar
allegations that modifications were made at Edgewater without complying with the CAA
requirements. In the Edgewater complaint from the Sierra Club, additional allegations were
made regarding violations of emission limits for visible emissions.
WPL believes the projects at Edgewater, Nelson Dewey and Columbia were routine or not
projected to increase emissions and therefore did not violate the permitting requirements of the
CAA. WPL is currently engaged in settlement negotiations with the EPA and Sierra Club.
Although WPL has not reached a settlement, and settlement is not guaranteed, for the purpose of
this CA application, WPL has assumed, based in part on existing EPA settlements, that any
settlement with EPA and Sierra Club will require SO2 emission reductions at Edgewater Unit 5.
To maintain schedule requirements, WPL is filing this CA application now using these assumed
emission reductions. If, as expected, a resolution of the EPA NOV is achieved, WPL will update
this application to take into account any terms or conditions of the settlement to the extent they
contradict the assumptions used in this application.
3.2 Emission Compliance Planning Process
Air emissions are managed by WPL on a system basis through a strategic planning process and
multi-emission strategy that considers both increasingly stringent environmental requirements
and changing demand on EGUs. This planning process is highly dynamic and continually
evolving to address current and anticipated conditions. Work associated with the planning
process encompasses strategy development, long-term strategic planning, and shorter-term
tactical implementation, more precisely detailed below.
3.2.1 Evaluate Engineering Aspects of Emission Control Systems
Air pollution control systems are evaluated for incorporation into the emission compliance plan,
factoring in current information on technology performance, cost, and operational constraints.
Commercially Available Control Technologies
The current status of emission control technology performance is monitored and evaluated
through trade organizations, emission control equipment suppliers, and engineering design firms
that support the installation of emission control equipment. This information assists in
determining appropriate emission control options to consider for long-term emissions planning.
Once long-term strategic emissions plans are approved, technical staff proceeds with preliminary
engineering necessary to make the final selection of plant and unit-specific emission controls.
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Physical and Operational Constraints
Each power plant site and EGU is unique in its configuration. This presents specific engineering
and design aspects that must be considered in the emission planning process, including fuel use
and fuel use capability, current emission control equipment performance, physical space
available for new emission controls, necessary equipment upgrades to support emission controls,
required maintenance, and the potential need to shut down units for prolonged periods to install
the new equipment. Each stakeholder must coordinate its power plant outages with those of
other regional power plants and the electric transmission system operator to confirm adequate
power is available during outage periods. The engineering services group defines possible
timing of control installation, including planned outages and other power plant maintenance
activities, to ensure the continuation of reliable and cost-effective utility operations during
emission control equipment installation.
3.2.2 Select Air Emission Compliance Plan
The air emission planning process creates cost-effective and feasible emission control strategies
that consider available emission control technologies and their associated costs and performance.
Emission reduction projects are chosen by matching projected future emissions against various
environmental compliance scenarios and forecasted electricity demand. As discussed earlier in
this section, the environmental compliance scenarios considered in emissions planning include
current federal and state air quality standards, as well as more stringent outcomes associated with
future federal and state regulations. The potential EPA settlement is an additional potential
compliance requirement and, as such, assumptions regarding a potential settlement are
incorporated into the WPL compliance plan.
The selection of an air emission plan is completed on the basis of regulatory compliance, cost,
and feasibility of implementation and technology performance. The air emission planning
process combines needed emission reductions, available emission controls, and other operational
considerations. The outcome is development of a long-term plan to install multi-emission
controls on specific generating units at specific points in time.
3.2.3 Implement Near-Term Tactical Responses for Regulatory Compliance
While long-term plans assist in understanding the sensitivity of proposed emission controls to
differing environmental compliance scenarios and help prioritize investments in emission control
equipment, shorter-term tactical plans aid in the selection of specific emission controls for
detailed technical reviews, determine feasibility at a plant and unit-specific level, refine cost
estimates, and update financial budgets. Shorter-term tactical plans span the immediate two to
five-year period. Due to the significant construction lead time necessary to install major air
pollution controls, implementation of the short-term tactical plan must occur as part of the
longer-term strategy.
3.3 Project Need and Alternative Analysis
WPL uses the EGEAS model to analyze its current and future generation needs. WPL‘s EGEAS
analysis of project need and alternative compliance strategies applies common generation unit
emission control and operations assumptions to WPL‘s two plans. Plan 1 represents installation
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of the DFGD and FF, and Plan 2 represents early retirement. Each plan was analyzed under a
Base Case (or Reference Case9). Each plan was also analyzed under nineteen sensitivities that
adjusted assumptions such as fuel prices, renewable generation requirements, constraints on
carbon emissions, etc.
WPL then compares the EGEAS Present Value Revenue Requirement (PVRR) of each Plan
under the Base Case and each sensitivity to determine the relative economic merit of each plan.
3.3.1 Project Need
CSAPR
The Control System is needed at Edgewater Unit 5 to comply with the SO2 emission reduction
requirements of Phase II of the CSAPR.
Table 5 summarizes plant controls and planned retirements with regard to SO2 emission
reductions. Retirement dates are not definitive.
Table 5. WPL Unit SO2 Emission Control and Operations Assumptions
Generation Unit Planned
Control/Operation
Timing
Columbia 1 DFGD and FF Mid-2014
Columbia 2 DFGD and FF Mid-2014
Edgewater 3 Unit Retirement End of 2015
Edgewater 4 Unit Retirement End of 2018
Edgewater 5 DFGD and FF End of 2016
Nelson Dewey 1 Unit Retirement End of 2015
Nelson Dewey 2 Unit Retirement End of 2015
In its project need planning and analysis, WPL assumes that annual SO2 emissions under
the CSAPR cannot exceed the WPL fleet allowance allocation by more than 18%. This
assumption avoids the possibility of any potential assurance provision-related penalties.
WPL‘s project need analysis also considers that CSAPR requires retirement of emission
allowance allocations for units that cease operation in the fifth year after operations have
ceased.
9 Base Case and Reference Case are used interchangeably in the application and in Appendix C.
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Table 6 presents projected SO2 emissions data for the WPL coal-fired generation fleet after the
Edgewater Unit 5 SO2 controls are operational (90 percent removal efficiency) compared to the
CSAPR Phase II SO2 allowance allocation. As demonstrated by the data presented in Table 6,
WPL will achieve compliance with CSAPR Phase II SO2 emission reduction requirements under
its emission control and operational plan. As shown in Table 7, without the planned Edgewater
Unit 5 Control System, WPL would have a CSAPR Phase II SO2 allowance deficit of
approximately 3,500 tons, nearly 60% of its allocation, after unit retirements. This would subject
WPL to potential CSAPR assurance provision related penalties.
Table 6. WPL CSAPR Annual SO2 Emissions Comparison with Edgewater Unit 5 SO2
Controls
Generation
Unita
2011 Actual
SO2
Emissionsb
(tons)
Projected
SO2
Emissionsc
(tons)
CSAPR Phase II
SO2 Allowance
Allocationd
(tons)
CSAPR Phase II
SO2 Allowance
Allocation Post-Unit
Retiremente (tons)
Columbia 1 5,750 624 1,789 1,789
Columbia 2 5,788 611 1,786 1,786
Edgewater 3 641 0 426 0
Edgewater 4 3,555 0 1,438 0
Edgewater 5 8,340 858 2,421 2,421
Nelson Dewey 1 5,684 0 746 0
Nelson Dewey 2 5,821 0 869 0
WPL TOTAL 35,579 2,093 9,475 5,995
a. Data represents WPL‘s share of jointly-owned units
b. Actual 2011 emissions data as measured by continuous emissions monitor
c. Projected emissions based on anticipated emission rate after controls are operational and 2011 actual heat
input
d. Allowance allocation does not include allowances assigned to WPL gas-fired units
e. Allowance allocation post-unit retirement assumes allocated allowances are no longer available in the fifth
year after the unit ceases operation, does not include allowances allocated to WPL gas-fired units
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Table 7. WPL CSAPR Annual SO2 Emissions Comparison without Edgewater Unit 5 SO2
Controls
Generation
Unita
2011
Actual
SO2
Emissionsb
(tons)
Projected
SO2
Emissionsc
(tons)
CSAPR Phase
II SO2
Allowance
Allocationd
(tons)
CSAPR Phase II
SO2 Allowance
Allocation Post-Unit
Retiremente (tons)
Columbia 1 5,750 624 1,789 1,789
Columbia 2 5,788 611 1,786 1,786
Edgewater 3 641 0 426 0
Edgewater 4 3,555 0 1,438 0
Edgewater 5 8,340 8,238 2,421 2,421
Nelson Dewey 1 5,684 0 746 0
Nelson Dewey 2 5,821 0 869 0
WPL TOTAL 35,579 9,473 9,475 5,995
a. Data represents WPL‘s share of jointly-owned units
b. Actual 2011 emissions data as measured by continuous emissions monitor
c. Projected emissions based on anticipated emission rate after controls are operational and 2011 actual heat
input
d. Allowance allocation does not include allowances assigned to WPL gas-fired units
e. Allowance allocation post-unit retirement assumes allocated allowances are no longer available in the
fifth year after the unit ceases operation, does not include allowances allocated to WPL gas-fired units
MATS Rule and Wisconsin State Mercury Rule
Edgewater Unit 5 currently meets the mercury reduction requirements under MATS and the
Wisconsin State Mercury Rule. This is accomplished using the current calcium bromide
injection and ACI systems. These systems currently operate in a manner that produces flyash
which is beneficially used by the concrete industry.
Utilizing the existing ACI system in combination with the planned FF may allow mercury
emissions to be controlled in a lower-cost manner. The FF provides increased retention time.
This may provide Edgewater Unit 5 with the flexibility to utilize less activated carbon and
reduce injection of calcium bromide. In addition, the planned FF may provide greater mercury
reductions and reductions of other hazardous air pollutants regulated under MATS.
Potential EPA NSR and PSD Settlement
Although WPL has not reached a settlement with EPA on alleged NSR and PSD violations, and
settlement is not a definitive outcome, for the purpose of this CA application, WPL assumed that
a potential settlement with the EPA regarding the alleged violations would require SO2 emission
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reductions at Edgewater Unit 5. The planned Control System would be needed to meet the SO2
emission reductions required by the potential settlement.
3.3.2 Analysis of Alternative Compliance Strategy
A. WPL‘s Integrated Resource Plan
On an ongoing basis, WPL analyzes its generation needs for the next decade and beyond in order
to assure that it will have sufficient capacity and energy to reliably supply its future retail and
wholesale loads in an economically efficient fashion consistent with applicable state and federal
policies. The results of this analysis, which are summarized in WPL‘s Integrated Resource Plan
(IRP), are used to guide WPL‘s generation plans and to identify the specific plans that would
meet WPL‘s capacity needs while balancing economic, environmental, and reliability impacts.
WPL strives to maintain a balanced resource portfolio, which incorporates base load,
intermediate, and peaking resources; energy from renewable sources; and demand-side
management programs which offset generation needs.
WPL utilizes the EGEAS model to develop its IRP analyses. EGEAS is an accepted computer
model designed, in part, to determine an optimal, least-cost, electric generation fleet expansion
plan that integrates alternative demand- and supply-side resources. The model will also calculate
the annual detailed production costs associated with the optimal plan. Inputs to the EGEAS
model generally include:
forecasts of load and energy requirements;
characteristics of:
o existing generation resources;
o energy efficiency and demand-side management projections; and
o potential new resources (planning alternatives) including generating plants and
off-system purchases;
on-going and expected wholesale energy sales and purchases;
fuel, operating, and emission allowance cost projections; and
system reliability criteria.
Based on the inputs and modeling specifications, EGEAS produces a generation expansion plan,
which satisfies system load and operating requirements while minimizing the present value
revenue requirement (PVRR). The PVRR is calculated over a study period, which in WPL‘s IRP
analyses is usually a 30-year study period with a 35-year extension period. Generally,
differences in PVRR values between modeled plans are used to determine impacts (benefits or
detriments) on customer costs for generation resources and measure the relative economic value
of the modeled plans. The greater the PVRR difference between the modeled plan and the
alternative plan, the greater the impact on customer generation costs relative to the alternative
plan.
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WPL updated its IRP over the course of late 2011 and early 2012 (2012 IRP), with the EGEAS
runs supporting the 2012 IRP completed in June 2012. The IRP is presented in Appendix C.
1. Reference Case and Sensitivity Cases.
WPL created and generated a reference case, or base case, in EGEAS for the 2012 IRP, which
modeled various assumptions, including peak and energy load forecasts, coal and natural gas
price forecasts, emission rates and allowance costs, capital costs, and other factors. The
assumptions for the reference case are described in detail in Section 10 of WPL‘s 2012 IRP.
Following the development of the reference case, WPL created and generated nineteen
sensitivities to evaluate the effects of changes to various key assumptions in the EGEAS model.
Table 8. WPL’s 2012 IRP Base Case and Sensitivities
Case Sensitivity
CASE B1 Reference/Base Case
CASE B2 Higher DFGD&FF Capital cost for Edgewater 5
CASE B3 Economy energy purchases not available
CASE B4 Higher RPS with more wind resource added
CASE B5 Higher natural gas prices by 10%
CASE B6 Higher natural gas prices by 20%
CASE B7 Lower natural gas prices by 10%
CASE B8 Lower natural gas prices by 20%
CASE B9 Higher coal fuel prices by 10%
CASE B10 Lower coal fuel prices by 10%
CASE B11 Higher supply-side capital costs by 10%
CASE B12 Lower supply-side capital costs by 10%
CASE B13 Higher cost for new wind resources
CASE B14 Monetizing emission costs for CO2
CASE B15 Higher emission costs for SO2 by 10%
CASE B16 Lower emission costs for SO2 by 10%
CASE B17 Higher emission costs for NOx by 10%
CASE B18 Lower emission costs for NOx by 10%
CASE H1 High Load Forecast
CASE L1 Low Load Forecast
Section 13 of Appendix C of the 2012 IRP, describes the nineteen sensitivities in greater
detail.
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2. Supply-Side Planning Alternatives.
WPL‘s 2012 IRP included various supply-side planning alternatives, which the EGEAS model
could choose to install in the expansion plans. The EGEAS model is able to select among these
various planning alternatives and to ―install‖ one or more of these units, depending upon the
specific unit constraints, to create an optimal (least-cost) expansion plan. The planning
alternatives include non-combustible and combustible renewable resources (wind and biomass),
natural gas-fired combined cycle and combustion turbines, and other generating units. The
expansion alternatives included in the 2012 IRP were designed to provide a spectrum of
supply-side expansion alternatives, including noncombustible renewable resources, combustible
renewable resources, and nonrenewable combustible resources. Among the specific supply-side
planning alternatives that WPL modeled are:
Solar Photovoltaic at 10 MW
Wind Turbines at 100 MW blocks
Biomass at 35 MW
Biogas at 10 MW
Simple cycle GE 7FA.05 at approx. 189 MW
Combined cycle 2X1 GE 7FA.05 at 300 MW (jointly owned)10
Ultra-Supercritical Pulverized Coal at 300 MW (jointly owned)
Subcritical Circulating Fluidized Bed at 300 MW (jointly owned)
Integrated Gasification Comb. Cycle at 300 MW (jointly owned)
Advanced Passive 1000 (Nuclear) at 300 MW (jointly owned)
Peak Purchases at 50 MW.
This spectrum of resources (in addition to the demand side alternatives discussed below) enables
WPL to study its resource portfolio under the Wisconsin Energy Priorities Law, Wis. Stat.
§ 1.12. Section 9 of WPL‘s 2012 IRP contains additional discussion of WPL‘s supply-side
planning alternatives.
3. Energy Efficiency and Conservation Alternatives.
Energy conservation and efficiency programs will remain an integral part of WPL‘s resource
strategy. Future Demand Side Management (DSM) spending combining Focus on Energy and
WPL‘s programs will remain near historic levels, thus yielding historic DSM results. The
existing levels of energy efficiency are incorporated in the 2012 IRP through the energy load
forecasts. WPL included existing and expected levels of interruptible load and direct load
10
The units parenthetically marked as ―jointly owned‖ are units WPL assumed, for modeling purposes, WPL would
own 50% of the entire unit. This enables WPL to calculate the economic and operating benefits of the larger units.
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control impacts through the peak load forecasts. WPL also modeled a committed supply side
resource at the 1.5% level to act as a proxy for demand side management.
In addition to the supply-side planning alternatives, WPL also modeled a demand-side planning
alternative in the 2012 IRP: Aggressive DSM. The Aggressive DSM alternative was based upon
the proposed increase in statewide conservation and efficiency programs included in the
November 2010 Quadrennial Planning Docket, Docket No. 05-GF-191. In the 2012 IRP, WPL
modeled aggressive DSM for 2014 through 2016.
In 2009, the annual incremental savings associated with the Statewide Focus and the Shared
Savings programs in WPL was 1.01% of retail load, which was the same goal for 2011 in the
Quadrennial Planning Docket. Conservation levels in 2012, 2013, and 2014 were projected to
increase above the WPL‘s historical conservation levels. Using this data, WPL modeled
additional annual incremental savings of 63,010 MWh; 96,554 MWh; and 99,237 MWh for
2014, 2015, and 2016, respectively, as an alternative aggressive DSM option. The Aggressive
DSM alternative modeled in WPL‘s 2012 IRP is initially available in 2014 with 63,010 MWh
and 13.1 MW. By 2016, the levelized savings tops out at 258,801 MWh and 53.7 MW from the
higher level in conservation. The Aggressive DSM alternative assumes the conservation
spending level reverts back to 2009 levels in 2017; however, the model assumes a 14-year
conservation equipment life with savings remaining through 2029.
4. Planning Reserve Margin.
For 2012, WPL projects to own or have under contract approximately 3,130 MISO planning
reserve credits (PRCs) of generating capacity based on summer capacity ratings. WPL‘s
capacity needs are presently met through a combination of owned capacity and purchased
capacity, some of which is in the state of Wisconsin and some of which is out-of-state. In
assessing capacity needs, WPL currently maintains a MISO planning reserve margin (PRM) of
3.81% in each year of the 30-year study period modeled in EGEAS. The 3.81% PRM reflects
the requirement for Planning Year 2011/2012 under the Resource Adequacy portion of the MISO
tariff (this portion of the tariff is also referred to as Module E). The PRM is determined annually
through a Loss of Load Expectation analysis process, and reflects adjustments for the impacts of
demand diversity and forced outages.
B. Modeling the Proposed Project and Alternative.
In the WPL 2012 IRP, Edgewater Unit 5 is modeled as having the proposed DFGD and FF
installed and operating in 2017 as part of WPL‘s current base system plan (Plan 1). To aid in the
determination of the economic impact (benefit or detriment) of this plan, WPL has specified an
alternative plan (Plan 2) to reduce SO2 emissions to comply with pending and future
environmental regulations and requirements by retiring Edgewater Unit 5 at the end of 2016.
Plan 2 was run under the same base or reference set of assumptions and the same nineteen
Sensitivities as discussed above for the plan to address the same SO2 reduction and regulatory
goals achieved by installing a DFGD and FF on Edgewater Unit 5. The results of Plans 1 and 2
are documented in Appendix C § 13D.
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C. Economic Benefits of the Proposed DFGD and FF Installed on Edgewater Unit 5
WPL‘s modeling of Plans 1 and 2 demonstrates that the Edgewater Unit 5 installation of a
DFGD and FF is the most cost effective plan for meeting future capacity and energy needs of
WPL. WPL‘s ability to continue to rely on Edgewater Unit 5 will help to ensure that WPL has
sufficient capacity and energy to economically meet its long-term demands at a lower cost than
the alternative plan of early retirement of Edgewater Unit 5.
1. Installing the DFGD and FF on Edgewater Unit 5 is Cost Effective Compared
to Early Retirement of Edgewater Unit 5 at the end of 2016
WPL modeled the installation of the DFGD and FF on Edgewater Unit 5 at a cost of $413
million under each of the reference/base case and nineteen sensitivities modeled in the 2012 IRP.
WPL also conducted EGEAS runs under each of those twenty sensitivities in which WPL
assumed that Edgewater Unit 5 was retired early, enabling EGEAS to select planning alternatives
to replace Edgewater Unit 5. Under the base case and eighteen of the nineteen sensitivities, the
runs that assume the installation of the DFGD and FF on Edgewater Unit 5 (Plan 1) result in
lower PVRR when compared to the runs that assume Edgewater Unit 5 is retired at the end of
2016 (Plan 2)11
. The benefits of Plan 1 range from a PVRR with extension of approximately $
57.7 million to $288.7 million depending on the sensitivity, as can be seen in Table 9, and in
more detail in Appendix C, § 13D.
11 Sensitivity B8 was the only sensitivity that resulted in a negative PVRR. This run demonstrated that significantly
lower gas prices throughout the study period would result in a negligible negative-PVRR to install the Control
System in place of early retirement.
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Table 9: Comparison of PVRR by Sensitivity between Installing DFGD and FF on Edgewater 5 and Early Retirement of Edgewater 5
Sensitivity / Case Plan 1
Install DFGD&FF on Edgewater 5
Plan 2
Retire Edgewater 5 Early, 12/31/2016
PVRR
Difference
Sensitivity PVRR M$ Sensitivity PVRR M$ M$
Reference/Base Case CASE B1 10493.7 CASE B1_E5P2 10632.6 138.9
Higher DFGD&FF Capital cost for
Edgewater 5 CASE B2 10574.9
CASE B2_E5P2 10632.6
57.7
Economy energy purchases not
available CASE B3 10661.5
CASE B3_E5P2 10797.7
136.2
Higher RPS with more wind resource
added CASE B4 10501.0
CASE B4_E5P2 10637.2
136.2
Higher natural gas prices by 10% CASE B5 10807.3 CASE B5_E5P2 11019.6 212.3
Higher natural gas prices by 20% CASE B6 11086.8 CASE B6_E5P2 11375.5 288.7
Lower natural gas prices by 10% CASE B7 10154.9 CASE B7_E5P2 10218.5 63.6
Lower natural gas prices by 20% CASE B8 9773.1 CASE B8_E5P2 9764.4 -8.7
Higher coal fuel prices by 10% CASE B9 10695.4 CASE B9_E5P2 10771.2 75.8
Lower coal fuel prices by 10% CASE B10 10288.6 CASE B10_E5P2 10493.2 204.6
Higher supply-side capital costs by 10% CASE B11 10631.8 CASE B11_E5P2 10822.1 190.3
Lower supply-side capital costs by 10% CASE B12 10342.8 CASE B12_E5P2 10431.9 89.1
Higher cost for new wind resources CASE B13 10716.4 CASE B13_E5P2 10860.3 143.9
Monetizing emission costs for CO2 CASE B14 11874.4 CASE B14_E5P2 11950.5 76.1
Higher emission costs for SO2 by 10% CASE B15 10494.2 CASE B15_E5P2 10633.1 138.9
Lower emission costs for SO2 by 10% CASE B16 10493.2 CASE B16_E5P2 10632.1 138.9
Higher emission costs for NOx by 10% CASE B17 10493.0 CASE B17_E5P2 10631.9 138.9
Lower emission costs for NOx by 10% CASE B18 10494.3 CASE B18_E5P2 10633.3 139.0
High Load Forecast CASE H1 10894.1 CASE H1_E5P2 11035.9 141.8
Low Load Forecast CASE L1 10115.6 CASE L1_E5P2 10257.4 141.8
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For example, the Reference Case examines resource needs if the DFGD and FF are assumed to
be installed on Edgewater Unit 5 and it operates until the end of 2045. The PVRR of this case
including the extension period is $10,493.7 million. In comparison, where the reference case is
modified to assume Edgewater Unit 5 is retired at the end of 2016, the PVRR including
extension is $10,632.6 million, which is $138.9 million higher than if the DFGD and FF are
installed on Edgewater Unit 5.
Table 10. EGEAS Analysis Results for the Base Case
Compliance Plan
PVRR
($ MM)
Differential from Base
Case
($ MM)
1. Install SO2 Emission Controls (Base Case) $ 10,493.7
2. Replace Edgewater Unit 5 $ 10,632.6 $ 138.9
Under the Base Case assumptions where Edgewater Unit 5 is retired early (Plan 2), the full
capacity of Edgewater 5 is replaced almost immediately, primarily with the combination of a 300
MW jointly owned combined cycle unit in 2017 and a 189 MW simple cycle combustion turbine
in 2018. This response occurs in 13 of the 19 sensitivities. In 5 of the remaining 6 sensitivities
this immediacy is advanced by adding the simple cycle combustion turbine in 2017. The
expansion plans for Plan 2 are provided in Appendix C § 13C.
Also of specific note is that, as shown in Table 9 above, all but one case where the Control
System is installed on Edgewater Unit 5 have a lower PVRR than the comparable cases where
Edgewater Unit 5 is retired early. This suggests that the modeled cost of the DFGD and FF for
Edgewater Unit 5, approximately $1,073/kW, in combination with its operational costs, are
lower in total than what otherwise would be purchased or generated if Edgewater Unit 5 were
retired early.
2. Aggressive Demand Side Management Does Not Obviate the Need for
Edgewater Unit 5 with the FGD
The Aggressive DSM planning alternative was selected in every sensitivity modeled in both
Plans 1 and 2. The selection of the Aggressive DSM planning alternative did not replace the
need to operate Edgewater Unit 5 with the DFGD and FF. Additionally, the installation of the
Edgewater Unit 5 DFGD and FF still remained the most cost effective means of meeting
capacity and energy needs for all but one sensitivity.
3. Payback Year Analysis
The calculations of the payback period of eight years is shown on Table 11, and is calculated as
follows: First, the year-to-year cumulative system PVRRs for each of Plans 1 and 2 are made
more comparable by removing the year-to-year cumulative PVRR for the DFGD and FF from
the Plan 1 cumulative PVRR (called ―Net Plan 1 cumulative PVRR‖). Next, the difference in
year-to-year Net Plan 1 cumulative PVRR and Plan 2 cumulative PVRR is calculated. Third, the
total cumulative PVRR for the DFGD and FF is compared to the annual differences in Net Plan 1
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cumulative PVRR and Plan 2 cumulative PVRR. The year in which the total cumulative PVRR
for the DFGD and FF exceeds the annual difference in Net Plan 1 cumulative PVRR and Plan 2
cumulative PVRR is the year prior to the year of payback. The number of payback years equals
the year of pay back less the first full year of operations plus one.
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Table 11. Calculations for the Payback Period of Installing a DFGD and FF On Edgewater Unit 5, $MM
Year Plan 1
Cumulative
PVRR
DFGD & FF
Capital Costs
Cumulative
PVRR
Net Plan 1
Cumulative PVRR:
Plan 1 Cumulative
PVRR Excluding
DFGD & FF
Capital Costs
Cumulative PVRR
Plan 2
Cumulative
PVRR
Net Plan 1
Cumulative
PVRR Less
Plan 2
Cumulative
PVRR
Total
DFGD &
FF Capital
Costs
Cumulative
PVRR
Payback
Period: The
Year of
Payback Less
The First Full
Year of
Operations
Plus One
a b c d = b - c e f = d - e g h
2011 $ 391.9 $ - $ 391.9 $ 391.9 $ -
2012 $ 768.7 $ - $ 768.7 $ 768.2 $ 0.5
2013 $ 1,135.2 $ 0.2 $ 1,135.0 $ 1,133.5 $ 1.5
2014 $ 1,534.5 $ 1.8 $ 1,532.7 $ 1,507.6 $ 25.1
2015 $ 1,983.8 $ 8.6 $ 1,975.2 $ 1,928.8 $ 46.4
2016 $ 2,425.0 $ 21.7 $ 2,403.3 $ 2,334.4 $ 68.9
2017 $ 2,875.0 $ 67.5 $ 2,807.5 $ 2,819.1 $ (11.6)
2018 $ 3,297.6 $ 108.1 $ 3,189.5 $ 3,281.3 $ (91.8)
2019 $ 3,745.1 $ 143.7 $ 3,601.4 $ 3,761.3 $ (159.9)
2020 $ 4,157.1 $ 174.9 $ 3,982.2 $ 4,200.0 $ (217.8)
2021 $ 4,535.5 $ 202.4 $ 4,333.1 $ 4,607.2 $ (274.1)
2022 $ 4,892.5 $ 226.5 $ 4,666.0 $ 4,990.3 $ (324.3)
2023 $ 5,233.6 $ 247.6 $ 4,986.0 $ 5,355.0 $ (369.0)
2024 $ 5,550.5 $ 266.1 $ 5,284.4 $ 5,689.5 $ (405.1) $ 375.1 8
2025 $ 5,847.5 $ 282.3 $ 5,565.2 $ 6,011.8 $ (446.6)
2026 $ 6,128.8 $ 296.5 $ 5,832.3 $ 6,310.3 $ (478.0)
2027 $ 6,393.2 $ 308.9 $ 6,084.3 $ 6,586.6 $ (502.3)
2028 $ 6,642.7 $ 319.6 $ 6,323.1 $ 6,844.2 $ (521.1)
2029 $ 6,883.5 $ 328.9 $ 6,554.6 $ 7,092.2 $ (537.6)
2030 $ 7,122.1 $ 337.0 $ 6,785.1 $ 7,324.9 $ (539.8)
2031 $ 7,339.5 $ 343.9 $ 6,995.6 $ 7,538.4 $ (542.8)
2032 $ 7,544.7 $ 349.8 $ 7,194.9 $ 7,746.2 $ (551.3)
2033 $ 7,735.3 $ 354.9 $ 7,380.4 $ 7,937.9 $ (557.5)
2034 $ 7,912.5 $ 359.1 $ 7,553.4 $ 8,116.0 $ (562.6)
2035 $ 8,097.8 $ 362.7 $ 7,735.1 $ 8,301.9 $ (566.8)
2036 $ 8,263.0 $ 365.7 $ 7,897.3 $ 8,466.3 $ (569.0)
2037 $ 8,417.0 $ 368.3 $ 8,048.7 $ 8,619.7 $ (571.0)
2038 $ 8,568.3 $ 370.4 $ 8,197.9 $ 8,770.1 $ (572.2)
2039 $ 8,711.9 $ 372.2 $ 8,339.7 $ 8,913.1 $ (573.4)
2040 $ 8,850.1 $ 373.7 $ 8,476.4 $ 9,042.9 $ (566.5)
Ext
Period $ 10,493.7 $ 375.1 $ 10,118.6 $ 10,632.6 $ (514.0)
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4. Summary of Economic Analyses
The EGEAS analysis provides a broad review of the installation of the DFGD and FF on
Edgewater Unit 5. The results of this analysis support the installation of the DFGD and FF on
Edgewater Unit 5 by demonstrating that the installation is the most economical alternative, under
many different sensitivities, to meet WPL‘s demand and energy needs for the modeled future.
Moreover, the analysis shows that the installation of the DFGD and FF on Edgewater Unit 5
represents the overall least cost alternative to WPL's ratepayers compared to early retirement of
Edgewater Unit 5 in order to reduce SO2 emissions to comply with pending and future
environmental regulations and requirements, and further compliance with current regulations.
The EGEAS analysis also demonstrates that the installation of the DFGD and FF on Edgewater
Unit 5 satisfies the Energy Priorities Law, Wis. Stat. § 1.12(4). While the EGEAS runs selected
Aggressive DSM, that selection did not obviate the need for the installation of the DFGD and FF
on Edgewater Unit 5. Additionally, WPL modeled various supply side alternatives including
wind and solar installations. The EGEAS runs demonstrate that the continued operation of
Edgewater Unit 5, with the installation of the DFGD and FF, as well as the other aspects of
WPL‘s base plan and fleet expansion is a more cost effective means of meeting the capacity and
energy needs than retiring Edgewater 5 early.
3.4 Need and Alternatives Analysis Summary
The Edgewater Unit 5 proposed DFGD and FF system will reduce SO2 emissions at the
Edgewater Generating Station. Installation will allow WPL to comply with CSAPR SO2
emission reduction requirements without subjecting WPL to potential CSAPR assurance
provision related penalties. Moreover, installation of the controls will satisfy potential unit-
specific emission reduction requirements which WPL believes could be required under a
settlement with EPA and Sierra Club over alleged NSR and PSD violations. The Control System
is a critical component of WPL‘s emission compliance strategy for the following reasons:
Investment in SO2 emission controls at Edgewater Unit 5 will significantly reduce
emissions of SO2;
Investment in SO2 emission controls at Edgewater Unit 5 and continued operation of the
unit, compared to retirement and replacement of Edgewater Unit 5, reduces ratepayer
revenue requirements for nearly all of the sensitivities modeled;
Investment in SO2 emission controls at Edgewater Unit 5 is responsive to the increasing
stringency and uncertainty associated with achieving and maintaining compliance.
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4.0 OPERATING PARAMETERS
The Control System for Edgewater Unit 5 will be designed to meet key operating parameters, including SO2 removal. The following sections describe operations of this system on Edgewater Unit 5 and associated operating costs based on burning the Design Coal—actual operating costs and emission reductions are subject to the coal type used at Edgewater Unit 5.
4.1 Cost of Operations
Table 12 provides a preliminary breakdown of key performance, fixed and variable operating parameters for the Control System to be installed on Edgewater Unit 5. For the purpose of estimating operating costs, the variable operating parameters and associated cost estimates are based on Edgewater Unit 5 burning the Design Coal and operating information from the vendors. Fixed operating parameters are based on operating and maintenance typical of a DFGD and FF system of this size and operating capability.
Table 12. Edgewater Unit 5 DFGD Design Operating Parameters
Operating Parameter Edgewater Unit 5 Units Performance Parameters
Plant Gross Maximum Rating 430 MW
Annual Capacity Factor %
SO2 Removal Efficiency (minimum) 92 %
SO2 Removed 0.79 lb/MMBtu
10,200 tons/year
Variable Operating Parameters
Flue Gas Flow Rate 1,190,000 scfm
FGD Solids to Disposal 4.3 tons/hr
Potable Water to Lime Preparation 35 Gpm
Dilution Water to DFGD 355 Gpm
Lime Consumption 4,000 lb/hr
Power Requirement (DFGD, FF and ID fan) 6.9 MW
Fixed Operating Parameter
Additional Operating Personnel 12 FTEs
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Fixed and variable operating costs are based on the consumption rates presented in Table 9 and
the following assumptions:
Pebble Lime Reagent: $124/ton
Edgewater Off-site Landfill: $18/ton
Potable Water: $1.12/1000 gallons
Dilution Water: $0.40/1000 gallons
Operating Personnel: $58/hr
The total annual operating cost (fixed and variable) for the Edgewater Unit 5 Control System is
estimated to be approximately $12,470,000 (in 2011 dollars12
).
4.2 Operating Characteristics
Installation of the Control System on Edgewater Unit 5 will have impacts on the operation of the
unit. The most significant items are as follows.
Boiler Furnace Pressure Transients and ID Fans
The addition of the Control System on Edgewater Unit 5 is not expected to trigger the need for
furnace reinforcement. This will be confirmed during the detailed design phase of the project.
Edgewater Unit 5 currently operates with forced draft (FD) and ID fans. The DFGD system and
FF will be located downstream of the existing ID fans, which will remain in service for this
project. Booster ID fans, installed at the outlet of the new FF, will be needed to overcome the
additional pressure drop required to carry the flue gas through the proposed emission control
equipment and interconnecting ductwork.
Process Control
The Control System will require new controls to be added and integrated into the operator
interface in the existing control room. Plant personnel will require training on all new equipment
and controls.
Materials Handling System
The lime will be delivered as pebble or hydrated lime. The pebble lime will be processed to
hydrated lime for use in the DFGD vessel. The DFGD byproduct solids will be collected in a
storage silo prior to being transported to an off-site landfill for disposal. The storage silo will be
equipped with vent filters to control the release of dust.
12
Annual operating costs were estimated in 2011 dollars and do not include costs associated with the auxiliary
power. In the EGEAS analysis accompanying this Application, the operating costs were escalated from 2011 dollars
to year-of-occurrence dollars.
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Truck and Rail Traffic
Based on the economic analysis performed as part of the creation of the application for a
certificate of authority, in conjunction with consulting engineers, WPL has determined that the
least capital intensive method for ongoing delivery of lime reagent and removal of the DFGD
byproduct solids is a truck delivery and removal system. While the truck solution results in the
lowest capital cost, it will result in an increase in the truck traffic around the site. It is
anticipated that about three trucks daily will be delivering lime and about 6 trucks daily will be
removing waste product to the landfill site. Rail traffic to the site is not expected to be affected
by the operation of the Control System.
Plant Operating Personnel
Based on historical data and operational studies, it is estimated that 12 new operating staff will
be needed to operate the proposed emission control and landfill systems. Actual staffing levels
will be determined by plant personnel at a later date.
Chemical Handling
Lime is the primary chemical required for operation of the Control System. The lime will be
delivered in crushed, pebble, or hydrated form via enclosed truck trailers and pneumatically
conveyed to the storage silo. The storage silo and lime preparation area will be equipped with
vent filters to control release of dust.
Auxiliary Power Consumption
Approximately 7 MW of auxiliary power will be consumed by the Control System. The
auxiliary power is for operation of the lime preparation equipment, DFGD vessel, FF, solids
handling equipment, balance of plant equipment, and booster ID fan.
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5.0 DESCRIPTION AND COST OF PROPERTY BEING REPLACED
The current project layout and general arrangement of the Control System was developed to
improve constructability, reduce length of equipment tie-in outages and reduce relocation and
demolition work. Based on preliminary engineering completed, the following major facilities are
planned for demolition:
Northeast storage building
Two rail spurs
Undergrounds (culverts, piping, electrical, foundations, etc.)
The cost estimate for the Edgewater Unit 5 project includes $1,300,000 (2011 dollars) for
demolition and removal. The net book value of the facilities is approximately $12,997 as of
12/31/2011. No other existing equipment or structures are anticipated to be demolished or
replaced as part of this project. Two 12 kV electrical lines supplying the SWWTF plant will need
to be relocated. See Appendix A for further detail on the demolition plans.
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6.0 REDUCTION TECHNOLOGY SELECTION
The following section is a synopsis of the emission control technology selection analysis. The
complete analysis of technologies considered, including the pros and cons of their application for
Edgewater Unit 5 that form the basis of the decision for the technology selected, can be found in
Appendix B.
6.1 Technology Selection Process
The following technologies were evaluated for SO2 reduction:
Semi-dry FGD, Spray Dry Absorber (SDA)
Semi-dry FGD, Circulating Dry Scrubber (CDS)
Semi-dry FGD, Alstom NIDTM
technology
Dry FGD, Dry Sorbent Injection (DSI)
Integrated Emission Control (IEC), Regenerative Activated Coke technology (ReACT)
Wet FGD, Limestone Forced Oxidation (LSFO)
Specific technologies selected for evaluation were determined based upon the following criteria:
Technology must be capable of achieving a minimum of 90% SO2 removal to promote
compliance with current, pending and future rules and any potential settlement.
Technology must be commercially available and proven for emission reductions at units
of comparable or larger size.
Capability of technology to meet strict surface water mercury discharge standards or
achieve zero liquid discharge.
Technology and fuel compatibility.
Reliable and long-term removal efficiencies achievable by each technology.
Co-benefits for maximum multi-pollutant emission controls, including sulfur trioxide
(SO3), mercury, and other HAPS cited in the EPA‗s MATS rule.
Implementation timeframes, especially lead times and availability of critical components.
Plant specific considerations (e.g. space or current plant equipment constraints).
The final selection of the technology to accomplish the goal of SO2 emission reductions at
Edgewater Unit 5 was determined as the least-cost system from an analysis of the relative costs
of the candidate technologies meeting the above selection criteria.
6.2 Summary of Technology Assessment
Although the LSFO system is capable of the required removal, it was eliminated for technical
reasons related to wastewater production and treatment and the requirement of new wet chimney
to handle the cooled and saturated flue gas. The LSFO system produces a wastewater stream,
which will require further treatment prior to discharge. Additionally, new wastewater effluent
guidelines for power plants, scheduled to be proposed in November 2012, could require the
installation of a zero liquid discharge (ZLD) system to treat the LSFO wastewater stream.
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Although ZLD systems are currently marketed for this service, the ability of such a system to
consistently and reliably treat the wastewater produced by the LSFO system has not been proven.
It is uncertain whether WPL could permit a new emission source, which would be required with
the installation of a new chimney. Additionally, when the flue gas exits the chimney it will form
a dense water vapor plume under all ambient conditions that can be perceived as a major impact
on area visibility.
The DSI system was eliminated from consideration because it has limited operational history for
SO2 control, is unable to achieve the required emission reduction level of 90%, imposes the
greatest limitations on Edgewater Unit 5 by limiting future SO2 reductions, fuel flexibility, and
eliminating flyash sales. The DSI system also required the greatest amount of in-plant rail and/or
truck traffic to handle the byproduct.
The ReACT system was eliminated from consideration for this application because there are no
commercial installations of similar or greater size units operating in the U.S.; the only source of
supply for the key reagent of activated coke is China; and the required creation and requisite
handling of a concentrated sulfuric acid byproduct and mercury contaminated waste.
The remaining semi-dry FGD technologies (SDA, CDS and NID), referred to in this Application,
as dry FGD (DFGD) because they produce a dry byproduct, are the best options to meet the
requirements for Edgewater Unit 5 in that they:
All are commercially available. Although SDA has the most established operational
history, both CDS and NID have been installed and operated long enough to be
considered viable alternates. They are best suited to units that fire coal with a coal sulfur
content 1.5 wt% or less. Because Edgewater Unit 5 currently fires a PRB coal with lower
sulfur content, these technologies allow for future fuel flexibility.
Provide cost effective control. The above DFGD systems can reliably and
economically achieve a minimum of 90% reduction in SO2 emissions.
Utilize the existing chimney. The flue gas exiting the DFGD system is not saturated
with water vapor. Therefore, chimney exit velocity requirements can be maintained and
the potential for corrosion of the existing chimney liner is limited. This allows the
existing chimney to remain in operation, saving considerable project cost associated with
constructing a new chimney.
Produce no mercury contaminated wastewater. A DFGD and FF system produces a
dry byproduct. There is no continuous wastewater stream containing mercury or other
pollutants that would require treatment to meet discharge standards.
Provide increased flexibility to maintain Edgewater Unit 5 ash sales. The installation
of a baghouse allows for the future injection of activated carbon for mercury control
downstream of the existing ESPs and collected separately from the flyash.
Provide additional co-benefits. The DFGD and FF system is very effective at capturing
fine particulate matter such as PM2.5 and acid mist.
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7.0 ENVIRONMENTAL IMPACTS/PERMITS
The proposed project location and preliminary site layout for the project are shown in Section 1,
on Figure 1 and Figure 2. The general site layout is also shown in Appendix A.
7.1 Emissions Reductions
The proposed Project at Edgewater Unit 5 is designed to reduce SO2. There will be co-benefit
reductions of mercury, acid gases, and other HAPs. Controlling SO2 emissions will reduce acid
rain and the formation of fine particulate matter in the atmosphere.
7.2 Proximity to Floodplains
The area for the location of the Edgewater Unit 5 Control System is not within a floodway, 100-
year floodplain, or flood-prone areas.
7.3 Information on Applicable Environmental Factors
Several environmental factors have been considered for the proposed project. The studies
performed include the following:
Archaeological and historic resources
Threatened or endangered species
Solid waste
Water resources
Wastewater discharge
Additional information is found in the following sections.
7.3.1 Archaeological and Historic Resources
A study was performed in January 2008 by an independent consultant regarding the potential
presence of cultural, archeological, and burial sites at the Edgewater facility. According to the
study, there are no known archaeological or historic resources in the construction footprint of the
project.
7.3.2 Threatened and Endangered Species
A study was performed in December 2007 by an independent consultant identifying potential
threatened and endangered species at the Edgewater facility. According to the study, the
potential exists to impact threatened, endangered, or special concern species on the Edgewater
property, especially on the sand dunes along the lakeshore. These species include: red-
shouldered hawk (buteo lineatus); piping plover (charadrius melodus); one-flowered broomrape
(orobanche uniflora); thickspike (elymus lanceolatus ssp. psammophilus); American sea-rocket
(cakile edenntula); Northern Mosaic Forest; and Southern Sedge Meadow.
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However, construction of the Control System on Edgewater Unit 5 will occur on already
developed WPL property with no adverse impacts to critical habitats for endangered, threatened,
or special concern species. Appropriate Best Management Practices (BMPs) and erosion control
techniques will be used to prevent impacts to habitats. Accordingly, no detrimental impact to
threatened, endangered, or special impact species is expected.
7.3.3 Solid Waste
Currently, bottom ash and flyash is sold or transported off-site to a company-owned landfill.
The existing ESPs are expected to remain in operation after the addition of the Control System,
allowing for continued beneficial reuse of the flyash. No impact on the bottom ash composition
or disposition is expected. The proposed FF will collect dry FGD process particulates, including
calcium compounds, unused lime reagent, and any flyash and activated carbon from the ACI
system remaining in the flue gas. No market currently exists for this material, although WPL is
participating in research to evaluate the beneficial use of DFGD byproducts. For the purpose of
determining the environmental impacts of the project, WPL assumes that the volume of solid
waste collected in the FF will be sent off-site for disposal.
7.3.4 Water Resources
A study was performed in January 2008 by an independent consultant regarding the potential
presence of wetlands and open waters at the Edgewater facility. Based on information in this
study, the area where Edgewater Unit 5 construction activities will take place will not impact
wetlands or open waters.
To operate the proposed emission control systems, plant water consumption will increase. The
lime preparation process will require approximately 35 gallons per minute (gpm) of high quality
water such as potable or lake water. Based on 2011 water use data, this will potentially increase
Edgewater Generating Station‘s water usage by approximately 0.02%. Edgewater Unit 5
currently uses 216,952 gpm, which will increase to 216,987 gpm. The increased amount is still
well within the plant‘s permitted water usage rate of 321,250 gpm. An additional 355 gpm of
dilution water is required to cool the flue gas in the DFGD vessel. This dilution water can be of
a lower quality such as cooling pond water, ash pond water or other wastewater stream. The
water quality of each source will need to be verified for its suitability for the process. WPL will
attempt to minimize the impact to water resources by first utilizing existing water sources, such
as waters that are part of the facility‘s wastewater discharge system, before committing to
consuming any additional or new water supply. A plant water balance study will be performed as
part of this project to understand which existing water sources can be used to supply the project‘s
water needs.
7.3.5 Wastewater Discharge
Edgewater Generating Station‘s wastewater discharge will not be affected by the addition of the
proposed emission reduction systems because the DFGD system operates without wastewater
discharge. Water used in the DFGD system is absorbed in the process and the spent reagent and
particulate matter is collected in a FF and sent for disposal or recycled back to the absorber.
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7.3.6 Air Quality Resources
Operation of the Control System is expected to result in a direct decrease in air pollutants.
Ancillary operations, including material deliveries, lime unloading and storage, and byproduct
handling may result in minor increases in fugitive dust PM. WPL will develop dust mitigation
strategies to minimize fugitive dust as part of the detailed engineering design.
7.4 List of Permits and Approvals Needed
Table 13 provides a list of permits and approvals that may be required for the project.
Table 13. List of Required Permits and Approvals
Agency Reference Permit/Plan/Approval/
Report Regulated Activity Needed
Water Quality
WDNR Wis. Stat. Ch. 30 Waterway Permit Work within a drainage way or waterway
Prior to construction
WDNR WAC NR 216
Erosion Control Plan and Storm Water Management Plan for Construction Activities
Land disturbances greater than 1 acre
Prior to construction
WDNR WAC NR 216 SWPPP Storm water management for industrial facilities. This may need to be updated for the new operation
Prior to operation
WDNR WAC NR 200 WPDES Discharge Permit Tank containment and tank loading pad system discharge
Prior to construction
WDNR WAC NR 200 WPDES General Discharge Permit Dewatering during construction
Prior to construction
WDNR WAC NR 200 WPDES General Discharge Permit Hydrostatic testing of tanks Prior to hydrostatic testing
WDNR WAC NR 142.06 Water Use Registration and Consumptive Use Permit
Increased water use Prior to construction
Hazardous Materials
USEPA 40 CFR Part 112 SPCC Plan Temporary oil storage on-site for construction activities
Prior to arrival of oil on-site
USEPA 40 CFR Part 112 SPCC Plan Additional chemical or fuel storage on-site supporting the newly constructed equipment
Prior to commencing operation
USEPA 40 CFR Part 302 CERCLA Emergency Response Planning Spill response of hazardous materials. We typically cover this in our SPCC plan.
Prior to chemicals being on-site
USEPA 40 CFR Part 355 EPCRA Emergency Response Planning Spill response of hazardous materials. We typically cover this in our SPCC plan.
Prior to chemicals being on-site
USEPA 40 CFR Part 370 Initial Notification Notification of lime stored onsite
Prior to chemicals being on-site
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Agency Reference Permit/Plan/Approval/
Report Regulated Activity Needed
Air Quality
USEPA 40 CFR Part 72 Acid Rain Permit Emission controls, rates, and averaging plans need to be updated if NOx or SO2 emissions change.
Prior to operation
WDNR WAC NR 405 and 406
Construction Permit (NSR, PSD, etc.) New or increased emissions due to the modification
Prior to construction
WDNR WAC NR 407 Title V Operation Permit Activities covered in construction permit need to be rolled into the Title V operating permit
Within time period specified in construction permit
Tall Structures
FAA 14 CFR Part 77 Notice of Proposed Construction or Alteration
Use of crane during construction 200 feet tall or within 20,000 feet of an airport.
Prior to construction
Solid Waste/Byproducts
WDNR Waste Disposal Authorization Approval to dispose of new material in a landfill
Prior to disposal
WDNR Byproduct Use Authorization Approval for beneficial reuse Prior to use
Transportation
WDOT WAC Trans 254 Delivery of large/heavy components Single trip permit for the transportation of loads of excessive size and or weight
Prior to shipment
Municipality City, county, village, etc.
Delivery of large/heavy components Single trip permit for the transportation of loads of excessive size and/or weight
Prior to shipment
Municipality City, county, village, etc.
Transport to Landfill Multi trip permit for the transportation of DFGD byproduct solids by truck to land fill.
Prior to disposal
Local Approvals
Municipality City of Sheboygan Construction Permit Building permit Prior to construction
Municipality and County
City, county, village, etc.
Zoning Variance Evaluate local ordinances for zoning requirements and approvals based on detailed engineering and construction (e.g. for structure height requirements).
Prior to construction
Municipality and County
City, county, village, etc.
Local approvals for air quality, water quality, storm water, hazardous materials, etc.
Evaluate local ordinances for environmental or construction requirements based on detailed engineering and construction.
Prior to construction
Public Version
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8.0 DESIGNATION OF PUBLIC UTILITIES AND OTHERS AFFECTED
Edgewater Unit 5 is wholly owned by WPL. The project will require coordination with the
American Transmission Company (ATC) for any required modifications or enhancements to
ATC assets to power the equipment. The SWWTF is immediately north of the plant. The
SWWTF‘s electrical power currently runs underground in the proposed construction area. This
electrical service may need to be relocated to accommodate the DFGD design and construction.
No other public utilities will be affected by this project.
Public Version
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